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

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

Commission file number 1-13926

DIAMOND OFFSHORE DRILLING, INC.

(Exact name of registrant as specified in its charter)

Delaware (State or other jurisdiction of incorporation or organization)		76-0321760 (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 (Do not check if a smaller reporting company)		Smaller reporting company o

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, 2009		$5,694,071,609

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 19, 2010		Common Stock, $0.01 par value per share		139,026,178 shares

     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, 2009, are incorporated by reference in Part III of this report.

 

 

DIAMOND OFFSHORE DRILLING, INC.
FORM 10-K for the Year Ended December 31, 2009

TABLE OF CONTENTS

		Page No.
Cover Page			1
Document Table of Contents			2
Part I
Item 1. Business			3
Item 1A. Risk Factors			8
Item 1B. Unresolved Staff Comments			16
Item 2. Properties			16
Item 3. Legal Proceedings			16
Item 4. Submission of Matters to a Vote of Security Holders			16
Part II
Item 5. Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities			18
Item 6. Selected Financial Data			20
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations			21
Item 7A. Quantitative and Qualitative Disclosures About Market Risk			49
Item 8. Financial Statements and Supplementary Data			52
Consolidated Financial Statements			54
Notes to Consolidated Financial Statements			59
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure			88
Item 9A. Controls and Procedures			88
Item 9B. Other Information			89
Part III
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
Part IV
Item 15. Exhibits and Financial Statement Schedules			89
Signatures			91
Exhibit Index			92
EX-10.9
EX-10.19
EX-12.1
EX-21.1
EX-23.1
EX-24.1
EX-31.1
EX-31.2
EX-32.1
EX-101 INSTANCE DOCUMENT
EX-101 SCHEMA DOCUMENT
EX-101 CALCULATION LINKBASE DOCUMENT
EX-101 LABELS LINKBASE DOCUMENT
EX-101 PRESENTATION LINKBASE DOCUMENT
EX-101 DEFINITION LINKBASE DOCUMENT

PART I

Item 1.		Business.

General

     Diamond Offshore Drilling, Inc. is a leading, global offshore oil and gas drilling contractor with a fleet of 47 offshore rigs consisting of 32 semisubmersibles, 14 jack-ups and one drillship. Unless the context otherwise requires, references in this report to “Diamond Offshore,” “we,” “us” or “our” mean Diamond Offshore Drilling, Inc. and our consolidated subsidiaries. We were incorporated in Delaware in 1989.

The Fleet

     Our fleet includes some of the most technologically advanced rigs in the world, enabling us to offer a broad range of services worldwide in various markets, including the 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 25, 2010, seven of our 13 high-specification semisubmersibles, including the recently acquired Ocean Courage, were located in the United States, or U.S., Gulf of Mexico, or GOM. At that date we had two high- specification semisubmersibles rigs operating offshore Brazil, while a third was en route to Brazil from the GOM. Of our remaining high-specification semisubmersibles, one was located offshore each of Malaysia and Angola, while the final rig, the Ocean Valor, was completing its commissioning in Singapore. See “ – Fleet Enhancements and Additions.”

     Our intermediate semisubmersibles generally work in maximum water depths up to 4,000 feet. As of January 25, 2010, we had 19 intermediate semisubmersible rigs in various locations around the world. Seven of these semisubmersibles were operating offshore Brazil and an eighth unit was en route to Brazil; three were located in the North Sea; two each were located offshore Australia and offshore Mexico; one was located in the GOM and one offshore Vietnam. One unit was en route to the Falkland Islands, and our final intermediate semisubmersible rig, the Ocean Bounty, was in the process of being cold stacked in Malaysia.

     Drillship. We have one high-specification drillship, the Ocean Clipper, which was located offshore Brazil as of January 25, 2010. Drillships, which are typically self-propelled, are positioned over a drillsite through the use of either an anchoring system or a dynamic-positioning system similar to those used on certain semisubmersible rigs. Deepwater drillships compete in many of the same markets as do high-specification semisubmersible rigs.

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

     Jack-ups. We currently have 14 jack-up drilling rigs. Jack-up rigs are mobile, self-elevating drilling platforms equipped with legs that are lowered to the ocean floor until a foundation is established to support the drilling platform. The rig hull includes the drilling rig, jacking system, crew quarters, loading and unloading facilities, storage areas for bulk and liquid materials, heliport and other related equipment. Our jack-ups are used for drilling in water depths from 20 feet to 350 feet. The water depth limit of a particular rig is principally determined by the length of the rig’s legs. A jack-up rig is towed to the drillsite with its hull riding in the sea, as a vessel, with its legs retracted. Once over a drillsite, the legs are lowered until they rest on the seabed and jacking continues 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 25, 2010, six of our 14 jack-up rigs were located in the GOM and a seventh rig, the Ocean Scepter, was en route from Uruguay for a six-well drilling program in the GOM. Four of those rigs are independent-leg cantilevered units, two are mat-supported cantilevered units, and one is a mat-supported slot unit. We cold-stacked the three mat-supported jack-up rigs located in the GOM during the second quarter of 2009 and are no longer actively marketing these drilling units. 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 Indonesia, Croatia and the Joint Petroleum Development Area, or JPDA, between Australia and Timor Leste.

     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. During 2009, we acquired two new-build deepwater, semisubmersible, dynamically-positioned drilling rigs, the Ocean Courage (June 2009) and the Ocean Valor (September 2009). As of January 25, 2010, the Ocean Courage was in process of completing its commissioning and preparing for its first contract in the GOM, which we expect to begin in the first quarter of 2010. We expect commissioning of the Ocean Valor to be completed in Singapore in the first quarter of 2010.

     In addition, excluding our two new deepwater floaters acquired in 2009, we have, since 1995, increased the number of our rigs capable of operating in 3,500 feet or more of water from three rigs to 14 (11 of which are high-specification units), primarily by upgrading our existing fleet. Seven of these upgrades were to our Victory-class semisubmersible rigs, the design of which is well-suited for significant upgrade projects. We have two additional Victory-class intermediate semisubmersibles that could potentially be upgraded at some time in the future.

     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 – Sources of Liquidity and Capital Resources – Liquidity and Capital Requirements” in Item 7 of this report.

     More detailed information concerning our fleet of mobile offshore drilling rigs, as of January 25, 2010, 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; 15K; 4M

2009

Singapore

Commissioning

Ocean Courage

10,000

DP; 15K; 4M

2009

GOM

Commissioning and contract preparation: Petrobras Americas

Ocean Confidence

10,000

DP; 15K; 4M

2001/2008

GOM

Murphy Exploration

Ocean Monarch

10,000

VC; 15K; 4M

1974/2008

GOM

Marathon Oil

Ocean Endeavor

10,000

VC; 15K; 4M

1975/2007

GOM

ExxonMobil

Ocean Rover

8,000

VC; 15K; 4M

1973/2008

Malaysia

Shell Malaysia

Ocean Baroness

7,000

VC; 15K; 4M

1973/2002

GOM

Hess

Ocean Victory

5,500

VC; 15K; 3M

1972/2006

GOM

ATP Oil & Gas

Ocean America

5,500

SP; 15K; 3M

1988/1999

GOM

Mariner Energy

Ocean Valiant

5,500

SP; 15K; 3M

1988/1999

Angola

Total

Ocean Star

5,500

VC; 15K; 3M

1974/1999

Brazil

Mobilizing: OGX

Ocean Alliance

5,250

DP; 15K; 3M

1988/1999

Brazil

Petrobras

Ocean Quest

4,000

VC; 15K; 3M

1973/1996

Brazil

OGX

Drillship (1):

Ocean Clipper

7,875

DP; 15K; 3M

1976/1999

Brazil

Petrobras

Intermediate Semisubmersibles (19):

Ocean Winner

4,000

3M

1977/2004

Brazil

Petrobras

Ocean Worker

4,000

3M

1982/2008

Brazil

Petrobras

Ocean Yatzy

3,300

DP

1989/1998

Brazil

Petrobras

Ocean Voyager

3,200

VC; 3M

1973/1995

Mexico

Actively marketing

Ocean Patriot

3,000

15K; 3M

1982/2003

Australia

Esso Australia

Ocean Epoch

3,000

3M

1977/2000

Australia

BHPB

Ocean General

3,000

3M

1976/2000

Vietnam

PVEP Dai Hung

Ocean Yorktown

2,850

3M

1976/1996

Brazil

Petrobras

Ocean Concord

2,300

3M

1975/1999

Brazil

Petrobras

Ocean Lexington

2,200

3M

1976/1995

Brazil

Mobilizing: OGX

Ocean Saratoga

2,200

3M

1976/1995

GOM

Taylor Energy

Ocean Whittington

1,650

3M

1974/1995

Brazil

Petrobras

Ocean Bounty

1,500

VC; 3M

1977/1992

Malaysia

Preparing for cold stacking

Ocean Guardian

1,500

15K; 3M

1985

Falkland Islands

Mobilizing: AGR/Desire

Ocean New Era

1,500

3M

1974/1990

Mexico

PEMEX

Ocean Princess

1,500

15K; 3M

1977/1998

North Sea/U.K.

Talisman

Ocean Vanguard

1,500

15K; 3M

1982

North Sea/Norway

Statoil

Ocean Nomad

1,200

3M

1975/2001

North Sea/U.K.

Actively Marketing

Ocean Ambassador

1,100

3M

1975/1995

Brazil

OGX

Jack-ups (14):

Ocean Scepter

350

IC; 15K; 3M

2008

GOM

Mobilizing: Arena Energy

Ocean Shield

350

IC; 15K; 3M

2008

JPDA

Petronas Carigali Timor Leste

Ocean Titan

350

IC; 15K; 3M

1974/2004

GOM

ANKOR Energy

Ocean King

300

IC; 3M

1973/1999

Croatia

Bareboat charter to CROSCO

Ocean Nugget

300

IC

1976/1995

Mexico

PEMEX

Ocean Summit

300

IC

1972/2003

Mexico

PEMEX

Ocean Heritage

300

IC

1981/2002

Egypt

SUCO

Ocean Spartan

300

IC

1980/2003

GOM

Samson Offshore

Ocean Spur

300

IC

1981/2003

Egypt

WEPCO

Ocean Sovereign

300

IC

1981/2003

Indonesia

Kodeco

Ocean Champion

250

MS

1975/2004

GOM

Cold stacked

Ocean Columbia

250

IC

1978/1990

GOM

Shipyard: Survey

Ocean Crusader

200

MC

1982/1992

GOM

Cold stacked

Ocean Drake

200

MC

1983/1986

GOM

Cold stacked

See the footnotes to this table on the following page.

     The principal markets for our offshore contract drilling services are the following:

	•		the Gulf of Mexico, including the U.S. and Mexico;
	•		South America, principally in Brazil;
	•		Europe, principally in the United Kingdom, or U.K., and Norway;
	•		the Mediterranean Basin, including Egypt;
	•		Africa, currently in Angola;
	•		Australia and Asia, including Malaysia, Indonesia and Vietnam; and
	•		the Middle East, including Kuwait, Qatar and Saudi Arabia.

     We actively market our rigs worldwide. From time to time our fleet operates in various other markets throughout the world as the market demands. See Note 17 “Segments and Geographic Area Analysis” to our Consolidated Financial Statements in Item 8 of this report.

     We believe our presence in multiple markets is valuable in many respects. For example, we believe that our experience with safety and other regulatory matters in the U.K. has been beneficial in Australia and 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.

     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, and we are not fully insured against all of them” 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 2009, we performed services for 47 different customers and for 49 different customers during each of 2008 and 2007. During 2009, 2008 and 2007, 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 15%, 13% and 9% of our annual total consolidated revenues, respectively. No other customer accounted for 10% or more of our annual total consolidated revenues during 2009 and 2008, nor did any single customer account for 10% or more of our annual total consolidated revenues during 2007.

     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 12 rigs in our fleet either currently working or contracted to work during 2010. Our contract backlog attributable to our expected operations offshore Brazil is $1.1 billion, $1.1 billion and $867.0 million for the years 2010, 2011 and 2012, respectively, and $1.2 billion in the aggregate for the years 2013 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 office in The Hague, The Netherlands with support from our regional offices in Aberdeen, Scotland and Perth, Australia. We provide technical and administrative support functions from our Houston office.

Competition

     The offshore contract drilling industry is highly competitive with numerous industry participants, none of which at the present time has a dominant market share. The drilling industry has experienced consolidation in recent years and may experience additional consolidation, which could create additional large competitors. Some of our competitors may have greater financial or other resources than we do. We compete with offshore drilling contractors that together have more than 600 mobile rigs available worldwide.

     The offshore contract drilling industry is influenced by a number of factors, including global 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

the environment, and may include laws or regulations pertaining to climate change, carbon emissions or energy use. See “Risk Factors – Governmental laws and regulations 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 66%, 59% and 50% of our total consolidated revenues for the years ended December 31, 2009, 2008 and 2007, 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, 2009, we had approximately 5,500 workers, including international crew personnel furnished through independent labor contractors. We have experienced satisfactory labor relations and provide comprehensive benefit plans for our employees.

Access to Company Filings

     We are subject to the informational requirements of the Securities Exchange Act of 1934, as amended, or the Exchange Act, and accordingly file annual, quarterly and current reports, any amendments to those reports, proxy statements and other information with the United States Securities and Exchange Commission, or SEC. You may read and copy the information we file with the SEC at the public reference facilities maintained by the SEC at 100 F Street, N.E., Washington, DC 20549. Please call the SEC at 1-800-SEC-0330 for further information on the operation of the public reference room. Our SEC filings are also available to the public from the SEC’s Internet site at www.sec.gov or from our Internet site at www.diamondoffshore.com. Our website provides a hyperlink to a third-party SEC filings website where these reports may be viewed and printed at no cost as soon as reasonably practicable after we have electronically filed such material with, or furnished it to, the SEC. The information contained on our website, or on other websites linked to our website, is not part of this report.

Item 1A.		Risk Factors.

     Our business is subject to a variety of risks, including the risks described below. You should carefully consider these risks when evaluating us and our securities. The risks and uncertainties described below are not the only ones facing our company. We are also subject to a variety of risks that affect many other companies generally, as well as additional risks and uncertainties not known to us or that we currently believe are not as significant as the risks described below. If any of the following risks actually occur, our business, financial condition, results of operations and cash flows, and the trading prices of our securities, may be materially and adversely affected.

Our business depends on the level of activity in the oil and gas industry, which is significantly affected by volatile oil and gas prices.

     Our business depends on the level of activity in offshore oil and gas exploration, development and production in markets worldwide. Worldwide demand for oil and gas, oil and gas prices, market expectations of potential changes in these prices and a variety of political and economic factors significantly affect this level of activity. However, higher or lower commodity demand and prices do not necessarily translate into increased or decreased drilling activity since our customers’ project development time, reserve replacement needs, as well as expectations of future commodity demand and prices all combine to 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;
	•		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.

The continuing global financial crisis and worldwide economic downturn has had, and may continue to have, a negative impact on our business and financial condition.

     The continuing worldwide financial crisis has reduced the availability of liquidity and in some cases has reduced the availability of and/or increased the cost of credit to fund the continuation and expansion of industrial business operations worldwide, and has led to a worldwide economic recession. This deterioration of the worldwide economy has resulted in reduced demand for crude oil and natural gas, exploration and production activity and offshore drilling services that has had a negative impact on our business and financial condition, including declines in dayrates earned by our drilling rigs and a decrease in new contract activity, which may continue and may worsen.

     In addition, the worldwide economic recession has had, and could continue to have, a negative impact on our customers and/or our suppliers including, among other things, causing them to fail to meet their obligations to us. Additionally, if a potential customer is unable to obtain an adequate level of credit, it may preclude us from doing business with that potential customer. Similarly, the restricted credit market could affect lenders participating in our credit facility, making them unable to fulfill their commitments and obligations to us. Any such reductions in drilling activity or failure by our customers, suppliers or lenders to meet their contractual obligations to us, or our inability to secure additional financing, could adversely affect our financial position, results of operations and cash flows.

Our industry is highly competitive and cyclical, with intense price competition.

     The offshore contract drilling industry is highly competitive with numerous industry participants, none of which at the present time has a dominant market share. Some of our competitors may have greater financial or other resources than we do. The drilling industry has experienced consolidation in recent years and may experience additional consolidation, which could create additional large competitors. Drilling contracts are traditionally awarded on a competitive bid basis. Intense price competition is often the primary factor in determining which qualified contractor is awarded a job, although rig availability and location, a drilling contractor’s safety record and the quality and technical capability of service and equipment may also be considered. Mergers among oil and natural gas exploration and production companies, as well as the contraction of the global economy, have reduced the number of available customers, increasing competition.

     Our industry has historically been cyclical. There have been periods of 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 three of our rigs as of the date of this report and are in the process of cold stacking a fourth unit. 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 70

floaters on order and scheduled for delivery between 2010 and 2012. 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. This potential oversupply of uncontracted rigs is greater in the jack-up market than it is in the floater market. However, 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.

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 $8.5 billion for contracted future work extending, in some cases, until 2016. Generally, contract backlog only includes future earnings under firm commitments; however, from time to time, we may report anticipated commitments for which definitive agreements have not yet been executed. We can provide no assurance that we will be able to perform under these contracts due to events beyond our control or that we will be able to ultimately execute a definitive agreement in cases where one does not currently exist. In addition, we can provide no assurance that our customers will be able to or willing to fulfill their contractual commitments to us. Our inability to perform under our contractual obligations or to execute definitive agreements or our customers’ inability to fulfill their contractual commitments to us may have a material adverse effect on our financial position, results of operations and cash flows. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Overview – Contract Drilling Backlog” included in Item 7 of this report.

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

     We provide offshore drilling services to a customer base that includes major and independent oil and gas companies and government-owned oil companies. However, the number of potential customers has decreased in recent years as a result of mergers among the major international oil companies and large independent oil companies. In 2009, our five largest customers in the aggregate accounted for 41% of our consolidated revenues. We expect Petrobras, who accounted for approximately 15% of our consolidated revenues in 2009, to continue to be a significant customer in 2010. While it is normal for our customer base to change over time as work programs are completed, the loss of any major customer may have a material adverse effect on our financial position, results of operations and cash flows.

The terms of 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.

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 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, and we are not fully insured against all of them.

     Our operations are subject to the usual hazards inherent in drilling for oil and gas offshore, such as blowouts, reservoir damage, loss of production, loss of well control, punchthroughs, craterings, fires and natural disasters such as hurricanes. The occurrence of these events could result in the suspension of drilling operations, damage to or destruction of the equipment involved and injury or death to rig personnel, damage to producing or potentially productive oil and gas formations and environmental damage, and could have a material adverse effect on our results of operations and financial condition. Operations also may be suspended because of machinery breakdowns, abnormal drilling conditions, failure of subcontractors to perform or supply goods or services or personnel shortages. In addition, offshore drilling operators are subject to perils peculiar to marine operations, including capsizing, grounding, collision and loss or damage from severe weather, and we do not typically retain loss-of-hire insurance policies to cover our rigs. Damage to the environment could also result from our operations, particularly through oil spillage or extensive uncontrolled fires. Pollution and environmental risks generally are not fully insurable. We may also be subject to damage claims by oil and gas companies or other parties.

     Our insurance policies and contractual rights to indemnity may not adequately cover our losses, or may have exclusions of coverage for some losses. We do not have insurance coverage or rights to indemnity for all risks, including, among other things, liability risk for certain amounts of excess coverage and certain physical damage risk. If a significant accident or other event occurs and is not fully covered by insurance or contractual indemnity, it could adversely affect our financial position, results of operations and cash flows. There can be no assurance that we will continue to carry the insurance we currently maintain or that those parties with contractual obligations to indemnify us will necessarily be financially able to indemnify us against all these risks. In addition, no assurance can be made that we will be able to maintain adequate insurance in the future at rates we consider to be reasonable or that we will be able to obtain insurance against some risks.

We 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 or 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, 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;
	•		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.

     As of the date of this report, the greatest concentration of our operating assets outside the United States was offshore Brazil, where we had 12 rigs in our fleet either currently working or contracted to work during 2010.

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 and operating structures 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 our operational structure, intercompany pricing policies or the taxable presence of our key subsidiaries in certain countries; or if the terms of certain income tax treaties are interpreted in a manner that is adverse to our structure; 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. During 2007, DOIL made a non-recurring distribution to its U.S. parent company, and we recognized U.S. federal income tax expense on the portion of the distribution that consisted of earnings of the subsidiary that had not previously been subjected to U.S. federal income tax. Notwithstanding the non-recurring distribution made in December 2007, it remains our intention to indefinitely reinvest the future earnings of DOIL to finance foreign activities, except for the earnings of Diamond East Asia Limited, or DEAL, a wholly-owned subsidiary of DOIL formed in December 2008. 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.

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

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

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

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

We may be subject to litigation that could have an adverse effect on us.

     We are, from time to time, involved in various litigation matters. These matters may include, among other things, contract disputes, personal injury claims, environmental claims or proceedings, asbestos and other toxic tort claims, employment and tax matters and other litigation that arises in the ordinary course of our business. Although we intend to defend these matters vigorously, we cannot predict with certainty the outcome or effect of any claim or other litigation matter, and there can be no assurance as to the ultimate outcome of any litigation. Litigation may have an adverse effect on us because of potential adverse outcomes, defense costs, the diversion of our management’s resources and other factors.

Governmental laws and regulations may add to our costs or limit our drilling activity.

     Our operations are affected from time to time in varying degrees by governmental laws and regulations. The drilling industry is dependent on demand for services from the oil and gas exploration industry and, accordingly, is affected by changing tax and other laws relating to the energy business generally. We may be required to make significant capital expenditures to comply with governmental laws and regulations. It is also possible that these laws and regulations may in the future add significantly to our operating costs or may significantly limit drilling activity.

     Governments in some foreign countries are increasingly active in regulating and controlling the ownership of concessions, the exploration for oil and gas and other aspects of the oil and gas industries. The modification of existing laws or regulations or the adoption of new laws or regulations curtailing exploratory or developmental drilling for oil and gas for economic, environmental or other reasons could materially and adversely affect our operations by limiting drilling opportunities.

     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-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 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.

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

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

     In the United States and in many of the international locations in which we operate, regulations controlling the discharge of materials into the environment, requiring removal and cleanup of materials that may harm the environment or otherwise relating to the protection of the environment apply to some of our operations. For example, we, as an operator of mobile offshore drilling units in navigable United States waters and some offshore areas, may be liable for damages and costs incurred in connection with oil spills related to those operations. Laws and regulations protecting the environment have become increasingly stringent, and may in some cases impose “strict liability,” rendering a person liable for environmental damage without regard to negligence or fault on the part of that person. These laws and regulations may expose us to liability for the conduct of or conditions caused by others or for acts that were in compliance with all applicable laws at the time they were performed.

     The United States Oil Pollution Act of 1990, or OPA ’90, and similar legislation enacted in Texas, Louisiana and other coastal states, addresses oil spill prevention and control and significantly expands liability exposure across all segments of the oil and gas industry. OPA ’90 and such similar legislation and related regulations impose a variety of obligations on us related to the prevention of oil spills and liability for damages resulting from such spills. OPA ‘90 imposes strict and, with limited exceptions, joint and several liability upon each responsible party for oil removal costs and a variety of public and private damages.

     The application of these requirements or the adoption of new requirements could have a material adverse effect on our financial position, results of operations and cash flows.

Failure to obtain and retain highly skilled personnel could hurt our operations.

     We require highly skilled personnel to operate and provide technical services and support for our business. To the extent that demand for drilling services and the size of the worldwide industry fleet increase (including the impact of newly constructed rigs), shortages of qualified personnel could arise, creating upward pressure on wages and difficulty in staffing and servicing our rigs, which could adversely affect our results of operations. In addition, the entrance of new participants into the offshore drilling market would cause further competition for qualified and experienced personnel as these entities seek to hire personnel with expertise in the offshore drilling industry. 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.

     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, 2009, 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 19, 2010 and is in a position to control actions that require the consent of stockholders, including the election of directors, amendment of our Restated Certificate of Incorporation and any merger or sale of substantially all of our assets. In addition, three officers of Loews serve on our Board of Directors. One of those, James S. Tisch, the Chairman of the Board of our company, is also the Chief Executive Officer and a director of Loews. We have also entered into a services agreement and a registration rights agreement with Loews and we may in the future enter into other agreements with Loews.

     Loews and its subsidiaries and we are generally engaged in businesses sufficiently different from each other as to make conflicts as to possible corporate opportunities unlikely. However, it is possible that Loews may in some circumstances be in direct or indirect competition with us, including competition with respect to certain business strategies and transactions that we may propose to undertake. In addition, potential conflicts of interest exist or could arise in the future for our directors who are also officers of Loews with respect to a number of areas relating to the past and ongoing relationships of Loews and us, including tax and insurance matters, financial commitments and sales of common stock pursuant to registration rights or otherwise. Although the affected directors may abstain from voting on matters in which our interests and those of Loews are in conflict so as to avoid potential violations of their fiduciary duties to stockholders, the presence of potential or actual conflicts could affect the process or outcome of Board deliberations. We cannot assure you that these conflicts of interest will not materially adversely affect us.

Item 1B. Unresolved Staff Comments.

     Not applicable.

Item 2. Properties.

     We own an eight-story office building containing approximately 182,000-net rentable square feet on approximately 6.2 acres of land located in Houston, Texas, where our corporate headquarters are located, two buildings totaling 39,000 square feet and 20 acres of land in New Iberia, Louisiana, for our offshore drilling warehouse and storage facility, a 13,000-square foot building and five acres of land in Aberdeen, Scotland, for our North Sea operations and two buildings totaling 65,000 square feet and 11 acres of land in Macae, Brazil, for our South American operations. Additionally, we currently lease various office, warehouse and storage facilities in Louisiana, Australia, Brazil, Indonesia, Norway, The Netherlands, Malaysia, Singapore, Egypt, Angola, Vietnam and Mexico to support our offshore drilling operations.

Item 3. Legal Proceedings.

     Not applicable.

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

     Not applicable.

Executive Officers of the Registrant

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

		Age as of
Name		January 31, 2010				Position
Lawrence R. Dickerson			57			President, Chief Executive Officer and Director
John M. Vecchio			59			Executive Vice President
Gary T. Krenek			51			Senior Vice President and Chief Financial Officer
William C. Long			43			Senior Vice President, General Counsel & Secretary
Beth G. Gordon			54			Controller – Chief Accounting Officer
Lyndol L. Dew			55			Senior Vice President – Worldwide Operations
Robert G. Blair			58			Senior Vice President – Contracts & Marketing

     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.

     Robert G. Blair has served as a Senior Vice President since July 2009. Mr. Blair previously served as our Vice President – Contracts & Marketing – North & South America from November 1999 to June 2009.

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

     As of February 19, 2010 there were approximately 218 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 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. In 2008, we paid regular cash dividends of $0.125 per share of our common stock on March 3, June 2, September 1 and December 1. We also paid special cash dividends in 2008 of $1.25 per share of our common stock on March 3, June 2 and September 1 and $1.875 per share of our common stock on December 1.

     On February 3, 2010, we declared a regular cash dividend and a special cash dividend of $0.125 and $1.875, respectively, per share of our common stock. Both the regular and special cash dividends are payable on March 1, 2010 to stockholders of record on February 12, 2010.

     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.

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, 2009.

Comparison of 2005 – 2009 Cumulative Total Return (1)

				Dec. 31,					Dec. 31,					Dec. 31,					Dec. 31,					Dec. 31,					Dec. 31,
				2004					2005					2006					2007					2008					2009
	Diamond Offshore				100					175					206					392					172					318
	S&P 500				100					105					121					128					81					102
	Peer Group (2)				100					147					156					212					86					148

          Our dividend history for the periods reported above is as follows:

				Q1										Q2										Q3										Q4
	Year			Regular					Special					Regular					Special					Regular					Special					Regular					Special
	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					—
	2005			$	0.063					—				$	0.063					—				$	0.125					—				$	0.125					—

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 four 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 all past periods presented below. See Note 1 “General Information” to our Consolidated Financial Statements included in Item 8 of this report.

		As of and for the Year Ended December 31,
						2008				2007				2006				2005
		2009				Adjusted				Adjusted				Adjusted				Adjusted
		(In thousands, except per share and ratio data)
Income Statement Data:
Total revenues		$	3,631,284			$	3,544,057			$	2,567,723			$	2,052,572			$	1,221,002
Operating income			1,903,213				1,910,194				1,223,044				940,029				373,996
Net income			1,376,219				1,310,547				844,464				699,088				243,293
Net income per share:
Basic			9.90				9.43				6.13				5.41				1.89
Diluted			9.89				9.42				6.11				5.14				1.88
Balance Sheet Data:
Drilling and other property and equipment, net		$	4,432,052			$	3,414,373			$	3,056,300			$	2,644,392			$	2,313,207
Total assets			6,264,261				4,954,431				4,357,702				4,148,006				3,616,921
Long-term debt (excluding current maturities) (1)			1,495,375				503,280				503,071				931,937				927,811
Other Financial Data:
Capital expenditures		$	1,362,468			$	666,857			$	647,877			$	556,392			$	294,388
Cash dividends declared per share			8.00				6.13				5.75				2.00				0.375
Ratio of earnings to fixed charges (2)			37.29	x			64.54	x			31.16	x			19.03	x			5.74	x

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 fleet of 47 offshore drilling rigs consists of 32 semisubmersibles, 14 jack-ups and one drillship.

Overview

Industry Conditions

     The global economy remained weak in the fourth quarter of 2009 and into the first quarter of 2010 and energy prices continued to be volatile. Given the unpredictable economic environment, the demand for our services and the dayrates we were able to command for new contracts softened. This volatility and uncertainty could continue until the global economy improves. Absent global economic improvement the decline in drilling activity could be further exacerbated by the influx of new-build rigs over the next several years, particularly in regard to jack-up units.

     We have experienced negative effects of the current market such as customer credit problems, customers attempting to renegotiate or terminate contracts, one customer seeking bankruptcy protection, a further slowing in the pace of new contracting activity, declines in dayrates for new contracts, declines in utilization and the stacking of idle equipment. Nevertheless, during 2009, we added new commitments to our contract backlog. We entered 2010 with a contract backlog approaching $8.5 billion, which we expect to help mitigate the impact of the current market on us in 2010.

     Floaters

     Approximately 81% of the time on our intermediate and high-specification floater rigs is committed for 2010. Additionally, 55% of the time on our floating rigs is committed in 2011.

     International Jack-ups

     The industry’s jack-up market is divided between an international sector and a U.S. sector, with the international sector historically characterized by contracts of longer duration and higher prices, compared to the generally shorter term and lower priced domestic sector. However, in 2009 demand and dayrates softened internationally as existing rigs rolled off contract and met competition from un-contracted new-build jack-ups that came to market. It is expected that this oversupply of jack-up rigs will have an increasingly negative impact on the international sector during 2010 and beyond.

     GOM Jack-ups

     In the domestic jack-up sector, lower natural gas prices have negatively impacted both demand and dayrates. In response, to reduce costs, we have cold-stacked three of our lower-end jack-up units, and they are not being actively marketed. Our four remaining higher-specification jack-ups in the GOM are largely working under short-term contracts. Absent a sustained improvement in energy prices, weakness in the GOM jack-up market is likely to continue in 2010, with the possibility of additional rigs being cold-stacked by the industry in an effort to help bring equipment supply and demand into equilibrium.

Contract Drilling Backlog

     The following table reflects our contract drilling backlog as of February 1, 2010, October 22, 2009 (the date reported in our Quarterly Report on Form 10-Q for the quarter ended September 30, 2009) and February 5, 2009 (the date reported in our Annual Report on Form 10-K for the year ended December 31, 2008). The October 2009 period includes both firm commitments (typically represented by signed contracts), as well as previously-disclosed letters of intent, or LOIs, where indicated. An LOI is subject to customary conditions, including the execution of a definitive agreement, and as such may not result in a binding contract. Contract drilling backlog is calculated by multiplying the contracted operating dayrate by the firm contract period and adding one-half of any potential rig performance bonuses. Our calculation also assumes full utilization of our drilling equipment for the contract period (excluding scheduled shipyard and survey days); however, the amount of actual revenue earned and the actual

periods during which revenues are earned will be different than the amounts and periods shown in the tables below due to various factors. Utilization rates, which generally approach 95-98% during contracted periods, can be adversely impacted by downtime due to various operating factors including, but not limited to, weather conditions and unscheduled repairs and maintenance. Contract drilling backlog excludes revenues for mobilization, demobilization, contract preparation and customer reimbursables. No revenue is generally earned during periods of downtime for regulatory surveys. Changes in our contract drilling backlog between periods are a function of the performance of work on term contracts, as well as the extension or modification of existing term contracts and the execution of additional contracts.

		February 1,				October 22,				February 5,
		2010(1) (2)				2009(3)				2009
		(In thousands)
Contract Drilling Backlog
High-Specification Floaters (1) (3)		$	4,177,000			$	4,450,000			$	4,448,000
Intermediate Semisubmersibles (2)			4,030,000				4,061,000				5,985,000
Jack-ups			249,000				249,000				421,000
Total		$	8,456,000			$	8,760,000			$	10,854,000

     The following table reflects the amount of our contract drilling backlog by year as of February 1, 2010.

		For the Years Ending December 31,
		Total				2010				2011				2012				2013 – 2016
		(In thousands)
Contract Drilling Backlog
High-Specification Floaters (1)		$	4,177,000			$	1,536,000			$	1,245,000			$	570,000			$	826,000
Intermediate Semisubmersibles (2)			4,030,000				1,393,000				1,026,000				860,000				751,000
Jack-ups			249,000				210,000				39,000				—				—
Total		$	8,456,000			$	3,139,000			$	2,310,000			$	1,430,000			$	1,577,000

     The following table reflects the percentage of rig days committed by year as of February 1, 2010. 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). Total available days have been calculated based on the expected final commissioning date for the Ocean Valor.

		For the Years Ending December 31,
		2010				2011				2012				2013 – 2016
Rig Days Committed (1)
High-Specification Floaters			84	%			57	%			27	%			10	%
Intermediate Semisubmersibles			78	%			54	%			44	%			10	%
Jack-ups			42	%			6	%			—				—

Casualty Loss

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

     In December 2008, we entered into an agreement to sell the Ocean Tower and transferred the $32.2 million net book value of the rig to “Assets held for sale” in our Consolidated Balance Sheets included in Item 8 of this report. The sale of the Ocean Tower was completed on October 26, 2009, and we recognized a $6.7 million gain on the sale which has been presented as “Gain on disposition of assets” in our Consolidated Statements of Operations for the year ended December 31, 2009 included in Item 8 of this report. The agreement prohibited the competitive use of the rig, which is expected to be deployed by the purchaser as an accommodation unit.

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 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.

     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.

     For 2010, we expect depreciation expense to increase approximately $26.6 million compared to 2009, due to the 2009 acquisitions of the Ocean Courage and Ocean Valor. See “ – Sources of Liquidity and Capital Resources – Liquidity and Capital Requirements – Capital Expenditures.”

     Periods of high, sustained utilization may result in cost increases for maintenance and repairs in order to maintain our equipment in proper, working order. In addition, during periods of high activity and dayrates, higher prices generally pervade the entire offshore drilling industry and its support businesses, which causes our costs for goods and services to increase.

     Our operating income is negatively impacted when we perform certain regulatory inspections, which we refer to as a 5-year survey, or special survey, that are due every five years for each of our rigs. Operating revenue decreases because these surveys are performed during scheduled downtime in a shipyard. Operating expenses increase as a result of these surveys due to the cost to mobilize the rigs to a shipyard, inspection costs incurred and repair and maintenance costs. Repair and maintenance costs may be required resulting from the survey or may have been previously planned to take place during this mandatory downtime. The number of rigs undergoing a 5-year survey will vary from year to year, as well as from quarter to quarter.

     In addition, operating income may be negatively impacted by intermediate surveys, which are performed at interim periods between 5-year surveys. Intermediate surveys are generally less extensive in duration and scope than a 5-year survey. Although an intermediate survey may require some downtime for the drilling rig, it normally does not require dry-docking or shipyard time, except for rigs located in the U.K. and Norwegian sectors of the North Sea.

     During 2010, five of our rigs will require 5-year surveys, and we expect that they will be out of service for approximately 320 days in the aggregate. We also expect to spend an additional approximately 730 days during 2010 for intermediate surveys, the mobilization of rigs, commissioning and 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 or cash flows. However, under our current insurance policy that expires on May 1, 2010, we continue to 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.

     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 years ended December 31, 2008 and 2007, we capitalized interest of $16.9 million and $19.3 million, respectively, on qualifying expenditures related to the upgrades of the Ocean Endeavor and 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. The upgrades of the Ocean Endeavor and Ocean Monarch were completed in March 2007 and December 2008, respectively. Construction of the Ocean Shield and Ocean Scepter was completed in May 2008 and August 2008, respectively. We did not capitalize interest on any qualifying assets during 2009.

     Interest Expense. We expect interest expense in 2010 to increase approximately $32.5 million compared to 2009 as a result of our issuance of $500.0 million in aggregate principal amount of 5.70% Senior Notes due 2039, or 5.70% Senior Notes, in October 2009 and $500.0 million aggregate principal amount of 5.875% Senior Notes due 2019, or 5.875% Senior Notes, in May 2009. See “ – Sources of Liquidity and Capital Resources – Liquidity and Capital Requirements – 5.70% Senior Notes” and “ – Sources of Liquidity and Capital Resources – Liquidity and Capital Requirements – 5.875% Senior Notes.” Also see Note 10 “Long-Term Debt” to our Consolidated Financial Statements in Item 8 of this report.

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 the 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 include the following:

•

dayrate by rig;

•

utilization rate by rig (expressed as the actual percentage of time per year that the rig would be used);

•

the per day operating cost for each rig if active, ready-stacked or cold-stacked; and

•

salvage value for each rig.

     Based on these assumptions and estimates, we develop a matrix by assigning probabilities to various combinations of assumed utilization rates and dayrates. We also consider the impact of a 5% reduction in assumed dayrates for the cold-stacked rigs (holding all other assumptions and estimates in the model constant), or alternatively the impact of a 5% reduction in utilization (again holding all other assumptions and estimates in the model constant) as part of our analysis.

     As of December 31, 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 have concluded that these four rigs were not subject to impairment at December 31, 2009.

     At December 31, 2009, the remaining rigs in our fleet were currently working under contract, mobilizing to new locations or being actively marketed. We do not believe that current circumstances indicate that there was an impairment of these 43 rigs at December 31, 2009.

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

     Personal Injury Claims. Our deductible for liability coverage for personal injury claims, which primarily result from Jones Act liability in the Gulf of Mexico, is $5.0 million per occurrence, with no aggregate deductible. The Jones Act is a federal law that permits seamen to seek compensation for certain injuries during the course of their employment on a vessel and governs the liability of vessel operators and marine employers for the work-related injury or death of an employee. We estimate our aggregate reserve for personal injury claims based on our historical losses and utilizing various actuarial models.

     The eventual settlement or adjudication of these claims could differ materially from our estimated amounts due to uncertainties such as:

	•		the severity of personal injuries claimed;
	•		significant changes in the volume of personal injury claims;
	•		the unpredictability of legal jurisdictions where the claims will ultimately be litigated;
	•		inconsistent court decisions; and
	•		the risks and lack of predictability inherent in personal injury litigation.

     Income Taxes. We account for income taxes in accordance with 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.

     We record interest related to accrued unrecognized tax positions in interest expense and recognize penalties associated with uncertain tax positions in our tax expense.

Results of Operations

     Although we perform contract drilling services with different types of drilling rigs and in many geographic locations, there is a similarity of economic characteristics among all our divisions and locations, including the nature of services provided and the type of customers for our services. We believe that the combination of our drilling rigs into one reportable segment is the appropriate aggregation in accordance with 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, 2009 and 2008

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

		Year Ended
		December 31,								Favorable/
		2009				2008				(Unfavorable)
						(In thousands)
CONTRACT DRILLING REVENUE
High-Specification Floaters		$	1,380,771			$	1,322,125			$	58,646
Intermediate Semisubmersibles			1,698,584				1,629,358				69,226
Jack-ups			457,224				524,934				(67,710	)
Total Contract Drilling Revenue		$	3,536,579			$	3,476,417			$	60,162
Revenues Related to Reimbursable Expenses		$	94,705			$	67,640			$	27,065
CONTRACT DRILLING EXPENSE
High-Specification Floaters		$	407,203			$	367,531			$	(39,672	)
Intermediate Semisubmersibles			557,634				581,161				23,527
Jack-ups			235,924				224,365				(11,559	)
Other			23,010				11,950				(11,060	)
Total Contract Drilling Expense		$	1,223,771			$	1,185,007			$	(38,764	)
Reimbursable Expenses		$	93,097			$	65,895			$	(27,202	)
OPERATING INCOME
High-Specification Floaters		$	973,568			$	954,594			$	18,974
Intermediate Semisubmersibles			1,140,950				1,048,197				92,753
Jack-ups			221,300				300,569				(79,269	)
Other			(23,010	)			(11,950	)			(11,060	)
Reimbursable expenses, net			1,608				1,745				(137	)
Depreciation			(346,446	)			(287,417	)			(59,029	)
General and administrative expense			(62,913	)			(60,142	)			(2,771	)
Bad debt expense			(9,746	)			(31,952	)			22,206
Casualty loss			—				(6,281	)			6,281
Gain on disposition of assets			7,902				2,831				5,071
Total Operating Income		$	1,903,213			$	1,910,194			$	(6,981	)
Other income (expense):
Interest income			4,497				11,744				(7,247	)
Interest expense			(49,610	)			(10,096	)			(39,514	)
Foreign currency transaction gain (loss)			11,483				(65,566	)			77,049
Other, net			(1,152	)			770				(1,922	)
Income before income tax expense			1,868,431				1,847,046				21,385
Income tax expense			(492,212	)			(536,499	)			44,287
NET INCOME		$	1,376,219			$	1,310,547			$	65,672

     Operating income in 2009 decreased $7.0 million, or less than 1%, compared to 2008. During 2009, our contracted revenue backlog allowed us to partially mitigate the impact of the global economic recession on our business. Despite the downturn in the market, our contract drilling revenues increased $60.2 million in 2009 compared to 2008. The Ocean Monarch, which began service in mid-March 2009 after completing a major upgrade, generated revenues of $124.5 million during 2009. Our two new-build jack-up rigs, the Ocean Shield and Ocean Scepter, contributed additional revenues of $90.1 million during 2009 compared to 2008. However, our operating results were negatively impacted by 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 is currently being prepared for cold-stacking in Malaysia. In addition, the international jack-up market, which had remained strong throughout the majority of 2008, continued to be affected by softening demand and reduced dayrates during 2009.

     Total contract drilling expenses in 2009 increased $38.8 million, or 3% compared to 2008. Operating costs during 2009 include normal operating costs for the upgraded Ocean Monarch and a full year of operating costs for our two new-build jack-ups.

     Depreciation expense increased $59.0 million to $346.4 million during 2009, or 21% 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 newly acquired Ocean Courage. See “—Sources of Liquidity and Capital Resources – Liquidity and Capital Requirements – Capital Expenditures.”

High-Specification Floaters.

		Year Ended
		December 31,								Favorable/
		2009				2008				(Unfavorable)
		(In thousands)
HIGH-SPECIFICATION FLOATERS:
CONTRACT DRILLING REVENUE
GOM		$	943,024			$	1,051,178			$	(108,154	)
Australia/Asia/Middle East			153,757				69,419				84,338
Europe/Africa/Mediterranean			66,156				—				66,156
South America			217,834				201,528				16,306
Total Contract Drilling Revenue		$	1,380,771			$	1,322,125			$	58,646
CONTRACT DRILLING EXPENSE
GOM		$	250,025			$	223,954			$	(26,071	)
Australia/Asia/Middle East			34,144				35,079				935
Europe/Africa/Mediterranean			14,037				—				(14,037	)
South America			108,997				108,498				(499	)
Total Contract Drilling Expense		$	407,203			$	367,531			$	(39,672	)
OPERATING INCOME		$	973,568			$	954,594			$	18,974

     GOM. Revenues generated by our high-specification floaters operating in the GOM decreased $108.2 million during 2009 compared to 2008. Excluding the Ocean Monarch, our GOM fleet had approximately 700 fewer rig operating days in 2009, compared to the prior year, resulting in a $283.7 million reduction in revenues generated by the fleet in 2009. The decrease in utilization is attributable to incremental downtime associated with contract preparation activities and subsequent relocation out of the GOM of two of our high-specification floaters, the Ocean Quest (to Brazil late in the first quarter of 2009) and the Ocean Valiant (to Angola during the third quarter of 2009) and scheduled surveys and related repairs. In addition, two of our rigs were ready stacked for a total of 245 days in 2009 compared to zero ready-stack days in 2008.

     Average operating revenue per day for our high-specification floaters in this market (excluding the Ocean Monarch) increased to $417,100 in 2009 compared to $394,100 in 2008, resulting in the generation of additional revenues of $51.1 million.

     Operating costs for our high-specification floaters in the GOM increased by $26.1 million in 2009 compared to 2008 to $250.0 million. The overall increase in operating costs in 2009 was primarily due to higher survey, repair and mobilization costs associated with a special survey for the Ocean America. These cost increases were partially offset by lower operating costs in the region for the Ocean Quest and Ocean Valiant, which we relocated to Brazil and Angola, respectively.

     The Ocean Monarch, which began operating in the GOM late in the first quarter of 2009, generated revenues and incurred operating expenses, including the amortization of deferred mobilization costs, of $124.5 million and $28.1 million, respectively.

     Australia/Asia/Middle East. During 2009, our high-specification rig operating offshore Malaysia, the Ocean Rover, generated $84.3 million in additional revenues compared to 2008 primarily due to an increase in average operating revenue per day from $237,200 during 2008 to $433,700 during 2009 ($69.7 million). Utilization increased in 2009 compared to 2008, when the rig had 67 days of scheduled downtime for a special survey and related repairs, resulting in the generation of $14.6 million in incremental revenues.

     Europe/Africa/Mediterranean. The Ocean Valiant began operating offshore Angola in the third quarter of 2009 and generated revenues and incurred operating expenses of $66.2 million and $14.0 million, respectively.

     South America. Revenues earned by our high-specification floaters operating offshore Brazil in 2009 increased $16.3 million compared to 2008. The Ocean Quest, which we relocated from the GOM late in the first quarter of 2009, generated additional revenues in 2009 of $90.3 million compared to 2008. Increased utilization in 2009 of the Ocean Clipper, which experienced significant downtime during 2008 for a survey and unplanned repairs to its propulsion system, generated incremental revenues of $17.3 million compared to 2008. However, total revenues generated in the region were negatively impacted by a decline in average operating revenue per day for the Ocean Alliance from $443,600 in 2008 to $187,200 in 2009, resulting in an $84.8 million reduction in revenues.

     Contract drilling expense for our operations in Brazil increased slightly in 2009 by $0.5 million compared to 2008, primarily due to the inclusion of normal operating costs for the Ocean Quest partially offset by a reduction in costs attributable to a 2008 survey of the Ocean Clipper and repairs to its propulsion system.

Intermediate Semisubmersibles.

		Year Ended
		December 31,								Favorable/
		2009				2008				(Unfavorable)
		(In thousands)
INTERMEDIATE SEMISUBMERSIBLES:
CONTRACT DRILLING REVENUE
GOM		$	132,195			$	134,880			$	(2,685	)
Mexico			217,628				220,754				(3,126	)
Australia/Asia/Middle East			423,117				395,124				27,993
Europe/Africa/Mediterranean			481,944				518,382				(36,438	)
South America			443,700				360,218				83,482
Total Contract Drilling Revenue		$	1,698,584			$	1,629,358			$	69,226
CONTRACT DRILLING EXPENSE
GOM		$	32,184			$	44,902			$	12,718
Mexico			46,769				54,187				7,418
Australia/Asia/Middle East			119,674				141,170				21,496
Europe/Africa/Mediterranean			137,542				167,786				30,244
South America			221,465				173,116				(48,349	)
Total Contract Drilling Expense		$	557,634			$	581,161			$	23,527
OPERATING INCOME		$	1,140,950			$	1,048,197			$	92,753

     GOM. Revenues generated by our intermediate semisubmersible fleet operating in the GOM in 2009 decreased $2.7 million compared to 2008. The decrease in revenues is primarily due to a decrease in operating dayrate earned by the Ocean Saratoga in 2009 compared to 2008 ($20.8 million). The Ocean Ambassador, which relocated to the GOM from Mexico in the second quarter of 2008, earned incremental revenues of $18.9 million in the GOM in 2009 prior to its relocation to the Brazil market late in the second quarter of 2009.

     During 2008, we had three rigs at various times either operating or undergoing surveys or shipyard projects in the GOM compared with only two rigs operating in the GOM for all or part of 2009. The decrease in the number of rigs in the GOM between 2008 and 2009, combined with the absence of survey-related costs in 2009, resulted in a $12.7 million reduction in operating costs in the region compared to the prior year.

     Mexico. Revenues generated and contract drilling expense incurred by our intermediate semisubmersibles operating offshore Mexico decreased $3.1 million and $7.4 million, respectively, during 2009 compared to 2008, primarily due to the relocation of the Ocean Ambassador to the GOM, which resulted in a reduction in 2009 revenues and operating expenses of $13.2 million and $8.0 million, respectively. The decline in 2009 revenues was partially offset by an increase in average operating revenue per day in 2009 compared to 2008 for both of our intermediate semisubmersibles operating for PEMEX as a result of an unfavorable reserve for disputed downtime recorded in December 2008.

     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. An increase in average operating revenue per day from $306,600 in 2008 to $333,700 in 2009 generated additional revenues of $41.6 million in 2009.

     Average utilization of our intermediate semisubmersible fleet in the region remained constant at 87% for both 2008 and 2009; however, downtime incurred in 2009, combined with reduced dayrates earned by the individual rigs, resulted in a $9.1 million reduction in 2009 revenues compared to 2008. The Ocean Bounty was stacked after completion of its contract offshore Australia at the beginning of the third quarter of 2009, resulting in a $40.6 million reduction in revenues compared to 2008. The negative impact on revenues from stacking the Ocean Bounty was partially offset by an increase in rig operating days for the Ocean Patriot and Ocean General that resulted in the generation of $34.6 million in incremental revenues during 2009.

     Contract drilling expense for the Australia/Asia/Middle East region decreased $21.5 million in 2009 compared to 2008, primarily due to the absence of costs associated with the 2008 special surveys of the Ocean Patriot and Ocean General and reduced costs for the Ocean Bounty, which completed drilling operations offshore Australia in July 2009.

     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. Our North Sea fleet (both U.K. and Norwegian sectors) generated $14.8 million less in revenues in 2009 compared to 2008 due to 129 fewer rig operating days in 2009 compared to 2008. Rig operating days decreased in 2009 as a result of the early termination of a drilling contract for the Ocean Nomad and intermittent work for the Ocean Guardian prior to its departure for the Falkland Islands, partially offset by reduced downtime for the Ocean Princess, which completed its 2008 special survey in early 2009. The impact of the reduction in rig operating days was partially offset by an increase in average operating revenue per day for our North Sea fleet from $321,200 in 2008 to $344,000 in 2009.

     The Ocean Lexington operated offshore Egypt during 2008 through August 2009, and in September 2009, the rig was mobilized to a shipyard in Cadiz, Spain for contract preparation activities in connection with a contract offshore Brazil. Revenues generated by the Ocean Lexington in 2009 decreased $21.6 million compared to 2008 due to 103 fewer rig operating days in 2009, partially offset by higher average operating revenue per day earned in 2009 as compared to the prior year. At December 31, 2009, the Ocean Lexington was en route to Brazil.

     Contract drilling expense for our intermediate semisubmersible rigs operating in the Europe/Africa/Mediterranean markets 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, 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 due to fewer rigs undergoing surveys in 2009 than in 2008. In addition, operating costs in this region decreased as a result of the relocation of the Ocean Lexington to a Spanish shipyard in September 2009.

     South America. Revenues generated by our intermediate semisubmersibles working in the South American region increased $83.5 million in 2009 compared to 2008. At December 31, 2009, we had seven intermediate semisubmersible rigs operating offshore Brazil and another rig, the intermediate semisubmersible Ocean Lexington, undergoing contract modification activities and mobilizing to Brazil. During 2009, our Brazilian intermediate semisubmersible fleet logged 1,996 rig operating days and earned average operating revenue per day of $217,400 compared to 1,425 rig operating days and average operating revenue per day of $177,600 in 2008. This increase in rig operating days and average operating revenue per day for our operations offshore Brazil combined to generate additional revenues of $185.4 million in 2009 compared to 2008. During 2008, the Ocean Worker earned $101.9 million operating offshore Trinidad and Tobago prior to mobilizing to Brazil in the third quarter of 2008. The Ocean Worker did not begin drilling operations offshore Brazil until March 2009.

     Contract drilling expense for our intermediate semisubmersibles operating in the South American region increased $48.3 million in 2009 compared to 2008. The increase in costs in the South American region reflects the increase in number of rigs in the region, including higher maintenance and other costs associated with customer acceptance testing and the amortization of costs associated with the mobilization of our rigs into the region, shorebase support costs and revenue-based agency fees. In addition, the increased operating costs reflect higher freight and customs charges that are inherent in operations in the region.

Jack-Ups.

		Year Ended
		December 31,								Favorable/
		2009				2008				(Unfavorable)
		(In thousands)
JACK-UPS:
CONTRACT DRILLING REVENUE
GOM		$	63,016			$	189,500			$	(126,484	)
Mexico			105,431				105,055				376
Australia/Asia/Middle East			140,783				92,596				48,187
Europe/Africa/Mediterranean			93,080				115,652				(22,572	)
South America			54,914				22,131				32,783
Total Contract Drilling Revenue		$	457,224			$	524,934			$	(67,710	)
CONTRACT DRILLING EXPENSE
GOM		$	72,454			$	99,533			$	27,079
Mexico			38,209				33,303				(4,906	)
Australia/Asia/Middle East			50,097				42,184				(7,913	)
Europe/Africa/Mediterranean			38,896				35,058				(3,838	)
South America			36,268				14,287				(21,981	)
Total Contract Drilling Expense		$	235,924			$	224,365			$	(11,559	)
OPERATING INCOME		$	221,300			$	300,569			$	(79,269	)

     GOM. Revenue generated by our jack-up rigs operating in the GOM decreased $126.5 million during 2009 compared to 2008. Average utilization decreased from 91% in 2008 to 39% in 2009 due to a decrease in demand for rigs in the GOM, and resulted in a $90.9 million decrease in revenues. Our jack-up fleet in the GOM had 1,011 ready- and cold-stacked days during 2009 compared to 22 ready-stacked days in 2008. In addition, we relocated the Ocean Summit to Mexico for a contract with PEMEX at the beginning of the third quarter of 2009. The Ocean Tower, prior to being taken out of service due to damage sustained in a hurricane in the third quarter of 2008, generated revenues of $34.3 million in 2008.

     As a result of the depressed GOM market, in 2009 we elected to cold stack and no longer actively market our three mat-supported jack-ups in this region.

     Contract drilling expense for our jack-ups operating in the GOM decreased $27.1 million in 2009 compared to 2008, primarily due to significantly reduced operating costs for the Ocean Tower (prior to its sale in October 2009) and our three cold-stacked rigs. The decline in operating costs was partially offset by 2009 survey and repair costs for the Ocean Titan and Ocean Summit and demobilization costs for the Ocean Columbia associated with its relocation from Mexico to the GOM in the fourth quarter of 2009 for a shipyard project.

     Mexico. Revenue and contract drilling expense generated by our jack-up rigs operating in Mexico increased $0.4 million and $4.9 million, respectively. The relatively stable revenues generated by our jack-up fleet offshore Mexico reflects incremental revenues generated by the Ocean Summit beginning in the third quarter of 2009, partly offset by a reduction in revenues generated by the Ocean Columbia, which completed its contract with PEMEX at the beginning of the fourth quarter of 2009. Revenues were further reduced, compared to 2008, due to a contract extension for the Ocean Nugget until 2011, but at a lower dayrate than it previously earned. The increase in contract drilling expense was primarily due to contract preparations and customer acceptance of the Ocean Summit, as well as the inclusion of normal operating costs, 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, including $57.3 million of incremental revenues earned by the Ocean Shield, which began operating in the region late in the second quarter of 2008. The Ocean Heritage, which generated $11.8 million in revenues in 2008, completed its contract offshore Qatar during the first quarter of 2008 and was relocated to Egypt in late June 2008.

     Contract drilling expense in the Australia/Asia/Middle East region increased $7.9 million in 2009 compared to 2008 primarily due to the inclusion of normal operating costs for the Ocean Shield for a full year in 2009 and costs associated with a survey and shipyard project for the Ocean Sovereign. The increased costs were partially offset by the absence of operating costs for the Ocean Heritage in 2009.

     Europe/Africa/Mediterranean. Revenues 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 an $18.2 million reduction in revenues generated by the Ocean Spur in 2009. The Ocean Spur operated offshore Egypt during both 2009 and 2008; however, average operating revenue per day for the Ocean Spur decreased to $107,700 in 2009 from $152,700 in 2008, while utilization increased to nearly 100% in 2009 compared to 91% in 2008. During 2008, we recognized a $6.5 million lump-sum demobilization fee earned by the Ocean Spur upon completion of its initial contract offshore Egypt.

     The $3.8 million increase in operating expense in the region in 2009 compared to 2008 is primarily attributable to the inclusion of a full year of operating costs in 2009 for the Ocean Heritage, which relocated from Qatar in the second quarter of 2008.

     South America. Our newly constructed jack-up rig, the Ocean Scepter, began operating offshore Argentina late in the third quarter of 2008. Our operations offshore Argentina generated $54.9 million in revenues and incurred $36.3 million in contract drilling expense during 2009. The Ocean Scepter completed its contract in July 2009.

Other Contract Drilling Expense.

     Other contract drilling expense increased $11.1 million in 2009 compared to 2008 primarily due to an increase in labor and overhead costs associated with rig-based training and a higher usage of fleet spare parts and supplies inventories.

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). 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.

Casualty Loss.

     During 2008, we wrote off certain equipment that was damaged during Hurricane Ike, including the net book value of approximately $2.6 million of the Ocean Tower’s derrick, drill floor and related equipment lost in the storm, and we 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 includes 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 is primarily the result of lower average interest-bearing cash balances during 2009 compared to 2008.

Interest Expense.

     Interest expense in 2009 and 2008 relates primarily to interest accrued on our outstanding indebtedness, net of capitalized interest, and our liabilities for uncertain tax positions. During 2009, we incurred interest expense of $19.6 million related to our 5.875% Senior Notes issued in May 2009 and $6.6 million related to our 5.70% Senior Notes issued in October 2009 partially offset by a net $3.4 million reduction in accrued interest expense related to uncertain tax positions. See “ – Income Tax Expense.”. During 2008, we 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 2009.

Foreign Currency Transaction Gain (Loss).

     Foreign currency transaction gains (losses) include 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. Prior to May 1, 2009, we did not designate any of our FOREX contracts as accounting hedges.

     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) 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, including $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 settlement of 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, respectively, 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.

     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 formed in December 2008. It is our intention to repatriate the earnings of DEAL and, accordingly, U.S. income taxes are provided on its earnings. 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. Consequently, we have 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.

Years Ended December 31, 2008 and 2007

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

		Year Ended
		December 31,								Favorable/
		2008				2007				(Unfavorable)
		(In thousands)
CONTRACT DRILLING REVENUE
High-Specification Floaters		$	1,322,125			$	1,030,892			$	291,233
Intermediate Semisubmersibles			1,629,358				1,028,667				600,691
Jack-ups			524,934				446,104				78,830
Total Contract Drilling Revenue		$	3,476,417			$	2,505,663			$	970,754
Revenues Related to Reimbursable Expenses		$	67,640			$	62,060			$	5,580
CONTRACT DRILLING EXPENSE
High-Specification Floaters		$	367,531			$	318,555			$	(48,976	)
Intermediate Semisubmersibles			581,161				482,464				(98,697	)
Jack-ups			224,365				183,024				(41,341	)
Other			11,950				19,746				7,796
Total Contract Drilling Expense		$	1,185,007			$	1,003,789			$	(181,218	)
Reimbursable Expenses		$	65,895			$	60,261			$	(5,634	)
OPERATING INCOME
High-Specification Floaters		$	954,594			$	712,337			$	242,257
Intermediate Semisubmersibles			1,048,197				546,203				501,994
Jack-ups			300,569				263,080				37,489
Other			(11,950	)			(19,746	)			7,796
Reimbursable expenses, net			1,745				1,799				(54	)
Depreciation			(287,417	)			(235,729	)			(51,688	)
General and administrative expense			(60,142	)			(53,483	)			(6,659	)
Bad debt expense			(31,952	)			—				(31,952	)
Casualty loss			(6,281	)			—				(6,281	)
Gain on disposition of assets			2,831				8,583				(5,752	)
Total Operating Income		$	1,910,194			$	1,223,044			$	687,150
Other income (expense):
Interest income			11,744				33,566				(21,822	)
Interest expense			(10,096	)			(21,878	)			11,782
Foreign currency transaction gain (loss)			(65,566	)			2,906				(68,472	)
Other, net			770				5,734				(4,964	)
Income before income tax expense			1,847,046				1,243,372				603,674
Income tax expense			(536,499	)			(398,908	)			(137,591	)
NET INCOME		$	1,310,547			$	844,464			$	466,083

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

     Total contract drilling revenues in 2008 increased $970.8 million, or 39% compared to 2007, to $3.5 billion. Average realized dayrates in 2008 in many of our floater markets increased as our rigs operated under contracts at higher dayrates than those earned during 2007, which resulted in the generation of additional contract drilling revenues. However, overall revenue increases for our floater fleet were negatively impacted by the effect of

downtime associated with scheduled shipyard projects and mandatory inspections or surveys. In addition, the GOM jack-up market, which had improved in early 2008 compared to the prior year, experienced reduced demand and dayrates by the end of 2008. The international jack-up market, which had been strong throughout the majority of 2008, also began to reflect softening demand and reduced dayrates by the end of 2008. Our GOM and international jack-up fleets earned lower dayrates during 2008 compared to 2007 despite a fleet-wide increase in utilization during 2008.

     Total contract drilling expense increased $181.2 million, or 18%, in 2008 compared to 2007. Overall cost increases for maintenance and repairs between the 2008 and 2007 periods reflected the impact of high, sustained utilization of our drilling units across our fleet, additional survey and related maintenance costs, contract preparation and mobilization costs, as well as the inclusion of normal operating costs for the Ocean Endeavor, Ocean Shield and Ocean Scepter. The increase in overall operating and overhead costs also reflected the impact of higher prices throughout the offshore drilling industry and its support businesses, including higher costs associated with hiring and retaining skilled personnel for our worldwide offshore fleet.

     Depreciation expense increased $51.7 million to $287.4 million during 2008, or 22% compared to 2007, due to a higher depreciable asset base.

     Our results during 2008 were negatively impacted by $54.0 million in losses on foreign currency forward exchange contracts not designated as accounting hedges included in “Foreign currency transaction gain (loss)”, a $31.9 million provision for bad debt expense related to one of our North Sea semisubmersible rigs that was contracted to a U.K. customer that had entered into administration under U.K. law and the recognition of a casualty loss aggregating $6.3 million in connection with damages sustained from Hurricane Ike. See “ – Overview – Casualty Loss.”

High-Specification Floaters.

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

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

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

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

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

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

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

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

Intermediate Semisubmersibles.

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

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

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

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

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

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

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

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

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

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

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

     South America. Revenues generated by our intermediate semisubmersibles working in the South American region increased $228.1 million during 2008 compared to 2007. During 2008, six of our rigs operated in the region compared to four rigs during 2007. Following the first quarter of 2007, we relocated the Ocean Whittington and Ocean Concord to Brazil and the Ocean Worker to Trinidad and Tobago where they generated additional aggregate revenues of $196.2 million in 2008. The Ocean Yorktown began operating in Brazil during the third quarter of 2008 and generated $30.4 million in revenues.

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

Jack-Ups.

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