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DIAMOND OFFSHORE DRILLING, INC. - Annual Report: 2010 (Form 10-K)

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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, 2010
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 whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).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 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, 2010   $4,286,231,692
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 17, 2011   Common Stock, $0.01 par value per share   139,026,897 shares
DOCUMENTS INCORPORATED BY REFERENCE
     Portions of the definitive proxy statement relating to the 2010 Annual Meeting of Stockholders of Diamond Offshore Drilling, Inc., which will be filed within 120 days of December 31, 2010, are incorporated by reference in Part III of this report.
 
 

 

 

DIAMOND OFFSHORE DRILLING, INC.
FORM 10-K for the Year Ended December 31, 2010
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Certain 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.
        
 
        
       
 
        
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 EX-101 INSTANCE DOCUMENT
 EX-101 SCHEMA DOCUMENT
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 EX-101 LABELS LINKBASE DOCUMENT
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 EX-101 DEFINITION LINKBASE DOCUMENT

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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 46 offshore rigs consisting of 32 semisubmersibles, 13 jack-ups and one drillship. In addition, in December 2010, we entered into a turnkey contract for construction of a new dynamically positioned, ultra-deepwater drillship with delivery scheduled for late in the second quarter of 2013, and, in January 2011, we entered into another turnkey contract for the construction of a second, sister drillship with delivery scheduled for the fourth quarter of 2013. See “ – Fleet Enhancements and Additions.” 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 deepwater, harsh environment, conventional semisubmersible and jack-up markets.
     Semisubmersibles. We own and operate 32 semisubmersibles, consisting of 13 high-specification and 19 intermediate rigs. Semisubmersible rigs consist of an upper working and living deck resting on vertical columns connected to lower hull members. Such rigs operate in a “semi-submerged” position, remaining afloat, off bottom, in a position in which the lower hull is approximately 55 feet to 90 feet below the water line and the upper deck protrudes well above the surface. Semisubmersibles are typically anchored in position and remain stable for drilling in the semi-submerged floating position due in part to their wave transparency characteristics at the water line. Semisubmersibles can also be held in position through the use of a computer controlled thruster (dynamic-positioning) system to maintain the rig’s position over a drillsite. We have five 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 24, 2011, six of our 13 high-specification semisubmersibles were located offshore Brazil, and two were located in the United States, or U.S., Gulf of Mexico, or GOM. Of our remaining high-specification semisubmersibles, one was located offshore each of Angola, Egypt, Indonesia and the Republic of Congo and one was in a shipyard in Singapore.
     Our intermediate semisubmersibles generally work in maximum water depths up to 3,999 feet. As of January 24, 2011, we had 19 intermediate semisubmersible rigs in various locations around the world. Nine of these semisubmersibles were operating in the South America region, including eight offshore Brazil and one offshore the Falkland Islands; three were located in the North Sea; two were located offshore Australia; one was located offshore Vietnam and one was cold stacked in Malaysia. Our remaining three intermediate semisubmersibles are located in the GOM, where two have been cold stacked.
     Drillship. We currently have one high-specification drillship, the Ocean Clipper, which was located offshore Brazil as of January 24, 2011. 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. See “ – Fleet Enhancements and Additions.”
     Both semisubmersible rigs and drillships are commonly referred to as floaters in the offshore drilling industry.
     Jack-ups. We currently have 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

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retracted. Once over a drillsite, the legs are lowered until they rest on the seabed and jacking continues with the legs penetrating the seabed until resistance is sufficient to elevate the hull 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, which do not have this capability.
     As of January 24, 2011, six of our 13 jack-up rigs were located in the GOM, of which four units have been cold stacked, consisting of two mat-supported cantilevered units, one mat-supported slot unit and one independent-leg, cantilevered unit. Of our seven remaining jack-up rigs, all of which are independent-leg cantilevered units, two each were located offshore Egypt and Mexico, and one was located offshore each of Brazil and Montenegro. Our remaining jack-up rig was en route to Thailand.
     Fleet Enhancements and Additions. Our long-term strategy has been 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. In December 2010 and January 2011, we entered into separate turnkey contracts with Hyundai Heavy Industries Co., Ltd., or Hyundai, for the construction of two dynamically positioned, ultra-deepwater drillships with deliveries scheduled for late in the second and fourth quarters of 2013. We expect total cost for the sister drillships, including commissioning, spares and project management, to aggregate approximately $1.2 billion. In addition, we have also obtained from Hyundai a fixed-price option for the purchase of a third drillship, which we have the right to exercise at any time before the end of the first quarter of 2011.
     In June 2009 and September 2009, we acquired two new-build deepwater, dynamically positioned, semisubmersible drilling rigs, the Ocean Courage and the Ocean Valor, respectively. Including our rig acquisitions in 2009 and our two recent drillship orders, we have purchased, ordered or upgraded seven units with capabilities in 10,000 feet of water over the last four years.
     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 24, 2011, 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 (13):
                        
Ocean Valor
     10,000     DP; 6R; 15K; 4M   2009   Brazil   Petrobras
Ocean Courage
     10,000     DP; 6R; 15K; 4M   2009   Brazil   Petrobras
Ocean Confidence
     10,000     DP; 6R; 15K; 4M   2001/2009   Republic of Congo   Total/Cobalt Angola – rig acceptance
Ocean Monarch
     10,000     15K; 4M   1974/2008   GOM   Anadarko (Force Majeure dispute)
Ocean Endeavor
     10,000     15K; 4M   1975/2007   Egypt   Burullus / RASHPETCO
Ocean Rover
     8,000     15K; 4M   1973/2008   Indonesia   Murphy Exploration
Ocean Baroness
     7,000     15K; 4M   1973/2002   Brazil   Petrobras
Ocean Victory
     5,500     15K   1972/2006   GOM   ATP Oil & Gas
Ocean America
     5,500     15K   1988/1999   Singapore   Shipyard Project
Ocean Valiant
     5,500     15K   1988/1999   Angola   Total
Ocean Star
     5,500     15K   1974/1999   Brazil   OGX
Ocean Alliance
     5,250     DP; 15K   1988/1999   Brazil   Petrobras
Ocean Quest
     4,000     15K   1973/1996   Brazil   OGX
Drillship (1):
                        
Ocean Clipper
     7,875     DP; 15K   1976/1999   Brazil   Petrobras
Intermediate Semisubmersibles (19):
                        
Ocean Winner
     4,000         1977/2004   Brazil   Petrobras
Ocean Worker
     4,000         1982/2008   Brazil   Petrobras
Ocean Yatzy
     3,300     DP   1989/1998   Brazil   Petrobras
Ocean Voyager
     3,200         1973/1995   GOM   Cold stacked
Ocean Patriot
     3,000     15K   1982/2003   Australia   Apache Energy
Ocean Epoch
     3,000         1977/2000   Australia   Japan Energy
Ocean General
     3,000         1976/2000   Vietnam   PVEP Dai Hung
Ocean Yorktown
     2,850         1976/1996   Brazil   Petrobras
Ocean Concord
     2,300         1975/1999   Brazil   Petrobras
Ocean Lexington
     2,200         1976/1995   Brazil   OGX
Ocean Saratoga
     2,200         1976/1995   GOM   Taylor Energy
Ocean Whittington
     1,650         1974/1995   Brazil   Petrobras
Ocean Bounty
     1,500         1977/1992   Malaysia   Cold stacked
Ocean Guardian
     1,500     15K   1985   Falkland Islands   Rockhopper Exploration
Ocean New Era
     1,500         1974/1990   GOM   Cold stacked
Ocean Princess
     1,500     15K   1977/1998   North Sea/U.K.   Talisman
Ocean Vanguard
     1,500     15K   1982   North Sea/Norway   Statoil
Ocean Nomad
     1,200         1975/2001   North Sea/U.K.   B G International
Ocean Ambassador
     1,100         1975/1995   Brazil   OGX
Jack-ups (13):
                        
Ocean Scepter
     350     IC; 15K   2008   Brazil   OGX-waiting on IBAMA certification
Ocean Titan
     350     IC; 15K   1974/2004   GOM   Actively marketing
Ocean King
     300     IC   1973/1999   Montenegro   Actively marketing
Ocean Nugget
     300     IC   1976/1995   Mexico   PEMEX
Ocean Summit
     300     IC   1972/2003   Mexico   PEMEX
Ocean Heritage
     300     IC   1981/2002   Egypt   SUCO
Ocean Spartan
     300     IC   1980/2003   GOM   Cold stacked
Ocean Spur
     300     IC   1981/2003   Egypt   WEPCO
Ocean Sovereign
     300     IC   1981/2003   Enroute to Thailand   Diamond Offshore/Salamander
Ocean Champion
     250     MS   1975/2004   GOM   Cold stacked
Ocean Columbia
     250     IC   1978/1990   GOM   Actively marketing
Ocean Crusader
     200     MC   1982/1992   GOM   Cold stacked
Ocean Drake
     200     MC   1983/1986   GOM   Cold stacked
Under Construction (2)
                        
Ocean BlackHornet
     10,000     DP; 7R; 15K; 5M   2013   South Korea   On order
Ocean BlackHawk
     10,000     DP; 7R; 15K; 5M   2013   South Korea   On order
         
   
Attributes
    
DP   =  Dynamically Positioned/Self-Propelled
  MS  =  Mat-Supported Slot Rig   15K =  15,000 psi well control system
IC    =  Independent-Leg Cantilevered Rig
  6R   =  Six ram blow out preventer   4M  =  Four Mud Pumps
MC  =  Mat-Supported Cantilevered Rig
  7R   =  Seven ram blow out preventer   5M  =  Five Mud Pumps
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 operating water depth capability for each drilling unit. In many cases, individual rigs are capable of drilling, or have drilled in, greater water depths. In all cases, floating rigs are capable of working successfully at greater depths than their nominal water depth. On a case by case basis, we may achieve a greater depth capacity by providing additional equipment.
 
(b)   Such enhancements may include water depth upgrades, mud pump additions and increases in deck load capacity.
 
(c)   GOM means U.S. Gulf of Mexico. One of our drilling rigs was en route between geographic locations. It has been presented in the preceding table in the geographic location in which it is expected to commence drilling operations in 2011.
 
(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:
  •   South America, principally offshore Brazil and the Falkland Islands;
 
  •   Australia and Asia, including Malaysia, Indonesia, Thailand and Vietnam;
 
  •   the Middle East, including Kuwait, Qatar and Saudi Arabia;
 
  •   Europe, principally in the United Kingdom, or U.K., and Norway;
 
  •   West Africa, including Angola and the Republic of Congo;
 
  •   the Mediterranean Basin, including Egypt; and
 
  •   the Gulf of Mexico, including the U.S. and Mexico.
     We actively market our rigs worldwide. From time to time our fleet operates in various other markets throughout the world as the market demands. See Note 16 “Segments and Geographic Area Analysis” to our Consolidated Financial Statements in Item 8 of this report.
     We believe our presence in multiple markets is valuable in many respects. For example, we believe that our experience with safety and other regulatory matters in the U.K. has been beneficial in Australia and other international areas in which we operate, while production experience we have gained through our Brazilian and North Sea operations has potential application worldwide. Additionally, we believe our performance for a customer in one market segment or area enables us to better understand that customer’s needs and better serve that customer in different market segments or other geographic locations.
Offshore Contract Drilling Services
     Our contracts to provide offshore drilling services vary in their terms and provisions. We typically obtain our contracts through competitive bidding, although it is not unusual for us to be awarded drilling contracts without competitive bidding. Our drilling contracts generally provide for a basic drilling rate on a fixed dayrate basis regardless of whether or not such drilling results in a productive well. Drilling contracts may also provide for lower rates during periods when the rig is being moved or when drilling operations are interrupted or restricted by equipment breakdowns, adverse weather conditions or other conditions beyond our control. Under dayrate contracts, we generally pay the operating expenses of the rig, including wages and the cost of incidental supplies. Historically, dayrate contracts have accounted for the majority of our revenues. In addition, from time to time, our dayrate contracts may also provide for the ability to earn an incentive bonus from our customer based upon performance.
     A dayrate drilling contract generally extends over a period of time covering either the drilling of a single well or a group of wells, which we refer to as a well-to-well contract, or a fixed term, which we refer to as a term contract, and may be terminated by the customer in the event the drilling unit is destroyed or lost or if drilling operations are suspended for an extended period of time as a result of a breakdown of equipment or, in some cases, due to other events beyond the control of either party to the contract. In addition, certain of our contracts permit the customer to terminate the contract early by giving notice, and in most circumstances may require the payment of an early termination fee by the customer. The contract term in many instances may also be extended by the customer exercising options for the drilling of additional wells or for an additional length of time, generally at competitive market rates and mutually agreeable terms at the time of the extension. See “Risk Factors – The terms of our drilling contracts may limit our ability to attain profitability in a declining market or to benefit from increasing dayrates in an improving market,” “Risk Factors – Our drilling contracts may be terminated due to events beyond our control,” “Risk Factors – Our business involves numerous operating hazards which could expose us to

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significant losses and significant damage claims. We are not fully insured against all of these risks and our contractual indemnity provisions may not fully protect us” and “Risk Factors – We have elected to self-insure for physical damage to rigs and equipment caused by named windstorms in the U.S. Gulf of Mexico” in Item 1A of this report, which are incorporated herein by reference. For a discussion of our contract backlog, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Overview – Contract Drilling Backlog” in Item 7 of this report, which is incorporated herein by reference.
Customers
     We provide offshore drilling services to a customer base that includes major and independent oil and gas companies and government-owned oil companies. During 2010, 2009 and 2008, we performed services for 46, 47 and 49 different customers, respectively. During 2010, 2009 and 2008, one of our two customers in Brazil, Petróleo Brasileiro S.A., or Petrobras (a Brazilian multinational energy company that is majority-owned by the Brazilian government), accounted for 24%, 15% and 13% of our annual total consolidated revenues, respectively. OGX Petróleo e Gás Ltda., or OGX (a privately owned Brazilian oil and natural gas company), accounted for 14% of our annual total consolidated revenues in 2010. No other customer accounted for 10% or more of our annual total consolidated revenues during 2010, 2009 or 2008.
     Brazil is the most active floater market in the world today. As of the date of this report, the greatest concentration of our operating assets outside the United States is offshore Brazil, where we have 16 rigs currently working. Our contract backlog attributable to our expected operations offshore Brazil is $1.6 billion, $1.5 billion and $987.0 million for the years 2011, 2012 and 2013, respectively, and $1.0 billion in the aggregate for the years 2014 to 2016. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Overview – Contract Drilling Backlog” included in Item 7 of this report.
     We principally market our services in North America through our Houston, Texas office. We market our services in other geographic locations principally from our regional offices in Aberdeen, Scotland and Perth, Australia. We provide technical and administrative support functions from our Houston office.
Competition
     The offshore contract drilling industry is highly competitive with numerous industry participants, none of which at the present time has a dominant market share. The drilling industry has experienced consolidation in recent years and may experience additional consolidation, which could create additional large competitors. Some of our competitors may have greater financial or other resources than we do. We compete with offshore drilling contractors that together have more than 730 mobile rigs available worldwide.
     The offshore contract drilling industry is influenced by a number of factors, including global economies and 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.
     Drilling contracts are traditionally awarded on a competitive bid basis. Intense price competition is often the primary factor in determining which qualified contractor is awarded a job. Customers may also consider rig availability and location, a drilling contractor’s operational and safety performance record, and condition and suitability of equipment. We believe we compete favorably with respect to these factors.
     We compete on a worldwide basis, but competition may vary significantly by region at any particular time. See “—Markets.” Competition for offshore rigs generally takes place on a global basis, as these rigs are highly mobile and may be moved, at a cost that may be substantial, from one region to another. Competing contractors are able to adjust localized supply and demand imbalances by moving rigs from areas of low utilization and dayrates to areas of greater activity and relatively higher dayrates. Significant new rig construction and upgrades of existing drilling units could also intensify price competition. See “Risk Factors – Our industry is highly competitive and cyclical, with intense price competition” in Item 1A of this report, which is incorporated herein by reference.
Governmental Regulation
     Our operations are subject to numerous international, U.S., state and local laws and regulations that relate directly or indirectly to our operations, including regulations controlling the discharge of materials into the environment, requiring removal and clean-up under some circumstances, or otherwise relating to the protection of

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the environment, and may include laws or regulations pertaining to climate change, carbon emissions or energy use. See “Risk Factors – The aftermath of the moratorium on offshore drilling in the U.S. Gulf of Mexico and new regulations adopted as a result of the investigation into the Macondo well blowout could negatively impact us,” “Risk Factors – Governmental laws and regulations, both domestic and international, may add to our costs or limit our drilling activity” and “Risk Factors – Compliance with or breach of environmental laws can be costly and could limit our operations” in Item 1A of this report, which are incorporated herein by reference.
Operations Outside the United States
     Our operations outside the U.S. accounted for approximately 81%, 66% and 59% of our total consolidated revenues for the years ended December 31, 2010, 2009 and 2008, 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, 2010, we had approximately 5,300 workers, including international crew personnel furnished through independent labor contractors. We have experienced satisfactory labor relations and provide comprehensive benefit plans for our employees.
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, 2011   Position
Lawrence R. Dickerson
    58     President, Chief Executive Officer and Director
John M. Vecchio
    60     Executive Vice President
Gary T. Krenek
    52     Senior Vice President and Chief Financial Officer
William C. Long
    44     Senior Vice President, General Counsel & Secretary
Beth G. Gordon
    55     Controller – Chief Accounting Officer
Lyndol L. Dew
    56     Senior Vice President – Worldwide Operations
     Lawrence R. Dickerson has served as our President and a Director since March 1998 and as our Chief Executive Officer since June 2008. Mr. Dickerson served as our Chief Operating Officer from March 1998 to June 2008. Mr. Dickerson served on the United States Commission on Ocean Policy from 2001 to 2004.
     John M. Vecchio has served as Executive Vice President since August 2009. Mr. Vecchio previously served as our Senior Vice President – Technical Services from April 2002 to July 2009.
     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.
     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.

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Access to Company Filings
     We are subject to the informational requirements of the Securities Exchange Act of 1934, as amended, or the Exchange Act, and accordingly file annual, quarterly and current reports, any amendments to those reports, proxy statements and other information with the United States Securities and Exchange Commission, or SEC. You may read and copy the information we file with the SEC at the public reference facilities maintained by the SEC at 100 F Street, N.E., Washington, DC 20549. Please call the SEC at 1-800-SEC-0330 for further information on the operation of the public reference room. Our SEC filings are also available to the public from the SEC’s Internet site at www.sec.gov or from our Internet site at www.diamondoffshore.com. Our website provides a hyperlink to a third-party SEC filings website where these reports may be viewed and printed at no cost as soon as reasonably practicable after we have electronically filed such material with, or furnished it to, the SEC. The information contained on our website, or on other websites linked to our website, is not part of this report.
Item 1A. Risk Factors.
     Our business is subject to a variety of risks, including the risks described below. You should carefully consider these risks when evaluating us and our securities. The risks and uncertainties described below are not the only ones facing our company. We are also subject to a variety of risks that affect many other companies generally, as well as additional risks and uncertainties not known to us or that we currently believe are not as significant as the risks described below. If any of the following risks actually occur, our business, financial condition, results of operations and cash flows, and the trading prices of our securities, may be materially and adversely affected.
Our business depends on the level of activity in the oil and gas industry, which is significantly affected by volatile oil and gas prices.
     Our business depends on the level of activity in offshore oil and gas exploration, development and production in markets worldwide. Worldwide demand for oil and gas, oil and gas prices, market expectations of potential changes in these prices and a variety of political and economic factors significantly affect this level of activity. However, higher or lower commodity demand and prices do not necessarily translate into increased or decreased drilling activity since our customers’ project development time, reserve replacement needs, as well as expectations of future commodity demand and prices all combine to affect demand for our rigs. Oil and gas prices have been, and are expected to continue to be, extremely volatile and are affected by numerous factors beyond our control, including:
  •   worldwide demand for oil and gas;
 
  •   the level of economic activity in energy-consuming markets;
 
  •   the worldwide economic environment or economic trends, such as recessions;
 
  •   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;
 
  •   civil unrest;
 
  •   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;
 
  •   competition for customers’ drilling budgets from land-based energy markets around the world;
 
  •   domestic and foreign tax policy; and
 
  •   advances in exploration and development technology.

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The aftermath of the moratorium on offshore drilling in the U.S. Gulf of Mexico and new regulations adopted as a result of the investigation into the Macondo well blowout could negatively impact us.
     On April 20, 2010, the Macondo well (operated by BP p.l.c. and drilled by Transocean Ltd.) in the GOM experienced a blowout and immediately began flowing oil into the GOM (the Macondo incident). Efforts to permanently plug and abandon the well and contain the spill were successfully completed in September 2010. In the near-term aftermath of the Macondo incident, on May 30, 2010, the U.S. government imposed a six-month moratorium on certain drilling activities in water deeper than 500 feet in the GOM and subsequently implemented enhanced safety requirements applicable to all drilling operations in the GOM, including operations in water shallower than 500 feet. On October 12, 2010, the U.S. government lifted the moratorium subject to compliance with enhanced safety requirements including those set forth in Notices to Lessees, or NTL, 2010-N05 and 2010-N06, both of which were implemented during the drilling ban. Currently, all operations in the GOM are required to comply with the Interim Final Rule to Enhance Safety Measures for Energy Development on the Outer Continental Shelf (Drilling Safety Rule) and the Workplace Safety Rule on Safety and Environmental Management Systems, both of which were issued on September 30, 2010, as well as NTL 2010-N10 (known as the Compliance and Review NTL). We continue to evaluate these new measures to ensure that our rigs and equipment are in full compliance, where applicable. Additional requirements could be forthcoming based on further recommendations by regulatory agencies investigating the Macondo incident, as well as restructuring within the Department of the Interior and the Bureau of Ocean Energy Management, Regulation and Enforcement, or BOEMRE. We are not able to predict the likelihood, nature or extent of additional rulemaking, nor are we able to predict when the BOEMRE will issue drilling permits to our customers. We are not able to predict the future impact of these events on our operations. Even with the drilling ban lifted, requirements regarding certain deepwater drilling activities may remain uncertain until the BOEMRE resumes its regular permitting of those activities.
     The current and future regulatory environment in the GOM could result in a number of rigs being, or becoming available to be, moved to locations outside of the GOM, which could potentially put downward pressure on global dayrates and adversely affect our ability to contract our floating rigs that currently are not contracted or are coming off contract. Additional governmental regulations concerning licensing, taxation, equipment specifications, training requirements or other matters could increase the costs of our operations, and escalating costs borne by our customers, along with permitting delays, could reduce exploration activity in the GOM and therefore demand for our services. In addition, insurance costs across the industry are expected to increase as a result of the Macondo incident, and in the future certain insurance coverage is likely to become more costly, and may become less available or not available at all.
     The inability to redeploy our rigs impacted by the drilling moratorium, or to obtain dayrates sufficient to cover our additional operating expenses and mobilization costs if such impacted rigs are redeployed in international waters, could adversely affect our financial position, results of operations and cash flows. In addition, implementation of additional regulations may subject us to increased costs of operating and/or a reduction in the area of operation in the GOM.
Governmental laws and regulations, both domestic and international, 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 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 industry. The modification of existing laws or regulations or the adoption of new laws or regulations curtailing exploratory or developmental drilling for oil and gas for economic, environmental or other reasons could materially and adversely affect our operations by limiting drilling opportunities.
     As awareness of climate change issues increases, governments around the world are beginning to address the matter. This may result in new environmental regulations that may unfavorably impact us, our suppliers and our customers. We may be exposed to risks related to new laws or regulations pertaining to climate change, carbon emissions or energy use that could decrease the use of oil or natural gas, thus reducing demand for hydrocarbon-

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based fuel and our drilling services. Governments may also pass laws or regulations encouraging or mandating the use of alternative energy sources, such as wind power and solar energy, which may reduce demand for oil and natural gas and our drilling services. In addition, new laws or regulations, including those that may come into effect following the Macondo incident, may require an increase in our capital spending for additional equipment to comply with such requirements and could also result in a reduction in revenues associated with downtime required to install such equipment.
Compliance with or breach of environmental laws can be costly and could limit our operations.
     In the United States and in many of the international locations in which we operate, regulations controlling the discharge of materials into the environment, requiring removal and cleanup of materials that may harm the environment or otherwise relating to the protection of the environment apply to some of our operations. For example, we, as an operator of mobile offshore drilling units in navigable United States waters and some offshore areas, may be liable for damages and costs incurred in connection with oil spills related to those operations. Laws and regulations protecting the environment have become increasingly stringent, and may in some cases impose “strict liability,” rendering a person liable for environmental damage without regard to negligence or fault on the part of that person. These laws and regulations may expose us to liability for the conduct of or conditions caused by others or for acts that were in compliance with all applicable laws at the time they were performed.
     The United States Oil Pollution Act of 1990, or OPA ’90, and similar legislation enacted in Texas, Louisiana and other coastal states, addresses oil spill prevention and control and significantly expands liability exposure across all segments of the oil and gas industry. OPA ’90 and such similar legislation and related regulations impose a variety of obligations on us related to the prevention of oil spills and liability for damages resulting from such spills. OPA ‘90 imposes strict and, with limited exceptions, joint and several liability upon each responsible party for oil removal costs and a variety of public and private damages.
     The application of these requirements or the adoption of new requirements could have a material adverse effect on our financial position, results of operations and cash flows.
Our industry is highly competitive and cyclical, with intense price competition.
     The offshore contract drilling industry is highly competitive with numerous industry participants, none of which at the present time has a dominant market share. Some of our competitors may have greater financial or other resources than we do. The drilling industry has experienced consolidation in the past and may experience additional consolidation, which could create additional large competitors. Drilling contracts are traditionally awarded on a competitive bid basis. Intense price competition is often the primary factor in determining which qualified contractor is awarded a job, although rig availability and location, a drilling contractor’s safety record and the quality and technical capability of service and equipment may also be considered. Mergers among oil and natural gas exploration and production companies, as well as a contraction in the global economy, have reduced the number of available customers, increasing competition.
     Our industry has historically been cyclical. There have been periods of lower demand, excess rig supply and low dayrates, followed by periods of high demand, short rig supply and high dayrates. We cannot predict the timing or duration of such business cycles. Periods of excess rig supply intensify the competition in the industry and often result in rigs being idle for long periods of time. In response to a contraction in demand for our drilling services, we have cold stacked seven of our rigs as of the date of this report. We also may be required to idle additional rigs or to enter into lower rate contracts. Prolonged periods of low utilization and dayrates could also result in the recognition of impairment charges on certain of our drilling rigs if future cash flow estimates, based upon information available to management at the time, indicate that the carrying value of these rigs may not be recoverable.
     Significant new rig construction and upgrades of existing drilling units could also intensify price competition. As of the date of this report, based on analyst reports, we believe that there are approximately 50 jack-up rigs and 50 floaters on order and scheduled for delivery between 2011 and 2013. The resulting increases in rig supply could be sufficient to further depress rig utilization and intensify 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. The majority of the floaters on order are dynamically positioned drilling units, which further increases competition with our fleet in certain circumstances, depending on customer requirements.

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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 $6.6 billion for contracted future work extending, in some cases, until 2016. Generally, contract backlog only includes future revenues under firm commitments; however, from time to time, we may report anticipated commitments for which definitive agreements have not yet been, but are expected to be, executed. We can provide no assurance that we will be able to perform under these contracts due to events beyond our control or that we will be able to ultimately execute a definitive agreement in cases where one does not currently exist. In addition, we can provide no assurance that our customers will be able to or willing to fulfill their contractual commitments to us. Our inability to perform under our contractual obligations or to execute definitive agreements or our customers’ inability to fulfill their contractual commitments to us may have a material adverse effect on our financial position, results of operations and cash flows. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Overview – Contract Drilling Backlog” included in Item 7 of this report.
We rely heavily on a relatively small number of customers and the loss of a significant customer and/or a dispute that leads to the loss of a customer could have a material adverse impact on our financial results.
     We provide offshore drilling services to a customer base that includes major and independent oil and gas companies and government-owned oil companies. However, the number of potential customers has decreased in recent years as a result of mergers among the major international oil companies and large independent oil companies. In 2010, our five largest customers in the aggregate accounted for 56% of our consolidated revenues. We expect Petrobras, which accounted for approximately 24% of our consolidated revenues in 2010, and OGX, which accounted for approximately 14% of our consolidated revenues in 2010, to continue to be significant customers in 2011. Our contract drilling backlog, as of the date of this report, includes $1.7 billion, or 61% of our total contracted backlog for 2011, which is attributable to contracts with Petrobras and OGX for operations offshore Brazil in 2011. 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. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Overview – Contract Drilling Backlog” included in Item 7 of this report.
The terms of our drilling contracts may limit our ability to attain profitability in a declining market or 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 decreasing demand for offshore rigs, drilling contractors generally prefer longer term contracts, but often at flat or slightly lower dayrates, to preserve dayrates at existing levels and ensure utilization, while customers prefer shorter contracts that allow them to more quickly obtain the benefit of lower dayrates. Conversely, 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. An inability to obtain longer term contracts in a declining market or to fully benefit from increasing dayrates in an improving market through shorter term contracts may limit 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.

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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 we have to suspend drilling operations 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 periods of depressed market conditions, we may be subject to an increased risk of our customers seeking to repudiate their contracts. Our customers’ ability to perform their obligations under drilling contracts with us may also be adversely affected by restricted credit markets and the economic downturn. If our customers cancel some of their contracts, and we are unable to secure new contracts on a timely basis and on substantially similar terms, or if contracts are disputed or suspended for an extended period of time or if a number of our contracts are renegotiated, it could adversely affect our financial position, results of operations or cash flows.
Our business involves numerous operating hazards which could expose us to significant losses and significant damage claims. We are not fully insured against all of these risks and our contractual indemnity provisions may not fully protect us.
     Our operations are subject to the significant hazards inherent in drilling for oil and gas offshore, such as blowouts, reservoir damage, loss of production, loss of well control, unstable or faulty sea floor conditions, fires and natural disasters such as hurricanes. The occurrence of any of these types of 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 oil spillage, oil leaks, well blowouts and extensive uncontrolled fires, any of which could cause significant environmental damage. In addition, offshore drilling operations are subject to perils peculiar to marine operations, including capsizing, grounding, collision and loss or damage from severe weather. Any of the foregoing events could result in significant damage or loss to our properties and assets, significant loss of revenues, and significant damage claims against us, which could have a material adverse effect on our results of operations, financial condition and cash flows.
     We maintain liability insurance, which includes coverage for environmental damage; however, because of contractual provisions and policy limits, our insurance coverage may not adequately cover our losses and claim costs. In addition, pollution and environmental risks are generally not fully insurable when they are determined to be the result of criminal acts. Also, we do not typically purchase loss-of-hire insurance to cover lost revenues when a rig is unable to work. Accordingly, it is possible that our losses from the hazards we face could have a material adverse effect on our results of operations, financial condition and cash flows.
     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.
     Generally our contracts with our customers contain contractual rights to indemnity from our customer for, among other things, pollution originating from the well, while we retain responsibility for pollution originating from the rig. However, our contractual rights to indemnification may be unenforceable or limited due to negligent or willful acts of commission or omission by us, our subcontractors and/or suppliers and our customers may dispute, or be unable to meet, their contractual indemnification obligations to us.
     We believe that the policy limit under our marine liability insurance is within the range that is customary for companies of our size in the offshore drilling industry and is appropriate for our business. However, if an accident or other event occurs that exceeds our coverage limits or is not an insurable event under our insurance policies, or is not fully covered by contractual indemnity, it could have a material adverse effect on our results of operations, financial position and cash flows. There can be no assurance that we will continue to carry the insurance we currently maintain, that our insurance will cover all types of losses or that those parties with contractual obligations to indemnify us will necessarily be financially able to indemnify us against all of 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.
     Accordingly, the occurrence of any of the hazards we face could have a material adverse effect on our results of operations, financial condition and cash flows.

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We have elected to self-insure for physical damage to rigs and equipment caused by named windstorms in the U.S. Gulf of Mexico.
     Because the amount of insurance coverage available to us has been limited, and the cost for such coverage has increased substantially, we have elected to self-insure for physical damage to rigs and equipment caused by named windstorms in the U.S. Gulf of Mexico. This results in a higher risk of losses, which could be material, that are not covered by third party insurance contracts. If one or more named windstorms in the U.S. Gulf of Mexico cause significant damage to our rigs or equipment, it could have a material adverse effect on our financial position, results of operations and cash flows.
A significant portion of our operations are conducted outside the United States and involve additional risks not associated with domestic operations.
     We operate in various regions throughout the world which may expose us to political and other uncertainties, including risks of:
  •   terrorist acts, war and civil disturbances;
 
  •   piracy or assaults on property or personnel;
 
  •   kidnapping of personnel;
 
  •   expropriation of property or equipment;
 
  •   renegotiation or nullification of existing contracts;
 
  •   changing political conditions;
 
  •   foreign and domestic monetary policies;
 
  •   the inability to repatriate income or capital;
 
  •   difficulties in collecting accounts receivable and longer collection periods;
 
  •   fluctuations in currency exchange rates;
 
  •   regulatory or financial requirements to comply with foreign bureaucratic actions;
 
  •   travel limitations or operational problems caused by public health threats; and
 
  •   changing taxation policies.
     We are subject to the U.S. Treasury Department’s Office of Foreign Assets Control and other U.S. laws and regulations governing our international operations in addition to worldwide anti-bribery laws. 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;
 
  •   import-export quotas or other trade barriers;
 
  •   repatriation of foreign earnings or capital;
 
  •   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 may adversely affect our ability to compete.
     In addition, as of the date of this report, we have one high specification floater and two jack-up rigs contracted offshore Egypt. Although these rigs have continued to work throughout the recent political unrest in Egypt, there have been, and in the future there may be other, disruptions to the support networks within Egypt, including the banking institutions. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Overview – Egyptian Operations” included in Item 7 of this report.
     As of the date of this report, the greatest concentration of our operating assets outside the United States was offshore Brazil, where we had 16 rigs in our fleet either currently working or contracted to work during 2011.

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Our drilling contracts offshore Mexico expose us to greater risks than we normally assume.
     We currently operate, and expect to continue to operate, our drilling rigs offshore Mexico for PEMEX – Exploración y Producción, or PEMEX, the national oil company of Mexico. The terms of these contracts expose us to greater risks than we normally assume, such as exposure to greater environmental liability. In addition, each contract can be terminated by PEMEX on 30 days notice, contractually or by statute, subject to certain conditions. While we believe that the financial terms of these contracts and our operating safeguards in place mitigate these risks, we can provide no assurance that the increased risk exposure will not have a negative impact on our future operations or financial results.
Fluctuations in exchange rates and nonconvertibility of currencies could result in losses to us.
     Due to our international operations, we have experienced currency exchange losses where revenues are received and expenses are paid in nonconvertible currencies or where we do not effectively hedge an exposure to a foreign currency. We may also incur losses as a result of an inability to collect revenues because of a shortage of convertible currency available to the country of operation, controls over currency exchange or controls over the repatriation of income or capital. We can provide no assurance that financial hedging arrangements will effectively hedge any foreign currency fluctuation losses that may arise.
Changes in laws, effective income tax rates or adverse outcomes resulting from examination of our tax returns could adversely affect our financial results.
     Tax laws and regulations are highly complex and subject to interpretation and disputes. We conduct our worldwide operations through various subsidiaries in a number of different jurisdictions. We are subject to the tax laws, tax regulations and income tax treaties within and between the countries in which we operate as well as countries in which we may be resident. We determine our income tax expense based on our interpretation of the applicable tax laws and regulations in effect in each jurisdiction for the period during which we operate and earn income. Our overall effective tax rate could be adversely and suddenly affected by lower than anticipated earnings in countries where we have lower statutory rates and higher than anticipated earnings in countries where we have higher statutory rates, by changes in the valuation of our deferred tax assets and liabilities or by changes in tax law, tax treaties, regulations, accounting principles or interpretations thereof in one or more countries in which we operate.
     Our income tax returns are subject to review and examination. We do not recognize the benefit of income tax positions we believe are more likely than not to be disallowed upon challenge by a tax authority. If any tax authority successfully challenges any tax position taken, or if the terms of certain income tax treaties are interpreted in a manner that is adverse to our operations, or if we lose a material tax dispute in any country, our effective tax rate on our worldwide earnings could increase substantially and our earnings and cash flows from operations could be materially adversely affected.
We may be required to accrue additional tax liability on certain of our foreign earnings.
     Certain of our international rigs are owned and operated, directly or indirectly, by Diamond Offshore International Limited, or DOIL, our wholly-owned Cayman Islands subsidiary. Since forming this subsidiary it has been our intention to indefinitely reinvest the earnings of this subsidiary to finance foreign operations, except for the earnings of Diamond East Asia Limited, or DEAL, a wholly-owned subsidiary of DOIL. It is our intention to repatriate the earnings of DEAL, and U.S. income taxes will be provided on such earnings. We do not expect to provide for U.S. taxes on any future earnings generated by DOIL, except to the extent that these earnings are immediately subjected to U.S. federal income tax or as they relate to DEAL. 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.
Acts of terrorism and other political and military events could adversely affect the markets for our drilling services.
     Terrorist attacks and the continued threat of terrorism in the U.S. and 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

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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. While we take steps that we believe are appropriate to secure 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.
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.
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 due to 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. 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.
Although we have paid special cash dividends in the past, we may not pay special cash dividends in the future and we can give no assurance as to the amount or timing of the payment of any future special cash dividends.
     We have adopted a policy to consider paying special cash dividends, in amounts to be determined, on a quarterly basis. Any determination to declare a special cash dividend, as well as the amount of any special cash dividend which may be declared, will be based on our financial position, earnings, earnings outlook, capital spending plans and other factors that our Board of Directors considers relevant at that time. Moreover, our dividend policy may change from time to time. We cannot assure you that we will continue to declare any special cash dividends at all or in any particular amounts. If in the future we pay special cash dividends less frequently or in smaller amounts, or cease to pay any special cash dividends, it could have a negative effect on the market price of our common stock. See “Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities – Dividend Policy” included in Item 5 of this report and “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Sources of Liquidity and Capital Resources” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Historical Cash Flows” 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. 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.

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     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 with equally favorable terms.
Our debt levels may limit our liquidity and flexibility in obtaining additional financing and in pursuing other business opportunities.
     As of December 31, 2010, we had $1.5 billion in long-term debt. Our ability to meet our debt service obligations is dependent upon our future performance, which is subject to general economic conditions, industry cycles and financial, business and other factors affecting our operations, many of which are beyond our control. Our debt levels and the terms of our indebtedness may limit our liquidity and flexibility in obtaining additional financing and pursuing other business opportunities. In addition, our overall debt level and/or market conditions could lead the credit rating agencies to lower our corporate credit ratings. A downgrade in our corporate credit ratings could impact our ability to issue additional debt by raising the cost of issuing new debt. As a consequence, we may not be able to issue additional debt in amounts and/or with terms that we consider to be reasonable. This could limit our ability to pursue other business opportunities.
We are controlled by a single stockholder, which could result in potential conflicts of interest.
     Loews Corporation, which we refer to as Loews, beneficially owned approximately 50.4% of our outstanding shares of common stock as of February 17, 2011 and is in a position to control actions that require the consent of stockholders, including the election of directors, amendment of our Restated Certificate of Incorporation and any merger or sale of substantially all of our assets. In addition, three officers of Loews serve on our Board of Directors. One of those, James S. Tisch, the Chairman of the Board of our company, is also the Chief Executive Officer and a director of Loews. We have also entered into a services agreement and a registration rights agreement with Loews and we may in the future enter into other agreements with Loews.
     Loews is a holding company. In addition to us, its principal subsidiaries are CNA Financial Corporation, a 90% owned subsidiary engaged in commercial property and casualty insurance; HighMount Exploration & Production LLC, a wholly owned subsidiary engaged in exploration, production and marketing of natural gas and natural gas liquids; Boardwalk Pipeline Partners, LP, a 66% owned subsidiary engaged in the operation of interstate natural gas transmission pipeline systems; and Loews Hotels Holding Corporation, a wholly owned subsidiary engaged in the operation of hotels. Loews and its subsidiaries and we are generally engaged in businesses sufficiently different from each other as to make conflicts as to possible corporate opportunities unlikely. However, it is possible that Loews may in some circumstances be in direct or indirect competition with us, including competition with respect to certain business strategies and transactions that we may propose to undertake. In addition, potential conflicts of interest exist or could arise in the future for our directors who are also officers of Loews with respect to a number of areas relating to the past and ongoing relationships of Loews and us, including tax and insurance matters, financial commitments and sales of common stock pursuant to registration rights or otherwise. Although the affected directors may abstain from voting on matters in which our interests and those of Loews are in conflict so as to avoid potential violations of their fiduciary duties to stockholders, the presence of potential or actual conflicts could affect the process or outcome of Board deliberations. We cannot assure you that these conflicts of interest will not materially adversely affect us.
Item 1B. Unresolved Staff Comments.
     Not applicable.
Item 2. Properties.
     We own an eight-story office building containing approximately 170,000 net rentable square feet on approximately 6.2 acres of land located in Houston, Texas, where our corporate headquarters are located. We also own two buildings totaling 39,000 square feet and 20 acres of land in New Iberia, Louisiana, for our offshore drilling warehouse and storage facility, a 13,000-square foot building and five acres of land in Aberdeen, Scotland, for our North Sea operations, two buildings totaling 77,200 square feet and 11 acres of land in Macae, Brazil, for our South American operations and two buildings totaling 20,000 square feet and two acres of land in Ciudad del

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Carmen, Mexico, for our Mexican operations. Additionally, we currently lease various office, warehouse and storage facilities in Louisiana, Australia, Brazil, Indonesia, Norway, Malaysia, Singapore, Egypt, Angola, Republic of Congo, Vietnam and the U.K. to support our offshore drilling operations.
Item 3. Legal Proceedings.
     Not applicable.
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
2010
                
First Quarter
   $ 106.34     $ 83.23  
Second Quarter
     93.01       56.94  
Third Quarter
     68.88       58.18  
Fourth Quarter
     74.12       63.39  
 
                
2009
                
First Quarter
   $ 71.41     $ 54.29  
Second Quarter
     92.57       63.59  
Third Quarter
     96.85       76.21  
Fourth Quarter
     107.01       92.45  
     As of February 17, 2011 there were approximately 215 holders of record of our common stock. This number represents registered shareholders and does not include shareholders who hold their shares institutionally.
Dividend Policy
     In 2010, we paid regular cash dividends of $0.125 per share of our common stock on March 1, June 1, September 1 and December 1. We also paid special cash dividends in 2010 of $1.875 per share of our common stock on March 1, $1.375 per share of our common stock on June 1, and $0.75 per share of our common stock on September 1 and December 1. In 2009, we paid regular cash dividends of $0.125 per share of our common stock on March 2, June 1, September 1 and December 1. We also paid special cash dividends in 2009 of $1.875 per share of our common stock on March 2, June 1, September 1 and December 1.
     On February 2, 2011, we declared a regular cash dividend and a special cash dividend of $0.125 and $0.75, respectively, per share of our common stock. Both the regular and special cash dividends are payable on February 28, 2011 to stockholders of record on February 11, 2011.
     We have adopted a policy to consider paying special cash dividends, in amounts to be determined, on a quarterly basis. Any determination to declare a special cash dividend, as well as the amount of any special cash dividend which may be declared, will be based on our financial position, earnings, earnings outlook, capital spending plans and other factors that our Board of Directors considers relevant 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, 2010.
Comparison of 2006 – 2010 Cumulative Total Return (1)
(PERFORMANCE GRAPH)
                                                 
    Dec. 31,   Dec. 31,   Dec. 31,   Dec. 31,   Dec. 31,   Dec. 31,
    2005   2006   2007   2008   2009   2010
     
Diamond Offshore
     100       118       224       98       182       132  
S&P 500
     100       116       122       77       97       112  
Peer Group (2)
     100       108       167       65       111       117  
 
(1)   Total return assuming reinvestment of dividends. Assumes $100 invested on December 31, 2005 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.
 
    Our dividend history for the periods reported above is as follows:
                                                                 
    Q1   Q2   Q3   Q4
Year   Regular   Special   Regular   Special   Regular   Special   Regular   Special
2010
   $ 0.125     $ 1.875     $ 0.125     $ 1.375     $ 0.125     $ 0.75     $ 0.125     $ 0.75  
2009
   $ 0.125     $ 1.875     $ 0.125     $ 1.875     $ 0.125     $ 1.875     $ 0.125     $ 1.875  
2008
   $ 0.125     $ 1.25     $ 0.125     $ 1.25     $ 0.125     $ 1.25     $ 0.125     $ 1.875  
2007
   $ 0.125     $ 4.00     $ 0.125       —     $ 0.125       —     $ 0.125     $ 1.25  
2006
   $ 0.125     $ 1.50     $ 0.125       —     $ 0.125       —     $ 0.125       —  
 
(2)   The peer group is comprised of the following companies: Ensco plc, Noble Corporation, Pride International, Inc., Rowan Companies, Inc. and Transocean Ltd. 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. 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. Historical data for the three annual periods ending on or prior to December 31, 2008 have been restated to reflect the effect thereon of the adoption on January 1, 2009 of an accounting standard that requires all convertible debt securities that may be settled by the issuer fully or partially in cash to be separated into a debt and an equity component. The bifurcation requirement applies to both newly issued debt and debt issuances outstanding for any time during the accounting periods for which financial statements are presented and has been applied retrospectively to the historical periods as of and for the years ended December 31, 2008, 2007 and 2006 presented below.
                                         
    As of and for the Year Ended December 31,
                    2008   2007   2006
    2010   2009   Adjusted   Adjusted   Adjusted
    (In thousands, except per share and ratio data)
Income Statement Data:
                                        
Total revenues
   $ 3,322,974     $ 3,631,284     $ 3,544,057     $ 2,567,723     $ 2,052,572  
Operating income
     1,425,374       1,903,213       1,910,194       1,223,044       940,029  
Net income
     955,457       1,376,219       1,310,547       844,464       699,088  
Net income per share:
                                        
Basic
     6.87       9.90       9.43       6.13       5.41  
Diluted
     6.87       9.89       9.42       6.11       5.14  
 
                                        
Balance Sheet Data:
                                        
Drilling and other property and equipment, net
   $ 4,283,792     $ 4,432,052     $ 3,414,373     $ 3,056,300     $ 2,644,392  
Total assets
     6,726,984       6,264,261       4,954,431       4,357,702       4,148,006  
Long-term debt (excluding current maturities) (1)
     1,495,593       1,495,375       503,280       503,071       931,937  
 
                                        
Other Financial Data:
                                        
Capital expenditures
   $ 434,262     $ 1,362,468     $ 666,857     $ 647,877     $ 556,392  
Cash dividends declared per share
     5.25       8.00       6.13       5.75       2.00  
Ratio of earnings to fixed charges (2)
     15.35 x     37.29 x     64.54 x     31.16 x     19.03 x
 
(1)   See “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Sources of Liquidity and Capital Resources – 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)   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. Our current fleet of 46 offshore drilling rigs consists of 32 semisubmersibles, 13 jack-ups and one drillship.
Overview
Industry Conditions
     On October 12, 2010, the U.S. government lifted the ban on certain drilling activities in the GOM. All drilling in the GOM is now subject to compliance with enhanced safety requirements set forth in Notices to Lessees, or NTL, 2010-N05 and 2010-N06, both of which were implemented during the drilling ban. Additionally, all drilling in the GOM is required to comply with the Interim Final Rule to Enhance Safety Measures for Energy Development on the Outer Continental Shelf (Drilling Safety Rule) and the Workplace Safety Rule on Safety and Environmental Management Systems, which have become final, as well as NTL 2010-N10 (known as the Compliance and Review NTL). We continue to evaluate these new measures to ensure that our rigs and equipment are in full compliance, where applicable. Additional requirements could be forthcoming based on further recommendations by regulatory agencies investigating the Macondo incident. We are not able to predict the likelihood, nature or extent of additional rulemaking. Nor are we able to predict when the Bureau of Ocean Energy Management, Regulation and Enforcement, or BOEMRE, will issue drilling permits to our customers. We are not able to predict the future impact of these events on our operations. Even with the drilling ban lifted, certain deepwater drilling activities remain suspended until the BOEMRE resumes its regular permitting of those activities.
     It has been reported that the industry currently has 36 floating rigs in the GOM that have been impacted by the moratorium and that five floating rigs have left the GOM since the imposition of the moratorium, two of which rigs were ours. As of the date of this report, we have two semisubmersible units under contract in the GOM, in addition to the Ocean Monarch, whose contract the operator has sought to terminate as discussed below, as well as two jack-up units, one of which is under contract. Given the continuing uncertainty with respect to drilling activity in the GOM, our customers may seek to move additional rigs to locations outside of the GOM or perform activities which are allowed under the enhanced safety requirements. In June 2010, one of our customers asserted force majeure as a basis for its termination of the drilling contract for the Ocean Monarch, which had a remaining term of approximately 36 months. The operator has also filed suit against us in U.S. District Court in Houston seeking a declaratory judgment that its termination of the drilling contract is warranted under the contract. We do not believe the events cited by the operator come within the definition of force majeure under the drilling contract, and we do not believe that the operator has the right to terminate the drilling contract on this basis. Although we cannot predict with certainty the results of any such litigation, and there can be no assurance as to its ultimate outcome, we intend to vigorously defend this litigation and challenge the operator’s attempt to terminate the drilling contract.
     We are continuing to actively seek international opportunities to keep our rigs employed. However, we can provide no assurance that we will be successful in our efforts to employ our remaining impacted rigs in the GOM in the near term. In addition, given the ongoing uncertainty in the GOM with respect to drilling activity and other industry factors, we have cold stacked two intermediate floaters and four jack-up rigs in the GOM.
     While dayrates we receive for new contracts are no longer at the peak levels achieved at the height of the most recent up-cycle, improving oil prices, which had climbed to approximately $90 per barrel by the end of 2010, appear to be supporting demand for our equipment. As a result, dayrates for our international floater units appear to have stabilized, though demand for our services has not risen sufficiently to provide significant pricing power on new contracts. Additionally, the continuing regulatory uncertainty in the GOM could cause Diamond Offshore or others to move additional rigs out of the GOM to international locations. If we, or others, move a large number of additional rigs out of the GOM to international locations, the increased supply of available rigs entering the international market, coupled with un-contracted new-build rigs scheduled for delivery between now and the end of 2011, could create downward pressure on dayrates unless demand improves sufficiently to absorb the new supply.
     Since September 30, 2010 through the date of this report, we have entered into 17 new drilling contracts totaling approximately $457 million in backlog and ranging in duration from one well to one year. As of February 1, 2011, our contract backlog was approximately $6.6 billion, of which our contracts in the GOM (excluding amounts related

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to the contract for the Ocean Monarch discussed above) represented approximately $141.0 million, or 2%, of our total contract backlog.
     Floaters
     Our intermediate and high-specification floater rigs, both domestic and international, accounted for approximately 89% of our revenue during 2010. Approximately 74% of the time on our intermediate and high-specification floater rigs is committed for 2011. Additionally, 51% of the time on our floating rigs is committed in 2012.
     International Jack-ups
     During the fourth quarter of 2010, demand for our international jack-ups remained weak but stable. However, the high-specification new-build equipment coming to market is enjoying a significantly higher utilization rate than older existing equipment, and the oversupply of jack-up rigs could have an increasingly negative impact on the international sector throughout 2011 and beyond.
     U.S. Gulf of Mexico Jack-ups
     The jack-up market in the GOM has been negatively impacted by the slow issuance of jack-up permits subsequent to the lifting of the drilling moratorium, as well as the impact of lower natural gas prices on both demand and dayrates. Our two remaining jack-ups in the GOM are largely working under short-term contracts and could experience significant downtime unless permitting activity increases. Absent an increase in permitting activity and a sustained improvement in natural gas prices, weakness in the GOM jack-up market is likely to continue in 2011, with the possibility of additional rigs being cold-stacked by us and others in the industry.
Egyptian Operations
     We currently have one high-specification floater and two jack-up rigs contracted offshore Egypt with an aggregate net book value of $269.9 million, or approximately 6% of our total operating assets at December 31, 2010. Although these rigs have continued to work throughout the recent political unrest in Egypt, there have been, and in the future there may be other, disruptions to the support networks within Egypt, including the banking institutions. At February 1, 2011, our contract drilling backlog related to our drilling operations offshore Egypt was approximately $60.0 million, or 2% of our total contract drilling backlog, for 2011. Our customers may attempt to assert force majeure under the agreements under which these rigs are operating. As of the date of this report, we have not received any force majeure assertions with respect to our Egyptian operations.
Contract Drilling Backlog
     The following table reflects our contract drilling backlog as of February 1, 2011, October 18, 2010 (the date reported in our Quarterly Report on Form 10-Q for the quarter ended September 30, 2010) and February 1, 2010 (the date reported in our Annual Report on Form 10-K for the year ended December 31, 2009). Contract drilling backlog is calculated by multiplying the contracted operating dayrate by the firm contract period and adding one-half of any potential rig performance bonuses. Our calculation also assumes full utilization of our drilling equipment for the contract period (excluding scheduled shipyard and survey days); however, the amount of actual revenue earned and the actual periods during which revenues are earned will be different than the amounts and periods shown in the tables below due to various factors. Utilization rates, which generally approach 95-98% during contracted periods, can be adversely impacted by downtime due to various operating factors including, but not limited to, weather conditions and unscheduled repairs and maintenance. Contract drilling backlog excludes revenues for mobilization, demobilization, contract preparation and customer reimbursables. No revenue is generally earned during periods of downtime for regulatory surveys. Changes in our contract drilling backlog between periods are a function of the performance of work on term contracts, as well as the extension or modification of existing term contracts and the execution of additional contracts.

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    February 1,     October 18,     February 1,  
    2011     2010 (4)     2010 (4)  
            (In thousands)          
Contract Drilling Backlog
                        
High-Specification Floaters (1)
  $ 3,838,000     $ 4,371,000     $ 4,177,000  
Intermediate Semisubmersibles (2)
     2,700,000       3,009,000       4,030,000  
Jack-ups (3)
     107,000       122,000       249,000  
 
                  
Total
   $ 6,645,000     $ 7,502,000     $ 8,456,000  
 
                  
 
(1)   Contract drilling backlog as of February 1, 2011 for our high-specification floaters includes (i) $3.0 billion attributable to our contracted operations offshore Brazil for the years 2011 to 2016 and (ii) $100.0 million attributable to our contracted operations in the GOM during 2011.
 
(2)   Contract drilling backlog as of February 1, 2011 for our intermediate semisubmersibles includes (i) $2.1 billion attributable to our contracted operations offshore Brazil for the years 2011 to 2015 and (ii) $36.0 million attributable to our contracted operations in the GOM during 2011.
 
(3)   Contract drilling backlog as of February 1, 2011 for our jack-ups includes (i) $49.0 million attributable to our contracted operations offshore Brazil for the years 2011 and 2012 and (ii) $5.0 million attributable to our contracted operations in the GOM during 2011.
 
(4)   Contract drilling backlog as of October 18, 2010 and February 1, 2010 includes $394.0 million and $424.1 million, respectively, attributable to the Ocean Monarch pursuant to a contract that the operator has sought to terminate.
     The following table reflects the amount of our contract drilling backlog by year as of February 1, 2011.
                                         
    For the Years Ending December 31,  
    Total     2011     2012     2013     2014 - 2016  
    (In thousands)  
Contract Drilling Backlog
                                        
High-Specification Floaters (1)
   $ 3,838,000     $ 1,470,000     $ 1,034,000     $ 615,000     $ 719,000  
Intermediate Semisubmersibles (2)
     2,700,000       1,145,000       811,000       429,000       315,000  
Jack-ups (3)
     107,000       103,000       4,000       —       —  
 
                              
Total
   $ 6,645,000     $ 2,718,000     $ 1,849,000     $ 1,044,000     $ 1,034,000  
 
                              
 
(1)   Contract drilling backlog as of February 1, 2011 for our high-specification floaters includes (i) $851.0 million, $790.0 million and $615.0 million for the years 2011 to 2013, respectively, and $719.0 million in the aggregate for the years 2014 to 2016, attributable to our contracted operations offshore Brazil and (ii) $100.0 million for 2011 attributable to our contracted operations in the GOM.
 
(2)   Contract drilling backlog as of February 1, 2011 for our intermediate semisubmersibles includes (i) $762.0 million, $683.0 million and $372.0 million for the years 2011 to 2013, respectively, and $315.0 million in the aggregate for the years 2014 to 2016, attributable to our contracted operations offshore Brazil and (ii) $36.0 million for 2011 attributable to our contracted operations in the GOM.
 
(3)   Contract drilling backlog as of February 1, 2011 for our jack-ups includes (i) $45.0 million and $4.0 million for years 2011 and 2012, respectively, attributable to our contracted operations offshore Brazil and (ii) $5.0 million for 2011 attributable to our contracted operations in the GOM.

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     The following table reflects the percentage of rig days committed by year as of February 1, 2011. The percentage of rig days committed is calculated as the ratio of total days committed under contracts, as well as scheduled shipyard, survey and mobilization days for all rigs in our fleet, to total available days (number of rigs multiplied by the number of days in a particular year).
                                 
    For the Years Ending December 31,
    2011   2012   2013   2014 - 2016
Rig Days Committed (1)
                                
High-Specification Floaters
     83 %     60 %     33 %     13 %
Intermediate Semisubmersibles
     66 %     44 %     22 %     5 %
Jack-ups
     24 %     1 %     —       —  
 
(1)   Includes approximately 770 and 420 scheduled shipyard, survey and mobilization days for 2011 and 2012, respectively.
General
     The two most significant variables affecting our revenues are dayrates for rigs and rig utilization rates, each of which is a function of rig supply and demand in the marketplace. Demand for drilling services is dependent upon the level of expenditures set by oil and gas companies for offshore exploration and development, as well as a variety of political, regulatory and economic factors. The availability of rigs in a particular geographical region also affects both dayrates and utilization rates. These factors are not within our control and are difficult to predict.
     Demand affects the number of days our fleet is utilized and the dayrates earned. As utilization rates increase, dayrates tend to increase as well, reflecting the lower supply of available rigs. Conversely, as utilization rates decrease, dayrates tend to decrease as well, reflecting the excess supply of rigs. When a rig is idle, no dayrate is earned and revenues will decrease as a result. Revenues can also be affected as a result of the acquisition or disposal of rigs, required surveys and shipyard upgrades. In order to improve utilization or realize higher dayrates, we may mobilize our rigs from one market to another. However, during periods of mobilization, revenues may be adversely affected. As a response to changes in demand, we may withdraw a rig from the market by stacking it or may reactivate a rig stacked previously, which may decrease or increase revenues, respectively.
     We recognize revenue from dayrate drilling contracts as services are performed. In connection with such drilling contracts, we may receive fees (either lump-sum or dayrate) for the mobilization of equipment. We earn these fees as services are performed over the initial term of the related drilling contracts. We defer mobilization fees received, as well as direct and incremental mobilization costs incurred, and amortize each, on a straight-line basis, over the term of the related drilling contracts (which is the period we estimate to be benefited from the mobilization activity). Straight-line amortization of mobilization revenues and related costs over the term of the related drilling contracts (which generally range from two to 60 months) is consistent with the timing of net cash flows generated from the actual drilling services performed. Absent a contract, mobilization costs are recognized currently.
     From time to time, we may receive fees from our customers for capital improvements to our rigs (either lump-sum or dayrate). We defer such fees and recognize them into income on a straight-line basis over the period of the related drilling contract as a component of contract drilling revenue. We capitalize the costs of such capital improvements and depreciate them over the estimated useful life of the improvement.
     We receive reimbursements for the purchase of supplies, equipment, personnel services and other services provided at the request of our customers in accordance with a contract or agreement. We record these reimbursements at the gross amount billed to the customer as “Revenues related to reimbursable expenses” in our Consolidated Statements of Operations included in Item 8 of this report.
     Operating Income. Our operating income is primarily affected by revenue factors, but is also a function of varying levels of operating expenses. Our operating expenses represent all direct and indirect costs associated with the operation and maintenance of our drilling equipment. The principal components of our operating costs are, among other things, direct and indirect costs of labor and benefits, repairs and maintenance, freight, regulatory inspections, boat and helicopter rentals and insurance. Labor and repair and maintenance costs represent the most significant components of our operating expenses. In general, our labor costs increase primarily due to higher salary levels, rig staffing requirements and costs associated with labor regulations in the geographic regions in which our rigs operate. 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.

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     Our operating costs are also impacted by the regulatory environments in which we operate. The adoption of new regulations could result in additional inspection and certification costs, as well as require additional capital investment to comply with regulatory requirements. Accordingly, we cannot fully predict the financial impact of new regulations that have been adopted subsequent to the Macondo incident in April 2010 for rigs operating in the GOM, or any new regulations that may arise as the investigation into the incident continues or as a result of further recommendations by regulatory agencies. New laws or regulations may require an increase in our capital spending for additional equipment to comply with such requirements. Our business could be negatively impacted by additional downtime which may be required to obtain necessary equipment and to install such equipment or to obtain the required inspections or certifications as prescribed under such regulations.
     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 following capital upgrades.
     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 special surveys are performed during scheduled downtime in a shipyard. Operating expenses increase as a result of these special surveys due to the cost to mobilize the rigs to a shipyard, inspection costs incurred and repair and maintenance costs. Repair and maintenance activities may result from the special survey or may have been previously planned to take place during this mandatory downtime. The number of rigs undergoing a 5-year survey will vary from year to year, as well as from quarter to quarter.
     In addition, operating income may be negatively impacted by intermediate surveys, which are performed at interim periods between 5-year surveys. Intermediate surveys are generally less extensive in duration and scope than a 5-year survey. Although an intermediate survey may require some downtime for the drilling rig, it normally does not require dry-docking or shipyard time, except for rigs located in the U.K. and Norwegian sectors of the North Sea.
     During 2011, seven of our rigs will require 5-year surveys, and we expect that they will be out of service for approximately 455 days in the aggregate. We also expect to spend an additional approximately 290 days during 2011 for intermediate surveys, the mobilization of rigs, contract acceptance testing and extended maintenance projects. We can provide no assurance as to the exact timing and/or duration of downtime associated with regulatory inspections, planned rig mobilizations and other shipyard projects. See “ – Overview – Contract Drilling Backlog.”
     We are self-insured for physical damage to rigs and equipment caused by named windstorms in the U.S. Gulf of Mexico. If a named windstorm in the U.S. Gulf of Mexico causes significant damage to our rigs or equipment, it could have a material adverse effect on our financial position, results of operations and cash flows. Under our insurance policy that expires on May 1, 2011, we carry physical damage insurance for certain losses other than those caused by named windstorms in the U.S. Gulf of Mexico for which our deductible for physical damage is $25.0 million per occurrence. We do not typically retain loss-of-hire insurance policies to cover our rigs.
     In addition, under our insurance policy that expires on May 1, 2011, we carry marine liability insurance covering certain legal liabilities, including coverage for certain personal injury claims, with no exclusions for pollution and/or environmental risk. We believe that the policy limit for our marine liability insurance is within the range that is customary for companies of our size in the offshore drilling industry and is appropriate for our business. Our deductibles for marine liability coverage, including for personal injury claims, are $10.0 million for the first occurrence and vary in amounts ranging between $5.0 million and, if aggregate claims exceed certain thresholds, up to $100.0 million for each subsequent occurrence, depending on the nature, severity and frequency of claims which might arise during the policy year, which under the current policy commences on May 1 of each year. As a result of the Macondo

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incident, insurance costs across the industry are expected to increase and in the future, certain insurance coverage is likely to become more costly, and may become less available or not available at all.
     Construction and Capital Upgrade Projects. We capitalize interest cost for the construction and upgrade of qualifying assets in accordance with accounting principles generally accepted in the U.S., or GAAP. The period of interest capitalization covers the duration of the activities required to make the asset ready for its intended use, and the capitalization period ends when the asset is substantially complete and ready for its intended use. For the year ended December 31, 2008, we capitalized interest of $16.9 million on qualifying expenditures related to the upgrades of the Ocean Monarch for ultra-deepwater service and the construction of two jack-up rigs, the Ocean Shield and Ocean Scepter, through the date of each project’s completion. We did not capitalize interest on any qualifying assets during 2010 or 2009.
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 (such as cold stacking a rig or excess spending over budget on a new-build or major rig upgrade). We utilize a probability-weighted cash flow analysis in testing an asset for potential impairment. Our assumptions and estimates underlying this analysis may 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;
 
  •   the estimated maintenance, inspection or other costs associated with a rig returning to work;
 
  •   salvage value for each rig; and
 
  •   estimated proceeds that may be received on disposition of the 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).
     As of December 31, 2010, we had cold stacked four jack-up rigs consisting of three mat-supported rigs and one independent-leg, cantilevered rig (all in the GOM) and three intermediate semisubmersible drilling rigs (two in the GOM and one in Malaysia). We performed an impairment review for each of these rigs using the methodology described above. Based on our analyses, we have concluded that these seven rigs were not subject to impairment at December 31, 2010.
     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.

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     Personal Injury Claims. Our deductibles for liability coverage for personal injury claims, which primarily result from Jones Act liability in the Gulf of Mexico, are currently $10.0 million per the first occurrence, with no aggregate deductible, and vary in amounts ranging between $5.0 million and, if aggregate claims exceed certain thresholds, up to $100.0 million for each subsequent occurrence, depending on the nature, severity and frequency of claims which might arise during the policy year. 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 outside consultants to assist us in estimating our aggregate reserve for personal injury claims based on our historical losses and utilizing various actuarial models.
     The models used in estimating our aggregate reserve for personal injury claims include actuarial assumptions such as:
  •   claim emergence, or the delay between occurrence and recording of claims;
 
  •   settlement patterns, or the rates at which claims are closed;
 
  •   development patterns, or the rate at which known cases develop to their ultimate level;
 
  •   average, potential frequency and severity of claims; and
 
  •   effect of re-opened claims.
     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 accounting standards that require 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 do not establish deferred tax liabilities for certain of our foreign earnings that we intend to indefinitely reinvest to finance foreign activities. However, if these earnings become subject to U.S. federal tax, any required provision could have a material impact on our financial results. 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.
     Certain of our international rigs are owned and operated, directly or indirectly, by Diamond Offshore International Limited, or DOIL, a Cayman Islands subsidiary which we wholly own. Since forming this subsidiary in 2002, it has been our intention to indefinitely reinvest the earnings of the subsidiary to finance foreign activities. Consequently, no U.S. federal income taxes are provided on these earnings except to the extent that such earnings were immediately subject to U.S. federal income taxes and except for the earnings of Diamond East Asia Limited, or DEAL, a wholly-owned subsidiary of DOIL. It is our intention to repatriate the earnings of DEAL and, accordingly, U.S. income taxes are provided on its earnings.
     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, and utilize outside consultants to assist us in the development of such transfer pricing methodologies. 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.
     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 applicable accounting standards on segment reporting. 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, 2010, 2009 and 2008
     Comparative data relating to our revenues and operating expenses by equipment type are listed below.
                         
    Year Ended December 31,
    2010   2009   2008
    (In thousands)
CONTRACT DRILLING REVENUE
                        
High-Specification Floaters
   $ 1,414,697     $ 1,380,771     $ 1,322,125  
Intermediate Semisubmersibles
     1,546,837       1,698,584       1,629,358  
Jack-ups
     267,983       457,224       524,934  
Other
     219       —       —  
     
Total Contract Drilling Revenue
   $ 3,229,736     $ 3,536,579     $ 3,476,417  
     
 
                        
Revenues Related to Reimbursable Expenses
   $ 93,238     $ 94,705     $ 67,640  
 
                        
CONTRACT DRILLING EXPENSE
                        
High-Specification Floaters
   $ 576,421     $ 407,203     $ 367,531  
Intermediate Semisubmersibles
     605,282       557,634       581,161  
Jack-ups
     190,167       235,924       224,365  
Other
     19,216       23,010       11,950  
     
Total Contract Drilling Expense
   $ 1,391,086     $ 1,223,771     $ 1,185,007  
     
 
                        
Reimbursable Expenses
   $ 91,240     $ 93,097     $ 65,895  
 
                        
OPERATING INCOME
                        
High-Specification Floaters
   $ 838,276     $ 973,568     $ 954,594  
Intermediate Semisubmersibles
     941,555       1,140,950       1,048,197  
Jack-ups
     77,816       221,300       300,569  
Other
     (18,997 )     (23,010 )     (11,950 )
Reimbursable expenses, net
     1,998       1,608       1,745  
Depreciation
     (393,177 )     (346,446 )     (287,417 )
General and administrative expense
     (66,600 )     (62,913 )     (60,142 )
Bad debt expense
     9,789       (9,746 )     (31,952 )
Casualty loss
     —       —       (6,281 )
Gain on disposition of assets
     34,714       7,902       2,831  
     
Total Operating Income
   $ 1,425,374     $ 1,903,213     $ 1,910,194  
     
 
                        
Other income (expense):
                        
Interest income
     2,909       4,497       11,744  
Interest expense
     (90,698 )     (49,610 )     (10,096 )
Foreign currency transaction gain (loss)
     1,369       11,483       (65,566 )
Other, net
     (2,938 )     (1,152 )     770  
     
Income before income tax expense
     1,336,016       1,868,431       1,847,046  
Income tax expense
     (380,559 )     (492,212 )     (536,499 )
     
NET INCOME
   $ 955,457     $ 1,376,219     $ 1,310,547  
     

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Year Ended December 31, 2010 Compared to Year Ended December 31, 2009
     Operating Income. Operating income in 2010 decreased $477.8 million, or 25%, compared to 2009. During 2010, our operating results were negatively impacted by a decline in average daily revenue earned by our rigs in 2010 from the levels attained in 2009. While our contracted revenue backlog enabled us to partially mitigate the impact of the weakened market conditions, our total contract drilling revenue decreased $306.8 million, or 9%, compared to 2009. Revenue generated by our domestic and international floater rigs decreased an aggregate $117.8 million, or 4%, and revenue for our combined jack-up fleet decreased $189.2 million, or 41%, during 2010 compared to the previous year. During 2010, we cold stacked three additional rigs in the GOM, consisting of two intermediate floaters, which returned from Mexico during the year, and one jack-up rig. However, the two newest additions to our floater fleet, the Ocean Courage and Ocean Valor, began operating under contract during the first and fourth quarters of 2010, respectively, and contributed $109.3 million to our revenue during 2010. Total contract drilling expense increased $167.3 million, or 14%, in 2010 compared to 2009 and included normal operating costs for the Ocean Courage and Ocean Valor, as well as increased amortized mobilization costs and higher other operating costs associated with rigs operating internationally rather than domestically.
Other significant factors that affected the comparability of our operating income for the years ended December 31, 2010 and 2009 were as follows:
  •   Bad Debt Expense. In December 2009, we recorded a $10.7 million provision for bad debts to reserve a portion of the uncollected balance of receivables related to our operations in Egypt and recovered $0.9 million related to a previously established reserve for bad debt recorded in 2008 related to our operations in the U.K. During 2010, we recovered $5.6 million and $4.2 million related to previously established reserves for bad debts related to our operations in Egypt and the U.K., respectively.
 
  •   Depreciation Expense. Depreciation expense increased $46.7 million, or 13%, during 2010 compared to 2009 primarily due to depreciation associated with capital additions in 2009 and 2010, including depreciation of our two newest high-specification floaters, the Ocean Courage and Ocean Valor, which were placed in service in September 2009 and March 2010, respectively, but did not begin drilling operations until 2010.
 
  •   Gain on Disposition of Assets. Net gain on disposition of assets in 2010 was primarily related to the sale of the Ocean Shield on July 7, 2010. The rig was sold for net proceeds of $185.3 million and resulted in a net gain on sale of $32.8 million. Net gain on disposition of assets in 2009 included a $6.7 million gain on the sale of the Ocean Tower that was damaged during a hurricane in 2008.
     Interest Expense. Interest expense increased $41.1 million in 2010 compared to 2009, primarily due to a full year of interest expense in 2010 for our 5.875% Senior Notes due 2019, or 5.875% Senior Notes, and our 5.70% Senior Notes due 2039, or 5.70% Senior Notes, issued in May 2009 and October 2009, respectively ($31.9 million). In addition, during 2010, we recorded $4.8 million in interest expense related to uncertain tax positions compared to a $3.4 million net reduction of accrued interest expense related to an uncertain tax position for which the statute of limitations had expired during 2009.
     Foreign Currency Transaction Gain (Loss). Foreign currency transaction gain (loss) includes both realized and unrealized gains and losses from the settlement of and from mark-to-market accounting for our foreign currency forward exchange, or FOREX, contracts that we have not designated as accounting hedges. Such gains and losses fluctuate based on the level of transactions in foreign currencies, as well as fluctuations in such currencies.
     During 2009, we recognized net foreign currency exchange gains of $11.5 million, including $8.9 million realized and unrealized gains on FOREX contracts ($37.3 million in net unrealized gains from mark-to-market accounting and $28.4 million in net realized losses on settled FOREX contracts not designated as accounting hedges). During 2010, we designated all of our FOREX contracts as accounting hedges.
     Income Tax Expense. Our income tax expense is a function of the mix between our domestic and international pre-tax earnings or losses, respectively, as well as the mix of international tax jurisdictions in which we operate. We recognized $380.6 million of tax expense on pre-tax income of $1.3 billion for the year ended December 31, 2010 compared to tax expense of $492.2 million on pre-tax income of $1.9 billion in 2009. The effective annual tax rate

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of 28.5% in 2010 compared unfavorably to the effective annual tax rate of 26.3% in 2009 primarily because of higher taxes for income tax contingencies as well as taxes associated with the sale of the Ocean Shield.
     During 2010, we accrued approximately $35.7 million of expense for uncertain tax positions, primarily in Mexico and Brazil, of which $4.8 million is interest and $12.0 million is penalty related.
     On March 31, 2009, the statute of limitations relative to a 2003 uncertain tax position in Mexico expired. As a consequence, we reversed $5.5 million of previously accrued interest expense and $5.9 million of previously accrued tax expense, $0.8 million of which had been accrued for penalties.
Year Ended December 31, 2009 Compared to Year Ended December 31, 2008
     Operating Income. Operating income in 2009 decreased $7.0 million, or less than 1%, compared to 2008. During 2009, our contracted revenue backlog allowed us to substantially mitigate the impact of the global economic recession on our business. Despite the downturn in the market, our contract drilling revenue increased $60.2 million in 2009 compared to 2008. The Ocean Monarch completed a major upgrade at the end of 2008 and began operating under contract in mid-March 2009, generating revenue of $124.5 million. Our two new-build jack-up rigs, the Ocean Shield and Ocean Scepter, were completed in 2008 and contributed incremental revenue of $90.1 million during 2009 compared to 2008. However, our operating results for 2009 were negatively impacted by the ready-stacking of the Ocean Star, Ocean Victory, Ocean Guardian and Ocean Scepter for extended periods and the cold stacking of our three mat-supported GOM jack-up rigs. The Ocean Bounty completed its contract offshore Australia in the third quarter of 2009 and was being prepared for cold-stacking in Malaysia at the end of 2009. Total contract drilling expense increased $38.8 million, or 3%, in 2009 compared to 2008 and included normal operating costs for the upgraded Ocean Monarch and a full year of operating costs for our two new-build jack-ups.
Other significant factors that affected the comparability of our operating income for the years ended December 31, 2009 and 2008 were as follows:
  •   Bad Debt Expense. In December 2008, we recorded a $31.9 million provision for bad debts to reserve the uncollected balance of one of our customers in the U.K. that had entered into administration (a U.K. insolvency proceeding similar to U.S. Chapter 11 bankruptcy). We recovered $0.9 million associated with this reserve for bad debts during 2009. In December 2009, we recorded a $10.7 million provision for bad debts to reserve a portion of the uncollected balance of receivables related to our operations in Egypt.
 
  •   Depreciation Expense. Depreciation expense increased $59.0 million, or 21%, during 2009 compared to 2008 due to a higher depreciable asset base for 2009. Depreciation expense for 2009 included depreciation associated with our capital additions in 2008 and 2009, including the Ocean Shield, Ocean Scepter and Ocean Monarch, which were all placed in service at various times during 2008. Depreciation expense for 2009 also included depreciation of the Ocean Courage, which we acquired in June 2009 and placed in service in September 2009.
 
  •   Casualty Loss. In September 2008, one of our jack-up rigs in the GOM sustained significant damage, including the loss of the rig’s derrick, drill floor and related equipment. During 2008, we wrote off the approximately $2.6 million net book value of the lost equipment and accrued $3.7 million in estimated salvage costs for recovery of equipment from the ocean floor.
 
  •   Gain on Disposition of Assets. Net gain on disposition of assets in 2009 included a $6.7 million gain on the sale of the Ocean Tower compared to aggregate net gains of $2.8 million in 2008 on the sale and disposition of miscellaneous equipment.
     Interest Income. We earned interest income of $4.5 million in 2009 compared to $11.7 million in 2008. The $7.2 million decrease in interest income was primarily the result of lower average interest-bearing cash balances during 2009 compared to 2008.
     Interest Expense. Interest expense in 2009 and 2008 related primarily to interest accrued on our outstanding indebtedness, net of capitalized interest, and our liabilities for uncertain tax positions. During 2009, we incurred incremental interest expense of $25.9 million related to our 5.875% Senior Notes and 5.70% Senior Notes, partially offset by a net $3.4 million reduction in accrued interest expense related to uncertain tax positions. During 2008, we

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capitalized interest of $16.9 million related to qualifying construction projects and major upgrades that were all completed in 2008. We did not capitalize interest costs in 2009 as there were no qualifying activities during the year.
     Foreign Currency Transaction Gain (Loss). During 2009, we recognized net foreign currency exchange gains of $11.5 million, which included $8.9 million in realized and unrealized gains on FOREX contracts ($37.3 million in net unrealized gains from mark-to-market accounting and $28.4 million in net realized losses on settled FOREX contracts) and net gains of $2.6 million on other foreign currency transactions. During 2008, we recognized net foreign currency exchange losses of $65.6 million, which included $54.0 million in net losses on FOREX contracts ($37.2 million in net unrealized losses from mark-to-market accounting and $16.8 million in net realized losses on settled FOREX contracts) and other net foreign currency transaction losses of $11.6 million.
     Income Tax Expense. Our income tax expense is a function of the mix between our domestic and international pre-tax earnings or losses, as well as the mix of international tax jurisdictions in which we operate. We recognized $492.2 million of tax expense on pre-tax income of $1.9 billion for the year ended December 31, 2009 compared to tax expense of $536.5 million on pre-tax income of $1.8 billion in 2008. The effective annual tax rate of 26.3% in 2009 compared favorably to the effective annual tax rate of 29.1% in 2008 primarily because of higher earnings of DOIL in 2009 which were taxed at lower rates.
     Our income tax returns are subject to review and examination in the various jurisdictions in which we operate and we are currently contesting various tax assessments. We accrue for income tax contingencies, or uncertain tax positions, that we believe are more likely than not exposures. We recognized expense of $3.3 million and $3.4 million for uncertain tax positions in 2009 and 2008, respectively. During the year ended December 31, 2009 we recorded a net reduction to interest expense related to uncertain tax positions of $3.4 million. During the year ended December 31, 2008, we recognized $0.8 million of interest expense related to uncertain tax positions. Penalty related tax expense for uncertain tax positions during the years ended December 31, 2009 and 2008 was $4.7 million and $1.1 million, respectively. On March 31, 2009, the statute of limitations relative to a 2003 uncertain tax position in Mexico expired. As a consequence, we reversed $5.5 million of previously accrued interest expense and $5.9 million of previously accrued tax expense, $0.8 million of which had been accrued for penalties. In December 2009 we received an approximately $26 million assessment from the Brazilian tax authorities for the years 2004 and 2005. We contested the tax assessment in January 2010 and are awaiting the outcome of the appeal. As required by GAAP, only the portion of the tax benefit that has a greater than 50% likelihood of being realized upon settlement is to be recognized. During 2009 we accrued approximately $7 million of expense attributable to the portion of the tax assessment we determined to be an uncertain tax position in our 2009 Consolidated Statements of Operations, of which approximately $2 million was interest related and approximately $2 million was penalty related.

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High-Specification Floaters.
                         
    Year Ended December 31,
    2010   2009   2008
    (In thousands, except days, percentages and
    average daily revenue amounts)
HIGH-SPECIFICATION FLOATERS:
                        
REVENUE EARNING DAYS (1)
                        
GOM
     946       2,245       2,664  
Australia/Asia/Middle East
     513       355       293  
Europe/Africa/Mediterranean
     500       108       —  
South America
     1,603       891       593  
 
                        
UTILIZATION (2)
                        
GOM
     68 %     75 %     91 %
Australia/Asia/Middle East
     79 %     97 %     80 %
Europe/Africa/Mediterranean
     75 %     68 %     —  
South America
     69 %     85 %     81 %
 
                        
AVERAGE DAILY REVENUE (3)
                        
GOM
   $ 386,000     $ 419,600     $ 394,100  
Australia/Asia/Middle East
     432,700       433,700       237,200  
Europe/Africa/Mediterranean
     489,100       571,000       —  
South America
     311,700       237,800       339,700  
 
                        
CONTRACT DRILLING REVENUE
                        
GOM
   $ 397,671     $ 943,024     $ 1,051,178  
Australia/Asia/Middle East
     225,392       153,757       69,419  
Europe/Africa/Mediterranean
     270,557       66,156       —  
South America
     521,077       217,834       201,528  
     
Total Contract Drilling Revenue
   $ 1,414,697     $ 1,380,771     $ 1,322,125  
     
 
                        
CONTRACT DRILLING EXPENSE
                        
GOM
   $ 125,323     $ 250,025     $ 223,954  
Australia/Asia/Middle East
     66,044       34,144       35,079  
Europe/Africa/Mediterranean
     80,330       14,037       —  
South America
     304,724       108,997       108,498  
     
Total Contract Drilling Expense
   $ 576,421     $ 407,203     $ 367,531  
     
 
                        
OPERATING INCOME
   $ 838,276     $ 973,568     $ 954,594  
     
 
(1)   A revenue earning day is defined as a 24-hour period during which a rig earns a dayrate after commencement of operations and excludes mobilization, demobilization and contract preparation days.
 
(2)   Utilization is calculated as the ratio of total revenue-earning days divided by the total calendar days in the period for all of the specified rigs in our fleet (including cold-stacked rigs).
 
(3)   Average daily revenue is defined as contract drilling revenue for all of the specified rigs in our fleet (excluding revenues for mobilization, demobilization and contract preparation) per revenue earning day.

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Rig Relocations:
         
Rig   Relocation Details   Date
2010:
        
Ocean Star
  GOM to South America (Brazil)   January 2010
Ocean Valor
  Completion of construction and relocation from Singapore shipyard to South America (Brazil)   March 2010
Ocean Courage
  GOM to South America (Brazil)   March 2010
Ocean Baroness
  GOM to South America (Brazil)   March 2010
Ocean America
  GOM to Australia/Asia/Middle East (Australia)   March 2010
Ocean Confidence
  GOM to Europe/Africa/Mediterranean (Republic of Congo)   August 2010
Ocean Endeavor
  GOM to Europe/Africa/Mediterranean (Egypt)   August 2010
Ocean Rover
  Australia/Asia/Middle East (Malaysia to Indonesia)   November 2010
 
        
2009:
        
Ocean Quest
  GOM to South America (Brazil)   February 2009
Ocean Monarch
  Completion of major upgrade and relocation from Singapore shipyard to GOM   March 2009
Ocean Valiant
  GOM to Europe/Africa/Mediterranean (Angola)   July 2009
 
        
2008:
        
None
        
     Year Ended December 31, 2010 Compared to Year Ended December 31, 2009
     GOM. Revenue generated by our high-specification floaters operating in the GOM decreased $545.4 million during 2010 compared to 2009, as a result of 1,299 fewer revenue earning days ($544.9 million) and a decrease in average daily revenue earned during 2010 ($31.8 million), partially offset by a $30.7 million contract termination fee from a previous customer of the Ocean Endeavor. The decrease in revenue earning days in 2010 is primarily due to the relocation of several of our high-specification rigs to international markets since early 2009 and unplanned downtime due to a force majeure assertion by one of our customers in the GOM. Contract drilling expense for our high-specification floaters in the GOM decreased by $124.7 million in 2010 compared to 2009, primarily due to a $129.5 million reduction attributable to the rigs relocated to other regions, including $4.3 million of start-up costs for the Ocean Courage incurred in 2009 prior to a change in contract that redirected the rig to Brazil in early 2010.
     Australia/Asia/Middle East. During 2010, revenue from our high-specification rigs operating in the Australia/Asia/Middle East region increased $71.6 million compared to 2009, primarily due to 158 additional revenue earning days in 2010. The increase in revenue earning days in 2010 is primarily the result of the relocation of the Ocean America to Australia. Contract drilling expense for our operations in this region increased $31.9 million in 2010 compared to 2009, primarily due to the inclusion of normal operating, contract preparation and amortized mobilization costs for the Ocean America ($30.7 million).
     Europe/Africa/Mediterranean. Revenue generated by our high-specification floaters operating in the Europe/Africa/Mediterranean region increased $204.4 million in 2010 compared to 2009, primarily due to 392 incremental revenue earning days in 2010 ($223.7 million) and the recognition of $21.7 million in amortized mobilization fees, partially offset by a decrease in average daily revenue earned ($41.0 million). The increase in revenue earning days in 2010 is the result of the relocation of two additional rigs to this region in 2010 and a full year of operation for the Ocean Valiant. Contract drilling expense for our operations during 2010 increased $66.3 million compared to 2009 due to the inclusion of normal operating and amortized mobilization costs for the two rigs relocated to the region in 2010 and a full year of operating costs for the Ocean Valiant.
     South America. Revenue earned by our high-specification floaters operating offshore Brazil increased $303.2 million in 2010 compared to 2009, primarily due to 712 additional revenue earning days ($169.3 million) combined with an increase in average daily revenue earned by our rigs in this region ($118.4 million) during 2010 and the recognition of $15.5 million in amortized mobilization revenue. The increase in revenue earning days is primarily due to the additional rigs operating in the region during 2010 compared to 2009. Contract drilling expense for our

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operations in Brazil increased $195.7 million in 2010 compared to 2009 due to the inclusion of normal operating costs for the additional rigs operating in the region during 2010, including a full year of contract drilling expense for the Ocean Quest ($123.8 million) and higher contract drilling expense for the remainder of our South American rigs that operated in both 2010 and 2009 ($71.9 million). The increase in costs for our static fleet in 2010 compared to 2009 reflects higher labor and personnel-related costs, incremental shipyard and repair costs for the Ocean Alliance as a result of a 145-day shipyard period for an intermediate inspection and thruster change out, higher amortized mobilization costs and an increase in revenue-based fees.
     Year Ended December 31, 2009 Compared to Year Ended December 31, 2008
     GOM. Revenue generated by our high-specification floaters operating in the GOM decreased $108.2 million during 2009 compared to 2008, as a result of 419 fewer revenue earning days ($165.4 million), partially offset by the effect of an increase in average daily revenue earned during 2009 ($57.3 million). The decrease in revenue earning days in 2009, compared to 2008, was attributable to downtime associated with contract preparation activities for the Ocean Quest and Ocean Valiant, scheduled surveys days for the Ocean America and 191 ready-stack days for the Ocean Star, partially offset by incremental revenue earning days for the Ocean Monarch after completion of its major upgrade. Contract drilling expense for our high-specification floaters in the GOM increased by $26.1 million in 2009 compared to 2008 and included an aggregate of $32.0 million in incremental start-up and operating costs for the Ocean Monarch and start-up costs for the Ocean Courage (prior to a change in contract that subsequently relocated the rig to Brazil). Contract drilling expense for 2009 also reflected higher labor and related costs ($5.7 million), higher survey, repair and mobilization costs ($19.6 million), including incremental costs associated with a special survey for the Ocean America, and higher overhead costs ($5.8 million) compared to the prior year. These cost increases were partially offset by a $35.5 million reduction in contract drilling expense attributable to the two rigs that we relocated out of the GOM during 2009.
     Australia/Asia/Middle East. During 2009, our high-specification rig operating offshore Malaysia, the Ocean Rover, generated $84.3 million in additional revenue compared to 2008, primarily due to an increase in average daily revenue earned in 2009 ($69.7 million) and an increase in utilization during 2009 ($14.7 million). Utilization increased in 2009 compared to 2008, when the rig had 67 days of scheduled downtime for a special survey and related repairs. Contract drilling expense for the Ocean Rover decreased slightly compared to 2008 as lower survey and mobilization costs ($5.2 million) were partially offset by higher revenue-based agency fees ($2.7 million). Contract drilling expense for 2009 also included $1.2 million in repair costs for the Ocean Valor while in a shipyard in Singapore.
     Europe/Africa/Mediterranean. The Ocean Valiant began operating offshore Angola in the third quarter of 2009 and generated revenue and incurred contract drilling expense of $66.2 million and $14.0 million, respectively.
     South America. Revenue earned by our high-specification floaters operating offshore Brazil in 2009 increased $16.3 million compared to 2008, primarily due to 298 additional revenue earning days in 2009 ($101.1 million), partially offset by a decline in average daily revenue earned by our rigs in the region during 2009 ($90.8 million). The increase in revenue earning days is the result of the operation of the Ocean Quest offshore Brazil beginning in the first quarter of 2009, as well as increased utilization of the Ocean Clipper, which experienced significant downtime during 2008 for a survey and unplanned repairs to its propulsion system. We also recognized $6.0 million in amortized mobilization revenue associated with the relocation of the Ocean Quest from the GOM during 2009. Contract drilling expense for our operations in Brazil increased $0.5 million in 2009 compared to 2008 as the impact of the addition of incremental normal operating costs for the Ocean Quest ($23.1 million) was partially offset by a reduction in costs primarily attributable to the 2008 survey of the Ocean Clipper and repairs to its propulsion system ($15.6 million) and reduced labor and related costs ($5.1 million).

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Intermediate Semisubmersibles.
                         
    Year Ended December 31,
    2010   2009   2008
    (In thousands, except days, percentages and
    average daily revenue amounts)
INTERMEDIATE SEMISUBMERSIBLES:
                        
REVENUE EARNING DAYS (1)
                        
GOM
     446       531       483  
Mexico
     210       722       779  
Australia/Asia/Middle East
     1,044       1,268       1,274  
Europe/Africa/Mediterranean
     887       1,409       1,641  
South America
     2,866       1,996       1,615  
 
                        
UTILIZATION (2)
                        
GOM
     56 %     94 %     75 %
Mexico
     71 %     99 %     95 %
Australia/Asia/Middle East
     72 %     87 %     87 %
Europe/Africa/Mediterranean
     81 %     82 %     90 %
South America
     87 %     81 %     79 %
 
                        
AVERAGE DAILY REVENUE (3)
                        
GOM
   $ 198,900     $ 248,800     $ 279,400  
Mexico
     196,100       295,500       277,900  
Australia/Asia/Middle East
     329,000       333,700       306,600  
Europe/Africa/Mediterranean
     315,600       339,500       311,800  
South America
     263,600       217,400       215,200  
 
                        
CONTRACT DRILLING REVENUE
                        
GOM
   $ 88,605     $ 132,195     $ 134,880  
Mexico
     47,691       217,628       220,754  
Australia/Asia/Middle East
     343,419       423,117       395,124  
Europe/Africa/Mediterranean
     279,998       481,944       518,382  
South America
     787,124       443,700       360,218  
     
Total Contract Drilling Revenue
   $ 1,546,837     $ 1,698,584     $ 1,629,358  
     
 
                        
CONTRACT DRILLING EXPENSE
                        
GOM
   $ 35,813     $ 32,184     $ 44,902  
Mexico
     19,995       46,769       54,187  
Australia/Asia/Middle East
     103,780       119,674       141,170  
Europe/Africa/Mediterranean
     107,439       137,542       167,786  
South America
     338,255       221,465       173,116  
     
Total Contract Drilling Expense
   $ 605,282     $ 557,634     $ 581,161  
     
 
                        
OPERATING INCOME
   $ 941,555     $ 1,140,950     $ 1,048,197  
     
 
(1)   A revenue earning day is defined as a 24-hour period during which a rig earns a dayrate after commencement of operations and excludes mobilization, demobilization and contract preparation days.
 
(2)   Utilization is calculated as the ratio of total revenue-earning days divided by the total calendar days in the period for all of the specified rigs in our fleet (including cold-stacked rigs).
 
(3)   Average daily revenue is defined as contract drilling revenue for all of the specified rigs in our fleet (excluding revenues for mobilization, demobilization and contract preparation) per revenue earning day.

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     Rig Relocations:
         
Rig   Relocation Details   Date
2010:
        
Ocean Voyager
  Mexico to GOM (cold-stacked June 2010)   March 2010
Ocean New Era
  Mexico to GOM (cold-stacked September 2010)   August 2010
 
        
2009:
        
Ocean Ambassador
  Contract preparation and relocation from GOM to South America (Brazil)   June 2009
Ocean Bounty
  Preparations for cold-stacking (Malaysia)   July 2009
Ocean Lexington
  Europe/Africa/Mediterranean (Egypt) to South America (Brazil)   September 2009
Ocean Guardian
  Europe/Africa/Mediterranean (North Sea) to South America (Falkland Islands )   November 2009
 
        
2008:
        
Ocean Ambassador
  Mexico to GOM   April 2008
Ocean Yorktown
  GOM to South America (Brazil)   May 2008
     Year Ended December 31, 2010 Compared to Year Ended December 31, 2009
     GOM. Revenue generated by our intermediate semisubmersible fleet located in the GOM in 2010 decreased $43.6 million compared to 2009 due to a reduction in average daily revenue earned ($22.3 million) and 85 fewer revenue earning days ($21.3 million) in 2010. The decrease in dayrates and utilization was primarily related to the depressed GOM market, which was a contributing factor in our decision to cold stack two of our intermediate semisubmersible rigs in this market during the third quarter of 2010. Contract drilling expense for our intermediate floater fleet in the GOM increased $3.6 million in 2010 compared to 2009, as incremental contract drilling, mobilization and cold-stacking costs for the Ocean Voyager and Ocean New Era ($16.0 million) were partially offset by reduced contract drilling expense for the Ocean Ambassador ($13.1 million). We currently have one working and two cold-stacked intermediate semisubmersible rigs in the GOM.
     Mexico. Revenue generated by our intermediate semisubmersibles operating offshore Mexico decreased $169.9 million in 2010 compared to 2009 due to 512 fewer revenue earning days ($151.3 million) combined with a decrease in average daily revenue earned ($20.9 million). Contract drilling expense decreased $26.8 million during 2010 compared to 2009. The decline in revenue and contract drilling expense in 2010 was primarily due to the relocation of both of our Mexico intermediate semisubmersible rigs to the GOM after completion of their contracts. We currently have no intermediate semisubmersible rigs operating offshore Mexico.
     Australia/Asia/Middle East. Revenue generated by our intermediate semisubmersibles operating in the Australia/Asia/Middle East region decreased $79.7 million in 2010 compared to 2009, as a result of 224 fewer revenue earning days ($74.7 million) combined with a decrease in average daily revenue earned ($5.0 million) during 2010. Contract drilling expense for the Australia/Asia/Middle East region decreased $15.9 million in 2010 compared to 2009. The decrease in revenue and contract drilling expense in this region in 2010 was primarily due to cold stacking the Ocean Bounty after completion of its contract in 2009.
     Europe/Africa/Mediterranean. Operating revenue for our intermediate semisubmersibles working in the Europe/Africa/Mediterranean region decreased $201.9 million in 2010, primarily due to a 522 day reduction in revenue earning days ($177.3 million) and a reduction in average daily revenue earned ($21.1 million) in 2010 compared to 2009. Revenue earning days decreased in 2010 due to the relocation of two rigs to the South American region and approximately 100 days of planned downtime for a special survey of our rig in Norway. Contract drilling expense in the Europe/Africa/Mediterranean region decreased $30.1 million in 2010 compared to 2009, primarily due to the two rigs moved to the South American region ($50.3 million), partially offset by incremental costs associated with the regulatory survey of the Ocean Vanguard.
     South America. Revenue generated by our intermediate semisubmersibles operating in the South American region increased $343.4 million in 2010 compared to 2009. Both revenue earning days and average daily revenue

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earned increased in 2010 compared to 2009, and contributed incremental revenue of $189.1 million and $132.3 million, respectively. The increase in revenue is partially attributable to a full year of operations for the Ocean Ambassador and Ocean Lexington in 2010, compared to only a partial year of operations in 2009 after their relocation to the region, combined with higher dayrates earned in 2010, compared to 2009. We also recognized $22.0 million in incremental amortized mobilization revenue in 2010 compared to the prior year. Contract drilling expense in the region increased $116.8 million in 2010 compared to 2009, primarily due to the increase in the number of rigs operating in the region ($87.7 million) and higher contract drilling expense for our rigs operating offshore Brazil during both years, primarily for labor and personnel related expenditures, revenue-based fees and incremental costs associated with a special survey for the Ocean Winner.
     Year Ended December 31, 2009 Compared to Year Ended December 31, 2008
     GOM. Revenue generated by our intermediate semisubmersible fleet operating in the GOM in 2009 decreased $2.7 million compared to 2008, primarily due to lower average daily revenue earned in 2009. The effect of reduced average daily revenue was partially offset by an increase in revenue earning days, primarily as a result of the 2008 relocation of the Ocean Ambassador. Contract drilling expense for our intermediate floater fleet in the GOM decreased $12.7 million in 2009 compared to 2008, primarily due to a reduction in costs as a result of rigs transferred out of the GOM ($14.2 million), partially offset by higher overhead costs ($1.0 million) and labor and related costs ($0.9 million) for our remaining intermediate semisubmersible fleet in the GOM.
     Mexico. Revenue generated by our intermediate semisubmersibles operating offshore Mexico decreased $3.1 million and reflected a 57 day decrease in revenue earning days ($15.8 million), partially offset by an increase in average daily revenue earned in 2009 compared to 2008 ($12.7 million). Contract drilling expense decreased $7.4 million during 2009 compared to 2008. The decline in revenue and contract drilling expense in 2009 was primarily due to the relocation of the Ocean Ambassador out of the region.
     Australia/Asia/Middle East. Operating revenue for our intermediate semisubmersibles working in the Australia/Asia/Middle East region increased $28.0 million in 2009 compared to 2008, primarily due to an increase in average daily revenue earned during 2009 ($34.4 million), partially offset by a $4.5 million reduction in amortized mobilization revenue associated with the Ocean Patriot’s relocation within the region (New Zealand to Australia) in 2008. In 2009, we elected to cold stack the Ocean Bounty after completion of its contract offshore Australia in July and were in the process of finding a suitable location at the end of 2009. Contract drilling expense for the Australia/Asia/Middle East region decreased $21.5 million in 2009 compared to 2008, primarily due to reduced costs for the Ocean Bounty ($11.4 million), lower survey, repair and mobilization costs ($7.2 million), as a result of the completion of special surveys of the Ocean Patriot and Ocean General in 2008, and lower shorebase support costs ($1.9 million) associated with a Melbourne shorebase office that was closed in 2008.
     Europe/Africa/Mediterranean. Operating revenue for our intermediate semisubmersibles working in the Europe/Africa/Mediterranean region decreased $36.4 million in 2009 compared to 2008. Revenue earning days decreased by 232 days in 2009 ($72.3 million) compared to 2008, while average daily revenue increased in 2009 ($39.0 million). The decrease in revenue earning days in 2009 was the result of the early termination of a drilling contract for the Ocean Nomad and intermittent work for the Ocean Guardian, partially offset by reduced downtime for the Ocean Princess, which completed its 2008 special survey in early 2009. Contract drilling expense in the Europe/Africa/Mediterranean region decreased $30.2 million in 2009 compared to 2008, primarily due to lower labor and personnel-related costs for our rigs operating in the North Sea ($4.6 million), including the reversal of a previously recorded reserve for paid time off for our U.K. national employees, and reduced costs associated with regulatory surveys ($13.5 million), including repairs. Contract drilling expense in this region also decreased as a result of the relocation of two rigs to Brazil in the second half of 2009 ($10.1 million).
     South America. Revenue generated by our intermediate semisubmersibles working in the South American region increased $83.5 million in 2009 compared to 2008, primarily due to 381 incremental revenue earning days in 2009 ($81.8 million). In addition, 2009 revenue was favorably impacted by a slight increase in average daily revenue earned compared to 2008 ($4.4 million). Contract drilling expense for our intermediate semisubmersibles increased $48.3 million in 2009, compared to 2008, primarily due to an increase in the number of rigs operating in the region ($15.8 million). Contract drilling expense for 2009 also reflected higher overall operating and support costs, including revenue-based agency fees and non-income taxes ($11.2 million), labor and related costs ($7.0 million), maintenance and other costs associated with customer acceptance testing and inspections ($6.7 million) and shorebase support and overhead costs ($6.2 million).

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Jack-Ups.
                         
    Year Ended December 31,
    2010   2009   2008
    (In thousands, except days, percentages and
    average daily revenue amounts)
JACK-UPS:
                        
REVENUE EARNING DAYS (1)
                        
GOM
     945       807       2,346  
Mexico
     667       767       687  
Australia/Asia/Middle East
     570       642       673  
Europe/Africa/Mediterranean
     846       961       841  
South America
     —       205       95  
 
                        
UTILIZATION (2)
                        
GOM
     39 %     39 %     91 %
Mexico
     91 %     89 %     94 %
Australia/Asia/Middle East
     96 %     84 %     84 %
Europe/Africa/Mediterranean
     77 %     90 %     95 %
South America
     0 %     56 %     62 %
 
                        
AVERAGE DAILY REVENUE (3)
                        
GOM
   $ 58,300     $ 78,100     $ 80,800  
Mexico
     130,300       134,900       148,200  
Australia/Asia/Middle East
     127,300       207,100       137,700  
Europe/Africa/Mediterranean
     59,800       95,600       128,400  
South America
     —       234,700       199,400  
 
                        
CONTRACT DRILLING REVENUE
                        
GOM
   $ 55,812     $ 63,016     $ 189,500  
Mexico
     88,603       105,431       105,055  
Australia/Asia/Middle East
     72,561       140,783       92,596  
Europe/Africa/Mediterranean
     50,567       93,080       115,652  
South America
     440       54,914       22,131  
     
Total Contract Drilling Revenue
   $ 267,983     $ 457,224     $ 524,934  
     
 
                        
CONTRACT DRILLING EXPENSE
                        
GOM
   $ 64,544     $ 72,454     $ 99,533  
Mexico
     40,607       38,209       33,303  
Australia/Asia/Middle East
     36,185       50,097       42,184  
Europe/Africa/Mediterranean
     38,630       38,896       35,058  
South America
     10,201       36,268       14,287  
     
Total Contract Drilling Expense
   $ 190,167     $ 235,924     $ 224,365  
     
 
                        
OPERATING INCOME
   $ 77,816     $ 221,300     $ 300,569  
     
 
(1)   A revenue earning day is defined as a 24-hour period during which a rig earns a dayrate after commencement of operations and excludes mobilization, demobilization and contract preparation days.
 
(2)   Utilization is calculated as the ratio of total revenue-earning days divided by the total calendar days in the period for all of the specified rigs in our fleet (including cold-stacked rigs).
 
(3)   Average daily revenue is defined as contract drilling revenue for all of the specified rigs in our fleet (excluding revenues for mobilization, demobilization and contract preparation) per revenue earning day.

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Rig Relocations:
         
Rig   Relocation Details   Date
2010:
        
Ocean Shield
  Sold   July 2010
Ocean Scepter
  GOM to South America (Brazil)   August 2010
Ocean Spartan
  Cold-stacked (GOM)   September 2010
 
        
2009:
        
Ocean Champion
  Cold-stacked (GOM)   June 2009
Ocean Crusader
  Cold-stacked (GOM)   June 2009
Ocean Drake
  Cold-stacked (GOM)   June 2009
Ocean Summit
  GOM to Mexico   July 2009
Ocean Columbia
  Mexico to GOM   November 2009
Ocean Scepter
  South America (Argentina) to GOM   December 2009
 
        
2008:
        
Ocean Shield
  Placed in service; Australia/Asia/Middle East (Malaysia)   May 2008
Ocean Heritage
  Australia/Asia/Middle East to Europe/Africa/Mediterranean (Egypt)   June 2008
Ocean Scepter
  Placed in service; South America (Argentina)   September 2008
Ocean Tower
  Removed from service (hurricane damage)   October 2008
     Year Ended December 31, 2010 Compared to Year Ended December 31, 2009
     GOM. Revenue generated by our jack-up rigs operating in the GOM decreased $7.2 million during 2010 compared to 2009 due to a decrease in average daily revenue earned during 2010 ($18.7 million), partially offset by the effect of 138 incremental revenue earning days during 2010 ($10.8 million). Due to continued unfavorable market conditions in the GOM, we elected to cold stack an additional jack-up rig in the third quarter of 2010, leaving us with four cold-stacked jack-up rigs in the GOM at December 31, 2010. Contract drilling expense for our jack-ups in the GOM decreased $7.9 million during 2010 compared to 2009, primarily due to cold stacking of four of our jack-up rigs ($26.3 million) and the absence of costs associated with a special survey in 2009. However, the reduction in contract drilling expense in 2010 was partially offset by incremental costs resulting from the net increase of one rig in the GOM in 2010 compared to the prior year.
     Mexico. Revenue generated by our jack-up rigs operating offshore Mexico decreased $16.8 million in 2010 compared to 2009, primarily due to 100 fewer revenue earning days ($13.5 million) and a decrease in average daily revenue earned ($3.1 million). Contract drilling expense increased $2.4 million in 2010 compared to 2009 due to higher overhead, shorebase support and amortized mobilization costs.
     Australia/Asia/Middle East. Revenue generated by our jack-up rigs operating in the Australia/Asia/Middle East region decreased $68.2 million in 2010 compared to 2009, primarily due to a reduction in average daily revenue ($45.5 million) and 72 fewer revenue earning days ($14.9 million) in 2010. In addition, revenue in 2009 included $7.8 million in amortized mobilization revenue related to the Ocean Shield’s move to Australia. Revenue earning days during 2010 decreased due to the sale of the Ocean Shield in July 2010. Contract drilling expense decreased $13.9 million in 2010 compared to 2009, primarily due to a reduction in costs for the Ocean Shield ($10.9 million) and costs associated with the Ocean Sovereign’s 2009 survey and shipyard project.

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     Europe/Africa/Mediterranean. Revenue generated by our jack-up rigs operating in the Europe/Africa/Mediterranean region decreased $42.5 million in 2010 compared to 2009, primarily due to a decrease in average daily revenue earned ($30.3 million) and a decrease of 115 revenue earning days ($11.0 million) during 2010. Contract drilling expense decreased $0.3 million in 2010 compared to 2009 due to fewer operating days for the Ocean King, which completed its bareboat charter offshore Croatia in July 2010, partially offset by an increase in costs associated with a survey and related repairs for the Ocean Spur that was completed in the fourth quarter of 2010.
     South America. Revenue and contract drilling expense decreased $54.5 million and $26.1 million, respectively, in 2010 compared to 2009. Our only jack-up rig in this region, the Ocean Scepter, operated offshore Argentina until July 2009 and was subsequently relocated to the GOM. We moved this rig back to the region in August 2010 for a contract offshore Brazil, where it incurred $10.2 million in expense related to customer acceptance activities during 2010. The rig is expected to begin drilling under contract in the first quarter of 2011.
     Year Ended December 31, 2009 Compared to Year Ended December 31, 2008
     GOM. Revenue generated by our jack-up rigs operating in the GOM decreased $126.5 million during 2009 compared to 2008 due to 1,539 fewer revenue earning days in 2009 ($124.3 million) compounded by the effect of a lower average daily revenue earned in 2009 ($2.1 million). The decline in revenue earning days was reflective of the depressed GOM market, and as a result of such market factors, in 2009 we elected to cold stack our three mat-supported jack-ups in this region. In addition, the Ocean Tower, which received extensive damage during a 2008 hurricane, was removed from service in October 2008 and subsequently sold in 2009. Contract drilling expense for our jack-ups operating in the GOM decreased $27.1 million during 2009 compared to 2008, primarily due to significantly reduced operating costs for the Ocean Tower and our three cold-stacked rigs ($24.1 million) and a reduction in labor and related costs for our actively-marketed jack-up fleet in the GOM ($4.9 million). The decrease in costs in 2009 was partially offset by 2009 survey and repair costs for two rigs and demobilization costs for the Ocean Columbia, which relocated to the GOM for a shipyard project ($1.9 million).
     Mexico. Revenue and contract drilling expense generated by our jack-up rigs operating offshore Mexico increased $0.4 million and $4.9 million, respectively, in 2009 compared to the prior year. The effect on revenue of an increase in revenue earning days in 2009 was mostly offset by a decrease in average daily revenue earned during the 2009 period. Contract drilling expense increased primarily due to costs associated with contract preparation activities, customer acceptance and the inclusion of normal operating costs of the Ocean Summit, partially offset by lower operating costs for the Ocean Columbia due to its relocation to the GOM.
     Australia/Asia/Middle East. Revenue generated by our jack-up rigs operating in the Australia/Asia/Middle East region increased $48.2 million in 2009 compared to 2008 and included $57.3 million of incremental revenues earned by the Ocean Shield. However, total revenue earning days decreased in 2009 as incremental operating days for the Ocean Shield were more than offset by an increase in unpaid shipyard days for the Ocean Sovereign and due to the relocation of the Ocean Heritage to another region. Contract drilling expense increased $7.9 million in 2009 compared to 2008, primarily due to costs associated with the Ocean Sovereign’s 2009 survey and shipyard project and a net increase in normal operating costs in the region ($3.1 million). Contract drilling expense in 2009 also included $11.5 million in incremental operating costs, including amortized mobilization costs, for the Ocean Shield. Operating costs in 2009 were partially offset by reduced costs for the Ocean Heritage ($6.6 million).
     Europe/Africa/Mediterranean. Revenue generated by our jack-up rigs operating in the Europe/Africa/Mediterranean region decreased $22.6 million in 2009 compared to 2008, primarily due to a decrease in average daily revenue earned in 2009 ($31.5 million), partially offset by the impact of an increase in revenue earning days during the same period ($15.4 million). In addition, during 2008, we recognized a $6.5 million lump-sum demobilization fee for the Ocean Spur upon completion of its initial contract offshore Egypt. Contract drilling expense increased $3.8 million in 2009 compared to 2008, primarily due to the inclusion of a full year of operating costs in 2009 for the Ocean Heritage ($4.4 million).
     South America. Our newly constructed jack-up rig, the Ocean Scepter, began operating offshore Argentina late in the third quarter of 2008. The Ocean Scepter completed its contract in July 2009.

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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, 2010, we had $464.4 million in “Cash and cash equivalents” and $612.3 million in “Investments and marketable securities,” representing our investment of cash available for current operations.
     Cash Flows from Operations. Our cash flows from operations are impacted by the ability of our customers to weather the instability in the U.S. and global economies and restrictions in the credit market, as well as the volatility in energy prices. In general, before working for a customer with whom we have not had a prior business relationship and/or whose financial stability may appear uncertain to us, we perform a credit review on that company. Based on that analysis, we may require that the customer present a letter of credit, prepay or provide other credit enhancements. If a potential customer is unable to obtain an adequate level of credit, it may preclude us from doing business with that potential customer.
     These external factors which affect our cash flows from operations, many which are not within our control, 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.
     During 2009, we amended an existing contractual agreement at a customer’s request to provide short-term financial relief. The amended contract obligates the customer to pay us, over the term of the six-well drilling program, an aggregate drilling rate of $560,000 per day, consisting of $75,000 per day payable in accordance with our normal credit terms (due 30 days after receipt of invoice) and the remainder of the contractual dayrate, $485,000 per day, payable through the conveyance of a 27% net profits interest, or NPI, in certain developmental oil-and-gas producing properties. As of December 31, 2010, we had drilled four wells for this customer and were owed $85.0 million payable through the NPI. We began receiving monthly payments from the conveyance of the NPI in July 2010 and through the date of this report have received an aggregate of $13.7 million through the NPI.
     Based on current production payout estimates, we expect to collect $49.6 million of the receivable within the next twelve months and the remaining $35.4 million of the receivable within the following twelve months. However, payment of such amounts, and the timing of such payments, are contingent upon such production and upon energy sale prices.
     $285 Million Revolving Credit Facility. We maintain a $285 million syndicated, senior unsecured revolving credit facility, or Credit Facility, for general corporate purposes, including loans and performance or standby letters of credit, that will mature on November 2, 2011.
     Loans under the Credit Facility bear interest at a rate per annum equal to, at our election, either (i) the higher of the prime rate or the federal funds rate plus 0.5% or (ii) the London Interbank Offered Rate, or LIBOR, plus an applicable margin, varying from 0.20% to 0.525%, based on our current credit ratings. Under our Credit Facility, we also pay, based on our current credit ratings, and as applicable, other customary fees, including, but not limited to, a facility fee on the total commitment under the Credit Facility regardless of usage and a utilization fee that applies if the aggregate of all loans outstanding under the Credit Facility equals or exceeds 50% of the total commitment under the facility. Changes in credit ratings could lower or raise the fees that we pay under the Credit Facility.
     The Credit Facility contains customary covenants, including, but not limited to, the maintenance of a ratio of consolidated indebtedness to total capitalization, as defined in the Credit Facility, of not more than 60% at the end of each fiscal quarter and limitations on liens, mergers, consolidations, liquidation and dissolution, changes in lines of business, swap agreements, transactions with affiliates and subsidiary indebtedness.
     Based on our current credit ratings at December 31, 2010, the applicable margin on LIBOR loans would have been 0.24%. See “— Liquidity and Capital Requirements — Credit Ratings.” As of December 31, 2010, there were no loans outstanding under the Credit Facility; however $21.9 million in letters of credit were issued and outstanding under the Credit Facility.

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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, our ongoing rig equipment replacement and enhancement programs, and our obligations relating to the construction of our new drillships. We believe that our operating cash flows and cash reserves will be sufficient to meet both our working capital requirements and our capital commitments over the next twelve months; however, we will continue to make periodic assessments based on industry conditions and will adjust capital spending programs if required.
     In addition, we may, from time to time, issue debt or equity securities, or a combination thereof, to finance capital expenditures, the acquisition of assets and businesses or for general corporate purposes. Our ability to access the capital markets by issuing debt or equity securities will be dependent on our results of operations, our current financial condition, current market conditions and other factors beyond our control. Additionally, we may also make use of our Credit Facility to finance capital expenditures or for other general corporate purposes.
     Contractual Cash Obligations. The following table sets forth our contractual cash obligations at December 31, 2010.
Contractual Obligations
                                         
    Payments Due By Period
            Less than           After 5
    Total   1 year   1 — 3 years   4 — 5 years   years
    (In thousands)
Long-term debt (principal and interest) (1)
  $ 2,688,625     $ 82,938     $ 165,876     $ 652,998     $ 1,786,813  
Construction contracts (2)
    514,757       154,427       360,330       —       —  
Operating leases
    3,300       1,900       1,400       —       —  
     
Total obligations
  $ 3,206,682     $ 239,265     $ 527,606     $ 652,998     $ 1,786,813  
     
 
(1)   See Note 9 “Long-Term Debt” to our Consolidated Financial Statements in Item 8 of this report.
 
(2)   In December 2010, we entered into a turnkey contract with Hyundai for the construction of a dynamically positioned, ultra-deepwater drillship with delivery scheduled for late in the second quarter of 2013. See Note 11 “Commitments and Contingencies — Purchase Obligations” to our Consolidated Financial Statements in Item 8 of this report.
     The above table excludes FOREX contracts in the aggregate notional amount of $140.3 million outstanding at December 31, 2010. See further information regarding these contracts in Item 7A. “Quantitative and Qualitative Disclosures About Market Risk — Foreign Exchange Risk” and Note 6 “Derivative Financial Instruments” to our Consolidated Financial Statements in Item 8 of this report.
     As of December 31, 2010, the total unrecognized tax benefit related to uncertain tax positions was $45.9 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.
     We had no other purchase obligations for major rig upgrades or any other significant obligations at December 31, 2010, except for those related to our direct rig operations, which arise during the normal course of business. However, in January 2011, we entered into a turnkey contract with Hyundai for the construction of a second dynamically positioned, ultra-deepwater drillship with delivery scheduled for the fourth quarter of 2013. See Note 18 “Subsequent Event” to our Consolidated Financial Statements in Item 8 of this report.

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Other Commercial Commitments — Letters of Credit.
     We were contingently liable as of December 31, 2010 in the amount of $101.6 million under certain performance, bid, supersedeas and custom bonds and letters of credit, including $21.9 million in letters of credit issued under our Credit Facility. Three of these bonds totaling $47.7 million were purchased from a related party after obtaining competitive quotes. Agreements relating to approximately $47.7 million of performance bonds can require collateral at any time. As of December 31, 2010 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. Banks have issued letters of credit on our behalf securing certain of these bonds. See Note 12 “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   2011   2012   Thereafter
    (In thousands)
Other Commercial Commitments
                                
Customs bonds
   $ 5,559     $ 5,559     $ —     $ —  
Performance bonds
     68,159       50,866       17,293       —  
Other
     27,869       27,869       —       —  
     
Total obligations
   $ 101,587     $ 84,294     $ 17,293     $ —  
     
Credit Ratings.
     Our current credit rating is Baa1 for Moody’s Investors Services and A- for Standard & Poor’s. Although our long-term ratings continue at investment grade levels, lower ratings would result in higher rates for borrowings under our Credit Facility and could also result in higher interest rates on future debt issuances.
Capital Expenditures.
     During 2010, we spent approximately $434 million on capital expenditures, including approximately $80 million towards the commissioning and outfitting for service of the Ocean Courage and Ocean Valor and approximately $354 million relating to our ongoing rig equipment replacement and enhancement programs, equipment required for our long-term international contracts and other corporate requirements.
     We have budgeted approximately $320 million on capital expenditures for 2011 associated with our ongoing rig equipment replacement and enhancement programs and other corporate requirements. In addition, as of the date of this report, we have spent approximately $310 million in 2011 towards the construction of two new, ultra-deepwater drillships with delivery scheduled for late in the second and fourth quarters of 2013. We expect to finance our 2011 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, 2010 and 2009, we had no off-balance sheet debt or other arrangements.

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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, 2010 compared to 2009.
Net Cash Provided by Operating Activities.
                         
    Year Ended December 31,    
    2010   2009   Change
    (In thousands)
Net income
   $ 955,457     $ 1,376,219     $ (420,762 )
Net changes in operating assets and liabilities
     (3,119 )     (286,069 )     282,950  
Proceeds from settlement of FOREX contracts designated as accounting hedges
     3,307       8,895       (5,588 )
(Gain) on sale and disposition of assets
     (34,714 )     (7,902 )     (26,812 )
(Gain) loss on sale of marketable securities
     7       (619 )     626  
(Gain) on FOREX contracts
     (3,307 )     (17,751 )     14,444  
Deferred tax provision
     (6,916 )     85,524       (92,440 )
Depreciation and other non-cash items, net
     371,603       358,517       13,086  
     
 
   $ 1,282,318     $ 1,516,814     $ (234,496 )
     
     Our cash flows from operations in 2010 decreased $234.5 million compared to 2009. This decrease is primarily due to lower earnings resulting from an aggregate reduction in average utilization of and dayrates earned by our drilling fleet, increased mobilization costs, and the effect of lower deferred mobilization fees. The decrease in operating cash flows for the 2010 period was partially offset by a decrease in net cash required to satisfy working capital requirements in 2010 compared to 2009.
     We used $283.0 million less cash to satisfy working capital needs during 2010 primarily due to a decrease in our outstanding accounts receivable balances and an increase in accounts payable at December 31, 2010 compared to the prior year. Trade and other receivables generated cash of $143.1 million in 2010 compared to using cash of $219.9 million in 2009 and accounts payable and accrued liabilities generated cash of $33.3 million in 2010 compared to using cash of $26.7 million in 2009. During 2010, we made U.S. federal income tax payments of $427.5 million compared to $252.4 million in 2009. We paid foreign income taxes, net of refunds, of $128.5 million and $176.2 million during 2010 and 2009, respectively.
Net Cash Used in Investing Activities.
                         
    Year Ended December 31,    
    2010   2009   Change
    (In thousands)
Purchase of marketable securities
   $ (5,660,518 )   $ (4,473,575 )   $ (1,186,943 )
Proceeds from sale of marketable securities
     5,450,230       4,473,891       976,339  
Capital expenditures (including rig acquisitions)
     (434,262 )     (1,362,468 )     928,206  
Proceeds from disposition of assets
     188,066       40,462       147,604  
Cost to settle FOREX contracts not designated as accounting hedges
     —       (28,445 )     28,445  
     
 
   $ (456,484 )   $ (1,350,135 )   $ 893,651  
     
     Our investing activities used $456.5 million in 2010 compared to $1.4 billion in 2009. During 2010, we purchased marketable securities, net of sales, of $210.3 million compared to net sales of $0.3 million during 2009. 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 2010, we spent $434.3 million related to ongoing capital maintenance programs, including rig modifications to meet contractual requirements and final commissioning and initial outfitting costs of the Ocean Courage and Ocean Valor, compared to $1.4 billion in 2009. Capital expenditures in 2009 included $1.0 billion for the purchase of two newbuild, dynamically positioned, semisubmersible drilling rigs, the Ocean Valor and Ocean Courage. See “— Liquidity and Capital Requirements — Capital Expenditures.”

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     On July 7, 2010, we completed the sale of the Ocean Shield for net proceeds of $185.3 million. During 2009, we completed the sale of the Ocean Tower and received net proceeds of $35.4 million.
     Prior to May 2009, we entered into FOREX contracts as economic hedges of our foreign currency requirements; however, we did not designate these contracts as accounting hedges. During the latter part of 2008 and during 2009, the strengthening U.S. dollar (or, conversely, the weakening foreign currency) negatively impacted these expiring FOREX contracts and resulted in our having to pay a net $28.5 million on settlement of these contracts during 2009. During 2010, all of our FOREX contracts were designated as accounting hedges, the settlement of which was recognized as a component of “Net Cash Provided by Operating Activities.”
Net Cash Used in Financing Activities.
                         
    Year Ended December 31,    
    2010   2009   Change
    (In thousands)
Redemption of zero coupon debentures
   $ (4,238 )   $ —     $ (4,238 )
Issuance of senior notes
     —       995,975       (995,975 )
Payment of dividends
     (733,661 )     (1,115,211 )     381,550  
Other
     41       (7,078 )     7,119  
     
 
   $ (737,858 )   $ (126,314 )   $ (611,544 )
     
     On May 28, 2010, we redeemed the then outstanding $4.2 million accreted value, or $6.0 million in aggregate principal amount at maturity, of our Zero Coupon Convertible Debentures due 2020, or Zero Coupon Debentures, at a redemption price of $706.28 per $1,000 principal amount at maturity for cash.
     In 2009, we issued two tranches of senior, unsecured debt aggregating $1.0 billion for general corporate purposes and paid $8.7 million in fees related to these issuances.
     During 2010, we paid cash dividends totaling $733.7 million, consisting of aggregate regular cash dividends totaling $69.5 million, or $0.125 per share of our common stock per quarter, and aggregate special cash dividends totaling $664.2 million, or $1.875 and $1.375 per share of our common stock in the first and second quarters of 2010, respectively, and $0.75 per share of our common stock in each of the last two quarters of 2010. During 2009, we paid cash dividends totaling $1.1 billion, which consisted of aggregate regular cash dividends of $69.5 million, or $0.125 per share of our common stock per quarter, and aggregate special cash dividends of $1.0 billion, or $1.875 per share of our common stock per quarter.
     On February 2, 2011, we declared a regular cash dividend and a special cash dividend of $0.125 and $0.75, respectively, per share of our common stock. Both the quarterly and special cash dividends are payable on February 28, 2011 to stockholders of record on February 11, 2011.
     Our Board of Directors has adopted a policy to consider paying special cash dividends, in amounts to be determined, on a quarterly basis. 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, 2010 and 2009.
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 Brazil, the U.K., Australia, Angola and Mexico. 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.

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     To the extent that we are not able to cover our local currency operating costs with customer payments in the local currency, we also utilize FOREX contracts to reduce our currency exchange risk. Our FOREX contracts may obligate us to exchange predetermined amounts of specified foreign currencies at specified foreign exchange rates on specific dates or to net settle the spread between the contracted foreign currency exchange rate and the spot rate on the contract settlement date, which, for most of our contracts, is the average spot rate for the contract period.
     We record currency transaction gains and losses as “Foreign currency transaction gain (loss)” in our Consolidated Statements of Operations. Gains and losses arising from the settlement of our FOREX contracts that have been designated as cash flow hedges are reported as a component of “Contract drilling” expense in our Consolidated Statements of Operations.
Forward-Looking Statements
     We or our representatives may, from time to time, either in this report, in periodic press releases or otherwise, 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. In addition, any statement concerning future financial performance (including future revenues, earnings or growth rates), ongoing business strategies or prospects, and possible actions taken by or against us, which may be provided by management, are also forward-looking statements as so defined. 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;
 
  •   future uses of and requirements for financial resources;
 
  •   interest rate and foreign exchange risk;
 
  •   future contractual obligations;
 
  •   future operations outside the United States including, without limitation, our operations in Mexico, Egypt and Brazil;
 
  •   effects of the Macondo well blowout, including, without limitation, the impact of the moratorium and its aftermath on drilling in the U.S. Gulf of Mexico, related delays in permitting activities and related regulations and market developments;
 
  •   business strategy;
 
  •   growth opportunities;
 
  •   competitive position;
 
  •   expected financial position;
 
  •   future cash flows and contract backlog;
 
  •   future regular or special dividends;
 
  •   financing plans;
 
  •   market outlook;
 
  •   tax planning;
 
  •   debt levels, including impacts of the financial crisis and restrictions in the credit market;
 
  •   budgets for capital and other expenditures;
 
  •   our customer’s termination of the drilling contract for the Ocean Monarch and the related litigation;
 
  •   timing and duration of required regulatory inspections for our drilling rigs;
 
  •   timing and cost of completion of rig upgrades and other capital projects;
 
  •   delivery dates and drilling contracts related to rig conversion or upgrade projects, construction projects or rig acquisitions;
 
  •   plans and objectives of management;
 
  •   idling drilling rigs or reactivating stacked rigs;
 
  •   asset impairment evaluations;
 
  •   performance of contracts;
 
  •   outcomes of legal proceedings;
 
  •   compliance with applicable laws; and
 
  •   adequacy of insurance or indemnification.

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     These types of statements are based on current expectations about future events and inherently are subject to a variety of assumptions, risks and uncertainties, many of which are beyond our control, 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:
  •   those described under “Risk Factors” in Item 1A;
 
  •   general economic and business conditions, including the extent and duration of the recent financial crisis and restrictions in the credit market, the worldwide economic downturn and recession;
 
  •   worldwide demand for oil and natural gas;
 
  •   changes in foreign and domestic oil and gas exploration, development and production activity;
 
  •   oil and natural gas price fluctuations and related market expectations;
 
  •   the ability of the Organization of Petroleum Exporting Countries, commonly called 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;
 
  •   our inability to obtain contracts for our rigs that do not have contracts;
 
  •   the cancellation of contracts included in our reported contract backlog;
 
  •   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;
 
  •   the risk of physical damage to rigs and equipment caused by named windstorms in the U.S. Gulf of Mexico;
 
  •   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 ability of customers and suppliers to meet their obligations to us and our subsidiaries;
 
  •   the risk that a letter of intent 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 including, without limitation, regulations pertaining to climate change, carbon emissions or energy use;
 
  •   compliance with environmental laws and regulations;
 
  •   potential changes in accounting policies by the Financial Accounting Standards Board, the Securities and Exchange Commission, or SEC, or regulatory agencies for our industry which may cause us to revise our financial accounting and/or disclosures in the future, and which may change the way analysts measure our business or financial performance;
 
  •   development and exploitation of alternative fuels;
 
  •   customer preferences;
 
  •   effects of litigation, tax audits and contingencies and the impact of compliance with judicial rulings and jury verdicts;
 
  •   cost, availability and adequacy of insurance;
 
  •   invalidity of assumptions used in the design of our controls and procedures;
 
  •   the results of financing efforts;
 
  •   the risk that future regular or special dividends may not be declared;

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  •   adequacy of our sources of liquidity;
 
  •   risks resulting from our indebtedness;
 
  •   public health threats;
 
  •   negative publicity;
 
  •   impairments of assets;
 
  •   the availability of qualified personnel to operate and service our drilling rigs; and
 
  •   various other matters, many of which are beyond our control.
     The risks and uncertainties included here are not exhaustive. Other sections of this report and our other filings with the SEC include additional factors that could adversely affect our business, results of operations and financial performance. Given these risks and uncertainties, investors should not place undue reliance on forward-looking statements. Forward-looking statements included in this report speak only as of the date of this report. We expressly disclaim any obligation or undertaking to release publicly any updates or revisions to any forward-looking statement to reflect any change in our expectations or beliefs with regard to the statement or any change in events, conditions or circumstances on which any forward-looking statement is based.

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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, 2010 and 2009, 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, 2010 and 2009, due to instantaneous parallel shifts in the yield curve of 100 basis points, with all other variables held constant.
     The interest rates on certain types of assets and liabilities may fluctuate in advance of changes in market interest rates, while interest rates on other types may lag behind changes in market rates. Accordingly, the analysis may not be indicative of, is not intended to provide, and does not provide a precise forecast of the effect of changes in market interest rates on our earnings or stockholders’ equity. Further, the computations do not contemplate any actions we could undertake in response to changes in interest rates.
     Loans under our $285 million syndicated, senior unsecured revolving Credit Facility bear interest at our option at a rate per annum equal to (i) the higher of the prime rate or the federal funds rate plus 0.5% or (ii) LIBOR plus an applicable margin, varying from 0.20% to 0.525%, based on our current credit ratings. As of December 31, 2010 and 2009, there were no loans outstanding under the Credit Facility (however, as of December 31, 2010 and 2009, $21.9 million and $63.3 million, respectively, in letters of credit were issued and outstanding under the Credit Facility).
     Our long-term debt, as of December 31, 2010 and 2009, 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 $117.0 million and $121.3 million as of December 31, 2010 and 2009, respectively. A 100-basis point decrease would result in an increase in market value of $135.5 million and $136.2 million as of December 31, 2010 and 2009, respectively.

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Foreign Exchange Risk
     Foreign exchange rate risk arises from the possibility that changes in foreign currency exchange rates will impact the value of financial instruments. It is customary for us to enter into FOREX contracts in the normal course of business. These contracts generally require us to net settle the spread between the contracted foreign currency exchange rate and the spot rate on the contract settlement date, which for certain contracts is the average spot rate for the contract period. As of December 31, 2010, we had FOREX contracts outstanding in the aggregate notional amount of $140.3 million, consisting of $35.1 million in Australian dollars, $81.2 million in Brazilian reais, $9.2 million in British pounds sterling, $3.0 million in Mexican pesos and $11.8 million in Norwegian kroner. These contracts generally settle monthly through July 2011. At December 31, 2010, we have presented the fair value of our outstanding FOREX contracts as a current asset of $4.3 million in “Prepaid expenses and other current assets” and a current liability of $(0.1) million in “Accrued liabilities” in our Consolidated Balance Sheets included in Item 8 of this report. We have presented the fair value of our outstanding FOREX contracts at December 31, 2009 as a current asset of $2.6 million in “Prepaid expenses and other current assets” and a current liability of $(0.2) million in “Accrued liabilities” in our Consolidated Balance Sheets included in Item 8 of this report.
     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,
    2010   2009   2010   2009
    (In thousands)
Interest rate:
                                
Marketable securities
   $ 612,300  (a)   $ 400,900  (a)   $ (1,100 ) (c)   $ (300 ) (c)
Long-term debt
     1,585,100  (b)     1,546,900  (b)     —       —  
 
                                
Foreign Exchange:
                                
Forward exchange contracts — receivable positions
     4,300  (d)     2,600  (d)     (23,500 ) (e)     (17,600 ) (e)
Forward exchange contracts — liability positions
     (100 ) (d)     (200 ) (d)     (2,100 ) (e)     (3,700 ) (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, 2010 and 2009.
 
(b)   The fair values of our 4.875% Senior Notes due July 1, 2015, 5.15% Senior Notes due September 1, 2014, 5.875% Senior Notes due May 1, 2019 and 5.70% Senior Notes due October 15, 2039 are based on the quoted market prices on December 31, 2010.
 
(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, 2010 and 2009.
 
(d)   The fair value of our foreign currency forward exchange contracts is based on both quoted market prices and valuations derived from pricing models on December 31, 2010 and 2009.
 
(e)   The calculation of estimated foreign exchange risk assumes an instantaneous 20% decrease in the foreign currency exchange rates versus the U.S. dollar from their values at December 31, 2010 and 2009, with all other variables held constant.

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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, 2010 and 2009, 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, 2010. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the 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 Diamond Offshore Drilling, Inc. and subsidiaries as of December 31, 2010 and 2009, and the results of their operations and its cash flows for each of the three years in the period ended December 31, 2010, in conformity with accounting principles generally accepted in the United States of America.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of December 31, 2010, 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 23, 2011 expressed an unqualified opinion on the Company’s internal control over financial reporting.
/s/ Deloitte & Touche LLP
Houston, Texas
February 23, 2011

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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, 2010, 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 the 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, 2010, 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, 2010 of the Company and our report dated February 23, 2011 expressed an unqualified opinion on those financial statements.
/s/ Deloitte & Touche LLP
Houston, Texas
February 23, 2011

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DIAMOND OFFSHORE DRILLING, INC.
AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(In thousands, except share and per share data)
                 
    December 31,  
    2010     2009  
ASSETS
                
Current assets:
                
Cash and cash equivalents
   $ 464,393     $ 376,417  
Marketable securities
     612,346       400,853  
Accounts receivable, net of allowance for doubtful accounts
     609,606       791,023  
Prepaid expenses and other current assets
     177,153       155,077  
 
            
Total current assets
     1,863,498       1,723,370  
Drilling and other property and equipment, net of accumulated depreciation
     4,283,792       4,432,052  
Long-term receivable
     35,361       —  
Other assets
     544,333       108,839  
 
            
Total assets
   $ 6,726,984     $ 6,264,261  
 
            
 
                
LIABILITIES AND STOCKHOLDERS’ EQUITY
                
Current liabilities:
                
Accounts payable
   $ 99,236     $ 75,015  
Accrued liabilities
     469,190       301,871  
Taxes payable
     57,862       32,410  
Current portion of long-term debt
     —       4,179  
 
            
Total current liabilities
     626,288       413,475  
Long-term debt
     1,495,593       1,495,375  
Deferred tax liability
     542,258       546,024  
Other liabilities
     201,133       178,745  
 
            
Total liabilities
     2,865,272       2,633,619  
 
            
 
                
Commitments and contingencies (Note 11)
                
 
                
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; 143,943,624 shares issued and 139,026,824 shares outstanding at December 31, 2010; 143,942,978 shares issued and 139,026,178 shares outstanding at December 31, 2009)
     1,439       1,439  
Additional paid-in capital
     1,972,550       1,965,513  
Retained earnings
     1,998,995       1,776,498  
Accumulated other comprehensive gains
     3,141       1,605  
Treasury stock, at cost (4,916,800 shares at December 31, 2010 and 2009)
     (114,413 )     (114,413 )
 
            
Total stockholders’ equity
     3,861,712       3,630,642  
 
            
Total liabilities and stockholders’ equity
   $ 6,726,984     $ 6,264,261  
 
            
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,  
    2010     2009     2008  
Revenues:
                        
Contract drilling
   $ 3,229,736     $ 3,536,579     $ 3,476,417  
Revenues related to reimbursable expenses
     93,238       94,705       67,640  
 
                  
Total revenues
     3,322,974       3,631,284       3,544,057  
 
                  
 
                        
Operating expenses:
                        
Contract drilling, excluding depreciation
     1,391,086       1,223,771       1,185,007  
Reimbursable expenses
     91,240       93,097       65,895  
Depreciation
     393,177       346,446       287,417  
General and administrative
     66,600       62,913       60,142  
Bad debt (recovery) expense
     (9,789 )     9,746       31,952  
Casualty loss
     —       —       6,281  
Gain on disposition of assets
     (34,714 )     (7,902 )     (2,831 )
 
                  
Total operating expenses
     1,897,600       1,728,071       1,633,863  
 
                  
 
                        
Operating income
     1,425,374       1,903,213       1,910,194  
 
                        
Other income (expense):
                        
Interest income
     2,909       4,497       11,744  
Interest expense
     (90,698 )     (49,610 )     (10,096 )
Foreign currency transaction gain (loss)
     1,369       11,483       (65,566 )
Other, net
     (2,938 )     (1,152 )     770  
 
                  
Income before income tax expense
     1,336,016       1,868,431       1,847,046  
 
                        
Income tax expense
     (380,559 )     (492,212 )     (536,499 )
 
                  
 
                        
Net income
   $ 955,457     $ 1,376,219     $ 1,310,547  
 
                  
 
                        
Earnings per share:
                        
Basic
   $ 6.87     $ 9.90     $ 9.43  
 
                  
Diluted
   $ 6.87     $ 9.89     $ 9.42  
 
                  
 
                        
Weighted-average shares outstanding:
                        
Shares of common stock
     139,026       139,007       138,959  
Dilutive potential shares of common stock
     44       90       114  
 
                  
Total weighted-average shares outstanding assuming dilution
     139,070       139,097       139,073  
 
                  
 
                        
Cash dividends declared per share of common stock
   $ 5.25     $ 8.00     $ 6.125  
 
                  
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, 2008
     143,787,206     $ 1,438     $ 1,943,190     $ 1,060,158     $ 15       4,916,800     $ (114,413 )   $ 2,890,388  
     
Net income
     —       —       —       1,310,547       —       —       —       1,310,547  
Dividends to stockholders ($6.125 per share)
     —       —       —       (851,128 )     —       —       —       (851,128 )
Anti-dilution adjustment paid to stock plan participants ($5.625 per share)
     —       —       —       (2,669 )     —       —       —       (2,669 )
Conversion of long-term debt
     71,574       1       3,532       —       —       —       —       3,533  
Reversal of deferred tax liability related to imputed interest on converted debentures
     —       —       532       —       —       —       —       532  
Stock options exercised
     59,070       —       2,002       —       —       —       —       2,002  
Stock-based compensation, net of tax
     —       —       7,785       —       —       —       —       7,785  
Net gain on investments
     —       —       —       —       495       —       —       495  
     
December 31, 2008
     143,917,850       1,439       1,957,041       1,516,908       510       4,916,800       (114,413 )     3,361,485  
     
Net income
     —       —       —       1,376,219       —       —       —       1,376,219  
Dividends to stockholders ($8.00 per share)
     —       —       —       (1,112,058 )     —       —       —       (1,112,058 )
Anti-dilution adjustment paid to stock plan participants ($7.50 per share)
     —       —       —       (4,571 )     —       —       —       (4,571 )
Stock options exercised
     25,128       —       1,069       —       —       —       —       1,069  
Stock-based compensation, net of tax
     —       —       7,403       —       —       —       —       7,403  
Net gain on foreign currency forward exchange contracts
     —       —       —       —       1,563       —       —       1,563  
Net loss on investments
     —       —       —       —       (468 )     —       —       (468 )
     
December 31, 2009
     143,942,978       1,439       1,965,513       1,776,498       1,605       4,916,800       (114,413 )     3,630,642  
     
Net income
     —       —       —       955,457       —       —       —       955,457  
Dividends to stockholders ($5.25 per share)
     —       —       —       (729,888 )     —       —       —       (729,888 )
Anti-dilution adjustment paid to stock plan participants ($4.75 per share)
     —       —       —       (3,072 )     —       —       —       (3,072 )
Stock options exercised
     646       —       31       —       —       —       —       31  
Stock-based compensation, net of tax
     —       —       7,006       —       —       —       —       7,006  
Net gain on foreign currency forward exchange contracts
     —       —       —       —       1,170       —       —       1,170  
Net gain on investments
     —       —       —       —       366       —       —       366  
     
December 31, 2010
     143,943,624     $ 1,439     $ 1,972,550     $ 1,998,995     $ 3,141       4,916,800     $ (114,413 )   $ 3,861,712  
     
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,  
    2010     2009     2008  
Net income
   $ 955,457     $ 1,376,219     $ 1,310,547  
 
                        
Other comprehensive gains, net of tax:
                        
Foreign currency forward exchange contracts:
                        
Unrealized holding gain
     2,334       6,395       —  
Reclassification adjustment for gain included in net income
     (1,164 )     (4,832 )     —  
 
                        
Investments in marketable securities:
                        
Unrealized holding gain on investments
     343       41       507  
Reclassification adjustment for gain (loss) included in net income
     23       (509 )     (12 )
 
                  
Total other comprehensive gain
     1,536       1,095       495  
 
                  
Comprehensive income
   $ 956,993     $ 1,377,314     $ 1,311,042  
 
                  
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,
    2010   2009   2008
     
Operating activities:
                        
Net income
   $ 955,457     $ 1,376,219     $ 1,310,547  
Adjustments to reconcile net income to net cash
                        
provided by operating activities:
                        
Depreciation
     393,177       346,446       287,417  
Gain on disposition of assets
     (34,714 )     (7,902 )     (2,831 )
Casualty loss
     —       —       6,281  
Loss (gain) on sale of marketable securities, net
     7       (619 )     (1,282 )
(Gain) loss on foreign currency forward exchange contracts
     (3,307 )     (17,751 )     54,010  
Deferred tax provision
     (6,916 )     85,524       61,404  
Accretion of discounts on marketable securities
     (648 )     (679 )     (2,258 )
Amortization/write-off of debt issuance costs
     882       672       529  
Amortization of debt discounts
     277       299       242  
Stock-based compensation expense
     5,928       6,440       6,293  
Excess tax benefits from stock-based payment arrangements
     —       (99 )     (1,392 )
Deferred income, net
     17,777       37,405       4,610  
Deferred expenses, net
     (59,208 )     (46,640 )     (20,556 )
Other assets, noncurrent
     2,477       (2,775 )     (6,240 )
Other liabilities, noncurrent
     10,941       17,448       10,235  
Proceeds from settlement of foreign currency forward exchange contracts designated as accounting hedges
     3,307       8,895       —  
Changes in operating assets and liabilities:
                        
Accounts receivable
     143,096       (219,867 )     (42,451 )
Prepaid expenses and other current assets
     1,519       3,503       1,318  
Accounts payable and accrued liabilities
     33,326       (26,698 )     (27,150 )
Taxes payable
     (181,060 )     (43,007 )     (19,038 )
     
Net cash provided by operating activities
     1,282,318       1,516,814       1,619,688  
     
Investing activities:
                        
Capital expenditures
     (434,262 )     (412,444 )     (666,857 )
Rig acquisitions
     —       (950,024 )     —  
Proceeds from disposition of assets, net of disposal costs
     188,066       40,462       5,881  
Proceeds from sale and maturities of marketable securities
     5,450,230       4,473,891       1,493,803  
Purchase of marketable securities
     (5,660,518 )     (4,473,575 )     (1,888,792 )
Cost to settle foreign currency forward exchange contracts not designated as accounting hedges
     —       (28,445 )     (16,800 )
     
Net cash used in investing activities
     (456,484 )     (1,350,135 )     (1,072,765 )
     
Financing activities:
                        
Redemption of zero coupon debentures
     (4,238 )     —       —  
Issuance of 5.875% senior unsecured notes
     —       499,255       —  
Issuance of 5.70% senior unsecured notes
     —       496,720       —  
Debt issuance costs and arrangement fees
     (98 )     (8,671 )     —  
Payment of dividends
     (733,661 )     (1,115,211 )     (852,153 )
Proceeds from stock options exercised
     139       1,494       2,002  
Excess tax benefits from share-based payment arrangements
     —       99       1,392  
Redemption of remaining 1.5% debentures
     —       —       (73 )
     
Net cash used in financing activities
     (737,858 )     (126,314 )     (848,832 )
     
Net change in cash and cash equivalents
     87,976       40,365       (301,909 )
Cash and cash equivalents, beginning of year
     376,417       336,052       637,961  
     
Cash and cash equivalents, end of year
   $ 464,393     $ 376,417     $ 336,052  
     
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 46 offshore rigs consisting of 32 semisubmersibles, 13 jack-ups and one drillship. In December 2010 and January 2011, we entered into separate turnkey contracts for the construction of two sister ultra-deepwater drillships with delivery scheduled for late in the second and fourth quarters of 2013. See Note 18. 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 17, 2011, Loews Corporation, or Loews, owned 50.4% of the outstanding shares of our common stock.
Principles of Consolidation
     Our consolidated financial statements include the accounts of Diamond Offshore Drilling, Inc. and our subsidiaries after elimination of intercompany transactions and balances.
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.
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 gain (loss)” 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).”
     The effect of exchange rate changes on cash balances held in foreign currencies was not material for the years ended December 31, 2010, 2009 and 2008.

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Provision for Bad Debts
     We record a provision for bad debts on a case-by-case basis when facts and circumstances indicate that a customer receivable may not be collectible. In establishing these reserves, we consider historical and other factors that predict collectability, including write-offs, recoveries and the monitoring of credit quality. Such provision is reported as a component of “Operating expense” in our Consolidated Statements of Operations. See Note 2.
Derivative Financial Instruments
     Our derivative financial instruments consist of foreign currency forward exchange, or FOREX, contracts which we may designate as cash flow hedges. In accordance with GAAP, each derivative contract is 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 and is designated as an accounting hedge, the gains and losses are reflected in income in the same period as offsetting gains and losses on the qualifying hedged positions.
     Realized gains or losses upon settlement of derivative contracts not designated as cash flow hedges are reported as “Foreign currency transaction gain (loss)” in our Consolidated Statements of Operations. See Notes 6 and 7.
Drilling and Other Property and Equipment
     Our drilling and other property and equipment are carried at cost. We charge maintenance and routine repairs to income currently while replacements and betterments, which meet certain criteria, are capitalized. Costs incurred for major rig upgrades are accumulated in construction work-in-progress, with no depreciation recorded on the additions, until the month the upgrade is completed and the rig is placed in service. Upon retirement or sale of a rig, the cost and related accumulated depreciation are removed from the respective accounts and any gains or losses are included in our results of operations. Depreciation is recognized up to applicable salvage values by applying the straight-line method over the remaining estimated useful lives from the year the asset is placed in service. Drilling rigs and equipment are depreciated over their estimated useful lives ranging from three to 30 years.
Capitalized Interest
     We capitalize interest cost for the construction and upgrade of qualifying assets. For the year ended December 31, 2008 we capitalized interest on qualifying expenditures related to the major upgrade of one of our existing drilling rigs and the construction of two jack-up rigs through the date of each project’s completion. All qualifying construction and upgrade projects were completed at December 31, 2008.
     A reconciliation of our total interest cost to “Interest expense” as reported in our Consolidated Statements of Operations is as follows:
         
    For the Year Ended  
    December 31, 2008  
    (In thousands)  
Total interest cost including amortization of debt issuance costs
   $ 26,966  
Capitalized interest
     (16,870 )
 
      
Total interest expense as reported
   $ 10,096  
 
      
     We did not capitalize any interest cost during the years ended December 31, 2010 and 2009 as there were no qualifying expenditures during the period.
Asset Retirement Obligations
     At December 31, 2010 and 2009, we had no asset retirement obligations.

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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 (such as cold-stacking a rig or excess spending over budget on a new-build or major rig upgrade). We utilize a probability-weighted cash flow analysis in testing an asset for potential impairment. Our assumptions and estimates underlying this analysis may 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;
 
  •   the estimated maintenance, inspection or other costs associated with a rig returning to work;
 
  •   salvage value for each rig; and
 
  •   estimated proceeds that may be received on disposition of the rig.
Based on these assumptions and estimates, we develop a matrix by assigning probabilities to various combinations of assumed utilization rates and dayrates.
     2010. As of December 31, 2010, our cold-stacked fleet consisted of one independent-leg, cantilevered and three mat-supported jack-up rigs (all in the U.S. Gulf of Mexico, or GOM) and three intermediate semisubmersible rigs (two in the GOM and one in Malaysia). We performed an impairment review for each of these rigs using the methodology described above. Based on our analyses, we concluded that these seven rigs were not subject to impairment at December 31, 2010.
     2009. As of December 31, 2009, we had cold-stacked our three mat-supported jack-up rigs and were in the process of cold-stacking an intermediate semisubmersible drilling rig in Malaysia. We performed an impairment review for each of these rigs using the methodology described above. Based on our analyses, we concluded that these four rigs were not subject to impairment at December 31, 2009.
     2008. As of December 31, 2008, all of our drilling rigs were either under contract, in shipyards for surveys or contract modifications or, as in the case of the upgraded Ocean Monarch, mobilizing to the U.S., except for two jack-up rigs. One of these idle units, the Ocean Tower, was damaged during Hurricane Ike in September 2008 (see Note 15) and taken out of service. The rig was subsequently sold in October 2009 for a net gain of $6.7 million. At December 31, 2008, the second of our idle rigs was ready stacked while waiting to begin drilling operations in early January 2009. Consequently, we determined that an impairment test of our drilling equipment was not needed as all of our drilling units were being marketed at the time, and we did not have any cold-stacked rigs at December 31, 2008.
     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 7.
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.
Income Taxes
     We account for income taxes in accordance with accounting standards that require 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

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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.
     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 13.
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 2010, 2009 or 2008.
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, 2010, 2009 and 2008 includes net income (loss) and unrealized holding gains and losses on marketable securities and financial derivatives designated as cash flow accounting hedges. See Note 10.
Foreign Currency
     Our functional currency is the U.S. dollar. Foreign currency transaction gains and losses, including gains and losses from the settlement of FOREX contracts not designated as accounting hedges, are reported as “Foreign currency transaction gain (loss)” in our Consolidated Statements of Operations. For the years ended December 31, 2010, 2009 and 2008, we recognized net foreign currency gains (losses) of $1.4 million, $11.5 million and $(65.6) million, respectively. See Note 6.
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 we estimate to be benefited from the mobilization activity). Straight line amortization of mobilization revenues and related costs over the initial term of the related drilling contracts (which generally range from two to 60 months) is consistent with the timing of net cash flows generated from the actual drilling services performed. Absent a contract, mobilization costs are recognized as incurred.
     From time to time, we may receive fees from our customers for capital improvements to our rigs (either lump-sum or dayrate). We defer such fees received in “Accrued liabilities” and “Other liabilities” in our Consolidated Balance Sheets and recognize these fees into income on a straight-line basis over the period of the related drilling contract. We capitalize the costs of such capital improvements and depreciate them over the estimated useful life of the asset.
     We record reimbursements received for the purchase of supplies, equipment, personnel services and other services provided at the request of our customers in accordance with a contract or agreement, for the gross amount billed to the customer, as “Revenues related to reimbursable expenses” in our Consolidated Statements of Operations.

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2. Supplemental Financial Information
Consolidated Balance Sheet Information
     Accounts receivable, net of provision for bad debts, consist of the following:
                 
    December 31,
    2010   2009
    (In thousands)
Trade receivables
   $ 633,224     $ 812,180  
Value added tax receivables
     5,003       10,273  
Unbilled third party claims
     45       6,315  
Related party receivables
     538       115  
Other
     2,704       3,838  
     
 
     641,514       832,721  
Allowance for doubtful accounts
     (31,908 )     (41,698 )
     
Total
   $ 609,606     $ 791,023  
     
     During 2008, we recorded a $31.9 million provision for bad debts to reserve the uncollected balance of one of our customers in the United Kingdom, or U.K., that had entered into administration (a U.K. insolvency proceeding similar to U.S. Chapter 11 bankruptcy). In 2009, we recorded a $10.7 million provision for bad debts to reserve a portion of the uncollected balance of receivables related to our operations in Egypt and recovered $0.9 million associated with the reserve for bad debts recorded in 2008. During 2010, we recovered $4.2 million and $5.5 million associated with the reserves for bad debts recorded in 2008 and 2009, respectively. No additional allowances were deemed necessary for the years presented.
     Prepaid expenses and other current assets consist of the following:
                 
    December 31,
    2010   2009
    (In thousands)
Rig spare parts and supplies
   $ 50,288     $ 49,122  
Deferred mobilization costs
     76,868       45,502  
Prepaid insurance
     9,587       11,478  
Deferred tax assets
     9,557       7,235  
Deposits
     827       3,562  
Prepaid taxes
     20,347       27,679  
FOREX contracts
     4,326       2,634  
Other
     5,353       7,865  
     
Total
   $ 177,153     $ 155,077  
     
     Accrued liabilities consist of the following:
                 
    December 31,
    2010   2009
    (In thousands)
Accrued capital project/upgrade costs
   $ 28,947     $ 64,940  
Payroll and benefits
     76,041       69,065  
Deferred revenue
     69,825       46,666  
Rig operating expenses
     81,371       79,965  
Interest payable
     21,219       22,710  
Personal injury and other claims
     11,758       10,018  
Accrued drillship construction installment
     154,427       —  
Other
     25,602       8,507  
     
Total
   $ 469,190     $ 301,871  
     

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Consolidated Statement of Cash Flows Information
     We paid interest totaling $83.5 million, $39.5 million and $25.1 million on long-term debt for the years ended December 31, 2010, 2009 and 2008, respectively. We paid $0.9 million in interest on Internal Revenue Service assessments during the year ended December 31, 2010.
     We paid $128.5 million, $176.2 million and $120.7 million in foreign income taxes, net of foreign tax refunds, during the years ended December 31, 2010, 2009 and 2008, respectively. We paid $427.5 million, $252.4 million and $393.2 million in U.S. federal income taxes during the years ended December 31, 2010, 2009 and 2008, respectively. We paid state income taxes, net of refunds, of $0.1 million and $0.2 million during the years ended December 31, 2010 and 2009, respectively, and received a $0.1 million refund of state income tax during the year ended December 31, 2008.
     Cash payments for capital expenditures for the years ended December 31, 2010, 2009 and 2008 included $64.9 million, $59.4 million and $43.0 million, respectively, of capital expenditures that were accrued but unpaid on December 31, 2009, 2008 and 2007, respectively. Capital expenditures that were accrued but not paid as of December 31, 2010 and 2009 totaled $28.9 million and $64.9 million, respectively. We have included these amounts in “Accrued liabilities” in our Consolidated Balance Sheets at December 31, 2010 and 2009.
     We recorded income tax benefits of $0, $1.0 million and $1.5 million related to the exercise of employee stock options in 2010, 2009 and 2008, respectively.
     During 2008, holders of $33,000 in accreted, or carrying, value through the date of conversion of our Zero Coupon Convertible Debentures due 2020, or Zero Coupon Debentures, elected to convert their outstanding debentures into shares of our common stock. Also during 2008, the holders of $3.5 million in principal amount of our 1.5% Convertible Senior Debentures due 2031, or 1.5% Debentures, elected to convert their outstanding debentures into shares of our common stock. See Note 9.
3. 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 maximum 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.
     Total compensation cost recognized for Stock Plan transactions for the years ended December 31, 2010, 2009 and 2008 was $6.0 million, $6.5 million and $6.3 million, respectively. Tax benefits recognized for the years ended December 31, 2010, 2009 and 2008 related thereto were $2.0 million, $2.1 million and $2.1 million, respectively.
     The fair value of options and SARs granted under the Stock Plan during each of the years ended December 31, 2010, 2009 and 2008 was estimated using the Black Scholes pricing model.
     The following are the weighted average assumptions used in estimating the fair value of our options and SARs:
                         
    Year Ended December 31,
    2010   2009   2008
     
Expected life of stock options/SARs (in years)
     5       5       5  
Expected volatility
     35.99 %     37.24 %     31.96 %
Dividend yield
     .70 %     .62 %     .51 %
Risk free interest rate
     1.88 %     2.17 %     2.66 %
     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.

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     A summary of activity under the Stock Plan as of December 31, 2010 and changes during the year then ended is as follows:
                                 
                    Weighted-   Aggregate
                    Average Remaining   Intrinsic
            Weighted-   Contractual   Value
    Number of   Average   Term   (In
    Awards   Exercise Price   (Years)   Thousands)
     
Awards outstanding at January 1, 2010
     681,743     $ 94.82                  
Granted
     195,750     $ 72.81                  
Exercised
     (1,251 )   $ 54.43                  
Forfeited
     (32,623 )   $ 90.60                  
Expired
     (22,095 )   $ 100.19                  
 
                                
Awards outstanding at December 31, 2010
     821,524     $ 89.66       7.7     $ 1,532  
 
                                
Awards exercisable at December 31, 2010
     460,213     $ 91.73       7.0     $ 1,088  
 
                                
     The weighted-average grant date fair values of awards granted during the years ended December 31, 2010, 2009 and 2008 were $23.62, $28.46 and $33.73, respectively. The total intrinsic value of awards exercised during the years ended December 31, 2010, 2009 and 2008 was $8,000, $1.5 million and $6.3 million, respectively. The total fair value of awards vested during the years ended December 31, 2010, 2009 and 2008 was $6.6 million, $6.6 million and $5.3 million, respectively. As of December 31, 2010 there was $7.4 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 2.73 years.
4. Earnings Per Share
     A reconciliation of the numerators and the denominators of the basic and diluted per-share computations follows:
                         
    Year Ended December 31,
    2010   2009   2008
    (In thousands, except per share data)
Net income — basic (numerator):
   $ 955,457     $ 1,376,219     $ 1,310,547  
Effect of dilutive potential shares
                        
Zero Coupon Debentures
     56       94       32  
1.5% Debentures
     —       —       22  
     
 
                        
Net income including conversions — diluted (numerator):
   $ 955,513     $ 1,376,313     $ 1,310,601  
     
 
                        
Weighted-average shares — basic (denominator):
     139,026       139,007       138,959  
Effect of dilutive potential shares
                        
Zero Coupon Debentures
     21       51       51  
1.5% Debentures
     —       —       19  
Stock options and SARs
     23       39       44  
     
Weighted-average shares including conversions — diluted (denominator):
     139,070       139,097       139,073  
     
Earnings per share:
                        
 
                        
Basic
   $ 6.87     $ 9.90     $ 9.43  
     
Diluted
   $ 6.87     $ 9.89     $ 9.42  
     
     Our computation of diluted earnings per share, or EPS, for the year ended December 31, 2010 excludes stock options representing 11,447 shares of common stock and 584,319 SARs. Our computation of diluted EPS for the year ended December 31, 2009 excludes stock options representing 8,291 shares of common stock and 413,610

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SARs. Our computation of diluted EPS for the year ended December 31, 2008 excludes stock options representing 3,362 shares of common stock and 254,821 SARs.
     The inclusion of such potentially dilutive shares in the computation of diluted EPS for any of the years ended December 31, 2010, 2009 and 2008 would have been antidilutive for the respective period.
5. Marketable Securities
     We report our investments in marketable securities as current assets in our Consolidated Balance Sheets in “Marketable securities,” representing the investment of cash available for current operations.
     Our investments in marketable securities are classified as available for sale and are summarized as follows:
                         
    December 31, 2010
    Amortized   Unrealized   Market
    Cost   Gain (Loss)   Value
    (In thousands)
U.S. Treasury Bills (due within one year)
   $ 599,965     $ 15     $ 599,980  
Corporate bonds
     11,200       560       11,760  
Mortgage-backed securities
     553       53       606  
     
Total
   $ 611,718     $ 628     $ 612,346  
     
                         
    December 31, 2009
    Amortized   Unrealized   Market
    Cost   Gain (Loss)   Value
    (In thousands)
U.S. Treasury Bills (due within one year)
   $ 399,997     $ (1 )   $ 399,996  
Mortgage-backed securities
     792       65       857  
     
Total
   $ 400,789     $ 64     $ 400,853  
     
     Proceeds from maturities and sales of marketable securities and gross realized gains and losses are summarized as follows:
                         
    Year Ended December 31,
    2010   2009   2008
    (In thousands)
Proceeds from maturities
   $ 5,450,000     $ 1,925,000     $ 550,000  
Proceeds from sales
     230       2,548,891       943,803  
Gross realized gains
     —       791       1,291  
Gross realized losses
     (7 )     (172 )     (9 )
6. Derivative Financial Instruments
Foreign Currency Forward Exchange Contracts
     Our international operations expose us to foreign exchange risk associated with our costs payable in foreign currencies for employee compensation, foreign income tax payments and purchases from foreign suppliers. We may utilize FOREX contracts to reduce our foreign exchange risk. Our FOREX contracts may obligate us to exchange predetermined amounts of foreign currencies on specified dates or to net settle the spread between the contracted foreign currency exchange rate and the spot rate on the contract settlement date, which, for most of our contracts, is the average spot rate for the contract period.
     We enter into FOREX contracts when we believe market conditions are favorable to purchase contracts for future settlement with the expectation that such contracts, when settled, will reduce our exposure to foreign currency

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gains/losses on future foreign currency expenditures. The amount and duration of such contracts is based on our monthly forecast of expenditures in the significant currencies in which we do business and for which there is a financial market (i.e., Australian dollars, Brazilian reais, British pounds sterling, Mexican pesos and Norwegian kroner). These forward contracts are derivatives as defined by GAAP.
     In May 2009, we began a hedging strategy and designated certain of our qualifying FOREX contracts as cash flow hedges. These hedges are expected to be highly effective, and therefore, adjustments to record the carrying value of the effective portion of our derivative financial instruments to their fair value are recorded as a component of “Accumulated other comprehensive gains,” or AOCG, in our Consolidated Financial Statements. The effective portion of the cash flow hedge will remain in AOCG until it is reclassified into earnings in the period or periods during which the hedged transaction affects earnings or it is determined that the hedged transaction will not occur. Adjustments to record the carrying value of the ineffective portion of our derivative financial instruments to fair value are recorded as “Foreign currency transaction gain (loss)” in our Consolidated Statements of Operations.
     Realized gains or losses upon settlement of derivative contracts designated as cash flow hedges are reported as a component of “Contract drilling” expense in our Consolidated Statements of Operations to offset the impact of foreign currency fluctuations in our expenditures in local foreign currencies in the countries in which we operate.
     For derivative contracts entered into prior to May 2009, we did not seek hedge accounting treatment under GAAP. Accordingly, prior to May 2009, all adjustments to record the carrying value of our derivative financial instruments at fair value were reported as “Foreign currency transaction gain (loss)” in our Consolidated Statements of Operations.
     During the year ended December 31, 2010, we settled FOREX contracts with an aggregate notional value of approximately $332.5 million, of which the entire aggregate amount was designated as an accounting hedge. During the year ended December 31, 2009, we settled FOREX contracts with an aggregate notional value of approximately $333.4 million, of which an aggregate notional value of $112.8 million was designated as an accounting hedge. During the year ended December 31, 2008, we settled FOREX contracts with an aggregate notional value of approximately $538.8 million, none of which were designated as accounting hedges.
     The following table presents the amounts recognized in our Consolidated Statements of Operations related to our FOREX contracts designated as hedging instruments for the years ended December 31, 2010, 2009 and 2008.
                         
    Amount of Gain Recognized in Income
    For the Years Ended December 31,
Location of Gain (Loss) Recognized in Income   2010   2009   2008
    (In thousands)
Contract drilling expense
   $ 3,307     $ 8,895     $ —  
     The following table presents the amounts recognized in our Consolidated Statements of Operations related to our FOREX contracts not designated as hedging instruments for the years ended December 31, 2010, 2009 and 2008.
                         
    Amount of Gain (Loss) Recognized in Income
    For the Years Ended December 31,
Location of Gain (Loss) Recognized in Income   2010   2009   2008
    (In thousands)
Foreign currency transaction gain (loss)
   $ —     $ 8,856     $ (54,010 )
     The amounts presented in the table above for the years ended December 31, 2009 and 2008 include net unrealized gains aggregating $37.3 million and net unrealized losses of approximately $(37.2) million, respectively, to record the carrying value of our derivative financial instruments to their fair value. There were no gains or losses associated with FOREX contracts not designated as accounting hedges during the year ended December 31, 2010.
     As of December 31, 2010, we had FOREX contracts outstanding in the aggregate notional amount of $140.3 million, consisting of $35.1 million in Australian dollars, $81.2 million in Brazilian reais, $9.2 million in British pounds sterling, $3.0 million in Mexican pesos and $11.8 million in Norwegian kroner. These contracts generally settle monthly through July 2011. As of December 31, 2010, all outstanding derivative contracts had been designated as cash flow hedges.

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     The following table presents the fair values of our derivative financial instruments at December 31, 2010.
                         
    Assets   Liabilities
    Balance Sheet           Balance Sheet    
    Location   Fair Value   Location   Fair Value
        (In       (In
        thousands)       thousands)
Derivatives designated as hedging instruments:
                        
 
   Prepaid expenses                    
 
   and other current                    
FOREX contracts
   assets   $ 4,327     Accrued liabilities   $ (121 )
     The following table presents the fair values of our derivative financial instruments at December 31, 2009.
                         
    Assets   Liabilities
    Balance Sheet           Balance Sheet    
    Location   Fair Value   Location   Fair Value
        (In       (In
        thousands)       thousands)
Derivatives designated as hedging instruments:
                        
 
   Prepaid expenses
 
   and other current                    
FOREX contracts
   assets   $ 2,634     Accrued liabilities   $ (230 )
     The following table presents the amounts recognized in our Consolidated Balance Sheets and Consolidated Statements of Operations related to our FOREX contracts designated as cash flow hedges for the years ended December 31, 2010, 2009 and 2008.
                                                                                 
                                                    Location of Gain    
                                                    Recognized in    
                                                    Income on    
                        Location of                           Derivative   Amount of Gain
                        Gain                           (Ineffective   Recognized in Income
                        Reclassified                           Portion and   on Derivative
Amount of Gain   from AOCG   Amount of Gain   Amount   (Ineffective Portion
Recognized in AOCG on   into Income   Reclassified from   Excluded from   and Amount Excluded
Derivative (Effective   (Effective   AOCG into Income   Effectiveness   from Effectiveness
Portion)   Portion)   (Effective Portion)   Testing)   Testing)
For the years ended       For the years ended           For the years ended
December 31,       December 31,           December 31,
2010   2009   2008       2010   2009   2008           2010   2009   2008
(In thousands)       (In thousands)           (In thousands)
$ 3,591     $ 9,838     $ —    
Contract drilling expense
   $ 1,790     $ 7,434     $ —     Foreign currency transaction gain   $ —     $ —     $ —  
     As of December 31, 2010, the estimated amount of net unrealized gains associated with our FOREX contracts that will be reclassified to earnings during the next twelve months was $4.2 million. The net unrealized gains associated with these derivative financial instruments will be reclassified to contract drilling expense.
7. Financial Instruments and Fair Value Disclosures
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 generally place our excess cash investments in high quality

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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.
     A majority of our investments in debt securities are U.S. government securities with minimal credit risk. However, we are exposed to market risk due to price volatility associated with interest rate fluctuations.
     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. One of our two customers in Brazil, Petróleo Brasileiro S.A. (a Brazilian multinational energy company that is majority-owned by the Brazilian government), accounted for $180.8 million and $115.6 million, or 29% and 14%, of the total consolidated trade accounts receivable balances as of December 31, 2010 and 2009, respectively.
     In general, before working for a customer with whom we have not had a prior business relationship and/or whose financial stability may be uncertain to us, we perform a credit review on that company. Based on that analysis, we may require that the customer present a letter of credit, prepay or provide other credit enhancements. Historically, we have not experienced significant losses on our trade receivables. We record a provision for bad debts on a case-by-case basis when facts and circumstances indicate that a customer receivable may not be collectible. Our provision for bad debts was $31.9 million and $41.7 million at December 31, 2010 and 2009, respectively. See Note 2.
     During 2009, we amended an existing contractual agreement at a customer’s request to provide short-term financial relief. The amended contract obligates the customer to pay us, over the term of the six-well drilling program, an aggregate drilling rate of $560,000 per day, consisting of $75,000 per day payable in accordance with our normal credit terms (due 30 days after receipt of invoice) and the remainder of the contractual dayrate, $485,000 per day, payable through the conveyance of a 27% net profits interest, or NPI, in certain developmental oil-and-gas producing properties. We began receiving payments from the conveyance of the NPI in July 2010. Based on current production payout estimates, we expect to collect $49.6 million of the receivable within the next twelve months. However, payment of such amounts, and the timing of such payments, are contingent upon such production and upon energy sale prices.
     At December 31, 2010, $85.0 million was payable to us from the NPI, of which $49.6 million and $35.4 million are presented as “Accounts receivable” and “Long-term receivable,” respectively, in our Consolidated Balance Sheets. At December 31, 2009, $70.5 million was payable to us from the NPI, all of which was presented as “Accounts receivable” in our Consolidated Balance Sheets. At December 31, 2010 and 2009, we believe that collectability of the amount owed pursuant to the NPI arrangement was reasonably assured.
Fair Values
     The amounts reported in our Consolidated Balance Sheets for cash and cash equivalents, marketable securities, accounts receivable, forward exchange contracts, long term receivables, and accounts payable approximate fair value. Fair values and related carrying values of our debt instruments are shown below.
                                 
    Year Ended December 31,
    2010   2009
    Fair Value   Carrying Value   Fair Value   Carrying Value
            (In millions)        
Zero Coupon Debentures
   $ —     $ —     $ 5.1     $ 4.2  
4.875% Senior Notes
     270.0       249.7       257.5       249.7  
5.15% Senior Notes
     271.1       249.7       263.3       249.7  
5.70% Senior Notes
     493.1       496.8       490.4       496.7  
5.875% Senior Notes
     550.9       499.4       530.6       499.3  
     We have estimated the fair value amounts by using appropriate valuation methodologies and information available to management as of December 31, 2010 and 2009, respectively. Considerable judgment is required in developing these estimates, and accordingly, no assurance can be given that the estimated values are indicative of

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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 residential mortgage-backed securities, available for sale were based on the quoted closing market prices on December 31, 2010 and 2009, 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 FOREX contracts is based on both quoted market prices and valuations derived from pricing models on December 31, 2010 and 2009, respectively.
 
  •   Long-term receivable — The carrying amount approximates fair value based on the nature of the instrument.
 
  •   Long-term debt — The fair value of our 5.70% Senior Notes due 2039, or 5.70% Senior Notes, 5.875% Senior Notes due 2019, or 5.875% Senior Notes, 4.875% Senior Notes due July 1, 2015, or 4.875% Senior Notes, and 5.15% Senior Notes due September 1, 2014, or 5.15% Senior Notes, was based on the quoted closing market price on December 31, 2010 and 2009, respectively, from brokers of these instruments. The fair value of our Zero Coupon Debentures was based on the closing market price of our common stock on December 31, 2009, and the stated conversion rate for these debentures.
     Certain of our assets and liabilities are required to be measured at fair value in accordance with GAAP. Fair value is defined as the exchange price that would be received for an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date. The fair value hierarchy prescribed by GAAP requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. There are three levels of inputs that may be used to measure fair value:
     
Level 1
  Quoted prices for identical instruments in active markets. Level 1 assets include short-term investments such as money market funds and U.S. Treasury Bills. Our Level 1 assets at December 31, 2010 consisted of cash held in money market funds of $442.2 million and investments in U.S. Treasury Bills of $600.0 million. Our Level 1 assets at December 31, 2009 consisted of cash held in money market funds of $337.8 million and investments in U.S. Treasury Bills of $400.0 million.
 
    
Level 2
  Quoted market prices for similar instruments in active markets; quoted prices for identical or similar instruments in markets that are not active; and model-derived valuations in which all significant inputs and significant value drivers are observable in active markets. Level 2 assets and liabilities include residential mortgage-backed securities, corporate bonds purchased in a private placement offering and over-the-counter FOREX contracts. Our residential mortgage-backed securities are valued using a model-derived valuation technique based on the quoted closing market prices received from a financial institution. Our private placement bonds are valued based on the mid-point of the bid/ask spread for the bond obtained from a financial institution and then corroborated with quoted closing market prices from other financial institutions available on Bloomberg and also with market prices of comparable bonds which are publicly traded. FOREX contracts are valued based on quoted market prices, which are derived from observable inputs including current spot and forward rates, less the contract rate multiplied by the notional amount. The inputs used in our valuation are obtained from a Bloomberg curve analysis which uses par coupon swap rates to calculate implied forward rates so that projected floating rate cash flows can be calculated. The valuation techniques underlying the models are widely accepted in the financial services industry and do not involve significant judgment.
 
    
Level 3
  Valuations derived from valuation techniques in which one or more significant inputs or significant value drivers are unobservable. Level 3 assets and liabilities generally include financial instruments whose value is determined using pricing models, discounted cash flow methodologies, or similar techniques, as well as instruments for which the determination of fair value requires significant management judgment or estimation or for which there is a lack of transparency as to the inputs used.

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Assets and liabilities measured at fair value on a recurring basis are summarized below:
                                 
    December 31, 2010
    Fair Value Measurements Using   Assets at Fair
    Level 1   Level 2   Level 3   Value
    (In thousands)
Assets:
                                
Short-term investments
   $ 1,042,224     $ —     $ —     $ 1,042,224  
FOREX contracts
     —       4,327       —       4,327  
Corporate bonds
     —       11,760       —       11,760  
Mortgage-backed securities
     —       606       —       606  
 
          
Total assets
   $ 1,042,224     $ 16,693     $ —     $ 1,058,917  
 
          
 
                                
Liabilities:
                                
FOREX contracts
   $ —     $ (121 )   $ —     $ (121 )
 
          
 
                                 
    December 31, 2009
    Fair Value Measurements Using   Assets at Fair
    Level 1   Level 2   Level 3   Value
    (In thousands)
Assets:
                                
Short-term investments
   $ 737,830     $ —     $ —     $ 737,830  
FOREX contracts
     —       2,634       —       2,634  
Mortgage-backed securities
     —       857       —       857  
 
          
Total assets
   $ 737,830     $ 3,491     $ —     $ 741,321  
 
          
 
                                
Liabilities:
                                
FOREX contracts
   $ —     $ (230 )   $ —     $ (230 )
 
          
8. Drilling and Other Property and Equipment
     Cost and accumulated depreciation of drilling and other property and equipment are summarized as follows:
                 
    December 31,
    2010   2009
    (In thousands)
Drilling rigs and equipment
   $ 7,163,196     $ 6,950,303  
Land and buildings
     56,536       44,640  
Office equipment and other
     44,689       38,203  
 
      
Cost
     7,264,421       7,033,146  
Less accumulated depreciation
     (2,980,629 )     (2,601,094 )
 
      
Drilling and other property and equipment, net
   $ 4,283,792     $ 4,432,052  
 
      
     During 2010, we sold the Ocean Shield and certain equipment for a net purchase price of $185.3 million and recorded a net gain on sale of approximately $32.8 million.

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9. Long-Term Debt
     Long-term debt consists of the following:
                 
    December 31,
    2010   2009
    (In thousands)
5.70% Senior Notes (due 2039)
   $ 496,773     $ 496,730  
5.875% Senior Notes (due 2019)
     499,351       499,292  
4.875% Senior Notes (due 2015)
     249,724       249,671  
5.15% Senior Notes (due 2014)
     249,745       249,682  
Zero Coupon Debentures (due 2020)
     —       4,179  
 
      
 
     1,495,593       1,499,554  
Less: Current maturities
     —       4,179  
 
      
Total
   $ 1,495,593     $ 1,495,375  
 
      
     The aggregate maturities of long-term debt for each of the five years subsequent to December 31, 2010, are as follows:
         
(Dollars in thousands)  
2011
   $ —  
2012
     —  
2013
     —  
2014
     249,745  
2015
     249,724  
Thereafter
     996,124  
 
      
 
     1,495,593  
Less: Current maturities
     —  
 
      
Total
   $ 1,495,593  
 
      
$285 Million Revolving Credit Facility
     In November 2006, we entered into a $285 million syndicated, senior unsecured revolving credit facility, or Credit Facility, for general corporate purposes, including loans and performance or standby letters of credit, that will mature on November 2, 2011.
     Loans under the Credit Facility bear interest at a rate per annum equal to, at our election, either (i) the higher of the prime rate or the federal funds rate plus 0.5% or (ii) the London Interbank Offered Rate, or LIBOR, plus an applicable margin, varying from 0.20% to 0.525%, based on our current credit ratings. Under our Credit Facility, we also pay, based on our current credit ratings, and as applicable, other customary fees, including, but not limited to, a facility fee on the total commitment under the Credit Facility regardless of usage and a utilization fee that applies if the aggregate of all loans outstanding under the Credit Facility equals or exceeds 50% of the total commitment under the facility. Changes in credit ratings could lower or raise the fees that we pay under the Credit Facility.
     The Credit Facility contains customary covenants, including, but not limited to, the maintenance of a ratio of consolidated indebtedness to total capitalization, as defined in the Credit Facility, of not more than 60% at the end of each fiscal quarter and limitations on liens, mergers, consolidations, liquidation and dissolution, changes in lines of business, swap agreements, transactions with affiliates and subsidiary indebtedness.
     Based on our current credit ratings at December 31, 2010, the applicable margin on LIBOR loans would have been 0.24%. As of December 31, 2010, there were no loans outstanding under the Credit Facility. See Note 11 for a discussion of letters of credit issued under the Credit Facility.

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5.70% Senior Notes
     On October 8, 2009, we issued $500.0 million aggregate principal amount of our 5.70% Senior Notes for general corporate purposes. The 5.70% Senior Notes were issued at an offering price of 99.344% of the principal and resulted in net proceeds to us of approximately $496.7 million. We incurred issuance costs of $4.8 million related to this transaction.
     These notes bear interest at 5.70% per year, payable semiannually in arrears on April 15 and October 15 of each year, and mature on October 15, 2039. The 5.70% Senior Notes are unsecured and unsubordinated obligations of Diamond Offshore Drilling, Inc. and rank equal in right of payment to its existing and future unsecured and unsubordinated indebtedness, and will be effectively subordinated to all existing and future obligations of our subsidiaries. We have the right to redeem all or a portion of these 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.
5.875% Senior Notes
     On May 4, 2009, we issued $500.0 million aggregate principal amount of our 5.875% Senior Notes for general corporate purposes. The 5.875% Senior Notes were issued at an offering price of 99.851% of the principal and resulted in net proceeds to us of approximately $499.3 million. We incurred issuance costs of $4.0 million related to this transaction.
     These notes bear interest at 5.875% per year, payable semiannually in arrears on May 1 and November 1 of each year, and mature on May 1, 2019. The 5.875% Senior Notes are unsecured and unsubordinated obligations of Diamond Offshore Drilling, Inc. and rank equal in right of payment to its existing and future unsecured and unsubordinated indebtedness, and will be effectively subordinated to all existing and future obligations of our subsidiaries. We have the right to redeem all or a portion of these 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.
4.875% Senior Notes
     Our 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. Our 4.875% Senior Notes are unsecured and unsubordinated obligations of Diamond Offshore Drilling, Inc. and rank equal in right of payment to its existing and future unsecured and unsubordinated indebtedness, and 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, 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 rank equal in right of payment to its existing and future unsecured and unsubordinated indebtedness, and 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
     On June 6, 2000, we issued Zero Coupon Debentures at a price of $499.60 per $1,000 principal amount at maturity, representing a yield to maturity of 3.50% per year, with a maturity date of June 6, 2020.
     We had 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. On May 28, 2010, we redeemed the then

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outstanding $4.2 million accreted value, or $6.0 million in aggregate principal amount at maturity, of our Zero Coupon Debentures at a redemption price of $706.28 per $1,000 principal amount at maturity for cash. At December 31, 2010, there were no Zero Coupon Debentures outstanding.
10. Other Comprehensive Income (Loss)
     The components of our other comprehensive income (loss) and the associated income tax effects allocated to such components are as follows:
                         
    Year Ended December 31, 2010
    Before Tax   Tax Effect   Net-of-Tax
    (In thousands)
FOREX contracts:
                        
Unrealized holding gain
   $ 3,591     $ (1,257 )   $ 2,334  
Reclassification adjustment for gain included in net income
     (1,790 )     626       (1,164 )
 
        
Net unrealized gain on FOREX contracts
     1,801       (631 )     1,170  
 
                        
Investments in marketable securities:
                        
Unrealized holding gain
     528       (185 )     343  
Reclassification adjustment for gain included in net income
     36       (13 )     23  
 
        
Net unrealized loss on marketable securities
     564       (198 )     366  
 
                        
 
        
Other comprehensive income
   $ 2,365     $ (829 )   $ 1,536  
 
        
                         
    Year Ended December 31, 2009
    Before Tax   Tax Effect   Net-of-Tax
    (In thousands)
FOREX contracts:
                        
Unrealized holding gain
   $ 9,838     $ (3,443 )   $ 6,395  
Reclassification adjustment for gain included in net income
     (7,434 )     2,602       (4,832 )
 
        
Net unrealized gain on FOREX contracts
     2,404       (841 )     1,563  
 
                        
Investments in marketable securities:
                        
Unrealized holding gain
     63       (22 )     41  
Reclassification adjustment for gain included in net income
     (783 )     274       (509 )
 
        
Net unrealized gain on marketable securities
     (720 )     252       (468 )
 
                        
 
        
Other comprehensive income
   $ 1,684     $ (589 )   $ 1,095  
 
        
                         
    Year Ended December 31, 2008
    Before Tax   Tax Effect   Net-of-Tax
    (In thousands)
Investments in marketable securities:
                        
Unrealized holding gain
   $ 780     $ (273 )   $ 507  
Reclassification adjustment for gain included in net income
     (18 )     6       (12 )
 
        
Net unrealized loss on marketable securities
     762       (267 )     495  
 
                        
 
        
Other comprehensive income
   $ 762     $ (267 )   $ 495  
 
        

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     The components of our accumulated other comprehensive income (loss) included in our Consolidated Balance Sheets are as follows:
                         
    Unrealized Gain (Loss) on        
                    Total Other
    FOREX   Marketable   Comprehensive
    Contracts   Securities   Income (Loss)
    (In thousands)
Balance at January 1, 2009
   $ —     $ 510     $ 510  
Other comprehensive gain
     1,563       (468 )     1,095  
 
        
Balance at December 31, 2009
     1,563       42       1,605  
Other comprehensive gain
     1,170       366       1,536  
 
        
Balance at December 31, 2010
   $ 2,733     $ 408     $ 3,141  
 
        
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. 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 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.
     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 deductibles for marine liability coverage, including personal injury claims, which primarily result from Jones Act liability in the Gulf of Mexico, are currently $10.0 million per the first occurrence, with no aggregate deductible, and vary in amounts ranging between $5.0 million and, if aggregate claims exceed certain thresholds, up to $100.0 million for each subsequent occurrence, depending on the nature, severity and frequency of claims which might arise during the policy year. 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 outside consultants to assist us in estimating our aggregate reserve for personal injury claims based on our historical losses and utilizing various actuarial models. We allocate a portion of the aggregate reserve to “Accrued liabilities” based on an estimate of claims expected to be paid within the next twelve months with the residual recorded as “Other liabilities.” At December 31, 2010, our estimated liability for personal injury claims was $35.0 million, of which $11.1 million and $23.9 million were recorded in “Accrued liabilities” and “Other liabilities,” respectively, in our Consolidated Balance Sheets. At December 31, 2009, our estimated liability for personal injury claims was $32.1 million, of which $9.2 million and $22.9 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. On December 30, 2010, we entered into a turnkey contract with Hyundai Heavy Industries Co., Ltd., or Hyundai, for the construction of a new dynamically positioned, ultra-deepwater drillship with delivery scheduled for late in the second quarter of 2013. The contracted price of the new drillship is payable in two installments. The first installment in the amount of $154.4 million was paid in January 2011. The total cost, including commissioning, spares and project management, is expected to be approximately $590.0 million. At December 31, 2010, we had accrued the first installment of $154.4 million and recorded the related noncurrent asset in an equal amount in “Accrued liabilities” and “Other assets,” respectively, in our Consolidated Balance Sheets. At December 31, 2010, we had no other purchase obligations for major rig upgrades or any other significant obligations, except for those related to our direct rig operations, which arise during the normal course of business.
     In January 2011, we entered into a turnkey contract with Hyundai for the construction of a second ultra-deepwater drillship. See Note 18.
     Operating Leases. We lease office and yard facilities, housing, equipment and vehicles under operating leases, which expire at various times through the year 2013. Total rent expense amounted to $8.0 million, $6.0 million and $5.7 million for the years ended December 31, 2010, 2009 and 2008, respectively. Future minimum rental payments under leases are approximately $1.9 million, $1.1 million and $0.3 million for the years ending December 31, 2011, 2012 and 2013, respectively. There are no minimum future rental payments under leases after 2013.
     Letters of Credit and Other. We were contingently liable as of December 31, 2010 in the amount of $101.6 million under certain performance, bid, supersedeas, tax appeal and custom bonds and letters of credit, including $21.9 million in letters of credit issued under our Credit Facility. At December 31, 2010, three of our outstanding bonds, totaling $47.7 million, had been purchased from a related party in a previous year after obtaining competitive quotes. Agreements relating to approximately $47.7 million of performance bonds can require collateral at any time. As of December 31, 2010, 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. Related-Party Transactions
     Transactions with Loews. We are party to a services agreement with Loews, or the Services Agreement, pursuant to which Loews performs certain administrative and technical services on our behalf. Such services include personnel, internal auditing, accounting, and cash management services, in addition to advice and assistance with respect to preparation of tax returns and obtaining insurance. Under the Services Agreement, we are required to reimburse Loews for (i) allocated personnel costs (such as salaries, employee benefits and payroll taxes) of the Loews personnel actually providing such services and (ii) all out-of-pocket expenses related to the provision of such services. The Services Agreement may be terminated at our option upon 30 days’ notice to Loews and at the option of Loews upon six months’ notice to us. In addition, we have agreed to indemnify Loews for all claims and damages arising from the provision of services by Loews under the Services Agreement unless due to the gross negligence or willful misconduct of Loews. We were charged $1.3 million, $1.1 million and $0.5 million by Loews for these support functions during the years ended December 31, 2010, 2009 and 2008, respectively.
     In addition, since 2006 we have purchased performance and appeal bonds in support of our drilling operations offshore Mexico and workers compensation claims, respectively, from affiliates of a majority-owned subsidiary of Loews after obtaining competitive quotes. At December 31, 2010, three such performance bonds totaling $47.7 million were outstanding. Premiums and fees associated with bonds purchased from affiliates totaled $58,000, $213,000 and $74,000 in 2010, 2009 and 2008, respectively.

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     Transactions with Other Related Parties. We hire marine vessels and helicopter transportation services at the prevailing market rate from subsidiaries of SEACOR Holdings Inc. The Chairman of the Board of Directors, President and Chief Executive Officer of SEACOR Holdings Inc. is also a member of our Board of Directors. For the years ended December 31, 2010, 2009 and 2008, we paid $3.1 million, $3.6 million and $0.5 million, respectively, for the hire of such vessels and such services.
     During the years ended December 31, 2010, 2009 and 2008 we made payments of $1.0 million, $2.1 million and $2.0 million, respectively, to Ernst & Young LLP for tax and other consulting services. The wife of our President and Chief Executive Officer is an audit partner at this firm.
13. Income Taxes
     Our income tax expense is a function of the mix between our domestic and international pre-tax earnings or losses, as well as the mix of international tax jurisdictions in which we operate. Certain of our international rigs are owned and operated, directly or indirectly, by Diamond Offshore International Limited, or DOIL, a Cayman Islands subsidiary which we wholly own. It is our intention to indefinitely reinvest future earnings of DOIL to finance foreign activities except for the earnings of Diamond East Asia Limited, or DEAL, a wholly-owned subsidiary of DOIL. It is our intention to repatriate the earnings of DEAL and, accordingly, U.S. income taxes are provided on its earnings.
     Although we do not intend to repatriate the earnings of DOIL, these foreign earnings could become subject to U.S. federal tax if remitted, or if deemed remitted as a dividend; however, it is not practicable to estimate this potential tax liability.
     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 these foreign subsidiaries. As of December 31, 2010, we provided $15.0 million for U.S. taxes attributable to undistributed earnings of the foreign subsidiaries. On actual remittance, certain countries may impose withholding taxes that, subject to certain limitations, are then available for use as tax credits against a U.S. tax liability, if any.
     The components of income tax expense (benefit) are as follows:
                         
    Year Ended December 31,
    2010   2009   2008
    (In thousands)
Federal — current
   $ 183,825     $ 255,753     $ 346,796  
State — current
     191       131       (282 )
                         
Foreign — current
     203,459       150,804       128,581  
 
        
                         
Total current
     387,475       406,688       475,095  
 
        
                         
Federal — deferred
     8,287       80,258       52,624  
Foreign — deferred
     (15,203 )     5,266       8,780  
 
        
                         
Total deferred
     (6,916 )     85,524       61,404  
 
        
                         
Total
   $ 380,559     $ 492,212     $ 536,499  
 
        

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     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,
    2010   2009   2008
    (In thousands)
Income before income tax expense:
                        
U.S.
   $ 755,982     $ 1,250,094     $ 1,375,857  
Foreign
     580,034       618,337       471,189  
 
        
Worldwide
   $ 1,336,016     $ 1,868,431     $ 1,847,046  
 
        
 
                        
Expected income tax expense at federal statutory rate
   $ 467,606     $ 653,951     $ 646,466  
Foreign earnings of foreign subsidiaries (not taxed at the statutory federal income tax rate) net of related foreign taxes
     (191,789 )     (184,783 )     (131,132 )
Foreign earnings of foreign subsidiaries for which U.S. federal income taxes have been provided
     29,736       62,025       8,641  
Foreign taxes of domestic and foreign subsidiaries for which U.S. federal income taxes have also been provided
     119,009       111,381       99,587  
Foreign tax credits
     (89,809 )     (167,756 )     (68,914 )
Reduction of deferred tax liability related to a goodwill deduction resulting from a prior period stock acquisition
     (8,850 )     (8,850 )     (8,850 )
Domestic production activities deduction
     —       (6,271 )     (13,390 )
Uncertain tax positions
     30,950       8,003       4,446  
Revision of estimated tax balance
     (11,563 )     446       (2,022 )
Amortization of deferred charges associated with intercompany rig sales to other tax jurisdictions
     30,442       14,167       (1,480 )
Long-term capital gain on dividend distribution
     —       2,450       —  
Net expense in connection with resolutions of tax issues and adjustments relating to prior years
     4,217       6,470       2,814  
Other
     610       979       333  
 
        
Income tax expense
   $ 380,559     $ 492,212     $ 536,499  
 
        

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     Significant components of our deferred income tax assets and liabilities are as follows:
                 
    December 31,
    2010   2009
    (In thousands)
Deferred tax assets:
                
Net operating loss carryforwards, or NOLs
   $ 34,824     $ 30,947  
Goodwill
     1,049       4,198  
Worker’s compensation and other current accruals (1)
     17,178       15,000  
Disputed receivables reserved
     2,521       873  
Deferred compensation
     7,478       4,377  
Foreign contribution taxes
     3,100       —  
Foreign tax credits
     186       107  
Nonqualified stock options and SARs
     6,048       4,150  
Other
     3,133       3,253  
 
      
Total deferred tax assets
     75,517       62,905  
Valuation allowance for foreign tax credits
     (186 )     (107 )
Valuation allowance for NOLs
     (31,916 )     (30,868 )
 
      
Net deferred tax assets
     43,415       31,930  
 
      
Deferred tax liabilities:
                
Depreciation
     (558,346 )     (551,437 )
Unbilled revenue
     (347 )     (8,141 )
Mobilization
     (2,181 )     (11,095 )
Undistributed earnings of foreign subsidiaries
     (15,023 )     (24 )
Other
     (219 )     (22 )
 
      
Total deferred tax liabilities
     (576,116 )     (570,719 )
 
      
Net deferred tax liability
   $ (532,701 )   $ (538,789 )
 
      
 
(1)   $9.6 million and $7.2 million reflected in “Prepaid expenses and other current assets” in our Consolidated Balance Sheets at December 31, 2010 and 2009, respectively. See Note 2.
     We record a valuation allowance to derecognize a portion of our deferred tax assets, which we do not expect to be ultimately realized. A summary of changes in the valuation allowance is as follows:
                         
    For the Year Ended December 31,
    2010   2009   2008
    (In thousands)
Valuation allowance as of January 1
   $ 30,975     $ 29,087     $ 40,468  
Establishment of valuation allowances:
                        
Foreign tax credits
     79       107       —  
Net operating losses
     13,381       2,025       —  
Releases of valuation allowances in various jurisdictions
     (12,333 )     (244 )     (11,381 )
 
            
Valuation allowance as of December 31
   $ 32,102     $ 30,975     $ 29,087  
 
            
     Our income tax returns are subject to review and examination in the various jurisdictions in which we operate and we are currently contesting various tax assessments. We accrue for income tax contingencies, or uncertain tax positions, that we believe are more likely than not exposures. A reconciliation of the beginning and ending amount of unrecognized tax benefits, excluding interest and penalties, is as follows:

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    Long term           Net Liability
    Tax   Long term Tax   for Uncertain Tax
    Receivable   Payable   Positions
            (In thousands)        
Balance at January 1, 2008
   $ 3,427     $ (23,756 )   $ (20,329 )
Reduction based on tax positions related to a prior year
     —       307       307  
Additions based on tax positions related to the current year
     2,418       (7,941 )     (5,523 )
Reductions as a result of a lapse of the applicable statute of limitations
     (311 )     2,159       1,848  
 
            
Balance at December 31, 2008
   $ 5,534     $ (29,231 )   $ (23,697 )
Additions based on tax positions related to a prior year
     —       (4,557 )     (4,557 )
Additions based on tax positions related to the current year
     2,441       (6,781 )     (4,340 )
Reductions as a result of a lapse of the applicable statute of limitations
     (1,504 )     7,090       5,586  
 
            
Balance at December 31, 2009
   $ 6,471     $ (33,479 )   $ (27,008 )
Additions based on tax positions related to a prior year
     —       (15,764 )     (15,764 )
Additions based on tax positions related to the current year
     565       (3,729 )     (3,164 )
 
            
Balance at December 31, 2010
   $ 7,036     $ (52,972 )   $ (45,936 )
 
            
     At December 31, 2010, all $45.9 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, 2009, we recorded a net reduction to interest expense of $3.4 million. During the years ended December 31, 2008 and 2010, we recognized $0.8 million and $4.8 million of interest expense related to uncertain tax positions, respectively. Penalty related tax expense for uncertain tax positions during the years ended December 31, 2010, 2009 and 2008 was $12.0 million, $4.7 million and $1.1 million, respectively. Accruals for the payment of interest and penalties in our Consolidated Balance Sheets at December 31, 2010 and 2009 were $34.2 million and $17.4 million, respectively.
     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 2011, 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 $6.8 million through December 31, 2011.
     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 2002 to 2009. We are currently under audit in several of these jurisdictions, including an audit by the Internal Revenue Service for the year 2008. We do not anticipate that any adjustments resulting from the tax audits will have a material impact on our consolidated results of operations, financial position and cash flows.
     The Brazilian tax authorities have audited our income tax returns for the years 2000, 2004 and 2005 and are currently auditing our income tax return for the year 2007. The tax auditors have issued an assessment for tax year

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2000 of approximately $1.5 million, including interest and penalty. We have appealed the tax assessment and are awaiting the outcome of the appeal. In December 2009, we received an assessment of approximately $26.0 million for the years 2004 and 2005, including interest and penalties. We contested the tax assessment in January 2010 and are awaiting the outcome of the appeal. As required by GAAP, only the portion of the tax benefit that has a greater than 50% likelihood of being realized upon settlement is to be recognized. Consequently, we have accrued approximately $14.9 million of expense attributable to the portion of the tax assessment we determined to be an uncertain tax position, of which approximately $3.5 million is interest related and approximately $4 million is penalty related. We do not anticipate that any adjustments resulting from the tax audit of any of these years will have a material impact on our consolidated results of operations, financial position and cash flows.
     The Mexican tax authorities have audited our income tax returns for the year 2004 and are currently auditing our income tax returns for the year 2006. The tax auditors have issued assessments for tax year 2004 of approximately $22.9 million, including interest and penalty. We have appealed the tax assessments and are awaiting the outcome of the appeals. We do not anticipate that any adjustments resulting from the tax audit of any of these years will have a material impact on our consolidated results of operations, financial position and cash flows.
     As of December 31, 2010, we had recorded a deferred tax asset of $34.8 million for the benefit of NOL carryforwards related to our international operations. Approximately $14.8 million of this deferred tax asset relates to NOL carryforwards that have an indefinite life. The remaining $20.0 million relates to NOL carryforwards of our Mexican entities. Unless utilized, the tax benefits of these Mexican NOL carryforwards will expire between 2014 and 2020 as follows:
         
    Tax Benefit of  
    NOL  
    Carryforwards  
Year Expiring   (In millions)  
2014
   $ 1.2  
2015
     4.6  
2016
     7.8  
2017
     6.3  
2018
     —  
2019
     —  
2020
     0.1  
 
      
Total
   $ 20.0  
 
      
     As of December 31, 2010, a valuation allowance of $31.9 million has been recorded for our NOLs as only $2.9 million of the deferred tax asset is more likely than not to be realized.
14. 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 Internal Revenue Code of 1986, as amended, or the Code. Under the 401k Plan, each participant may elect to defer taxation on a portion of his or her eligible earnings, as defined by the 401k Plan, by directing his or her employer to withhold a percentage of such earnings. A participating employee may also elect to make after-tax contributions to the 401k Plan. During the years ended December 31, 2010, 2009 and 2008, we contributed 4%, 5% and 5%, respectively, of participants’ defined compensation and in each year matched 100% 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, 2010, 2009 and 2008, our provision for contributions was $23.8 million, $26.0 million and $23.8 million, respectively.
     The defined contribution retirement plan for our U.K. employees 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 $1.2 million, $1.4 million and $1.7 million for the years ended December 31, 2010, 2009 and 2008, respectively.

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     The defined contribution retirement plan for our TCN employees, or International Savings Plan, is similar to the 401k Plan. During the years ended December 31, 2010, 2009 and 2008, we contributed 4%, 5% and 5%, respectively, of participants’ defined compensation and in each year matched 100% of the first 6% of each employee’s compensation contributed to the International Savings Plan. Our provision for contributions was $2.8 million, $2.5 million and $2.3 million for the years ended December 31, 2010, 2009 and 2008, 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. Our provision for contributions to the Supplemental Plan for the years ended December 31, 2010, 2009 and 2008 was approximately $238,000, $241,000 and $222,000, respectively.
15. Casualty Loss
     In September 2008, one of our jack-up rigs, the Ocean Tower, sustained significant damage during a hurricane, which included the loss of its derrick, drill floor and drill floor equipment. During 2008, we wrote off the approximately $2.6 million in net book value of the Ocean Tower’s derrick, drill floor and drill floor equipment and accrued $3.7 million in estimated salvage costs for the recovery of equipment from the ocean floor. The aggregate of these items is reflected in “Casualty loss” in our Consolidated Statements of Operations for the year ended December 31, 2008.
     We sold the Ocean Tower in 2009 and recognized a $6.7 million gain on disposition, net of broker commission, which was reported as “(Gain) on disposition of assets” in our Consolidated Statements of Operations for the year ended December 31, 2009.
16. Segments and Geographic Area Analysis
     Although we provide contract drilling services with different types of offshore drilling rigs and also provide such services in many geographic locations, we have aggregated these operations into one reportable segment based on the similarity of economic characteristics among all divisions and locations, including the nature of services provided and the type of customers of such services, in accordance with Financial Accounting Standards Board Accounting Standards Codification Topic 280, Segment Reporting.
     Revenues from contract drilling services by equipment-type are listed below:
                         
    Year Ended December 31,
    2010   2009   2008
    (In thousands)
High-Specification Floaters
   $ 1,414,697     $ 1,380,771     $ 1,322,125  
Intermediate Semisubmersibles
     1,546,837       1,698,584       1,629,358  
Jack-ups
     267,983       457,224       524,934  
Other
     219       —       —  
 
        
Total contract drilling revenues
     3,229,736       3,536,579       3,476,417  
Revenues related to reimbursable expenses
     93,238       94,705       67,640  
 
        
Total revenues
   $ 3,322,974     $ 3,631,284     $ 3,544,057  
 
        

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Geographic Areas
     Our drilling rigs are highly mobile and may be moved to other markets throughout the world in response to market conditions or customer needs. At December 31, 2010, our drilling rigs were located offshore thirteen countries in addition to the United States. Revenues by geographic area are presented by attributing revenues to the individual country or areas where the services were performed.
                         
    Year Ended December 31,
    2010   2009   2008
    (In thousands)
United States
   $ 635,545     $ 1,232,940     $ 1,443,200  
International:
                        
South America
     1,308,641       716,448       583,876  
Australia/Asia/Middle East
     641,372       717,658       557,138  
Europe/Africa/Mediterranean
     601,122       641,180       634,033  
Mexico
     136,294       323,058       325,810  
 
        
 
     2,687,429       2,398,344       2,100,857  
 
                        
 
        
Total revenues
   $ 3,322,974     $ 3,631,284     $ 3,544,057  
 
        
     An individual international country may, from time to time, comprise a material percentage of our total contract drilling revenues from unaffiliated customers. For the years ended December 31, 2010, 2009 and 2008, individual countries that comprised 5% or more of our total contract drilling revenues from unaffiliated customers are listed below.
                         
    Year Ended December 31,
    2010   2009   2008
Brazil
     36.8 %     18.2 %     13.0 %
Australia
     10.0 %     10.8 %     9.6 %
Mexico
     4.1 %     8.9 %     9.2 %
United Kingdom
     5.6 %     6.7 %     8.3 %
Angola
     6.1 %     1.8 %     —  
     The following table presents our long-lived tangible assets by geographic location as of December 31, 2010, 2009 and 2008. A substantial portion of our assets is mobile, and therefore asset locations at the end of the period are not necessarily indicative of the geographic distribution of the earnings generated by such assets during the periods. In circumstances where our drilling rigs were in transit at the end of a calendar year, they have been presented in the tables below within the geographic area in which they are expected to operate.
                         
            December 31,    
    2010   2009   2008
    (In thousands)
Drilling and other property and equipment, net:
                        
United States
   $ 638,529     $ 2,176,993     $ 1,739,938  
 
                        
International:
                        
Australia/Asia/Middle East
     417,121       1,015,273       511,946  
South America
     2,290,412       874,644       816,638  
Europe/Africa/Mediterranean
     897,998       262,037       246,301  
Mexico
     39,732       103,105       99,550  
 
        
 
     3,645,263       2,255,059       1,674,435  
 
                        
 
        
Total
   $ 4,283,792     $ 4,432,052     $ 3,414,373  
 
        

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     The following table presents countries where we had a material concentration of operating assets as of December 31, 2010, 2009 and 2008:
                         
    December 31,
    2010   2009   2008
United States
     14.9 %     49.1 %     51.0 %
Brazil
     52.7 %     19.7 %     18.8 %
Singapore
     1.9 %     11.5 %     —  
Republic of Congo
     9.3 %     —       —  
Egypt
     6.3 %     0.9 %     1.2 %
Malaysia
     0.2 %     4.0 %     9.8 %
Argentina
     —       —       5.1 %
     As of December 31, 2010, 2009 and 2008, no other countries had more than a 5% concentration of our operating assets.
Major Customers
     Our customer base includes major and independent oil and gas companies and government-owned oil companies. Revenues from our major customers for the years ended December 31, 2010, 2009 and 2008 that contributed more than 10% of our total revenues are as follows:
                         
    Year Ended December 31,
Customer   2010   2009   2008
Petróleo Brasileiro S.A.
     23.7 %     15.0 %     13.1 %
OGX Petróleo e Gás Ltda.
     14.1 %     1.4 %     —  

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17. Unaudited Quarterly Financial Data
     Unaudited summarized financial data by quarter for the years ended December 31, 2010 and 2009 is shown below.
                                 
    First   Second   Third   Fourth
    Quarter   Quarter   Quarter   Quarter
    (In thousands, except per share data)
2010
                                
Revenues
   $ 859,681     $ 822,603     $ 799,724     $ 840,966  
Operating income (a)
     426,677       345,807       317,180       335,710  
Income before income tax expense
     406,012       320,926       298,566       310,512  
Net income (b)
     290,853       224,393       198,524       241,687  
Net income per share:
                                
Basic
   $ 2.09     $ 1.61     $ 1.43     $ 1.74  
Diluted
   $ 2.09     $ 1.61     $ 1.43     $ 1.74  
 
                                
2009
                                
Revenues
   $ 885,720     $ 946,407     $ 908,375     $ 890,782  
Operating income (c)
     456,936       517,619       479,460       449,198  
Income before income tax expense
     453,337       520,838       475,285       418,971  
Net income (d)
     348,581       387,440       364,134       276,064  
Net income per share:
                                
Basic
   $ 2.51     $ 2.79     $ 2.62     $ 1.99  
Diluted
   $ 2.51     $ 2.79     $ 2.62     $ 1.98  
 
(a)   Results for the fourth quarter of 2010 include a $3.9 million recovery of bad debt reserves recorded in previous years.
 
(b)   Results for the fourth quarter of 2010 reflect a reduction in income tax expense, partially attributable to recording the full year tax effect of the Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 2010 that was passed in mid-December 2010.
 
(c)   In December 2009, we recorded a $10.7 million provision for bad debts to reserve a portion of the uncollected balance of receivables related to our operations in Egypt and recovered $0.9 million associated with the reserve for bad debts recorded in 2008. See Note 2.
 
    In addition, our results for the fourth quarter of 2009 include a $6.7 million gain on the sale of the Ocean Tower, which was presented as “Assets held for sale” in our Consolidated Balance Sheets at December 31, 2008. See Note 15.
 
(d)   Results for the fourth quarter of 2009 reflect increased tax expense that arose from (i) a change in mix of domestic and international earnings during the year from that which was previously expected, (ii) impact of foreign exchange differences on foreign tax credits and (iii) an assessment from the Brazilian tax authorities for the years 2004 and 2005. See Note 13.
18. Subsequent Event
     In January 2011, we entered into a turnkey contract with Hyundai for the construction of a second dynamically positioned, ultra-deepwater drillship with delivery scheduled for the fourth quarter of 2013. The total cost, including commissioning, spares and project management, is expected to be approximately $590.0 million.

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Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.
     Not applicable.
Item 9A. Controls and Procedures
Disclosure Controls and Procedures
     We maintain a system of disclosure controls and procedures which are designed to ensure that information required to be disclosed by us in reports that we file or submit under the federal securities laws, including this report, is recorded, processed, summarized and reported on a timely basis. These disclosure controls and procedures include controls and procedures designed to ensure that information required to be disclosed by us under the federal securities laws is accumulated and communicated to our management on a timely basis to allow decisions regarding required disclosure.
     Our Chief Executive Officer, or CEO, and Chief Financial Officer, or CFO, participated in an evaluation by our management of the effectiveness of our disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) as of December 31, 2010. Based on their participation in that evaluation, our CEO and CFO concluded that our disclosure controls and procedures were effective as of December 31, 2010.
Internal Control Over Financial Reporting
Management’s Annual Report on Internal Control Over Financial Reporting
     Our management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for Diamond Offshore Drilling, Inc. Our internal control system was designed to provide reasonable assurance to our management and Board of Directors regarding the preparation and fair presentation of published financial statements.
     There are inherent limitations to the effectiveness of any control system, however well designed, including the possibility of human error and the possible circumvention or overriding of controls. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Management must make judgments with respect to the relative cost and expected benefits of any specific control measure. The design of a control system also is based in part upon assumptions and judgments made by management about the likelihood of future events, and there can be no assurance that a control will be effective under all potential future conditions. As a result, even an effective system of internal controls can provide no more than reasonable assurance with respect to the fair presentation of financial statements and the processes under which they were prepared.
     Our management assessed the effectiveness of our internal control over financial reporting as of December 31, 2010. In making this assessment, our management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control — Integrated Framework. Based on management’s assessment our management believes that, as of December 31, 2010, our internal control over financial reporting was effective based on those criteria to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with U.S. generally accepted accounting principles.
     Deloitte & Touche LLP, the registered public accounting firm that audited our financial statements included in this Annual Report on Form 10-K, has issued an attestation report on the effectiveness of our internal control over financial reporting. The attestation report of Deloitte & Touche LLP is included at the beginning of Item 8 of this Form 10-K.
     Changes in Internal Control Over Financial Reporting
     There were no changes in our internal control over financial reporting identified in connection with the foregoing evaluation that occurred during our fourth fiscal quarter of 2010 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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Item 9B. Other Information.
     Not applicable.
PART III
     Reference is made to the information responsive to Items 10, 11, 12, 13 and 14 of this Part III contained in our definitive proxy statement for our 2011 Annual Meeting of Stockholders, which is incorporated herein by reference.
Item 10. Directors, Executive Officers and Corporate Governance.
Item 11. Executive Compensation.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.
Item 13. Certain Relationships and Related Transactions, and Director Independence.
Item 14. Principal Accountant Fees and Services.
PART IV
Item 15. Exhibits and Financial Statement Schedules.
     (a) Index to Financial Statements, Financial Statement Schedules and Exhibits
         
    Page  
     (1) Financial Statements
        
         
 
    51  
 
    53  
 
    54  
 
    55  
 
    56  
 
    57  
 
    58  
 
         
 
     (2) Exhibit Index
     88  
     See the Exhibit Index for a list of those exhibits filed herewith, which Exhibit Index also includes and identifies management contracts or compensatory plans or arrangements required to be filed as exhibits to this Form 10-K by Item 601 of Regulation S-K.

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SIGNATURES
    Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on February 25, 2011.
         
  DIAMOND OFFSHORE DRILLING, INC.
 		  
  By:   /s/ GARY T. KRENEK    
    Gary T. Krenek   
    Senior Vice President and Chief Financial Officer  
 
     Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
         
Signature   Title   Date
 
        
/s/ LAWRENCE R. DICKERSON*
 
   President, Chief Executive Officer and    February 25, 2011
Lawrence R. Dickerson
  Director (Principal Executive Officer)    
 
        
/s/ GARY T. KRENEK*
 
   Senior Vice President and    February 25, 2011
Gary T. Krenek
  Chief Financial Officer
(Principal Financial Officer)		    
 
        
/s/ BETH G. GORDON*
 
Beth G. Gordon
  Controller (Principal Accounting Officer)    February 25, 2011
 
        
/s/ JAMES S. TISCH*
 
James S. Tisch
  Chairman of the Board    February 25, 2011
 
        
/s/ JOHN R. BOLTON*
 
John R. Bolton
  Director    February 25, 2011
 
        
/s/ CHARLES L. FABRIKANT*
 
Charles L. Fabrikant
  Director    February 25, 2011
 
        
/s/ PAUL G. GAFFNEY II*
 
Paul G. Gaffney II
  Director    February 25, 2011
 
        
/s/ EDWARD GREBOW*
 
Edward Grebow
  Director    February 25, 2011
 
        
/s/ HERBERT C. HOFMANN*
 
Herbert C. Hofmann
  Director    February 25, 2011
 
        
/s/ ARTHUR L. REBELL*
 
Arthur L. Rebell
  Director    February 25, 2011
 
        
/s/ RAYMOND S. TROUBH*
 
Raymond S. Troubh
  Director    February 25, 2011
         
     
  *By:   /s/ WILLIAM C. LONG    
    William C. Long   
    Attorney-in-fact   
 

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EXHIBIT INDEX
     
Exhibit No.   Description
3.1
  Amended and Restated Certificate of Incorporation of Diamond Offshore Drilling, Inc. (incorporated by reference to Exhibit 3.1 to our Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2003) (SEC File No. 1-13926).
 
    
3.2
  Amended and Restated By-laws (as amended through October 22, 2007) of Diamond Offshore Drilling, Inc. (incorporated by reference to Exhibit 3.1 to our Current Report on Form 8-K filed October 26, 2007).
 
    
4.1
  Indenture, dated as of February 4, 1997, between Diamond Offshore Drilling, Inc. and The Bank of New York Mellon (formerly known as The Bank of New York) (as successor to The Chase Manhattan Bank), as Trustee (incorporated by reference to Exhibit 4.1 to our Annual Report on Form 10-K for the fiscal year ended December 31, 2001) (SEC File No. 1-13926).
 
    
4.2
  Fourth Supplemental Indenture, dated as of August 27, 2004, between Diamond Offshore Drilling, Inc. and The Bank of New York Mellon (formerly known as The Bank of New York) (as successor to JPMorgan Chase Bank), as Trustee (incorporated by reference to Exhibit 4.2 to our Current Report on Form 8-K filed September 1, 2004) (SEC File No. 1-13926).
 
    
4.3
  Fifth Supplemental Indenture, dated as of June 14, 2005, between Diamond Offshore Drilling, Inc. and The Bank of New York Mellon (formerly known as The Bank of New York) (as successor to JPMorgan Chase Bank, National Association), as Trustee (incorporated by reference to Exhibit 4.2 to our Current Report on Form 8-K filed June 16, 2005) (SEC File No. 1-13926).
 
    
4.4
  Sixth Supplemental Indenture, dated as of May 4, 2009, between Diamond Offshore Drilling, Inc. and The Bank of New York Mellon, as Trustee (incorporated by reference to Exhibit 4.2 to our Current Report on Form 8-K filed May 4, 2009).
 
    
4.5
  Seventh Supplemental Indenture, dated as of October 8, 2009, between Diamond Offshore Drilling, Inc. and The Bank of New York Mellon, as Trustee (incorporated by reference to Exhibit 4.2 to our Current Report on Form 8-K filed October 8, 2009).
 
    
10.1
  Registration Rights Agreement (the “Registration Rights Agreement”) dated October 16, 1995 between Loews and Diamond Offshore Drilling, Inc. (incorporated by reference to Exhibit 10.1 to our Annual Report on Form 10-K for the fiscal year ended December 31, 2001) (SEC File No. 1-13926).
 
    
10.2
  Amendment to the Registration Rights Agreement, dated September 16, 1997, between Loews and Diamond Offshore Drilling, Inc. (incorporated by reference to Exhibit 10.2 to our Annual Report on Form 10-K for the fiscal year ended December 31, 1997) (SEC File No. 1-13926).
 
    
10.3
  Services Agreement, dated October 16, 1995, between Loews and Diamond Offshore Drilling, Inc. (incorporated by reference to Exhibit 10.3 to our Annual Report on Form 10-K for the fiscal year ended December 31, 2001) (SEC File No. 1-13926).
 
    
10.4+
  Amended and Restated Diamond Offshore Management Company Supplemental Executive Retirement Plan effective as of January 1, 2007 (incorporated by reference to Exhibit 10.4 to our Annual Report on Form 10-K for the fiscal year ended December 31, 2006).
 
    
10.5+
  Diamond Offshore Management Bonus Program, as amended and restated, and dated as of December 31, 1997 (incorporated by reference to Exhibit 10.6 to our Annual Report on Form 10-K for the fiscal year ended December 31, 1997) (SEC File No. 1-13926).
 
    
10.6+
  Second Amended and Restated Diamond Offshore Drilling, Inc. 2000 Stock Option Plan, as amended (incorporated by reference to Exhibit 10.6 to our Annual Report on Form 10-K for the fiscal year ended December 31, 2007).
 
    
10.7+
  Form of Stock Option Certificate for grants to executive officers, other employees and consultants pursuant to the Second Amended and Restated Diamond Offshore Drilling, Inc. 2000 Stock Option Plan

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Exhibit No.   Description
 
  (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed October 1, 2004) (SEC File No. 1-13926).
 
    
10.8+
  Form of Stock Option Certificate for grants to non-employee directors pursuant to the Second Amended and Restated Diamond Offshore Drilling, Inc. 2000 Stock Option Plan (incorporated by reference to Exhibit 10.2 to our Current Report on Form 8-K filed October 1, 2004) (SEC File No. 1-13926).
 
    
10.9+
  Diamond Offshore Drilling, Inc. Incentive Compensation Plan for Executive Officers (amended and restated as of December 18, 2009) (incorporated by reference to Exhibit 10.9 to our Annual Report on Form 10-K for the fiscal year ended December 31, 2009).
 
    
10.10+
  Form of Award Certificate for stock appreciation right grants to the Company’s executive officers, other employees and consultants pursuant to the Second Amended and Restated Diamond Offshore Drilling, Inc. 2000 Stock Option Plan (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed April 28, 2006).
 
    
10.11+
  Form of Award Certificate for stock appreciation right grants to non-employee directors pursuant to the Second Amended and Restated Diamond Offshore Drilling, Inc. 2000 Stock Option Plan (incorporated by reference to Exhibit 10.1 to our Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2007).
 
    
10.12
  5-Year Revolving Credit Agreement, dated as of November 2, 2006, among Diamond Offshore Drilling, Inc., JPMorgan Chase Bank, N.A., as administrative agent, The Bank of Tokyo-Mitsubishi UFJ, Ltd. Houston Agency, Fortis Capital Corp., HSBC Bank USA, National Association, Wells Fargo Bank, N.A. and Bayerische Hypo-Und Vereinsbank AG, Munich Branch, as co-syndication agents, and the lenders named therein (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed November 3, 2006).
 
    
10.13+
  Employment Agreement between Diamond Offshore Management Company and Lawrence R. Dickerson dated as of December 15, 2006 (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed December 21, 2006).
 
    
10.14+
  Employment Agreement between Diamond Offshore Management Company and Gary T. Krenek dated as of December 15, 2006 (incorporated by reference to Exhibit 10.2 to our Current Report on Form 8-K filed December 21, 2006).
 
    
10.15+
  Employment Agreement between Diamond Offshore Management Company and John M. Vecchio dated as of December 15, 2006 (incorporated by reference to Exhibit 10.15 to our Annual Report on Form 10-K for the fiscal year ended December 31, 2006).
 
    
10.16+
  Employment Agreement between Diamond Offshore Management Company and William C. Long dated as of December 15, 2006 (incorporated by reference to Exhibit 10.16 to our Annual Report on Form 10-K for the fiscal year ended December 31, 2006).
 
    
10.17+
  Employment Agreement between Diamond Offshore Management Company and Lyndol L. Dew dated as of December 15, 2006 (incorporated by reference to Exhibit 10.17 to our Annual Report on Form 10-K for the fiscal year ended December 31, 2006).
 
    
10.18+
  Employment Agreement between Diamond Offshore Management Company and Beth G. Gordon dated as of January 3, 2007 (incorporated by reference to Exhibit 10.19 to our Annual Report on Form 10-K for the fiscal year ended December 31, 2006).
 
    
10.19+
  Amendment to Employment Agreement, dated June 16, 2008, between Diamond Offshore Management Company and Lawrence R. Dickerson (incorporated by reference to Exhibit 10.1 to our Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2008).
 
    
12.1*
  Statement re Computation of Ratios.
 
    
21.1*
  List of Subsidiaries of Diamond Offshore Drilling, Inc.

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Exhibit No.   Description
23.1*
  Consent of Deloitte & Touche LLP.
 
    
24.1*
  Powers of Attorney.
 
    
31.1*
  Rule 13a-14(a) Certification of the Chief Executive Officer.
 
    
31.2*
  Rule 13a-14(a) Certification of the Chief Financial Officer.
 
    
32.1*
  Section 1350 Certification of the Chief Executive Officer and Chief Financial Officer.
 
    
101.INS**
  XBRL Instance Document.
 
    
101.SCH**
  XBRL Taxonomy Extension Schema Document.
 
    
101.CAL**
  XBRL Taxonomy Calculation Linkbase Document.
 
    
101.LAB**
  XBRL Taxonomy Label Linkbase Document.
 
    
101.PRE**
  XBRL Presentation Linkbase Document.
 
    
101.DEF**
  XBRL Taxonomy Extension Definition.
 
*   Filed or furnished herewith.
 
**   The documents formatted in XBRL (Extensible Business Reporting Language) and attached as Exhibit 101 to this report are deemed not filed or part of a registration statement or prospectus for purposes of sections 11 or 12 of the Securities Act, are deemed not filed for purposes of section 18 of the Exchange Act, and otherwise, not subject to liability under these sections.
 
+   Management contracts or compensatory plans or arrangements.

90