Edgar Filing: DIAMOND OFFSHORE DRILLING INC

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UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K


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

For the fiscal year ended December 31, 2006


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

For the transition period from to

Commission file number 1-13926

DIAMOND OFFSHORE DRILLING, INC.

(Exact name of registrant as specified in its charter)


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

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

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

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


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

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

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

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

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

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one): Large Accelerated Filer þ Accelerated Filer o Non-Accelerated Filer 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, 2006				$4,956,973,448

Indicate the number of shares outstanding of each of the registrant’s classes of common stock, as of the latest practicable date.


As of February 20, 2007		Common Stock, $0.01 par value per share		138,347,072 shares

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the definitive proxy statement relating to the 2007 Annual Meeting of Stockholders of Diamond Offshore Drilling, Inc., which will be filed within 120 days of December 31, 2006, are incorporated by reference in Part III of this report.

DIAMOND OFFSHORE DRILLING, INC.
FORM 10-K for the Year Ended December 31, 2006

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		13

Item 2.	Properties		14

Item 3.	Legal Proceedings		14

Item 4.	Submission of Matters to a Vote of Security Holders		14

Part II
Item 5.	Market for the Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		16

Item 6.	Selected Financial Data		18

Item 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations		19

Item 7A.	Quantitative and Qualitative Disclosures About Market Risk		52

Item 8.	Financial Statements and Supplementary Data		54

	Consolidated Financial Statements		56
	Notes to Consolidated Financial Statements		61

Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		90

Item 9A.	Controls and Procedures		90

Item 9B.	Other Information		91

Part III
	Information called for by Part III Items 10, 11, 12, 13 and 14 has been omitted as the Registrant intends to file with the Securities and Exchange Commission not later than 120 days after the end of its fiscal year a definitive Proxy Statement pursuant to Regulation 14A.

Part IV
Item 15.	Exhibits and Financial Statement Schedules		91

Signatures			94

Exhibit Index			95
Supplemental Executive Retirement Plan
Employment Agreement - John M. Vecchio
Employment Agreement - William C. Long
Employment Agreement - Lyndol L. Dew
Employment Agreement - Mark F. Baudoin
Employment Agreement - Beth G. Gordon
Statement Re: Compuation of Ratios
List of Subsidiaries
Consent of Deloitte & Touche LLP
Powers of Attorney
Rule 13a-14(a) Certification of Chief Executive Officer
Rule 13a-14(a) Certification of Chief Financial Officer
Section 1350 Certification of the CEO and CFO

PART I

Item 1. Business.

General

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

The Fleet

Our fleet includes some of the most technologically advanced rigs in the world, enabling us to offer a broad range of services worldwide in various markets, including the deep water, harsh environment, conventional semisubmersible and jack-up markets.

Semisubmersibles. We own and operate 30 semisubmersibles, consisting of nine high-specification and 21 intermediate semisubmersible rigs. Semisubmersible rigs consist of an upper working and living deck resting on vertical columns connected to lower hull members. Such rigs operate in a “semi-submerged” position, remaining afloat, off bottom, in a position in which the lower hull is approximately 55 feet to 90 feet below the water line and the upper deck protrudes well above the surface. Semisubmersibles are typically anchored in position and remain stable for drilling in the semi-submerged floating position due in part to their wave transparency characteristics at the water line. Semisubmersibles can also be held in position through the use of a computer controlled thruster (dynamic-positioning) system to maintain the rig’s position over a drillsite. We have three semisubmersible rigs in our fleet with this capability.

Our high specification semisubmersibles have high-capacity deck loads and 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 29, 2007, seven of our nine high-specification semisubmersibles were located in the U.S. Gulf of Mexico, or GOM, while the remaining two rigs were located offshore Brazil and Malaysia.

Our intermediate semisubmersibles generally work in maximum water depths up to 4,000 feet, and many have diverse capabilities that enable them to provide both shallow and deep water service in the U.S. and in other markets outside the U.S. As of January 29, 2007, we had 19 intermediate semisubmersible rigs drilling offshore various locations around the world. Five of these semisubmersibles were located in the GOM; three were located in the Gulf of Mexico offshore Mexico, or Mexican GOM, four were located in the North Sea, two were located offshore Australia, two were located offshore Brazil and one was located offshore each of New Zealand, Vietnam and Egypt.

Our remaining two intermediate semisubmersibles, the Ocean Endeavor and Ocean Monarch, are currently in Singapore. The shipyard portion of the upgrade of the Ocean Endeavor has been completed, and the rig is currently undergoing sea trials and commissioning. The upgrade of the Ocean Monarch commenced in mid-2006. See “ — Fleet Enhancements and Additions.”

Jack-ups. We currently own and operate 13 jack-up drilling rigs. Jack-up rigs are mobile, self-elevating drilling platforms equipped with legs that are lowered to the ocean floor until a foundation is established to support the drilling platform. The rig hull includes the drilling rig, jacking system, crew quarters, loading and unloading facilities, storage areas for bulk and liquid materials, heliport and other related equipment. Our jack-ups are used for drilling in water depths from 20 feet to 350 feet. The water depth limit of a particular rig is principally determined by the length of the rig’s legs. A jack-up rig is towed to the drillsite with its hull riding in the sea, as a vessel, with its legs retracted. Once over a drillsite, the legs are lowered until they rest on the seabed and jacking continues until the hull is elevated above the surface of the water. After completion of drilling operations, the hull is lowered until it rests in the water and then the legs are retracted for relocation to another drillsite.

Most of our jack-up rigs are equipped with a cantilever system that enables the rig to cantilever or extend its drilling package over the aft end of the rig. This is particularly important when attempting to drill over existing platforms. Cantilever rigs have historically earned higher dayrates and achieved greater utilization compared to slot rigs.

As of January 29, 2007, nine of our 13 jack-up rigs were located in the GOM. Six of those rigs are independent-leg cantilevered units, two are mat-supported cantilevered units, and one is a mat-supported slot unit. Of our four remaining jack-up rigs, three are internationally based and are independent-leg cantilevered rigs; one was located offshore Indonesia, one was located offshore Africa and the other rig was located offshore Qatar. Our remaining jack-up rig was located in the Mexican GOM and is also an independent-leg cantilever unit.

In addition, we have two premium jack-up rigs currently under construction. We expect delivery of both of these units during the first quarter of 2008. See “ — Fleet Enhancements and Additions.”

Drillship. We have one high-specification drillship, the Ocean Clipper, which was located offshore Brazil as of January 29, 2007. 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.

Fleet Enhancements and Additions. Our strategy is to economically upgrade our fleet to meet customer demand for advanced, efficient, high-tech rigs, particularly deepwater semisubmersibles, in order to maximize the utilization and dayrates earned by the rigs in our fleet. Since 1995, we have increased the number of our rigs capable of operating in 3,500 feet or more of water from three rigs to 12 (nine of which are high-specification units), primarily by upgrading our existing fleet. Five of these upgrades were to our Victory-class semisubmersible rigs, the design of which we believe is well-suited for significant upgrade projects. We have recently completed the shipyard portion of the upgrade of one of our remaining Victory-class rigs and another upgrade is currently underway in Singapore. We have two additional Victory-class rigs that are currently operating as intermediate semisubmersibles.

In 2006, we began a major upgrade of the Ocean Monarch, a Victory-class semisubmersible that we acquired in August 2005 for $20.0 million. The modernized rig is being designed to operate in up to 10,000 feet of water in a moored configuration for an estimated cost of approximately $300 million. Through December 31, 2006, we had spent $33.9 million related to this project. The Ocean Monarch is expected to be ready for deepwater service in the fourth quarter of 2008.

In addition, the shipyard portion of the upgrade of the Ocean Endeavor has been completed. The rig is currently undergoing sea trials and commissioning. The unit will remain in Singapore until the arrival of a heavy-lift vessel, anticipated late in the first quarter of 2007, which will return the rig to the GOM. The Ocean Endeavor is expected to commence drilling operations in the GOM in mid-2007. We estimate that the total cost of the upgrade will be approximately $253 million of which $208.4 million had been spent through December 31, 2006.

In the second quarter of 2005, we entered into agreements to construct two high-performance, premium jack-up rigs. The two new drilling units, the Ocean Scepter and the Ocean Shield, are being constructed in Brownsville, Texas and Singapore, respectively, at an aggregate expected cost of approximately $320 million, including drill pipe and capitalized interest, of which $176.1 million had been spent through December 31, 2006. Each newbuild jack-up rig will be equipped with a 70-foot cantilever package, be capable of drilling depths of up to 35,000 feet and have a hook load capacity of two million pounds. We expect delivery of both of these units during the first quarter of 2008. See “Risk Factors” in Item 1A of this report.

We will evaluate further rig acquisition and upgrade opportunities as they arise. However, we can provide no assurance whether or to what extent we will continue to make rig acquisitions or upgrades to our fleet. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Requirements” in Item 7 of this report.

More detailed information concerning our fleet of mobile offshore drilling rigs, as of January 29, 2007, 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 (9):

Ocean Confidence

7,500

DP; 15K; 4M

2001

GOM

Ocean Baroness

7,000

VC; 15K; 4M

1973/2002

GOM

Amerada Hess

Ocean Rover

7,000

VC; 15K; 4M

1973/2003

Malaysia

Murphy Exploration

Ocean America

5,500

SP; 15K; 3M

1988/1999

GOM

Mariner Energy

Ocean Valiant

5,500

SP; 15K; 3M

1988/1999

GOM

Anadarko

Ocean Victory

5,500

VC; 15K; 3M

1972/1997

GOM

Dominion E&P

Ocean Star

5,500

VC; 15K; 3M

1974/1999

GOM

Anadarko

Ocean Alliance

5,000

DP; 15K; 3M

1988/1999

Brazil

Petrobras

Ocean Quest

3,500

VC; 15K; 3M

1973/1996

GOM

ATP Oil & Gas

Drillship (1):

Ocean Clipper

7,500

DP; 15K; 3M

1976/1999

Brazil

Petrobras

Intermediate Semisubmersibles (19):

Ocean Winner

4,000

1977/2004

Brazil

Petrobras

Ocean Worker

3,500

1982/1992

Mexican GOM

PEMEX

Ocean Yatzy

3,300

1989/1998

Brazil

Petrobras

Ocean Voyager

3,200

1973/1995

GOM

Woodside Energy

Ocean Patriot

3,000

15K; 3M

1982/2003

New Zealand

NZOP

Ocean Yorktown

2,200

1976/1996

Mexican GOM

PEMEX

Ocean Concord

2,200

1975/1999

GOM

Pogo Producing

Ocean Lexington

2,200

1976/1995

Egypt

BP Egypt

Ocean Saratoga

2,200

1976/1995

GOM

Shipyard; Life extension project

Ocean Epoch

1,640

1977/2000

Australia

Shell Australia

Ocean General

1,640

1976/1999

Vietnam

Premier Oil

Ocean Bounty

1,500

VC; 3M

1977/1992

Australia

Woodside Energy

Ocean Guardian

1,500

15K; 3M

1985

North Sea

Shell

Ocean New Era

1,500

1974/1990

GOM

W&T Offshore

Ocean Princess

1,500

15K; 3M

1977/1998

North Sea

Talisman

Ocean Whittington

1,500

1974/1995

GOM

Shipyard; Life extension project

Ocean Vanguard

1,500

15K; 3M

1982

North Sea

Total

Ocean Nomad

1,200

1975/2001

North Sea

Talisman

Ocean Ambassador

1,100

1975/1995

Mexican GOM

PEMEX

Jack-ups (13):

Ocean Titan

350

IC; 15K; 3M

1974/2004

GOM

Actively Marketing

Ocean Tower

350

IC; 3M

1972/2003

GOM

Chevron

Ocean King

300

IC; 3M

1973/1999

GOM

El Paso Production

Ocean Nugget

300

1976/1995

Mexican GOM

PEMEX

Ocean Summit

300

1972/2003

GOM

Newfield Exploration

Ocean Heritage

300

1981/2002

Qatar

Maersk Oil

Ocean Spartan

300

1980/2003

GOM

Walter Oil & Gas

Ocean Spur

300

1981/2003

Tunisia

Soco Tunisia

Ocean Sovereign

300

1981/2003

Indonesia

Kodeco

Ocean Champion

250

1975/2004

GOM

Apache

Ocean Columbia

250

1978/1990

GOM

Newfield Exploration

Ocean Crusader

200

1982/1992

GOM

Walter Oil & Gas

Ocean Drake

200

1983/1986

GOM

Chevron

Under Construction (4):

Ocean Endeavor

10,000

VC; 15K; 4M

1975/2007

Singapore

Construction completed: Sea trials and commissioning

Ocean Monarch

1,500

1974/2008

Singapore

Shipyard; Upgrade to 10,000'

Ocean Scepter

350

IC; 15K; 3M

2008

GOM/Brownsville, TX

New; Under Construction

Ocean Shield

350

IC; 15K; 3M

2008

Singapore

New; Under Construction

Attributes

Dynamically-Positioned/Self-Propelled

Mat-Supported Slot Rig

Three Mud Pumps

Independent-Leg Cantilevered Rig

Victory-Class

Four Mud Pumps

Mat-Supported Cantilevered Rig

Self-Propelled

15K

15,000 psi well control system

See the footnotes to this table on the following page.

(a)

Nominal water depth (in feet), as described above for semisubmersibles and drillships, reflects the current outfitting for each drilling unit. In many cases, individual rigs are capable of achieving, or have achieved, greater water depths. In all cases, floating rigs are capable of working successfully at greater depths than their nominal water depth. On a case by case basis, we may achieve a greater depth capacity by providing additional equipment.

(b)		Such enhancements may include the installation of top-drive drilling systems, water depth upgrades, mud pump additions and increases in deck load capacity. Top-drive drilling systems are included on all rigs included in the table above.

(c)		GOM means U.S. Gulf of Mexico. Mexican GOM means the Gulf of Mexico offshore Mexico.

(d)		For ease of presentation in this table, customer names have been shortened or abbreviated.

Markets

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

	•		the Gulf of Mexico, including the United States and Mexico;

	•		Europe, principally in the United Kingdom, or U.K., and Norway;

	•		the Mediterranean Basin, including Egypt, Libya and Tunisa and other parts of Africa;

	•		South America, principally in Brazil;

	•		Australia and Asia, including Malaysia, Indonesia and Vietnam; and

	•		the Middle East, including Kuwait, Qatar and Saudi Arabia.

We actively market our rigs worldwide. From time to time our fleet operates in various other markets throughout the world as the market demands. See Note 16 “Segments and Geographic Area Analysis” to our Consolidated Financial Statements in Item 8 of this report.

We believe our presence in multiple markets is valuable in many respects. For example, we believe that our experience with safety and other regulatory matters in the U.K. has been beneficial in Australia and in the Gulf of Mexico, while production experience we have gained through our Brazilian and North Sea operations has potential application worldwide. Additionally, we believe our performance for a customer in one market segment or area enables us to better understand that customer’s needs and better serve that customer in different market segments or other geographic locations.

Offshore Contract Drilling Services

Our contracts to provide offshore drilling services vary in their terms and provisions. We typically obtain our contracts through competitive bidding, although it is not unusual for us to be awarded drilling contracts without competitive bidding. Our drilling contracts generally provide for a basic drilling rate on a fixed dayrate basis regardless of whether or not such drilling results in a productive well. Drilling contracts may also provide for lower rates during periods when the rig is being moved or when drilling operations are interrupted or restricted by equipment breakdowns, adverse weather conditions or other conditions beyond our control. Under dayrate contracts, we generally pay the operating expenses of the rig, including wages and the cost of incidental supplies. Historically, dayrate contracts have accounted for a substantial portion 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 a period of time as a result of a breakdown of equipment or, in some cases, due to other events beyond the control of either party to the contract. In addition, certain of our contracts permit the customer to terminate the contract early by giving notice, and in some circumstances may require the payment of an early termination fee by the customer. The contract term in many instances may also be extended by the customer exercising options for the drilling of additional wells or for an additional length of time, generally at competitive market rates and mutually agreeable terms at the time of the extension. See “Risk Factors — The terms of some of our dayrate drilling contracts may limit our ability to benefit from increasing dayrates in an improving market” and

“Risk Factors — Our business involves numerous operating hazards, and we are not fully insured against all of them” in Item 1A of this report, which are incorporated herein by reference.

Customers

We provide offshore drilling services to a customer base that includes major and independent oil and gas companies and government-owned oil companies. Several customers have accounted for 10.0% or more of our annual consolidated revenues, although the specific customers may vary from year to year. During 2006, we performed services for 51 different customers with Anadarko Petroleum Corporation (which acquired Kerr-McGee Oil & Gas Corporation, or Kerr-McGee, in mid-2006) and Petróleo Brasileiro S.A., or Petrobras, accounting for 10.6% and 10.4% of our annual total consolidated revenues, respectively. During 2005, we performed services for 53 different customers with Petrobras and Kerr-McGee accounting for 10.7% and 10.3% of our annual total consolidated revenues, respectively. During 2004, we performed services for 53 different customers with Petrobras and PEMEX — Exploración Y Producción, or PEMEX, accounting for 12.6% and 10.5% of our annual total consolidated revenues, respectively.

We principally market our services in North America through our Houston, Texas office, with support for activities in the GOM provided by our regional office in New Orleans, Louisiana. We market our services in other geographic locations principally from our office in The Hague, The Netherlands with support from our regional offices in Aberdeen, Scotland and Perth, Western Australia. We provide technical and administrative support functions from our Houston office.

Competition

The offshore contract drilling industry is highly competitive and is influenced by a number of factors, including current and anticipated prices of oil and natural gas, expenditures by oil and gas companies for exploration and development of oil and natural gas and the availability of drilling rigs. See “Risk Factors — Our industry is highly competitive and cyclical, with intense price competition” in Item 1A of this report, which is incorporated herein by reference.

Governmental Regulation

Our operations are subject to numerous international, U.S., state and local laws and regulations that relate directly or indirectly to our operations, including regulations controlling the discharge of materials into the environment, requiring removal and clean-up under some circumstances, or otherwise relating to the protection of the environment. See “Risk Factors — Compliance with or breach of environmental laws can be costly and could limit our operations” in Item 1A of this report, which is incorporated herein by reference.

Operations Outside the United States

Our operations outside the United States accounted for approximately 43%, 45% and 56% of our total consolidated revenues for the years ended December 31, 2006, 2005 and 2004, 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 in the Mexican GOM 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, 2006, we had approximately 4,800 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. Oil and gas prices, market expectations of potential changes in these prices and a variety of political and economic factors significantly affect this level of activity. However, higher commodity prices do not necessarily translate into increased drilling activity since our customers’ expectations of future commodity prices typically drive demand for our rigs. Oil and gas prices are extremely volatile and are affected by numerous factors beyond our control, including:

	•		the political environment of oil-producing regions, including uncertainty or instability resulting from an escalation or additional outbreak of armed hostilities in the Middle East or other geographic areas or further acts of terrorism in the United States or elsewhere;

	•		worldwide demand for oil and gas;

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

	•		advances in exploration and development technology.

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

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

Our industry has historically been cyclical. There have been periods of high demand, short rig supply and high dayrates (such as we are currently experiencing in many of the markets in which we operate), followed by periods of

lower demand, excess rig supply and low dayrates. Periods of excess rig supply intensify the competition in the industry and often result in rigs being idle for long periods of time.

Current oil and natural gas prices are significantly above historical averages, which has resulted in higher utilization and dayrates earned by our drilling units, generally beginning in the third quarter of 2004. However, we can provide no assurance that the current industry cycle of high demand, short rig supply and higher dayrates will continue. We may be required to idle rigs or to enter into lower rate contracts in response to market conditions in the future.

Significant new rig construction and upgrades of existing drilling units could also intensify price competition. We believe that there are currently more than 100 jack-up rigs and floaters (semisubmersible rigs and drillships) on order and scheduled for delivery between 2007 and 2010. Improvements in dayrates and expectations of sustained improvements in rig utilization rates and dayrates may result in the construction of additional new rigs. These increases in rig supply could result in depressed rig utilization and greater price competition from both existing competitors, as well as new entrants into the offshore drilling market. As of the date of this report, not all of the rigs currently under construction have been contracted for future work, which may further intensify price competition as scheduled delivery dates occur. In addition, competing contractors are able to adjust localized supply and demand imbalances by moving rigs from areas of low utilization and dayrates to areas of greater activity and relatively higher dayrates.

Prolonged periods of low utilization and dayrates could also result in the recognition of impairment charges on certain of our drilling rigs if future cash flow estimates, based upon information available to management at the time, indicate that the carrying value of these rigs may not be recoverable.

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

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

We have experienced and continue to experience upward pressure on salaries and wages and increased competition for skilled workers as a result of the strengthening offshore drilling market. We have also sustained the loss of experienced personnel to our competitors. In response to these market conditions we have implemented retention programs, including increases in compensation. The heightened competition for skilled personnel could adversely impact our financial position, results of operations and cash flows by limiting our operations or further increasing our costs.

The terms of some of our dayrate drilling contracts may limit our ability to benefit from increasing dayrates in an improving market.

The duration of offshore drilling contracts is generally determined by market demand and the respective management strategies of the offshore drilling contractor and its customers. In periods of rising demand for offshore rigs, contractors typically prefer well-to-well contracts that allow them to profit from increasing dayrates. In contrast, during these periods customers with reasonably definite drilling programs typically prefer longer term contracts to maintain dayrate prices at a consistent level. Conversely, in periods of decreasing demand for offshore rigs, contractors generally prefer longer term contracts to preserve dayrates at existing levels and ensure utilization, while customers prefer well-to-well contracts that allow them to obtain the benefit of lower dayrates.

To the extent possible, we seek to have a foundation of long-term contracts with a reasonable balance of single-well, well-to-well and short-term contracts to attempt to limit the downside impact of a decline in the market while still participating in the benefit of increasing dayrates in an improving market. However, we can provide no assurance that we will be able to achieve or maintain such a balance from time to time. Our inability to fully benefit from increasing dayrates in an improving market, due to the long-term nature of some of our contracts, may adversely affect our profitability.

Contracts for our drilling units are generally fixed dayrate contracts, and increases in our operating costs could adversely affect our profitability on those contracts.

Our contracts for our drilling units provide for the payment of a fixed dayrate per rig operating day, although some contracts do provide for a limited escalation in dayrate due to increased operating costs incurred by us. Many of our operating costs, such as labor costs, are unpredictable and fluctuate based on events beyond our control. The gross margin that we realize on these fixed dayrate contracts will fluctuate based on variations in our operating costs over the terms of the contracts. In addition, for contracts with dayrate escalation clauses, we may not be able to fully recover increased or unforeseen costs from our customers. Our inability to recover these increased or unforeseen costs from our customers could adversely affect our financial position, results of operations and cash flows.

Our drilling contracts may be terminated due to events beyond our control.

Our customers may terminate some of our term drilling contracts if the drilling unit is destroyed or lost or if drilling operations are suspended for a specified period of time as a result of a breakdown of major equipment or, in some cases, due to other events beyond the control of either party. In addition, some of our drilling contracts permit the customer to terminate the contract after specified notice periods by tendering contractually specified termination amounts. These termination payments may not fully compensate us for the loss of a contract. In addition, the early termination of a contract may result in a rig being idle for an extended period of time, which could adversely affect our financial position, results of operations and cash flows.

During depressed market conditions, our customers may also seek renegotiation of firm drilling contracts to reduce their obligations. The renegotiation of our drilling contracts could adversely affect our financial position, results of operations and cash flows.

We can provide no assurance that our current backlog of contract drilling revenue will be ultimately realized.

As of the date of this report, our contract drilling backlog was $7.4 billion for expected future work extending until 2013, which includes future earnings under both firm commitments and anticipated commitments for which definitive agreements have not yet been executed. We can provide no assurance that we will be able to perform under these contracts due to events beyond our control or that we will be able to ultimately execute a definitive agreement where one does not currently exist. Our inability to perform under our contractual obligations or to execute definitive agreements may have a material adverse effect on our financial position, results of operations and cash flows. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Overview — Contract Drilling Backlog” included in Item 7 of this report.

Rig conversions, upgrades or newbuilds may be subject to delays and cost overruns.

From time to time we may undertake to add new capacity through conversions or upgrades to our existing rigs or through new construction. We have entered into agreements to upgrade two of our semisubmersible drilling units to ultra-deepwater capability at an estimated aggregate cost of approximately $553 million. The shipyard portion of the upgrade of one rig has been completed, and we expect that the unit will return to the GOM in mid-2007. We expect delivery of our other semisubmersible unit during the fourth quarter of 2008. We have also entered into agreements to construct two new jack-up drilling units with expected delivery dates in the first quarter of 2008 at an aggregate cost of approximately $320 million, including drill pipe and capitalized interest. These projects and other projects of this type are subject to risks of delay or cost overruns inherent in any large construction project resulting from numerous factors, including the following:

	•		shortages of equipment, materials or skilled labor;

	•		work stoppages;

	•		unscheduled delays in the delivery of ordered materials and equipment;

	•		unanticipated cost increases;

	•		weather interferences;

	•		difficulties in obtaining necessary permits or in meeting permit conditions;

	•		design and engineering problems;

	•		shipyard failures; 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.

Our business involves numerous operating hazards, and we are not fully insured against all of them.

Our operations are subject to the usual hazards inherent in drilling for oil and gas offshore, such as blowouts, reservoir damage, loss of production, loss of well control, punchthroughs, craterings and natural disasters such as

hurricanes or fires. The occurrence of these events could result in the suspension of drilling operations, damage to or destruction of the equipment involved and injury or death to rig personnel, damage to producing or potentially productive oil and gas formations and environmental damage. Operations also may be suspended because of machinery breakdowns, abnormal drilling conditions, failure of subcontractors to perform or supply goods or services or personnel shortages. In addition, offshore drilling operators are subject to perils peculiar to marine operations, including capsizing, grounding, collision and loss or damage from severe weather. Damage to the environment could also result from our operations, particularly through oil spillage or extensive uncontrolled fires. We may also be subject to damage claims by oil and gas companies or other parties.

Pollution and environmental risks generally are not fully insurable, and we do not typically retain loss-of-hire insurance policies to cover our rigs. Our insurance policies and contractual rights to indemnity may not adequately cover our losses, or may have exclusions of coverage for some losses. We do not have insurance coverage or rights to indemnity for all risks, including, among other things, war risk, 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 or 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 significantly increased our insurance deductibles and have elected to self-insure for a portion of our liability exposure and for physical damage to rigs and equipment caused by named windstorms in the GOM.

Because the amount of insurance coverage available to us has been significantly limited and the cost for such coverage has increased substantially, we have elected to self-insure for a portion of our liability exposure and for physical damage to rigs and equipment caused by named windstorms in the GOM. Although we continue to carry physical damage insurance for certain other losses, we have significantly increased our deductibles to offset or mitigate premium increases. Our deductible for physical damage insurance is currently $150.0 million per occurrence (or lower for some rigs if they are declared a constructive total loss). We continue to carry liability insurance with coverages similar to prior years, except that we have elected to self-insure for a portion of our excess liability coverage related to named windstorms in the GOM. Our deductible for liability coverage generally has increased to $5.0 million per occurrence, but our deductibles arising in connection with certain liabilities relating to named windstorms in the GOM have increased to $10.0 million per occurrence, with no annual aggregate deductible. To the extent that we incur certain liabilities related to named windstorms in the GOM in excess of $75.0 million, we are self-insured for up to a maximum retention of $17.5 million per occurrence in addition to these deductibles. These changes result in a higher risk of losses that are not covered by third party insurance contracts. If named windstorms in the GOM cause significant damage to our rigs or equipment or to the property of others for which we may be liable, it could have a material adverse effect on our financial position, results of operations 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;

	•		kidnapping of personnel;

	•		expropriation of property or equipment;

	•		foreign and domestic monetary policy;

	•		the inability to repatriate income or capital;

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

	•		changing taxation policies.

In addition, international contract drilling operations are subject to various laws and regulations in countries in which we operate, including laws and regulations relating to:

	•		the equipping and operation of drilling units;

	•		repatriation of foreign earnings;

	•		oil and gas exploration and development;

	•		taxation of offshore earnings and earnings of expatriate personnel; and

	•		use and compensation of local employees and suppliers by foreign contractors.

No prediction can be made as to what governmental regulations may be enacted in the future that could adversely affect the international drilling industry. The actions of foreign governments, including initiatives by OPEC, may adversely affect our ability to compete.

Our drilling contracts in the Mexican GOM expose us to greater risks than we normally assume.

As of the date of this report, we have three intermediate semisubmersible rigs and one jack-up rig drilling offshore Mexico for PEMEX, the national oil company of Mexico, and have two additional intermediate semisubmersibles contracted to begin working for PEMEX in the third quarter of 2007. The terms of these contracts expose us to greater risks than we normally assume, such as exposure to greater environmental liability. In addition, each contract can be terminated by PEMEX on short-term notice, contractually or by statute, subject to certain conditions. While we believe that the financial terms of these contracts and our operating safeguards in place mitigate these risks, we can provide no assurance that the increased risk exposure will not have a negative impact on our future operations or financial results.

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

Due to our international operations, we may experience currency exchange losses where revenues are received and expenses are paid in nonconvertible currencies or where we do not hedge an exposure to a foreign currency. We may also incur losses as a result of an inability to collect revenues because of a shortage of convertible currency available to the country of operation, controls over currency exchange or controls over the repatriation of income or capital. We can provide no assurance that financial hedging arrangements will effectively hedge any foreign currency fluctuation losses that may arise.

We may be required to accrue additional tax liability on certain of our foreign earnings.

Certain of our international rigs are owned and operated, directly or indirectly, by Diamond Offshore International Limited, our wholly-owned Cayman Islands subsidiary. We do not intend to remit earnings from this subsidiary to the U.S., and we plan to indefinitely reinvest these earnings internationally. We have not provided for U.S. taxes on these earnings nor have we recognized any U.S. tax benefits on losses generated by the subsidiary. Should a distribution be made from the unremitted earnings of our subsidiary, we may be required to record additional U.S. income taxes that, if material, could have an adverse effect on our financial position, results of operations and cash flows.

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

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

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

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

and regulations may in the future add significantly to our operating costs or may significantly limit drilling activity.

Hurricanes Katrina and Rita caused damage to a number of rigs in the GOM and rigs that were moved off location by the storms may have done damage to platforms, pipelines, wellheads and other drilling rigs. We believe that we are currently in compliance with the existing regulations set forth by the Minerals Management Service of the U.S. Department of the Interior regarding our operations in the GOM. However, these regulations are currently under review by various other government agencies and industry groups. We can provide no assurance that these groups will not take other steps or implement additional requirements that could increase the cost of operating, or reduce the area of operation, in the GOM.

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

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

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

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

We are controlled by a single stockholder, which could result in potential conflicts of interest.

Loews Corporation, which we refer to as Loews, beneficially owns approximately 50.7% of our outstanding shares of common stock as of February 20, 2007 and is in a position to control actions that require the consent of stockholders, including the election of directors, amendment of our Restated Certificate of Incorporation and any merger or sale of substantially all of our assets. In addition, three officers of Loews serve on our Board of Directors. One of those, James S. Tisch, the Chief Executive Officer and Chairman of the Board of our company, is also the Chief Executive Officer and a director of Loews. We have also entered into a services agreement and a registration rights agreement with Loews and we may in the future enter into other agreements with Loews.

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

Item 1B. Unresolved Staff Comments.

Not applicable.

Item 2. Properties.

We own an eight-story office building containing approximately 182,000-net rentable square feet on approximately 6.2 acres of land located in Houston, Texas, where our corporate headquarters are located, two buildings totaling 39,000 square feet and 20 acres of land in New Iberia, Louisiana, for our offshore drilling warehouse and storage facility, and a 13,000-square foot building and five acres of land in Aberdeen, Scotland, for our North Sea operations. Additionally, we currently lease various office, warehouse and storage facilities in Louisiana, Australia, Brazil, Indonesia, Norway, The Netherlands, Malaysia, Qatar, Singapore 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, 2007		Position
James S. Tisch		54	Chairman of the Board of Directors and Chief Executive Officer
Lawrence R. Dickerson		54	President, Chief Operating Officer and Director
Gary T. Krenek		48	Senior Vice President and Chief Financial Officer
William C. Long		40	Senior Vice President, General Counsel & Secretary
Beth G. Gordon		51	Controller — Chief Accounting Officer
Mark F. Baudoin		54	Senior Vice President — Administration
Lyndol L. Dew		52	Senior Vice President — Worldwide Operations
John L. Gabriel, Jr.		53	Senior Vice President — Contracts & Marketing
John M. Vecchio		56	Senior Vice President — Technical Services

James S. Tisch has served as our Chief Executive Officer since March 1998. Mr. Tisch has also served as Chairman of the Board since 1995 and as a director since June 1989. Mr. Tisch has served as Chief Executive Officer of Loews, a diversified holding company and our controlling stockholder, since January 1999. Mr. Tisch, a director of Loews since 1986, also serves as a director of CNA Financial Corporation, an 89% owned subsidiary of Loews.

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

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

William C. Long has served as a Senior Vice President and our General Counsel and Secretary since October 2006. Mr. Long previously served as our Vice President, General Counsel and Secretary since March 2001 and as our General Counsel and Secretary from March 1999 through February 2001.

Beth G. Gordon has served as our Controller and Chief Accounting Officer since April 2000.

Mark F. Baudoin has served as a Senior Vice President since October 2006. Mr. Baudoin previously served as our Vice President — Administration and Operations Support since March 1996.

Lyndol L. Dew has served as a Senior Vice President since September 2006. Previously, Mr. Dew served as our Vice President — International Operations from January 2006 to August 2006 and as our Vice President — North American Operations from January 2003 to December 2005. Mr. Dew previously served as an Area Manager for our domestic operations since February 2002.

John L. Gabriel, Jr. has served as a Senior Vice President since November 1999.

John M. Vecchio has served as a Senior Vice President since April 2002. Previously, Mr. Vecchio served as our Technical Services Vice President from October 2000 through March 2002 and as our Engineering Vice President from July 1997 through September 2000.

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

2006
First Quarter	$	90.70	$	72.75
Second Quarter		96.15		72.49
Third Quarter		85.44		67.46
Fourth Quarter		84.43		63.90

2005
First Quarter	$	50.89	$	38.25
Second Quarter		55.90		40.40
Third Quarter		62.40		52.10
Fourth Quarter		71.31		51.46

As of February 20, 2007 there were approximately 238 holders of record of our common stock.

Dividend Policy

In 2006, we paid cash dividends of $0.125 per share of our common stock on March 1, June 1, September 1 and December 1 and a special cash dividend of $1.50 per share of our common stock on March 1. In 2005, we paid cash dividends of $0.0625 per share of our common stock on March 1 and June 1 and cash dividends of $0.125 per share on September 1 and December 1.

On January 30, 2007, we declared a quarterly cash dividend of $0.125 per share of our common stock and a special cash dividend of $4.00 per share of our common stock, both of which are payable March 1, 2007 to stockholders of record on February 14, 2007. Any future determination as to payment of quarterly dividends will be made at the discretion of our Board of Directors. In addition, our Board of Directors may, in subsequent years, consider paying additional annual special dividends, in amounts to be determined, if it believes that our financial position, earnings, and capital spending plans and other relevant factors warrant such action at that time.

CUMULATIVE TOTAL STOCKHOLDER RETURN

The following graph shows the cumulative total stockholder return for our common stock, the Standard & Poor’s 500 Index, a Competitor/Service Industry Group Index and a Peer Group Index over the five year period ended December 31, 2006.

Comparison of 2002 — 2006 Cumulative Total Return (1)


(1)		Total return assuming reinvestment of dividends. Dividends for the periods reported include quarterly dividends of $0.125 per share of our common stock that we paid during 2002, the first three quarters of 2003, the last two quarters of 2005 and all four quarters of 2006. Beginning in the fourth quarter of 2003 through the first two quarters of 2005, we paid a quarterly dividend of .0625 per share. Assumes $100 invested on December 31, 2001 in our common stock, the S&P 500 Index, a competitor/service industry group index that we constructed and a peer group index comprised of a group of other companies in the contract drilling industry. The new peer group index is comprised of companies that we believe provide a more accurate reflection of our industry peers than the competitor/service industry group index that we have included in the past. Therefore, we believe that the new peer group index provides a more meaningful comparison of our relative stock performance.

(2)		The competitor/service industry group that we constructed consists of the following companies: Baker Hughes Incorporated, ENSCO International Incorporated, Halliburton Company, Noble Drilling Corporation, Schlumberger Ltd., Tidewater Inc. and Transocean Inc. Total return calculations were weighted according to the respective company’s market capitalization.

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

Item 6. Selected Financial Data.

The following table sets forth certain historical consolidated financial data relating to Diamond Offshore. We prepared the selected consolidated financial data from our consolidated financial statements as of and for the periods presented. Prior periods have been reclassified to conform to the classifications we currently follow. Such reclassifications do not affect earnings. The selected consolidated financial data below should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Item 7 and our Consolidated Financial Statements (including the Notes thereto) in Item 8 of this report.


	As of and for the Year Ended December 31,
	2006		2005		2004			2003			2002
	(In thousands, except per share and ratio data)
Income Statement Data:
Total revenues	$	2,052,572	$	1,221,002	$	814,662		$	680,941		$	752,561
Operating income (loss)		940,432		374,399		3,928			(38,323	)		51,984
Net income (loss)		706,847		260,337		(7,243	)		(48,414	)		62,520
Net income (loss) per share:
Basic		5.47		2.02		(0.06	)		(0.37	)		0.48
Diluted		5.12		1.91		(0.06	)		(0.37	)		0.47

Balance Sheet Data:
Drilling and other property and equipment, net	$	2,628,453	$	2,302,020	$	2,154,593		$	2,257,876		$	2,164,627
Total assets		4,132,839		3,606,922		3,379,386			3,135,019			3,256,308
Long-term debt (excluding current maturities) (1)		964,310		977,654		709,413			928,030			924,475

Other Financial Data:
Capital expenditures	$	551,237	$	293,829	$	89,229		$	272,026		$	340,805
Cash dividends declared per share		2.00		0.375		0.25			0.438			0.50
Ratio of earnings to fixed charges (2)		28.26x		9.19x		N/A			N/A			4.51x


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

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

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

The following discussion should be read in conjunction with our Consolidated Financial Statements (including the Notes thereto) in Item 8 of this report.

We provide contract drilling services to the energy industry around the globe and are a leader in deepwater drilling with a fleet of 44 offshore drilling rigs. Our fleet currently consists of 30 semisubmersibles, 13 jack-ups and one drillship. In addition, we have two jack-up drilling units on order at shipyards in Brownsville, Texas and Singapore. We expect both of these units to be delivered during the first quarter of 2008.

Overview

Industry Conditions

Worldwide demand for our mid-water (intermediate) and deepwater (high-specification) semisubmersible rigs and international jack-up rigs remained strong during the fourth quarter of 2006. However, the jack-up market in the GOM continues to experience downward pricing pressure, with the potential for a given rig to be ready-stacked for a period of time between wells. As of January 29, 2007, we had one ready-stacked jack-up unit. Exclusive of the GOM jack-up market, which accounted for 12 percent of our total revenue for the quarter ended December 31, 2006, solid fundamental market conditions remain in place for all classes of offshore drilling rigs worldwide, and both dayrates and term contract opportunities have continued to slowly increase.

Gulf of Mexico. In the GOM, the market for our semisubmersible equipment remains firm. The dayrate on one of our seven high-specification floaters in the GOM, for which we have received a letter of intent, or LOI, is as high as $500,000 for future work. However, the pace of contracting for these rigs has slowed due to the backlog of our existing agreements, all of which extend into 2008 or 2009, except for the most recent agreement which extends into 2012.

Dayrates for our five intermediate semisubmersibles currently located in the GOM are as high as $300,000 for a current one-well contract and a future three-well contract. We continue to view the deepwater and intermediate markets in the GOM as under-supplied and believe that the GOM semisubmersible market will remain strong in 2007.

Our jack-up fleet in the GOM experienced somewhat lower utilization during the fourth quarter of 2006, coupled with increasing downward pressure on dayrates, compared to the third quarter of 2006. This situation began in the second quarter of 2006. We believe that the current pricing pressure on jack-up rigs in the GOM will extend at least until the second quarter of 2007.

We expect two of our intermediate semisubmersibles, the Ocean New Era and Ocean Voyager, to mobilize from the GOM to the Mexican GOM in the third quarter of 2007 under approximately 2¹/2-year contracts both ending in early 2010. The rigs have commitments at dayrates of $265,000 and $335,000, respectively. The terms of our drilling contracts with PEMEX for these rigs expose us to greater risks than we normally assume, such as exposure to increased environmental liability. In addition, each contract can be terminated by PEMEX on short-term notice, contractually or by statute, subject to certain conditions, although we view this eventuality as unlikely. We expect the market for the Mexican GOM to remain strong in 2007.

Brazil. Two of our rigs operating in Brazil are currently working under term contracts with Petrobras that expire in 2009, and two additional rigs are operating under contracts expiring in 2010. Petrobras is continuing to seek additional intermediate semisubmersible rigs, and we expect the Brazilian semisubmersible demand to remain strong in 2007.

North Sea. Effective industry utilization remains at 100 percent in the North Sea where we have three intermediate semisubmersible rigs in the U.K. and one intermediate unit in Norway. Indicating the strength of this market, one of our four rigs in the North Sea recently received a term contract extending until the second quarter of 2009, with an option until late March 2007 to convert to a two-year contract ending in 2010. The other three rigs have term contracts that extend into 2010.

Australia/Asia/Middle East/Mediterranean. We currently have five semisubmersible rigs and one jack-up unit operating in the Australia/Asia market, and two jack-up rigs and one intermediate floater operating in the Middle

East/Mediterranean sector. All nine of these rigs are operating under contracts for work extending into 2007, 2008 or 2009. During the third quarter of 2006, one of our new-build jack-up rigs, the Ocean Shield, which is currently under construction in Singapore, received a one-year term contract at a dayrate of $265,000, with the option until late March 2007 to convert to a two-year contract, but at a slightly lower dayrate. Under the agreement, the rig is scheduled to begin work offshore Australia upon completion of construction and commissioning of the rig, which is estimated to occur in the first quarter of 2008. We believe that the Australia/Asia and Middle East/Mediterranean markets will remain strong in 2007.

Contract Drilling Backlog

The following table reflects our contract drilling backlog as of February 19, 2007 and February 6, 2006 (the date reported in our Annual Report on Form 10-K for the year ended December 31, 2005) and reflects both firm commitments (typically represented by signed contracts), as well as LOIs. An LOI is subject to customary conditions, including the execution of a definitive agreement. Contract drilling backlog is based on the full contractual dayrate for our drilling rigs and is calculated assuming full utilization of our drilling equipment for the contract period. 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% can be adversely impacted by downtime due to various operating factors including, but not limited to, unscheduled repairs, maintenance and weather. Our contract backlog is calculated by multiplying the contracted operating dayrate by the firm contract period, excluding revenues for mobilization, demobilization, contract preparation and customer reimbursables. Changes in our contract drilling backlog between periods is a function of both the performance of work on term contracts, as well as the extension or modification of existing term contracts and the execution of additional contracts.


	February 19,		February 6,
	2007		2006
	(In thousands)
Contract Drilling Backlog
High-Specification Floaters	$	4,115,000	$	2,606,000
Intermediate Semisubmersibles		2,895,000		1,603,000
GOM Jack-ups (including offshore Mexico)		114,000		210,000
International Jack-ups		318,000		124,000

Total	$	7,442,000	$	4,543,000

The following table reflects the amount of our contract drilling backlog by year as of February 19, 2007.


	For the Years Ending December 31,
	Total		2007		2008		2009		2010 - 2013
					(In thousands)
Contract Drilling Backlog
High-Specification Floaters ⁽¹⁾	$	4,115,000	$	903,000	$	1,210,000	$	876,000	$	1,126,000
Intermediate Semisubmersibles		2,895,000		964,000		1,025,000		742,000		164,000
GOM Jack-ups (including offshore Mexico)		114,000		98,000		16,000		—		—
International Jack-ups		318,000		134,000		155,000		29,000		—

Total	$	7,442,000	$	2,099,000	$	2,406,000	$	1,647,000	$	1,290,000


(1)		Includes an aggregate $1.1 billion in contract drilling revenue of which approximately $255 million, $347 million and $457 million is expected to be earned during 2008, 2009 and between 2010 and 2013, respectively, relating to expected future work under LOIs.

The following table reflects the percentage of rig days committed by year as of February 19, 2007. The percentage of rig days committed is calculated as the ratio of total days committed under contracts and LOIs and scheduled shipyard and survey days for all rigs in our fleet to total available days (number of rigs multiplied by the number of days in a particular year). Total available days have been calculated based on the expected delivery dates for the Ocean Endeavor, Ocean Monarch, and our two newbuild jack-up rigs, the Ocean Scepter and Ocean Shield.


	For the Years Ending December 31,
	2007			2008			2009			2010 - 2013
Contract Drilling Backlog
High-Specification Floaters		100	%		90	%		58	%		17	%
Intermediate Semisubmersibles		91	%		54	%		39	%		2	%
GOM Jack-ups (including offshore Mexico)		34	%		3	%		—			—
International Jack-ups		77	%		44	%		8	%		—

Impact of 2005 Hurricanes

In the third quarter of 2005, two major hurricanes, Katrina and Rita, struck the U.S. Gulf Coast and Gulf of Mexico. In late August 2005, one of our jack-up drilling rigs, the Ocean Warwick, was seriously damaged during Hurricane Katrina and other rigs in our fleet, as well as our warehouse in New Iberia, Louisiana, sustained lesser damage in Hurricane Katrina or Rita, or both storms. We believe that the physical damage to our rigs, as well as related removal and recovery costs, are primarily covered by insurance, after applicable deductibles. At December 31, 2006, we had filed several insurance claims related to the 2005 storms which are currently under review by insurance adjusters or are pending underwriter approval. Our results for 2005, and to a lesser extent 2006, reflect the impact of Hurricanes Katrina and Rita.

The Ocean Warwick, with a net book value of $14.0 million, was declared a constructive total loss effective August 29, 2005. We issued a proof of loss in the amount of $50.5 million to our insurers, representing the insured value of the rig less a $4.5 million deductible. We received all insurance proceeds related to this claim in 2005. Recovery and removal of the Ocean Warwick are subject to separate insurance deductibles which were estimated at the time of loss to be $2.5 million in the aggregate.

In the third quarter of 2005, we recorded a net $33.6 million casualty gain for the Ocean Warwick, representing net insurance proceeds of $50.5 million, less the write-off of the $14.0 million net carrying value of the drilling rig and $0.4 million in rig-based spare parts and supplies, and estimated insurance deductibles aggregating $2.5 million for salvage and wreck removal. We have presented this as “Casualty Gain on Ocean Warwick” in our Consolidated Statements of Operations for the year ended December 31, 2005 included in Item 8 of this report.

During 2006, we subsequently revised our estimate of expected deductibles related to salvage and wreck removal of the Ocean Warwick to $2.0 million and recorded a $0.5 million adjustment to “Casualty Gain on Ocean Warwick” in our Consolidated Statements of Operations for the year ended December 31, 2006 included in Item 8 of this report.

Damage to our other affected rigs and warehouse was less severe. At the time of loss, we estimated insurance deductibles related to the remaining rigs damaged during Hurricane Katrina and our rigs and facility damaged by Hurricane Rita to total $2.6 million in the aggregate, of which $1.2 million and $1.4 million were recorded as additional contract drilling expense and loss on disposition of assets, respectively, for the year ended December 31, 2005 in our Consolidated Statements of Operations included in Item 8 of this report. Subsequently, during 2006, we revised our estimate of the applicable deductibles related to these damages and recorded a $0.4 million gain on disposition of assets in our Consolidated Statements of Operations for the year ended December 31, 2006 included in Item 8 of this report.

In addition, in the third quarter of 2005 and during 2006, we wrote off the aggregate net book value of approximately $14.3 million in rig equipment that was either lost or damaged beyond repair during these storms as loss on disposition of assets and recorded a corresponding insurance receivable in an amount equal to our expected recovery from insurers. The write-off of this equipment and recognition of insurance receivables had no net effect on our consolidated results of operations for the years ended December 31, 2006 and 2005.

During the third and fourth quarters of 2005, we incurred additional operating expenses, including but not limited to the cost of rig crew over-time and employee assistance, hurricane relief supplies, temporary housing and office space and the rental of mooring equipment, of $5.1 million relating to relief and recovery efforts in the aftermath of Hurricanes Katrina and Rita, which we do not expect to be recoverable through our insurance.

contract drilling expense, $1.1 million as a gain on disposition of assets and the remaining $1.8 million as other income in our Consolidated Statements of Operations for the year ended December 31, 2006 included in Item 8 of this report.

General

Our revenues vary based upon demand, which affects the number of days our fleet is utilized and the dayrates earned. When a rig is idle, no dayrate is earned and revenues will decrease as a result. Revenues can also be affected as a result of the acquisition or disposal of rigs, required surveys and shipyard upgrades. In order to improve utilization or realize higher dayrates, we may mobilize our rigs from one market to another. However, during periods of mobilization, revenues may be adversely affected. As a response to changes in demand, we may withdraw a rig from the market by stacking it or may reactivate a rig stacked previously, which may decrease or increase revenues, respectively.

The two most significant variables affecting revenues are dayrates for rigs and rig utilization rates, each of which is a function of rig supply and demand in the marketplace. As utilization rates increase, dayrates tend to increase as well, reflecting the lower supply of available rigs, and vice versa. Demand for drilling services is dependent upon the level of expenditures set by oil and gas companies for offshore exploration and development, as well as a variety of political and economic factors. The availability of rigs in a particular geographical region also affects both dayrates and utilization rates. These factors are not within our control and are difficult to predict.

We recognize revenue from dayrate drilling contracts as services are performed. In connection with such drilling contracts, we may receive lump-sum fees for the mobilization of equipment. We earn these fees as services are performed over the initial term of the related drilling contracts. We defer mobilization fees received, as well as direct and incremental mobilization costs incurred, and amortize each, on a straight-line basis, over the term of the related drilling contracts (which is the period estimated to be benefited from the mobilization activity). Straight-line amortization of mobilization revenues and related costs over the term of the related drilling contracts (which generally range from two to 60 months) is consistent with the timing of net cash flows generated from the actual drilling services performed. Absent a contract, mobilization costs are recognized currently.

From time to time, we may receive fees from our customers for capital improvements to our rigs. We defer such fees and recognize them into income on a straight-line basis over the period of the related drilling contract as a component of contract drilling revenue. We capitalize the costs of such capital improvements and depreciate them over the estimated useful life of the improvement.

We receive reimbursements for the purchase of supplies, equipment, personnel services and other services provided at the request of our customers in accordance with a contract or agreement. We record these reimbursements at the gross amount billed to the customer, as “Revenues related to reimbursable expenses” in our Consolidated Statements of Operations included in Item 8 of this report.

Operating Income. Our operating income is primarily affected by revenue factors, but is also a function of varying levels of operating expenses. Our operating expenses represent all direct and indirect costs associated with the operation and maintenance of our drilling equipment. The principal components of our operating costs are, among other things, direct and indirect costs of labor and benefits, repairs and maintenance, freight, regulatory inspections, boat and helicopter rentals and insurance. Labor and repair and maintenance costs represent the most significant components of our operating expenses. In general, our labor costs increase primarily due to higher salary levels, rig staffing requirements, inflation and costs associated with labor regulations in the geographic regions in which our rigs operate. We have experienced and continue to experience upward pressure on salaries and wages as a result of the strengthening offshore drilling market and increased competition for skilled workers. In response to these market conditions we have implemented retention programs, including increases in compensation.

Costs to repair and maintain our equipment fluctuate depending upon the type of activity the drilling unit is performing, as well as the age and condition of the equipment.

Operating expenses generally are not affected by changes in dayrates and may not be significantly affected by short-term fluctuations in utilization. For instance, if a rig is to be idle for a short period of time, few decreases in operating expenses may actually occur since the rig is typically maintained in a prepared or “ready-stacked” state

with a full crew. In addition, when a rig is idle, we are responsible for certain operating expenses such as rig fuel and supply boat costs, which are typically costs of the operator when a rig is under contract. However, if the rig is to be idle for an extended period of time, we may reduce the size of a rig’s crew and take steps to “cold stack” the rig, which lowers expenses and partially offsets the impact on operating income. We recognize, as incurred, operating expenses related to activities such as inspections, painting projects and routine overhauls that meet certain criteria and which maintain rather than upgrade our rigs. These expenses vary from period to period. Costs of rig enhancements are capitalized and depreciated over the expected useful lives of the enhancements. Higher depreciation expense decreases operating income in periods subsequent to capital upgrades.

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

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

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

During 2007, we expect to spend an aggregate of approximately $46 million for 5-year surveys and intermediate surveys, including estimated mobilization costs, but excluding any resulting repair and maintenance costs, which could be significant. Costs of mobilizing our rigs to shipyards for scheduled surveys, which were a major component of our survey-related costs during 2006, are indicative of higher prices commanded by support businesses to the offshore drilling industry. We expect mobilization costs to be a significant component of our survey-related costs in 2007.

When we renewed our principal insurance policies effective May 1, 2006, coverage for offshore drilling rigs, if available, was offered at substantially higher premiums than in the past and was subject to an increasing number of coverage limitations, due in part to underwriting losses suffered by the insurance industry as a result of damage caused by hurricanes in the Gulf of Mexico in 2004 and 2005. In some cases, quoted renewal premiums increased by more than 200%, with the addition of substantial deductibles and limits on the amount of claims payable for losses arising from named windstorms. In light of these factors, we determined that retention of additional risk was preferable to paying dramatically higher premiums for limited coverage. Accordingly, we have elected to self-insure for physical damage to rigs and equipment caused by named windstorms in the U.S. Gulf of Mexico. For our other physical damage coverage, our deductible is $150.0 million per occurrence (or lower for some rigs if they are declared a constructive total loss). As a result of our reduced coverage, our premiums for this coverage were reduced from the amounts we paid in 2005 and were lower than the renewal rates quoted by our insurance carriers. We also renewed our liability policies in May 2006, with an increase in premiums and deductibles. Our new deductibles under these policies have generally increased to $5.0 million per occurrence, but our deductibles arising in connection with certain liabilities relating to named windstorms in the U.S. Gulf of Mexico have increased to $10.0 million per occurrence, with no annual aggregate deductible. In addition, we elected to self-insure a portion of our excess liability coverage related to named windstorms in the U.S. Gulf of Mexico. To the extent that we incur certain liabilities related to named windstorms in the U.S. Gulf of Mexico in excess of $75.0 million, we are self-insured for up to a maximum retention of $17.5 million per occurrence in addition to these deductibles. We are currently in the early stages of renewing our insurance policies that expire on May 1, 2007. Currently we are unable to predict what changes, if any, we may make to our insurance coverage on or after May 1, 2007.

If named windstorms in the U.S. Gulf of Mexico cause significant damage to our rigs or equipment or to the property of others for which we may be liable, it could have a material adverse effect on our financial position, results of operations or cash flows.

Insurance premiums will be amortized as expense over the applicable policy periods which generally expire at the end of April 2007.

Construction and Capital Upgrade Projects. We capitalize interest cost for the construction and upgrade of qualifying assets in accordance with Statement of Financial Accounting Standards, or SFAS, No. 34, “Capitalization of Interest Cost,” or SFAS 34. During 2006 and 2005, we began capitalizing interest on our two capital upgrade projects and the construction of our two new jack-up rigs. Pursuant to SFAS 34, the period of interest capitalization covers the duration of the activities required to make the asset ready for its intended use, and the capitalization period ends when the asset is substantially complete and ready for its intended use. In 2006 we began capitalizing interest on expenditures related to the capital upgrade of the Ocean Monarch and the construction of our two jack-up rigs, and in 2005, we began capitalizing interest on expenditures related to the upgrade of the Ocean Endeavor. See Note 1 “General Information — Capitalized Interest” to our Consolidated Financial Statements included in Item 8 of this report.

As of December 31, 2006, the shipyard portion of the Ocean Endeavor’s upgrade had been completed, and the rig is currently undergoing sea trials and commissioning in Singapore. We will continue to capitalize interest costs related to this upgrade until sea trials and commissioning are completed and the rig is loaded-out on a heavy-lift vessel for its return to the GOM, which we anticipate will occur at the end of the first quarter of 2007. We believe that this point in time represents the completion of the construction phase of the upgrade project, as the newly upgraded rig will be ready for its intended use. Accordingly, we will then cease capitalizing interest costs related to this upgrade and will begin depreciating the newly upgraded rig. As a result of the scheduled delivery of the Ocean Endeavor, we anticipate that depreciation and interest expense in 2007 will increase by approximately $6 million (representing nine months of expense) and $2.5 million, respectively.

Critical Accounting Estimates

Our significant accounting policies are included in Note 1 “General Information” to our Consolidated Financial Statements in Item 8 of this report. Judgments, assumptions and estimates by our management are inherent in the preparation of our financial statements and the application of our significant accounting policies. We believe that our most critical accounting estimates are as follows:

Property, Plant and Equipment. We carry our drilling and other property and equipment at cost. Maintenance and routine repairs are charged to income currently while replacements and betterments, which meet certain criteria, are capitalized. Depreciation is amortized up to applicable salvage values by applying the straight-line method over the remaining estimated useful lives. Our management makes judgments, assumptions and estimates regarding capitalization, useful lives and salvage values. Changes in these judgments, assumptions and estimates could produce results that differ from those reported.

We evaluate our property and equipment for impairment whenever changes in circumstances indicate that the carrying amount of an asset may not be recoverable. We utilize a probability-weighted cash flow analysis in testing an asset for potential impairment. Our assumptions and estimates underlying this analysis include the following:

	•		dayrate by rig;

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

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

	•		salvage value for each rig.

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

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

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

Personal Injury Claims. Effective May 1, 2006, in conjunction with our insurance policy renewals, we increased our deductible for liability coverage for personal injury claims, which primarily result from Jones Act liability in the Gulf of Mexico, to $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. Prior to this renewal, our uninsured retention of liability for personal injury claims was $0.5 million per claim with an additional aggregate annual deductible of $1.5 million. Our in-house claims department estimates the amount of our liability for our retention. This department establishes a reserve for each of our personal injury claims by evaluating the existing facts and circumstances of each claim and comparing the circumstances of each claim to historical experiences with similar past personal injury claims. Our claims department also estimates our liability for personal injuries that are incurred but not reported by using historical data. From time to time, we may also engage experts to assist us in estimating our reserve for such personal injury claims. In 2006 we engaged an actuary to estimate our liability for personal injury claims based on our historical losses and utilizing various actuarial models. We reduced our reserve for personal injury claims by $8.0 million during the fourth quarter of 2006 based on an actuarial review from which we determined that our aggregate reserve for personal injury claims should be $35.0 million at December 31, 2006.

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

	•		the severity of personal injuries claimed;

	•		significant changes in the volume of personal injury claims;

	•		the unpredictability of legal jurisdictions where the claims will ultimately be litigated;

	•		inconsistent court decisions; and

	•		the risks and lack of predictability inherent in personal injury litigation.

Income Taxes. We account for income taxes in accordance with SFAS No. 109, “Accounting for Income Taxes,” or SFAS 109, which requires the recognition of the amount of taxes payable or refundable for the current year and an asset and liability approach in recognizing the amount of deferred tax liabilities and assets for the future tax consequences of events that have been currently recognized in our financial statements or tax returns. In each of our tax jurisdictions we recognize a current tax liability or asset for the estimated taxes payable or refundable on tax returns for the current year and a deferred tax asset or liability for the estimated future tax effects attributable to temporary differences and carryforwards. Deferred tax assets are reduced by a valuation allowance, if necessary, which is determined by the amount of any tax benefits that, based on available evidence, are not expected to be realized under a “more likely than not” approach. For interim periods, we estimate our annual effective tax rate by forecasting our annual income before income tax, taxable income and tax expense in each of our tax jurisdictions. We make judgments regarding future events and related estimates especially as they pertain to forecasting of our effective tax rate, the potential realization of deferred tax assets such as utilization of foreign tax credits, and exposure to the disallowance of items deducted on tax returns upon audit.

In June 2006, the Financial Accounting Standards Board, or FASB, issued FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes,” or FIN 48, which clarifies the accounting for uncertainty in income taxes recognized in financial statements in accordance with SFAS 109. FIN 48 prescribes a recognition threshold

and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return and also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. FIN 48 is effective for fiscal years beginning after December 15, 2006. We are currently evaluating the guidance provided in FIN 48 and expect to adopt FIN 48 in the first quarter of 2007. Although our assessment has not yet been finalized, upon adoption of FIN 48 we expect to recognize a cumulative effect adjustment for uncertain tax positions of approximately $30 million, which will be charged to results of operations and equity.

Results of Operations

Years Ended December 31, 2006 and 2005

Comparative data relating to our revenues and operating expenses by equipment type are presented below. We have reclassified certain amounts applicable to the prior periods to conform to the classifications we currently follow. These reclassifications do not affect earnings.


	Year Ended
	December 31,						Favorable/
	2006			2005			(Unfavorable)
	(In thousands)
CONTRACT DRILLING REVENUE
High-Specification Floaters	$	766,873		$	448,937		$	317,936
Intermediate Semisubmersibles		785,047			456,734			328,313
Jack-ups		435,194			271,809			163,385
Other		—			1,535			(1,535	)

Total Contract Drilling Revenue	$	1,987,114		$	1,179,015		$	808,099


Revenues Related to Reimbursable Expenses	$	65,458		$	41,987		$	23,471

CONTRACT DRILLING EXPENSE
High-Specification Floaters	$	236,276		$	179,248		$	(57,028	)
Intermediate Semisubmersibles		391,092			325,579			(65,513	)
Jack-ups		159,424			123,833			(35,591	)
Other		25,265			9,880			(15,385	)

Total Contract Drilling Expense	$	812,057		$	638,540		$	(173,517	)


Reimbursable Expenses	$	57,465		$	35,549		$	(21,916	)

OPERATING INCOME
High-Specification Floaters	$	530,597		$	269,689		$	260,908
Intermediate Semisubmersibles		393,955			131,155			262,800
Jack-ups		275,770			147,976			127,794
Other		(25,265	)		(8,345	)		(16,920	)
Reimbursables, net		7,993			6,438			1,555
Depreciation		(200,503	)		(183,724	)		(16,779	)
General and Administrative Expense		(41,551	)		(37,162	)		(4,389	)
(Loss) gain on Sale and Disposition of Assets		(1,064	)		14,767			(15,831	)
Casualty gain on Ocean Warwick		500			33,605			(33,105	)

Total Operating Income	$	940,432		$	374,399		$	566,033

Continued strong demand for our rigs in all markets and geographic regions resulted in high utilization and historically high dayrates during 2006. Due to this continuing strong demand, our operating income in 2006 increased $566.0 million, or 151%, to $940.4 million, compared to $374.4 million in 2005. Dayrates have generally increased during 2006, compared to 2005, resulting in the generation of additional contract drilling revenues by our fleet. However, overall revenue increases were negatively impacted by the effect of downtime associated with mandatory surveys and related repair time and lower dayrates earned by some of our semisubmersible rigs due to

previously established job sequencing that caused the units to temporarily roll to older contracts with lower dayrates. Total contract drilling revenues in 2006 increased $808.1 million, or 69%, to $1,987.1 million compared to 2005.

Our results in 2006 were also impacted by higher expenses related to our mooring enhancement and other hurricane preparedness activities, wage increases in late 2005 and the first quarter of 2006 and surveys performed during 2006. The increase in survey costs included higher expenses for survey-related services and higher boat charges associated with moving rigs to and from shipyards. In addition, overall cost increases for maintenance and repairs between 2005 and 2006 reflect the impact of high, sustained utilization of our drilling units across our fleet and in all geographic locations in which we operate. The increase in overall operating and overhead costs also reflects the impact of higher prices throughout the offshore drilling industry and its support businesses. Total contract drilling expenses in 2006 increased $173.5 million, or 27%, to $812.1 million, compared to the same period in 2005. The increase in our operating expenses in 2006, as compared to 2005, was partially offset by an $8.0 million reduction in our reserve for personal injury claims based on an actuarial review.

Our operating results in 2005 included a $33.6 million casualty gain due to the constructive total loss of the Ocean Warwick as a result of Hurricane Katrina in August 2005 and an $8.0 million gain related to the June 2005 sale of the Ocean Liberator.

High-Specification Floaters.


	Year Ended
	December 31,				Favorable/
	2006		2005		(Unfavorable)
	(In thousands)
CONTRACT DRILLING REVENUE
GOM	$	574,594	$	304,642	$	269,952
Australia/Asia/Middle East		65,682		68,349		(2,667	)
South America		126,597		75,946		50,651

Total Contract Drilling Revenue	$	766,873	$	448,937	$	317,936


CONTRACT DRILLING EXPENSE
GOM	$	143,447	$	88,107	$	(55,340	)
Australia/Asia/Middle East		24,465		35,891		11,426
South America		68,364		55,250		(13,114	)

Total Contract Drilling Expense	$	236,276	$	179,248	$	(57,028	)



OPERATING INCOME	$	530,597	$	269,689	$	260,908

GOM. Revenues generated by our high-specification floaters operating in the GOM increased $270.0 million in 2006 compared to 2005, primarily due to higher average dayrates earned during the period and revenues generated by the Ocean Baroness, which relocated to the GOM from the Australia/Asia market in the latter half of 2005 ($58.1 million). Excluding the Ocean Baroness, average operating revenue per day for our rigs in this market increased to $242,000 during 2006, compared to $142,600 during 2005, generating additional revenues of $211.6 million. The higher overall dayrates achieved for our high-specification floaters reflect the continuing high demand for this class of rig in the GOM.

Average utilization for our high-specification rigs operating in the GOM, excluding the contribution from the Ocean Baroness, increased slightly to 96% in 2006 compared to 2005, and resulted in $0.2 million in revenue.

Operating costs during 2006 for our high-specification floaters in the GOM increased $55.3 million over operating costs incurred during 2005. The increase in operating costs is primarily due to the inclusion of normal operating costs and amortization of mobilization expenses for the Ocean Baroness during 2006 ($30.6 million) compared to the prior year when this drilling rig operated offshore Indonesia. In addition, our operating expenses for 2006, compared to 2005, reflect higher labor and benefits costs related to late 2005 and first quarter of 2006 wage increases, higher repair and maintenance costs, and higher miscellaneous operating expenses, including catering costs. Our operating expenses in 2005 reflect a $2.0 million reduction in costs due to a recovery from a

customer for damages sustained by one of our GOM rigs during Hurricane Ivan in 2004, partially offset by the recognition of $0.5 million in deductibles for damages sustained during Hurricane Katrina in 2005.

Australia/Asia. Revenues generated by our high-specification rigs in the Australia/Asia/Middle East market decreased $2.7 million in 2006 compared to 2005, primarily due to the relocation of the Ocean Baroness from this market to the GOM in the latter half of 2005. Prior to its relocation to the GOM, the Ocean Baroness generated $18.2 million in revenues during 2005. The decrease in revenues in 2006 was partially offset by additional revenue ($13.7 million) generated by an increase in the dayrate earned by the Ocean Rover compared to the prior year. The average operating revenue per day for this rig increased from $143,500 in 2005 to $181,500 in 2006 as a result of a new drilling program which began in the second quarter of 2006. Utilization improvements for the Ocean Rover during 2006, as compared to 2005 when the unit had 11 days of downtime for repairs, generated an additional $1.8 million in revenues.

Operating costs for our rigs in the Australia/Asia/Middle East market decreased $11.4 million in 2006 compared to 2005 primarily due to the relocation of the Ocean Baroness to the GOM ($15.5 million). This decrease was partially offset by an increase in operating costs for the Ocean Rover during 2006, compared to the prior year, primarily related to higher personnel-related costs as a result of late 2005 and March 2006 pay increases, increased agency fee costs (which are based on a percentage of revenues) and higher other miscellaneous operating expenses.

South America. Revenues for our high-specification rigs operating offshore Brazil increased $50.7 million in 2006 compared to 2005, primarily due to higher average dayrates earned by our rigs in this market ($44.1 million). Average operating revenue per day earned by the Ocean Alliance and the Ocean Clipper increased to $180,100 during 2006 up from $117,300 during the prior year as a result of contract renewals for both rigs in the latter part of 2005. Utilization for our rigs offshore Brazil increased from 89% in 2005 to 96% in 2006, contributing $6.6 million in additional revenues in 2006, primarily due to less downtime during 2006 for repairs.

Contract drilling expenses for our operations offshore Brazil increased $13.1 million in 2006 compared to 2005. The increase in costs is primarily due to higher labor, benefits and other personnel-related costs as a result of 2005 and March 2006 pay increases and other compensation enhancement programs, increased agency fee costs (which are based on a percentage of revenues), higher freight costs and higher maintenance and project costs.

Intermediate Semisubmersibles.


	Year Ended
	December 31,				Favorable/
	2006		2005		(Unfavorable)
	(In thousands)
CONTRACT DRILLING REVENUE
GOM	$	224,344	$	99,500	$	124,844
Mexican GOM		80,487		85,594		(5,107	)
Australia/Asia/Middle East		196,180		111,811		84,369
Europe/Africa		207,295		106,251		101,044
South America		76,741		53,578		23,163

Total Contract Drilling Revenue	$	785,047	$	456,734	$	328,313


CONTRACT DRILLING EXPENSE
GOM	$	80,498	$	49,947	$	(30,551	)
Mexican GOM		60,467		57,246		(3,221	)
Australia/Asia/Middle East		87,535		83,768		(3,767	)
Europe/Africa		109,741		93,253		(16,488	)
South America		52,851		41,365		(11,486	)

Total Contract Drilling Expense	$	391,092	$	325,579	$	(65,513	)



OPERATING INCOME	$	393,955	$	131,155	$	262,800

GOM. Revenues generated by our intermediate semisubmersible rigs operating in the GOM during 2006 increased $124.8 million over the prior year primarily due to higher average operating dayrates and the operation of the Ocean New Era ($53.9 million) which was reactivated in December 2005. Average operating dayrates for the remainder of our GOM fleet of intermediate rigs increased from $77,300 in 2005 to $149,300 in 2006 and generated additional revenues of $82.2 million during 2006. Excluding the Ocean New Era, utilization fell from 87% in 2005 to 75% in 2006, resulting in an $11.3 million reduction in revenues generated in 2006 compared to 2005. Average utilization in 2006 was negatively impacted by approximately five months of downtime for the Ocean Saratoga in connection with its survey and related repairs, as well as a life enhancement upgrade that commenced in the third quarter of 2006 and approximately one month of downtime for both the Ocean Voyager and Ocean Concord for mooring upgrades. Partially offsetting the decline in average utilization in 2006 was an improvement in utilization for the Ocean Lexington, which worked nearly all of 2006 prior to its move to Egypt at the beginning of the fourth quarter. During 2005, the Ocean Lexington incurred over four months of downtime for a survey and life enhancement upgrade.

Contract drilling expense for our GOM operations increased $30.6 million in 2006 compared to 2005, primarily due to normal operating costs for the Ocean New Era in 2006 ($7.6 million) and repair and other normal operating costs for the Ocean Whittington ($6.4 million) in the latter half of 2006 after its return from the Mexican GOM. Higher operating costs in 2006, as compared to 2005, reflect higher labor and benefits costs as a result of September 2005 and March 2006 wage increases for our rig-based personnel, mobilization costs associated with mooring upgrades for the Ocean Concord and Ocean Voyager, survey and related repair costs for the Ocean Saratoga and higher maintenance and other miscellaneous operating costs for our semisubmersible rigs in this market segment. In addition, during 2006, we incurred $2.4 million in costs associated with the rental of mooring lines and chains as temporary replacements for equipment lost during the 2005 hurricanes in the GOM. Partially offsetting the increased operating costs in 2006 was the absence of reactivation costs for the Ocean New Era, which returned to service in December 2005.

Mexican GOM. Revenues generated by our intermediate semisubmersibles operating in the Mexican GOM during 2006 decreased $5.1 million compared to 2005, primarily due to PEMEX’s early cancellation of its contract for the Ocean Whittington in July 2006, partially offset by increased revenues for the Ocean Worker as a result of a small dayrate increase received in December 2005. Our remaining three rigs in this market continue operating under contracts with PEMEX, two of which expire in mid-2007 and one that extends until late 2007. Operating costs in the Mexican GOM increased $3.2 million during 2006 compared to 2005, primarily due to the effect of 2005 and March 2006 wage increases for our rig-based personnel, as well as higher repair and maintenance costs, other miscellaneous operating costs and overheads, partially offset by lower operating costs for the Ocean Whittington pursuant to its third quarter relocation to the GOM after termination of its drilling contract by PEMEX. In addition, we incurred $1.9 million in costs associated with the demobilization of the Ocean Whittington from offshore Mexico to the GOM.

Australia/Asia. Our intermediate semisubmersible rigs operating in the Australia/Asia market during 2006 generated an additional $84.4 million in revenues compared to 2005 primarily due to higher average operating dayrates ($84.3 million). Average operating dayrates increased from $76,300 in 2005 to $135,600 in 2006. In addition, the over 95% utilization of both the Ocean Epoch and Ocean Patriot during 2006, as compared to 2005 when the average utilization for these two rigs was 84%, contributed an additional $6.6 million to 2006 revenues. During 2005 the Ocean Epoch had over two months of downtime associated with a scheduled 5-year survey, other regulatory inspections and contract preparation work prior to its relocation to Malaysia and the Ocean Patriot incurred over one month of downtime associated with an intermediate inspection and repairs.

These favorable revenue variances in 2006 were partially offset by the lower recognition of deferred mobilization, capital upgrade and other fees in 2006 compared to 2005. During 2006, we recognized $2.3 million in lump-sum mobilization revenue related to the Ocean Patriot’s move offshore New Zealand at the beginning of the fourth quarter of 2006 and equipment upgrade fees from two customers in connection with customer-requested capital improvements to the Ocean Patriot. However, during 2005, we recognized $5.7 million and $0.9 million in connection with the Ocean Patriot’s 2004 mobilization from South Africa to New Zealand and the Bass Strait and equipment upgrade fees, respectively. Additionally, we received a fee from another customer in this market for a drilling option for another rig, of which $0.6 million and $3.7 million were recognized in 2006 and 2005, respectively.

Contract drilling expense for the Australia/Asia/Middle East region increased slightly from $83.8 million in 2005 to $87.5 million in 2006. The $3.8 million net increase in costs for 2006 is primarily the result of higher labor costs (due to wage increases in late 2005 and March 2006), higher repair and maintenance costs, higher revenue-based agency fees and higher other operating costs. These unfavorable cost trends were partially offset by lower survey and inspection costs in 2006 and the recognition of an insurance deductible in 2005 related to an anchor winch failure on the Ocean Patriot. In addition, we recognized $1.1 million and $5.2 million in mobilization expenses for our rigs in this region during 2006 and 2005, respectively. The amount of mobilization expenses recognized during a period is dependent upon the duration of the rig move and the contract period over which the mobilization costs are to be recognized.

Europe/Africa. Revenues generated by our intermediate semisubmersibles operating in this market increased $101.0 million in 2006 compared to 2005, primarily due to an increase in the average operating revenue per day earned by our rigs in this market. Excluding the Ocean Lexington, which began operating in this market sector during the fourth quarter of 2006 and contributed revenues of $5.6 million, the average operating revenue per day for our rigs operating in this market increased from $87,500 in 2005 to $144,500 in 2006. This increase in average revenue per day generated additional revenues of $70.6 million in 2006 compared to 2005. All three of our rigs operating in the U.K. sector of the North Sea received operating dayrate increases during 2006 and the Ocean Vanguard began a drilling program in the fourth quarter of 2006 at a higher dayrate than it previously earned.

Average utilization for our rigs in the Europe/Africa region increased from 83% in 2005 to 94% in 2006, excluding the Ocean Lexington, generating $20.7 million in additional revenues. The increase in average utilization is primarily due to higher utilization in 2006 for the Ocean Vanguard, compared to 2005 when this unit incurred more than five months of downtime due to an anchor winch failure and for a 5-year survey and related repairs. Additionally, average utilization for our three rigs operating in the U.K. sector of the North Sea increased slightly, reflecting the nearly full utilization of the Ocean Nomad during 2006 compared to 2005, when the rig was ready-stacked for almost three weeks and incurred nearly a full month of downtime for repairs. These favorable utilization trends were partially offset by 48 days of downtime for the Ocean Princess which was in a shipyard for an intermediate survey during 2006. In comparison, the Ocean Princess operated for nearly all of 2005.

During 2006, we also recognized $4.4 million in revenues related to the amortization of lump-sum fees received from customers for capital improvements to the Ocean Guardian and Ocean Vanguard.

Contract drilling expenses for our intermediate semisubmersible rigs operating in the Europe/Africa region increased $16.5 million during 2006 compared to 2005, primarily due to the inclusion of $4.2 million of normal operating costs for the Ocean Lexington in Egypt and costs associated with scheduled surveys for the Ocean Guardian and Ocean Princess, including mobilization and related repair costs during 2006. Also contributing to the increase in costs during 2006 were higher personnel and related costs (including administrative and support personnel in the region), reflecting the impact of wage increases after September 2005 and higher overall other operating costs. These cost increases in 2006 were partially offset by lower maintenance costs for the Ocean Vanguard in 2006 compared to 2005 and the absence of mobilization costs in 2006 related to the Ocean Nomad’s relocation from Gabon to the North Sea at the end of 2004, which were fully recognized in 2005, as well as the 2005 recognition of mobilization costs incurred in connection with the Ocean Guardian’s first quarter 2006 survey.

South America. Revenues generated by our two intermediate semisubmersible rigs operating in Brazil increased $23.2 million to $76.7 million in 2006 from $53.6 million in 2005, primarily due to higher average operating dayrates earned by both of our rigs in this market. Average operating revenue per day rose from $75,100 in 2005 to $113,700 in 2006, contributing $26.4 million in additional revenues.

Reduced utilization for our two intermediate semisubmersible rigs operating offshore Brazil during 2006, compared to 2005, is primarily the result of additional downtime for repairs during 2006, including 45 days of downtime for a thruster change-out on the Ocean Yatzy. This overall decrease in average utilization in 2006 resulted in a $3.2 million reduction in revenues compared to the prior year.

Operating expenses for the Ocean Yatzy and Ocean Winner increased $11.5 million in 2006 compared to the prior year, primarily due to increased labor costs for our rig-based and shore-based personnel as a result of wage increases and other compensation enhancement programs implemented after the third quarter of 2005, higher

revenue-based agency fees, as well as higher repair, maintenance and freight costs and increases in other routine operating costs in 2006 compared to 2005.

Jack-Ups.


	Year Ended
	December 31,				Favorable/
	2006		2005		(Unfavorable)
	(In thousands)
CONTRACT DRILLING REVENUE
GOM	$	315,279	$	222,365	$	92,914
Mexican GOM		15,966		—		15,966
Australia/Asia/Middle East		61,141		49,444		11,697
Europe/Africa		42,808		—		42,808

Total Contract Drilling Revenue	$	435,194	$	271,809	$	163,385


CONTRACT DRILLING EXPENSE
GOM	$	112,524	$	98,866	$	(13,658	)
Mexican GOM		4,373		—		(4,373	)
Australia/Asia/Middle East		27,721		24,967		(2,754	)
Europe/Africa		14,806		—		(14,806	)

Total Contract Drilling Expense	$	159,424	$	123,833	$	(35,591	)



OPERATING INCOME	$	275,770	$	147,976	$	127,794

GOM. Revenues generated by our jack-up rigs in the GOM increased $92.9 million in 2006 compared to 2005 primarily due to an improvement in average operating dayrates for our rigs in this region. Excluding the Ocean Warwick, which was declared a constructive total loss in the third quarter of 2005, our average operating revenue per day increased to $100,800 in 2006 from $59,100 in 2005, generating additional revenues of $141.9 million. GOM revenues were reduced $37.2 million due to changes in average utilization which fell to 79% in 2006 from 96% in 2005 (excluding the Ocean Warwick). During 2006, utilization in the GOM was negatively impacted primarily by the relocation of the Ocean Spur to Tunisia in the first quarter of 2006 and over five months of downtime for the Ocean Nugget for a special survey, related repairs and contract preparation work prior to its relocation to the Mexican GOM in the fourth quarter of 2006. Also during 2006, the Ocean Spartan underwent leg repairs and was ready-stacked from mid-September 2006 until mid-December 2006 for total downtime of approximately four months, and the Ocean Summit incurred over three months of downtime for a special survey and related repairs. During 2005, the Ocean Warwick generated revenues of $11.8 million.

Contract drilling expense in the GOM during 2006 increased $13.7 million compared to 2005. The increase in 2006 operating costs is primarily due to higher labor and other personnel-related costs as a result of late 2005 and March 2006 wage increases, costs associated with special surveys and related repairs for the Ocean Summit and Ocean Nugget, leg repairs for the Ocean Nugget, leg/spud can repairs for the Ocean Spartan and higher overhead, catering and other miscellaneous operating expenses. The overall increase in contract drilling expenses was partially offset by the absence of operating costs for the Ocean Warwick during 2006 and reduced operating costs in the GOM for the Ocean Spur (which only operated in the GOM for 45 days in 2006 before relocating to Tunisia) and the Ocean Nugget (which was relocated to the Mexican GOM at the beginning of the fourth quarter of 2006). Both the Ocean Spur and Ocean Nugget operated solely in the GOM during 2005. Also partially offsetting these negative cost trends was a reduction in survey and related mobilization costs during 2006 associated with the Ocean Spartan’s survey in late 2005. We also recognized a $1.0 million insurance deductible for a leg punchthrough incident on the Ocean Spartan in 2005.

Mexican GOM. Our jack-up rig the Ocean Nugget, which relocated to the Mexican GOM at the beginning of the fourth quarter of 2006, generated $16.0 million there in 2006. This unit is contracted to work for PEMEX through March 2009. Contract drilling expenses related to this rig were $4.4 million. We had no jack-up units operating in this market during 2005.

Australia/Asia/Middle East. Revenues generated by our jack-up rigs in the Australia/Asia and Middle East regions were $61.1 million in 2006 compared to $49.4 million in 2005. The $11.7 million increase in revenues in this region during 2006 compared to the prior year is primarily attributable to higher average operating dayrates for both of our jack-up rigs in this region ($15.1 million). Average dayrates for our jack-up rigs in this region increased from $71,900 in 2005 to $95,600 in 2006. The favorable contribution to operating revenues by the increase in average operating dayrates was partially offset by the reduced recognition of deferred mobilization revenues in 2006, as compared to 2005 ($3.1 million) and the effect of slightly lower average utilization in this region in 2006 compared to 2005 ($0.3 million).

Contract drilling expenses for our jack-up rigs in the Australia/Asia and Middle East regions increased slightly from $25.0 million in 2005 to $27.7 million in 2006. Higher labor costs in 2006 (resulting from late 2005 and early 2006 wage increases), higher maintenance, inspection costs and revenue-based agency fees were partially offset by the 2005 recognition of an insurance deductible for leg damage to the Ocean Heritage and the recognition of mobilization costs related to relocation of the Ocean Sovereign to locations offshore Bangladesh and Indonesia during 2005.

Europe/Africa. The Ocean Spur began operating offshore Tunisia in mid-March 2006 and generated $42.8 million in revenues, including the recognition of $5.3 million in deferred mobilization revenue, and incurred operating expenses of $14.8 million during 2006. We did not have any of our jack-up rigs working in this region during 2005.

Other Contract Drilling.

Other contract drilling expenses increased $15.4 million during 2006 compared to 2005, primarily due to the inclusion of $12.7 million in costs related to anchor boat rental and other costs associated with our mooring enhancement and hurricane preparedness activities, which were implemented in response to mooring issues which arose during the 2005 hurricane season.

Reimbursable expenses, net.

Revenues related to reimbursable items, offset by the related expenditures for these items, were $8.0 million and $6.4 million for 2006 and 2005, respectively. Reimbursable expenses include items that we purchase, and/or services we perform, at the request of our customers. We charge our customers for purchases and/or services performed on their behalf at cost, plus a mark-up where applicable. Therefore, net reimbursables fluctuate based on customer requirements, which vary.

Depreciation.

Depreciation expense increased $16.8 million to $200.5 million during 2006 compared to $183.7 million during the same period in 2005 primarily due to depreciation associated with capital additions in 2005 and 2006, partially offset by lower depreciation expense resulting from the declaration of a constructive total loss of the Ocean Warwick in the third quarter of 2005.

General and Administrative Expense.

We incurred general and administrative expense of $41.6 million during 2006 compared to $37.2 million during 2005. The $4.4 million increase in overhead costs between the periods was primarily due to the recognition of stock-based compensation expense pursuant to our adoption of SFAS No. 123(R), effective January 1, 2006.

Gain (Loss) on Sale of Assets.

We recognized a net loss of $1.1 million on the sale and disposal of assets, including disposal costs, during 2006 compared to a net gain of $14.8 million during 2005. The loss recognized in 2006 is primarily the result of costs associated with the removal of production equipment from the Ocean Monarch, which was subsequently sold to a third party, partially offset by a $1.1 million recovery from certain of our customers related to the involuntary conversion of assets damaged during the 2005 hurricanes. Results for 2005 included a gain of $8.0 million related to the June 2005 sale of the Ocean Liberator, $5.6 million in insurance proceeds related to the involuntary conversion of certain assets damaged during Hurricane Ivan in 2004 and gains on the sale of used drill pipe during the period, partially offset by a $1.4 million loss due to the retirement of equipment lost or damaged during

Hurricanes Katrina and Rita in 2005.

Casualty Gain on Ocean Warwick.

We recorded a $33.6 million casualty gain in 2005 as a result of the constructive total loss of the Ocean Warwick, resulting from damages sustained during Hurricane Katrina in August 2005. Subsequently in 2006, we revised our estimate of expected deductibles related to this incident and recorded a $0.5 million favorable adjustment to “Casualty Gain on Ocean Warwick.” See “—Overview—Impact of 2005 Hurricanes.”

Interest Income.

We earned interest income of $37.9 million during 2006 compared to $26.0 million in 2005. The $11.9 million increase in interest income is primarily the result of the combined effect of slightly higher interest rates earned on higher average invested cash balances in 2006, as compared to 2005. See “— Liquidity and Capital Requirements” and “— Historical Cash Flows.”

Interest Expense.

We recorded interest expense of $24.1 million during 2006, reflecting a $17.7 million decrease in interest cost compared to 2005. The decrease in interest cost was primarily attributable to lower interest expense in 2006 related to our Zero Coupon Convertible Debentures due 2020, or Zero Coupon Debentures, as a result of our June 2005 repurchase of $774.1 million in aggregate principal amount at maturity of Zero Coupon Debentures, the associated write-off of $6.9 million of debt issuance costs in June 2005 and the conversion of $22.4 million in aggregate principal amount at maturity of Zero Coupon Debentures into shares of our common stock during 2006. In addition we capitalized an additional $9.1 million in interest costs in connection with qualifying upgrades and construction projects during 2006 compared to 2005. The decrease in interest cost was partially offset by additional interest expense on our 4.875% Senior Notes due July 1, 2015, or 4.875% Senior Notes, which we issued in June 2005.

Other Income and Expense (Other, net).

Included in “Other, net” are foreign currency translation adjustments and transaction gains and losses and other income and expense items, among other things, which are not attributable to our drilling operations. The components of “Other, net” fluctuate based on the level of activity, as well as fluctuations in foreign currencies. We recorded other income, net, of $12.1 million during 2006 and other expense, net, of $1.1 million in 2005.

Effective October 1, 2005, we changed the functional currency of certain of our subsidiaries operating outside the United States to the U.S. dollar to more appropriately reflect the primary economic environment in which these subsidiaries operate. Prior to this date, these subsidiaries utilized the local currency of the country in which they conducted business as their functional currency. During the years ended December 31, 2006 and 2005, we recognized net foreign currency exchange gains of $10.3 million and net foreign currency exchange losses of $0.8 million, respectively. Prior to the fourth quarter of 2005, we accounted for foreign currency translation gains and losses as a component of “Accumulated other comprehensive losses” in our Consolidated Balance Sheets included in Item 8 of this report.

Income Tax Expense.

Our net income tax expense is a function of the mix of our domestic and international pre-tax earnings, as well as the mix of earnings from the international tax jurisdictions in which we operate. We recognized $259.5 million of tax expense on pre-tax income of $966.3 million for the year ended December 31, 2006 compared to tax expense of $96.1 million on a pre-tax income of $356.4 million in 2005.

Certain of our rigs that operate internationally are owned and operated, directly or indirectly, by Diamond Offshore International Limited, a Cayman Islands subsidiary that we wholly own. We do not intend to remit earnings from this subsidiary to the U.S. and we plan to indefinitely reinvest these earnings internationally. Consequently, we provided no U.S. taxes on earnings and recognized no U.S. benefits on losses generated by this subsidiary during 2006 and 2005.

During 2006 we were able to utilize all of the foreign tax credits available to us and we had no foreign tax credit carryforwards as of December 31, 2006. At the end of 2005, we had a valuation allowance of $0.8 million for certain of our foreign tax credit carryforwards which was reversed during 2006 as the valuation allowance was no longer necessary. During 2005, we reversed $9.6 million of the previously established $10.3 million valuation allowance for certain of our foreign tax credit carryforwards.

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

During 2005, we reversed a previously established reserve of $8.9 million ($1.7 million included with Current Taxes Payable and $7.2 million in Other Liabilities in our Consolidated Balance Sheets) associated with exposure related to the disallowance of goodwill deductibility associated with a 1996 acquisition which we believed was no longer necessary.

During 2005, we settled an income tax dispute in East Timor (formerly part of Indonesia) for approximately $0.2 million. At December 31, 2004, our books reflected an accrued liability of $4.4 million related to potential East Timor and Indonesian income tax liabilities covering the period 1992 through 2000. Subsequent to the tax settlement, we determined that the accrual was no longer necessary and reversed the accrued liability in the fourth quarter of 2005.

During 2004 and 2005, the Internal Revenue Service, or IRS, examined our federal income tax returns for tax years 2000 and 2002. The examination was concluded during the fourth quarter of 2005. We and the IRS agreed to a limited number of adjustments for which we recorded additional income tax of $1.9 million in 2005.

Results of Operations

Years Ended December 31, 2005 and 2004


	Year Ended
	December 31,						Favorable/
	2005			2004			(Unfavorable)
	(In thousands)
CONTRACT DRILLING REVENUE
High-Specification Floaters	$	448,937		$	281,866		$	167,071
Intermediate Semisubmersibles		456,734			319,053			137,681
Jack-ups		271,809			178,391			93,418
Other		1,535			3,095			(1,560	)

Total Contract Drilling Revenue	$	1,179,015		$	782,405		$	396,610


Revenues Related to Reimbursable Expenses	$	41,987		$	32,257		$	9,730

CONTRACT DRILLING EXPENSE
High-Specification Floaters	$	179,248		$	172,182		$	(7,066	)
Intermediate Semisubmersibles		325,579			277,728			(47,851	)
Jack-ups		123,833			114,466			(9,367	)
Other		9,880			4,252			(5,628	)

Total Contract Drilling Expense	$	638,540		$	568,628		$	(69,912	)


Reimbursable Expenses	$	35,549		$	28,899		$	(6,650	)

OPERATING INCOME (LOSS)
High-Specification Floaters	$	269,689		$	109,684		$	160,005
Intermediate Semisubmersibles		131,155			41,325			89,830
Jack-ups		147,976			63,925			84,051
Other		(8,345	)		(1,157	)		(7,188	)
Reimbursables, net		6,438			3,358			3,080
Depreciation		(183,724	)		(178,835	)		(4,889	)
General and Administrative Expense		(37,162	)		(32,759	)		(4,403	)
Gain (Loss) on Sale and Disposition of Assets		14,767			(1,613	)		16,380
Casualty gain on Ocean Warwick		33,605			—			33,605

Total Operating Income	$	374,399		$	3,928		$	370,471

High-Specification Floaters.


	Year Ended
	December 31,				Favorable/
	2005		2004		(Unfavorable)
	(In thousands)
CONTRACT DRILLING REVENUE
GOM	$	304,642	$	144,077	$	160,565
Australia/Asia		68,349		80,666		(12,317	)
South America		75,946		57,123		18,823

Total Contract Drilling Revenue	$	448,937	$	281,866	$	167,071


CONTRACT DRILLING EXPENSE
GOM	$	88,107	$	81,083	$	(7,024	)
Australia/Asia		35,891		40,732		4,841
South America		55,250		50,367		(4,883	)

Total Contract Drilling Expense	$	179,248	$	172,182	$	(7,066	)



OPERATING INCOME	$	269,689	$	109,684	$	160,005

GOM. Revenues for our high-specification floaters in the GOM increased $160.6 million in 2005, primarily due to higher average dayrates earned ($128.0 million) and higher utilization of our fleet in this market ($31.9 million), as compared to 2004. The higher overall dayrates achieved for our high-specification floaters reflected the continuing high demand for this class of rig in the GOM. Average dayrates for these rigs increased to $143,800 in 2005 compared to $82,000 in 2004.

Fleet utilization for our high-specification rigs in the GOM increased to 91% in 2005 from 80% in 2004. Higher utilization in 2005 compared to the prior year reflects the return to drilling operations of several rigs which did not operate in 2004 due to scheduled inspections and repairs (Ocean Confidence and Ocean America) and upgrade projects (Ocean America) and the ready-stacking of the Ocean Star for the first five months of 2004. In the late third quarter of 2005, we relocated the Ocean Baroness from the Australia/Asia market to the GOM for a long-term contract extending until November 2009. The Ocean Baroness began operating under contract in the GOM in November 2005 and generated revenues of $9.8 million in 2005, which are included in the utilization factors discussed above.

Operating costs during 2005 for our high-specification floaters in the GOM increased $7.0 million over operating costs in 2004. The increase in operating costs is primarily attributable to higher labor and benefits costs related to higher utilization of our rigs and the effect of December 2004 and September 2005 wage increases. Costs in 2005 also include operating expenses for the Ocean Baroness in the GOM, including mobilization costs from Southeast Asia. Increased operating costs in 2005 were partially offset by our recovery from a customer for damages sustained to one of our high-specification rigs during Hurricane Ivan in 2004.

Australia/Asia. Revenues generated by our rigs in the Australia/Asia region decreased $12.3 million to $68.3 million in 2005, as compared to revenues of $80.7 million in 2004. Utilization in this region decreased from 95% in 2004 to 80% in 2005, primarily due to the relocation of the Ocean Baroness from this market to the GOM. Prior to its departure to the GOM, the Ocean Baroness was mobilized to a shipyard in Singapore in mid-May 2005 for an intermediate inspection and preparation for the rig’s dry tow to the GOM, which resulted in additional unpaid downtime for the drilling unit as compared to 2004. The decline in utilization in 2005, as compared to 2004, resulted in a $23.9 million reduction in revenues in 2005. Average operating dayrates in this region increased from $116,600 in 2004 to $141,000 in 2005 and resulted in additional revenues of $11.6 million in 2005 compared to 2004.

Contract drilling expenses in the region decreased $4.8 million in 2005, as compared to 2004, primarily due to the relocation of the Ocean Baroness to the GOM in the third quarter of 2005. The overall decline in operating costs in the region was partially offset by higher insurance costs associated with increased premiums for the 2005/2006 policy year and additional loss-of-hire insurance coverage.

South America. Revenues for our high-specification rig operations offshore Brazil increased $18.8 million in 2005, as compared to 2004, primarily as a result of increased utilization for the Ocean Alliance in 2005 as compared to the prior year, when this rig experienced approximately five months of unpaid downtime. Utilization for these rigs offshore Brazil increased from 76% in 2004 to 89% in 2005 and contributed $9.5 million in additional revenues. Additionally, we negotiated a contract extension, including a dayrate increase, for the Ocean Alliance in the third quarter of 2005. Average dayrates earned by our high-specification rigs in this region increased to $117,300 in 2005 from $102,900 in 2004, which contributed $9.3 million in additional revenues during 2005.

Contract drilling expense for these operations in Brazil increased $4.9 million in 2005 compared to the prior year. The increase in costs in 2005 was primarily due to higher labor and benefit costs as a result of December 2004 and September 2005 pay increases, increased local shorebase support costs due to the completion of a local training program in Brazil and higher insurance costs associated with increased premiums for the 2005/2006 policy year and additional loss-of-hire insurance.

Intermediate Semisubmersibles.


	Year Ended
	December 31,				Favorable/
	2005		2004		(Unfavorable)
	(In thousands)
CONTRACT DRILLING REVENUE
GOM	$	99,500	$	42,425	$	57,075
Mexican GOM		85,594		85,383		211
Australia/Asia		111,811		77,187		34,624
Europe/Africa		106,251		69,285		36,966
South America		53,578		44,773		8,805

Total Contract Drilling Revenue	$	456,734	$	319,053	$	137,681


CONTRACT DRILLING EXPENSE
GOM	$	49,947	$	37,300	$	(12,647	)
Mexican GOM		57,246		56,948		(298	)
Australia/Asia		83,768		63,969		(19,799	)
Europe/Africa		93,253		82,864		(10,389	)
South America		41,365		36,647		(4,718	)

Total Contract Drilling Expense	$	325,579	$	277,728	$	(47,851	)



OPERATING INCOME	$	131,155	$	41,325	$	89,830

GOM. Revenues generated in 2005 by our intermediate semisubmersible fleet operating in the GOM increased $57.1 million due to higher average dayrates earned ($31.3 million) and higher utilization of our fleet in this market ($27.5 million), as compared to 2004. Average dayrates earned increased to $77,300 in 2005 compared to $44,600 in 2004, reflecting the tightening market for intermediate semisubmersibles in the GOM. During 2004, we recognized $1.8 million in lump-sum mobilization fees for the Ocean Concord.

Overall utilization for our intermediate semisubmersibles in this region (excluding the Ocean Endeavor, which was cold-stacked during 2004 prior to commencing a major upgrade in 2005, and the cold-stacked Ocean Monarch, which we acquired in August 2005) increased to 71% in 2005 from 50% in 2004. The increase in utilization in 2005, as compared to 2004, is primarily due to the nearly full utilization of the Ocean Voyager in 2005 compared to 2004, when this unit was cold-stacked for most of the year, and increased utilization for the Ocean Concord, which was out of service for almost six months in 2004 for a 5-year survey and maintenance projects. Additionally, we reactivated the Ocean New Era from cold-stack status in the last half of 2005, and this drilling unit returned to active service in late December 2005. Partially offsetting the overall increase in utilization in 2005, as compared to 2004, was approximately four months of unpaid downtime for the Ocean Lexington in 2005 associated with inspections and a life enhancement project.

Contract drilling expense for our intermediate semisubmersibles’ operations in the GOM increased $12.6 million in 2005, as compared to 2004, primarily due to higher labor and benefits costs as a result of December 2004 and September 2005 wage increases for our rig-based personnel, normal operating costs for the Ocean Voyager and Ocean New Era in 2005 and higher inspection and maintenance project costs for the Ocean Lexington, which was in a shipyard for inspections and a life enhancement project during 2005. These cost increases were partially offset by lower reactivation costs for the Ocean New Era in 2005, as compared to costs incurred to reactivate the Ocean Voyager in 2004.

Australia/Asia. Our intermediate semisubmersibles working offshore Australia/Asia generated revenues of $111.8 million in 2005 compared to revenues of $77.2 million in 2004. The $34.6 million increase in operating revenues was primarily due to an increase in average operating dayrates to $76,300 in 2005 compared to $62,900 in 2004, which generated $16.9 million in additional revenues in 2005. Our results in this region in 2005 also reflect the favorable impact of the Ocean Patriot operating for the majority of the year following its relocation to the region in the second half of 2004. However, excluding the Ocean Patriot, our average utilization for these rigs in the Australia/Asia region decreased from 96% in 2004 to 92% in 2005, primarily due to unpaid downtime for the Ocean Epoch which was in a shipyard for approximately 70 days in 2005 for a scheduled 5-year survey and associated repairs. The net effect of changes in utilization in this region was the generation of $10.7 million in additional revenues in 2005 compared to 2004.

During 2005 we recognized $5.7 million in lump-sum mobilization fees for the Ocean Patriot related to its 2004 mobilization from South Africa to New Zealand and the Bass Strait, compared to $3.3 million in similar fees recognized in 2004. In 2005 we also recognized $3.7 million in revenue related to the extension of a contract option period for one of our rigs in this region and $0.9 million in revenues for the amortization of lump-sum fees received from a customer for rig modifications.

Contract drilling expense for the Australia/Asia region increased $19.8 million from 2004 to 2005, primarily due to costs associated with the Ocean Patriot operating offshore Australia for all of 2005, including the amortization of deferred mobilization expenses.

Europe/Africa. Operating revenues for our intermediate semisubmersibles working in this region increased $37.0 million in 2005 primarily due to an increase in the average operating dayrates from $54,400 in 2004 to $87,500 in 2005. This increase in average operating dayrates contributed $40.6 million in additional revenues in 2005, as compared to 2004.

With the exception of the Ocean Patriot, which relocated from this region to Australia in mid-2004, average utilization increased slightly in 2005 compared to 2004, primarily due to higher utilization of the Ocean Nomad in 2005 as compared to 2004, when this drilling unit was both ready-stacked and mobilizing between Africa and the U.K. for a total of approximately five months during the year. The net effect of changes in average utilization between 2005 and 2004 was a $1.9 million decrease in operating revenues in 2005. In 2004, we also recognized $2.0 million in mobilization revenue for the Ocean Nomad.

Contract drilling expense for our intermediate semisubmersible rigs operating offshore Europe increased $10.4 million in 2005 primarily due to increased labor and related costs and shorebase support costs for our operations in Norway, mostly due to Norwegian pay allowances and additional personnel required to comply with Norwegian regulations. Normal operating expenses for the Ocean Nomad increased in 2005, as compared to 2004, mainly due to higher labor costs associated with its operations in the U.K., as compared to the prior year when this unit worked a portion of the year offshore western Africa, as well as the recognition of mobilization expenses in 2005 related to the rig’s relocation from western Africa to the U.K. Our operating costs in this region in 2004 included $8.7 million in costs for the Ocean Patriot which relocated to the Australia/Asia region in mid-2004.

South America. Our intermediate semisubmersibles working in Brazil generated revenues of $53.6 million in 2005 compared to revenues of $44.8 million in 2004. The $8.8 million increase in operating revenues was primarily due to a contract extension for the Ocean Yatzy at a higher average dayrate than it previously earned. Average operating dayrates increased to $75,100, as compared to an average dayrate of $70,300 in 2004, and resulted in additional revenues of $4.3 million in 2005. Average utilization of our rigs in this region increased from 87% in

2004 to 98% in 2005, which resulted in additional revenues in 2005 of $4.5 million. The lower utilization in 2004 was primarily due to additional downtime for special surveys and inspections of both of our rigs in this region.

Operating expenses for the Ocean Yatzy and Ocean Winner increased $4.7 million in 2005, as compared to 2004, primarily due to increased labor costs for our rig-based personnel as a result of December 2004 and September 2005 wage increases and higher national labor and local shorebase support costs resulting from completion of a local competency program in Brazil.

Jack-Ups.


	Year Ended
	December 31,				Favorable/
	2005		2004		(Unfavorable)
	(In thousands)
CONTRACT DRILLING REVENUE
GOM	$	222,365	$	138,886	$	83,479
Australia/Asia/Middle East		49,444		21,290		28,154
South America		—		18,215		(18,215	)

Total Contract Drilling Revenue	$	271,809	$	178,391	$	93,418


CONTRACT DRILLING EXPENSE
GOM	$	98,866	$	89,906	$	(8,960	)
Australia/Asia/Middle East		24,967		15,546		(9,421	)
South America		—		9,014		9,014

Total Contract Drilling Expense	$	123,833	$	114,466	$	(9,367	)



OPERATING INCOME	$	147,976	$	63,925	$	84,051

GOM. Our operating results in this region reflected the improvement in average operating dayrates and utilization for jack-up rigs in the GOM during 2005. Average operating dayrates increased to $54,600 in 2005 from $36,300 in 2004, which resulted in additional revenues of $75.5 million in 2005. Utilization of our jack-up fleet in the GOM continued to improve in 2005 compared to the average utilization achieved by our rigs in 2004. Average utilization in 2005 increased to 96% from 87% in 2004, resulting in additional revenues of $8.0 million in 2005. The improvement in utilization was primarily due to the nearly full utilization of the Ocean Champion in 2005 as compared to 2004, when it completed its reactivation from cold-stacked status, and the full utilization of the Ocean Nugget in 2005, as compared to 60 days of unpaid downtime in 2004 for a spud can inspection and related repair work.

In late August 2005, the Ocean Warwick was declared a constructive total loss by our insurers as a result of damage it sustained during Hurricane Katrina. During 2005 and 2004, this drilling rig generated $11.8 million and $9.3 million in revenues, respectively, which are included in the revenue variances discussed above. See “—Overview — Impact of 2005 Hurricanes.”

Contract drilling expenses for our jack-up rigs operating in the GOM increased $9.0 million in 2005 compared to 2004, primarily due to higher labor and benefits costs for our rig-based personnel as a result of December 2004 and September 2005 wage increases, higher normal operating costs in 2005 for the Ocean Champion compared to 2004 when the rig was being reactivated and higher operating and overhead costs for most of our jack-ups in this region due to increased utilization.

Australia/Asia/Middle East. Revenues for jack-up rigs in the Australasian and Middle East regions were $49.4 million in 2005 compared to $21.3 million in 2004. The $28.2 million increase in revenues in this region in 2005 is primarily attributable to revenues generated by the Ocean Heritage ($17.0 million), which worked in this region for the entire year, compared to working in this region during only the last quarter of 2004, and an operating dayrate increase for the Ocean Sovereign ($11.2 million) after its second quarter 2005 relocation within the region to Indonesia.

Contract drilling expense for our jack-up rigs in the Australasian and Middle East regions increased $9.4 million to $25.0 million in 2005, as compared 2004, primarily due to normal operating costs associated with the Ocean Heritage operating in the region for the entire year, and higher normal repair and maintenance, travel and shore-based costs for the Ocean Sovereign.

South America. The Ocean Heritage operated offshore Ecuador for almost eight months in 2004. During its contract the rig generated $18.2 million in revenues, including the recognition of $8.5 million in lump-sum mobilization fees, and incurred operating expenses of $9.0 million before returning to the Australasia/Middle East region in the fourth quarter of 2004.

Other Operating Revenue and Expenses, net.

Other operating expenses, net of other revenues, were $8.3 million in 2005 compared to $1.2 million in 2004. The $7.2 million increase in net costs in 2005, as compared to 2004, relates primarily to costs associated with relief and recovery efforts in the aftermath of the 2005 GOM hurricanes, increased rig crew training costs due to higher staffing and recruiting levels in 2005 and higher costs in 2005 to repair and replace non-rig-specific spare equipment.

Reimbursable expenses, net.

Revenues related to reimbursable items, offset by the related expenditures for these items, were $6.4 million and $3.4 million in 2005 and 2004, respectively. Reimbursable expenses include items that we purchase, and/or services we perform, at the request of our customers. We charge our customers for purchases and/or services performed on their behalf at cost, plus a mark-up where applicable. Therefore, net reimbursables fluctuate based on customer requirements, which vary.

Depreciation.

Depreciation expense increased $4.9 million to $183.7 million in 2005 compared to $178.8 million in 2004 primarily due to depreciation recorded in 2005 associated with capital additions in 2004 and 2005. The increase in depreciation expense attributable to capital additions was partially offset by lower depreciation due to the constructive total loss of the Ocean Warwick in the third quarter of 2005 and the transfer of the Ocean Liberator to assets held for sale in December 2004.

General and Administrative Expense.

We incurred general and administrative expense of $37.2 million in 2005 compared to $32.8 million in 2004. The $4.4 million increase in overhead costs between the periods was primarily due to higher compensation expense related to our management bonus plan, higher fees paid to our external auditors and higher engineering consulting fees. Partially offsetting these higher expenses were lower legal fees in 2005 compared to 2004, primarily due to the settlement of litigation in December 2004, and the capitalization of certain costs associated with the upgrade of the Ocean Endeavor, which commenced in 2005.

Gain on Sale and Disposition of Assets.

We recognized a net gain of $14.8 million on the sale and disposition of assets in 2005 compared to a net loss of $1.6 million in 2004. Net gains recognized in 2005 include an $8.0 million gain on the June 2005 sale of the Ocean Liberator, $5.6 million in insurance proceeds related to the involuntary conversion of certain assets damaged during Hurricane Ivan in 2004 and gains on the sale of used drill pipe during the period. Partially offsetting the net gain in 2005 was a $1.4 million loss due to the retirement of equipment lost or damaged during Hurricanes Katrina and Rita. The loss on sale of assets in 2004 relates primarily to the retirement of equipment damaged during Hurricane Ivan.

Casualty Gain on Ocean Warwick.

We recorded a $33.6 million casualty gain in 2005 as a result of the constructive total loss of one of our jack-up rigs, the Ocean Warwick, resulting from damages sustained during Hurricane Katrina in August 2005. See “— Overview — Impact of 2005 Hurricanes.”

Interest Income.

We earned interest income of $26.0 million in 2005 compared to $12.2 million in 2004. The $13.8 million increase in interest income is primarily the result of the combined effect of slightly higher interest rates earned on higher average cash and investment balances in 2005, as compared to 2004. See “— Liquidity and Capital Requirements” and “— Historical Cash Flows.”

Interest Expense.

Interest expense for 2005 was $41.8 million, or an $11.5 million increase in interest cost compared to 2004. This increase was primarily attributable to interest related to our 4.875% Senior Notes and our 5.15% Senior Notes Due September 1, 2014, or 5.15% Senior Notes, which we issued in June 2005 and August 2004, respectively. In addition, interest expense for 2005 included a write-off of $6.9 million in debt issuance costs associated with our June 2005 repurchase of approximately 96% of our then outstanding Zero Coupon Debentures. This increase in interest cost was partially offset by lower interest expense on our Zero Coupon Debentures subsequent to our partial repurchase of the outstanding debentures in June 2005 and approximately $0.7 million in interest costs which were capitalized in 2005 related to qualifying upgrade and construction projects. See “— Liquidity and Capital Requirements — Contractual Cash Obligations.”

Other Income and Expense (Other, net).

Included in “Other, net” are foreign currency translation adjustments and transaction gains and losses and other income and expense items, among other things, which are not attributable to our drilling operations. The components of “Other, net” fluctuate based on the level of activity, as well as fluctuations in foreign currencies. We recorded other expense, net, of $1.1 million in both 2005 and 2004.

Effective October 1, 2005, we changed the functional currency of certain of our subsidiaries operating outside the United States to the U.S. dollar to more appropriately reflect the primary economic environment in which these subsidiaries operate. Prior to this date, these subsidiaries utilized the local currency of the country in which they conduct business as their functional currency. During 2005 and 2004, we recognized net foreign currency exchange losses of $0.8 million and $1.4 million, respectively, including $3.5 million in additional expense in 2005 as a result of our change in functional currency to the U.S. dollar. Prior to the fourth quarter of 2005, we accounted for foreign currency translation gains and losses as a component of “Accumulated other comprehensive losses” in our Consolidated Balance Sheets included in Item 8 of this report.

Income Tax Expense.

Our net income tax expense is a function of the mix of our domestic and international pre-tax earnings, as well as the mix of earnings from the international tax jurisdictions in which we operate. We recognized $96.1 million of tax expense on pre-tax income of $356.4 million for the year ended December 31, 2005 compared to tax expense of $3.7 million on a pre-tax loss of $3.5 million in 2004.

At the end of 2004 we had established a valuation allowance of $10.3 million for certain of our foreign tax credit carryforwards which were scheduled to expire beginning in 2011. At December 31, 2005, we had $15.3 million of foreign tax credit carryforwards. During 2005, we were able to utilize most of our net operating loss carryforwards to offset taxable income generated during the year. As a result, we expected to be able to utilize $14.5 million of our available foreign tax credit carryforwards prior to their expiration dates, and determined that a valuation allowance was no longer necessary for those credits. Consequently, we reversed $9.6 million of the previously established valuation allowance during 2005. With respect to the remaining $0.8 million of foreign tax credit carryforwards, we determined that a valuation allowance was necessary and as a result had a valuation allowance of $0.8 million at December 31, 2005.

At December 31, 2004 we had a reserve of $8.9 million ($1.7 million included with Current Taxes Payable and $7.2 in Other Liabilities in our Consolidated Balance Sheets) for the exposure related to the disallowance of goodwill deductibility associated with a 1996 acquisition. During 2005 we concluded that the reserve was no longer necessary and eliminated the reserve, which resulted in an income tax benefit of $8.9 million.

During 2005, we settled an income tax dispute in East Timor (formerly part of Indonesia) for approximately $0.2 million. At December 31, 2004, our books reflected an accrued liability of $4.4 million related to potential East Timor and Indonesian income tax liabilities covering the period 1992 through 2000. Subsequent to the tax settlement, we determined that the accrual was no longer necessary and wrote off the accrued liability in the fourth quarter of 2005.

During 2004 and 2005, the IRS examined our federal income tax returns for tax years 2000 and 2002. The examination was concluded during the fourth quarter of 2005. We and the IRS agreed to a limited number of adjustments for which we recorded additional income tax of $1.9 million in 2005.

Our tax expense in 2004 included $2.5 million associated with a revision to estimates in tax balance sheet accounts, a tax benefit of $5.2 million related to goodwill arising from a 1996 merger, and a tax benefit of $4.5 million due to the reversal of a tax liability associated with the Ocean Alliance lease-leaseback.

On October 22, 2004, the American Jobs Creation Act, or AJCA, was signed into law. The AJCA includes a provision allowing a deduction of 85% for certain foreign earnings that are repatriated. The AJCA provided us a potential opportunity to elect to apply this provision to qualifying earnings repatriations in 2005. Based on the language in the AJCA and subsequent guidance issued by the U.S. Treasury Department, and after considering our history of foreign earnings, we did not have undistributed foreign earnings that would qualify for the 85% deduction upon repatriation. Consequently, we did not repatriate any undistributed earnings in 2005 pursuant to the AJCA.

Sources of Liquidity and Capital Resources

Our principal sources of liquidity and capital resources are cash flows from our operations, proceeds from the issuance of debt securities and our cash reserves. We may also make use of our $285 million credit facility for cash liquidity. See “— $285 Million Revolving Credit Facility.”

At December 31, 2006, we had $524.7 million in “Cash and cash equivalents” and $301.2 million in “Investments and marketable securities,” representing our investment of cash available for current operations.

Cash Flows from Operations. We operate in an industry that has been, and we expect to continue to be, extremely competitive and highly cyclical. The dayrates we receive for our drilling rigs and rig utilization rates are a function of rig supply and demand in the marketplace, which is generally correlated with the price of oil and natural gas. Demand for drilling services is dependent upon the level of expenditures by oil and gas companies for offshore exploration and development, a variety of political and economic factors and availability of rigs in a particular geographic region. As utilization rates increase, dayrates tend to increase as well reflecting the lower supply of available rigs, and vice versa. These factors are not within our control and are difficult to predict. For a description of other factors that could affect our cash flows from operations, see “— Overview — Industry Conditions,” “ — Forward-Looking Statements” and “Risk Factors” in Item 1A of this report.

$285 Million Revolving Credit Facility. In November 2006, we entered into a $285 million syndicated, 5-year senior unsecured revolving credit facility, or Credit Facility, for general corporate purposes, including loans and performance or standby letters of credit.

Loans under the Credit Facility bear interest at our option at a rate per annum equal to (i) the higher of the prime rate or the federal funds rate plus 0.5% or (ii) the London Interbank Offered Rate, or LIBOR, plus an applicable margin, varying from 0.20% to 0.525%, based on our current credit ratings. Under our Credit Facility, we also pay, based on our current credit ratings, and as applicable, other customary fees, including, but not limited to, a facility fee on the total commitment under the Credit Facility regardless of usage and a utilization fee that applies if the aggregate of all loans outstanding under the Credit Facility equals or exceeds 50% of the total commitment under the facility. Changes in credit ratings could lower or raise the fees that we pay under the Credit Facility.

The Credit Facility contains customary covenants, including, but not limited to, the maintenance of a ratio of consolidated indebtedness to total capitalization, as defined in the Credit Facility, of not more than 60% at the end of each fiscal quarter and limitations on liens, mergers, consolidations, liquidation and dissolution, changes in lines of business, swap agreements, transactions with affiliates and subsidiary indebtedness.

Based on our current credit ratings at December 31, 2006, the applicable margin on LIBOR loans would have been 0.27%. As of December 31, 2006, there were no amounts outstanding under the Credit Facility.

Shelf Registration. We have the ability to issue an aggregate of approximately $117.5 million in debt, equity and other securities under a shelf registration statement. In addition, from time to time we may issue up to eight million shares of common stock which are registered under an acquisition shelf registration statement, after giving effect to the two-for-one stock split we declared in July 1997, in connection with one or more acquisitions by us of securities or assets of other businesses.

Liquidity and Capital Requirements

Our liquidity and capital requirements are primarily a function of our working capital needs, capital expenditures and debt service requirements. We determine the amount of cash required to meet our capital commitments by evaluating the need to upgrade rigs to meet specific customer requirements and by evaluating our ongoing rig equipment replacement and enhancement programs, including water depth and drilling capability upgrades. We believe that our operating cash flows and cash reserves will be sufficient to meet these capital commitments; however, we will continue to make periodic assessments based on industry conditions. In addition, we may, from time to time, issue debt or equity securities, or a combination thereof, to finance capital expenditures, the acquisition of assets and businesses or for general corporate purposes. Our ability to effect any such issuance will be dependent on our results of operations, our current financial condition, current market conditions and other

factors beyond our control. Additionally, we may also make use of our Credit Facility to finance capital expenditures or for other general corporate purposes.

We believe that we have the financial resources needed to meet our business requirements in the foreseeable future, including capital expenditures for rig upgrades and enhancements, as well as our working capital requirements.

Contractual Cash Obligations. The following table sets forth our contractual cash obligations at December 31, 2006.


	Payments Due By Period
			Less than 1						After 5
Contractual Obligations	Total		year		1 — 3 years		4 — 5 years		years
	(In thousands)
Long-term debt (principal and interest) ⁽¹⁾	$	1,177,056	$	31,963	$	513,542	$	56,098	$	575,453
Forward exchange contracts		22,463		22,463		—		—		—
Purchase obligations related to rig upgrade/modifications		456,022		263,213		192,809		—		—
Operating leases		3,227		2,460		767		—		—

Total obligations	$	1,658,768	$	320,099	$	707,118	$	56,098	$	575,453


(1)		See “ — 1.5% Debentures” and “ — Zero Coupon Debentures” and Note 18 “Subsequent Events” to our Consolidated Financial Statements included in Item 8 of this report for a discussion of changes in our long-term debt subsequent to December 31, 2006.

Payments of our long-term debt, including interest, could be accelerated due to certain rights that holders of our debentures have to put the securities to us. See the discussion below related to our 1.5% Convertible Senior Debentures Due 2031, or 1.5% Debentures, and Zero Coupon Debentures.

As of December 31, 2006, we had purchase obligations aggregating approximately $456 million related to the major upgrades of the Ocean Endeavor and Ocean Monarch and construction of two new jack-up rigs, the Ocean Scepter and Ocean Shield. We anticipate that expenditures related to these shipyard projects will be approximately $263 million and $193 million in 2007 and 2008, respectively. However, the actual timing of these expenditures will vary based on the completion of various construction milestones, which are beyond our control.

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

4.875% Senior Notes.

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

5.15% Senior Notes.

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

1.5% Debentures.

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

During 2006 and 2005, the holders of $20,000 and $13,000, respectively, in principal amount of our 1.5% Debentures elected to convert their outstanding debentures into shares of our common stock, resulting in the issuance of 404 shares and 264 shares of our common stock in 2006 and 2005, respectively.

Subsequent to December 31, 2006 and through February 14, 2007, the holders of $438.4 million in principal amount of our 1.5% Debentures converted their outstanding debentures into 8,943,284 shares of our common stock. As a result of these conversions, $21.5 million aggregate principal amount of the 1.5% Debentures remained outstanding as of February 14, 2007. The cash requirements for the interest payable to holders of our 1.5% Debentures will decrease due to the decrease in the outstanding principal amount.

Zero Coupon Debentures.

We issued our Zero Coupon Debentures on June 6, 2000 at a price of $499.60 per $1,000 principal amount at maturity, which represents a yield to maturity of 3.50% per year. The Zero Coupon Debentures mature on June 6, 2020, and, as of December 31, 2006, the aggregate accreted value of our outstanding Zero Coupon Debentures was $5.3 million. We will not pay interest prior to maturity unless we elect to convert the Zero Coupon Debentures to interest-bearing debentures upon the occurrence of certain tax events. The Zero Coupon Debentures are convertible at the option of the holder at any time prior to maturity, unless previously redeemed, into our common stock at a fixed conversion rate of 8.6075 shares of common stock per $1,000 principal amount at maturity of Zero Coupon Debentures, subject to adjustments in certain events. See “Zero Coupon Debentures” in Note 8 “Long-Term Debt” to our Consolidated Financial Statements in Item 8 of this report. The Zero Coupon Debentures are senior unsecured obligations of Diamond Offshore Drilling, Inc.

On June 7, 2005, we repurchased $460.0 million accreted value, or $774.1 million in aggregate principal amount at maturity, of our Zero Coupon Debentures at a purchase price of $594.25 per $1,000 principal amount at maturity, which represented 96% of our then outstanding Zero Coupon Debentures. Additionally, in connection with the June 2005 repurchase, we expensed $6.9 million in debt issuance costs associated with the retired debentures, which we have included in interest expense in our Consolidated Statements of Operations for the year ended December 31, 2005.

During 2006, holders of $13.7 million accreted value, or $22.4 million in aggregate principal amount at maturity, of our Zero Coupon Debentures elected to convert their outstanding debentures into shares of our common stock. We issued 193,147 shares of our common stock upon conversion of these debentures.

Subsequent to December 31, 2006 and through February 14, 2007, the holders of $1.5 million accreted value at the dates of conversion, or $2.4 million aggregate principal amount at maturity, of our Zero Coupon Debentures converted their outstanding debentures into 20,658 shares of our common stock. As a result of these conversions, $3.8 million in accreted value, or $6.0 million aggregate principal amount at maturity, of the Zero Coupon Debentures remained outstanding as of February 14, 2007.

Letters of Credit.

We are contingently liable as of December 31, 2006 in the amount of $122.0 million under certain performance, bid, supersedeas and custom bonds and letters of credit. We purchased three of these performance bonds totaling $73.2 million from a related party after obtaining competitive quotes. Agreements relating to approximately $107.3

million of performance bonds can require collateral at any time. As of December 31, 2006, we had not been required to make any collateral deposits with respect to these agreements. The remaining agreements cannot require collateral except in events of default. On our behalf, banks have issued letters of credit securing certain of these bonds. See Note 12 “Related-Party Transactions” to our Consolidated Financial Statements included in Item 8 of this report.

Credit Ratings.

Our current credit rating is Baa2 for Moody’s Investors Services and A- for Standard & Poor’s. Although our long-term ratings continue at investment grade levels, lower ratings would result in higher rates for borrowings under our Credit Facility and could also result in higher interest rates on future debt issuances.

Capital Expenditures.

In 2006, we began a major upgrade of the Ocean Monarch, a Victory-class semisubmersible that we acquired in August 2005 for $20.0 million. The modernized rig will be designed to operate in up to 10,000 feet of water in a moored configuration for an estimated cost of approximately $300 million of which we had spent $33.9 million through December 31, 2006. We expect to spend an additional $150.0 million and $116.1 million on this upgrade in 2007 and 2008, respectively.

In addition, the shipyard portion of the upgrade of the Ocean Endeavor has been completed. The newly upgraded rig is currently undergoing sea trials and commissioning. The unit will remain in Singapore until the arrival of a heavy-lift vessel, anticipated late in the first quarter of 2007, which will return the rig to the GOM. The Ocean Endeavor is expected to commence drilling operations in the GOM in mid-2007. We estimate that the total cost of the upgrade will be approximately $253 million of which $208.4 million had been spent through December 31, 2006. We expect to spend the remaining $44.0 million in 2007.

In the second quarter of 2005, we entered into agreements to construct two high-performance, premium jack-up rigs. The two new drilling units, the Ocean Scepter and the Ocean Shield, are being constructed in Brownsville, Texas and Singapore, respectively, at an aggregate expected cost of approximately $320 million, including drill pipe and capitalized interest, of which $176.1 million had been spent through December 31, 2006. Each newbuild jack-up rig will be equipped with a 70-foot cantilever package, be capable of drilling depths of up to 35,000 feet and have a hook load capacity of two million pounds. We expect to spend approximately $69 million and $77 million towards the construction of these two units in 2007 and 2008, respectively. Delivery of both the Ocean Scepter and Ocean Shield are expected in the first quarter of 2008.

We have budgeted approximately $316 million in additional capital expenditures in 2007 associated with our ongoing rig equipment replacement and enhancement programs, and other corporate requirements. We expect to finance our 2007 capital expenditures through the use of our existing cash balances or internally generated funds. From time to time, however, we may also make use of our Credit Facility to finance capital expenditures.

During 2006, we spent approximately $273.2 million on our continuing rig capital maintenance program (other than rig upgrades and new construction) and to meet other corporate capital expenditure requirements.

Off-Balance Sheet Arrangements.

At December 31, 2006 and 2005, we had no off-balance sheet debt or other arrangements.

Historical Cash Flows

The following is a discussion of our historical cash flows from operating, investing and financing activities for the year ended December 31, 2006 compared to 2005.

Net Cash Provided by Operating Activities.


	Year Ended December 31,
	2006			2005			Change
	(In thousands)
Net income	$	706,847		$	260,337		$	446,510
Net changes in operating assets and liabilities		(154,068	)		(84,906	)		(69,162	)
Loss on sale of marketable securities		31			1,180			(1,149	)
Depreciation and other non-cash items, net		207,279			211,960			(4,681	)

	$	760,089		$	388,571		$	371,518

Our cash flows from operations in 2006 increased $371.5 million or 96% over net cash generated by our operating activities in 2005. The increase in cash flow from operations in 2006 is primarily the result of higher average dayrates and, to a lesser extent, higher utilization earned by our offshore drilling units as a result of an increase in worldwide demand for offshore contract drilling services in 2006 as compared to 2005. These favorable trends were impacted by an increase in cash required to satisfy our working capital requirements, including an increase in our trade accounts receivable, which is primarily driven by higher dayrates earned by our drilling rigs in 2006 as compared to 2005. These trade receivables generate cash as the billing cycle is completed, customarily within 30 to 45 days of invoicing. In addition, we paid $248.7 million and $10.8 million in U.S. federal and foreign income taxes, respectively, each net of refunds received, during 2006. We received $7.7 million in refunds of U.S. federal income taxes and paid $5.3 million in foreign income taxes, net of refunds received, during 2005.

Net Cash (Used in) Provided by Investing Activities.


	Year Ended December 31,
	2006			2005			Change
	(In thousands)
Purchase of marketable securities	$	(2,472,431	)	$	(4,956,560	)	$	2,484,129
Proceeds from sale of marketable securities		2,187,766			5,610,907			(3,423,141	)
Capital expenditures		(551,237	)		(293,829	)		(257,408	)
Insurance proceeds from casualty loss of Ocean Warwick		—			50,500			(50,500	)
Proceeds from sale/involuntary conversion of assets		4,731			26,047			(21,316	)
Proceeds from maturities of Australian dollar time deposits		—			11,761			(11,761	)
Proceeds from settlement of forward contracts		7,289			1,136			6,153

	$	(823,882	)	$	449,962		$	(1,273,844	)

Our investing activities used $823.9 million in 2006, as compared to generating $450.0 million in 2005. During 2006, we purchased marketable securities, net of sales, of $284.7 million compared to net sales of $654.3 million during 2005. Our level of investment activity is dependent on our working capital and other capital requirements during the year, as well as a response to actual or anticipated events or conditions in the securities markets. The high level of marketable securities transactions during 2005, primarily during the first half of the year, was primarily in response to an increase in our short-term cash requirements in 2005 to partially fund the repurchase of $460.0 million accreted value of Zero Coupon Debentures in June 2005 and capital additions.

During 2006, we spent approximately $278.0 million related to the major upgrades of the Ocean Endeavor and Ocean Monarch and construction of the Ocean Scepter and Ocean Shield. During 2005, we spent approximately $140.4 million related to the major upgrade of the Ocean Endeavor and construction of our two new jack-up drilling rigs. Expenditures for our ongoing capital maintenance programs were $273.2 million in 2006 compared to $133.4 million in 2005. The increase in expenditures related to our ongoing capital maintenance program in 2006 compared to 2005 is related to an increase in discretionary funds available for capital spending in 2006, and, to a lesser extent, in response to the high sustained utilization of our drilling rigs in 2006. Our capital expenditures in 2005 also included $20.0 million for the purchase of the Ocean Monarch and its related equipment. See “— Liquidity and Capital Requirements — Capital Expenditures.”

We collected $50.5 million in insurance proceeds related to the casualty loss of the Ocean Warwick in 2005. Additionally, in 2005 we sold one of our then cold-stacked intermediate semisubmersible rigs, the Ocean Liberator, for net cash proceeds of $13.6 million and received $5.6 million in insurance proceeds (total proceeds of $14.5 million of which $8.9 million is included in net cash provided by operating activities) related to the involuntary conversion of assets damaged during Hurricane Ivan in 2004.

During 2006, we received $2.1 million in insurance proceeds (total proceeds of $10.8 million of which $8.7 million is included in net cash provided by operating activities) related to the involuntary conversion of riser equipment damaged on the Ocean Vanguard in December 2004 and recovered an additional $1.1 million from our customers (total recovery of $3.1 million of which $2.0 million is included in net cash provided by operating activities) related to the involuntary conversion of assets damaged during the 2005 hurricanes.

During 2005, our remaining investments in Australian dollar time deposits, which we originally entered into in 2004, matured, resulting in proceeds to us of $11.8 million. In the latter half of 2005, we stepped up our ongoing program of entering into foreign currency forward exchange contracts to reduce our forward exchange risk. During 2006, we realized net gains totaling $7.3 million on the settlement of several forward exchange contracts in various currencies. We realized net gains of $1.1 million on similar forward exchange transactions during 2005.

As of December 31, 2006, we had foreign currency exchange contracts outstanding, which aggregated $22.5 million, that require us to purchase the equivalent of $5.7 million in Brazilian reais, $2.7 million in British pounds sterling, $10.3 million in Mexican pesos and $3.8 million in Norwegian kroner at various times through June 2007.

Net Cash Used in Financing Activities.


	Year Ended December 31,
	2006			2005			Change
	(In thousands)
Proceeds from issuance of senior notes	$	—		$	249,462		$	(249,462	)
Payment of debt issuance costs		—			(1,866	)		1,866
Redemption of Zero Coupon Debentures		—			(460,015	)		460,015
Payment of dividends		(258,155	)		(48,260	)		(209,895	)
Ocean Alliance lease-leaseback agreement		—			(12,818	)		12,818
Proceeds from stock options exercised		3,263			11,547			(8,284	)
Other		793			—			793

	$	(254,099	)	$	(261,950	)	$	7,851

In June 2005, we issued $250.0 million principal amount of our 4.875% Senior Notes for net cash proceeds of $247.6 million. We repurchased $460.0 million accreted value, or approximately 96%, of our then outstanding Zero Coupon Debentures for cash in June 2005. We did not issue debt or repurchase any outstanding debentures during 2006.

During 2006, we paid cash dividends totaling $258.2 million (consisting of quarterly dividends of $64.6 million in the aggregate, or $0.125 per share of our common stock per quarter, and a special cash dividend of $1.50 per share of our common stock, totaling $193.6 million). We paid $48.3 million in quarterly cash dividends to our shareholders during 2005. Our quarterly dividend payments in the last half of 2005 reflected a $.0625 per share increase over dividends paid during the first half of 2005.

On January 30, 2007, we declared a quarterly cash dividend and a special cash dividend of $0.125 and $4.00, respectively, per share of our common stock. Both the quarterly and special cash dividends are payable on March 1, 2007 to stockholders of record on February 14, 2007. Any future determination as to payment of quarterly dividends will be made at the discretion of our Board of Directors. In addition, our Board of Directors may, in subsequent years, consider paying additional annual special dividends, in amounts to be determined, if it believes that our financial position, earnings outlook, capital spending plans and other relevant factors warrant such action at that time.

Depending on market conditions, we may, from time to time, purchase shares of our common stock in the open market or otherwise. We did not repurchase any shares of our outstanding common stock during the years ended December 31, 2006 and 2005.

We paid the final installment of $12.8 million on our lease-leaseback arrangement for the Ocean Alliance in December 2005.

Other

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

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

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

Recent Accounting Pronouncements

In September 2006, the SEC issued Staff Accounting Bulletin, or SAB, No. 108, “Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements,” or SAB 108. SAB 108 requires a registrant to quantify the impact of correcting all misstatements on its current year financial statements using two approaches, the rollover and iron curtain approaches. A registrant is required to adjust its current year financial statements if either approach to accumulate and identify misstatements results in quantifying a misstatement that is material, after considering all relevant quantitative and qualitative factors. SAB 108 is required to be considered for financial statements for fiscal years ending after November 15, 2006; however, earlier application of the guidance in SAB 108 to interim financial statements issued for fiscal years ending after November 15, 2006 is encouraged. The adoption of SAB 108 had no impact on our consolidated results of operations, financial position or cash flows.

In September 2006, the FASB issued SFAS No. 158, “Accounting for Defined Benefit Pension or Other Postretirement Plans,” or SFAS 158. SFAS 158 amends existing guidance to require (1) balance sheet recognition of the funded status of defined benefit plans, (2) recognition in other comprehensive income of various items before they are recognized in periodic benefit cost, (3) the measurement date for plan assets and the benefit obligation to be the balance sheet date, and (4) additional disclosures regarding the effects on periodic benefit cost for the following fiscal year arising from delayed recognition in the current period. SFAS 158 also includes guidance regarding selection of assumed discount rates for use in measuring the benefit obligation. SFAS 158 provides different effective dates for various aspects of the new rules. For public companies, requirements to recognize the funded status of the plan and to comply with the disclosure provisions of SFAS 158 are effective as of the end of the fiscal year ending after December 15, 2006, and the requirement to measure plan assets and benefit obligations as of the balance sheet date is effective for fiscal years ending after December 15, 2008. Early adoption of SFAS 158 is encouraged and must be applied to all of an entity’s benefit plans. During the fourth quarter of 2006, we adopted the requirement to recognize the funded status of our defined benefit pension plan, as well as the disclosure provisions. See Note 14 “Employee Benefit Plans” to our Consolidated Financial Statements included in Item 8 of this report.

Changes resulting from the application of SFAS 157 relate to the definition of fair value, the methods used to measure fair value and the expanded disclosures about fair value measurements. SFAS 157 emphasizes that fair value is a market-based measurement, rather than an entity-specific measurement. It also establishes a fair value hierarchy that distinguishes between (i) market participant assumptions developed based on market data obtained from independent sources and (ii) the reporting entity’s own assumptions about market participant assumptions developed based on the best information available under the circumstances. SFAS 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007, including interim periods within those fiscal years. Earlier application is encouraged, provided that the reporting entity has not yet issued financial statements for that fiscal year, including interim periods. We are in the process of evaluating the impact, if any, of applying SFAS 157 on our financial statements; however, we do not expect the adoption of SFAS 157 to have a material impact on our consolidated results of operations, financial position or cash flows.

In June 2006, the FASB issued FIN 48, which clarifies the accounting for uncertainty in income taxes recognized in financial statements in accordance with SFAS 109. FIN 48 prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return and also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. FIN 48 is effective for fiscal years beginning after December 15, 2006. We are currently evaluating the guidance provided in FIN 48 and expect to adopt FIN 48 in the first quarter of 2007. Although our assessment has not yet been finalized, upon adoption of FIN 48 we expect to recognize a cumulative effect adjustment for uncertain tax positions of approximately $30 million, which will be charged to results of operations and equity.

Forward-Looking Statements

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

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

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

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

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

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

	•		business strategy;

	•		growth opportunities;

	•		competitive position;

	•		expected financial position;

	•		future cash flows;

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

	•		financing plans;

	•		tax planning (See “— Overview — Critical Accounting Estimates — Income Taxes,” “— Years Ended December 31, 2006 and 2005 — Income Tax Expense” and “— Years Ended December 31, 2005 and 2004 — Income Tax Expense”);

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

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

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

	•		plans and objectives of management;

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

	•		outcomes of legal proceedings;

	•		compliance with applicable laws; and

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

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

	•		general economic and business conditions;

	•		worldwide demand for oil and natural gas;

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

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

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

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

	•		advances in exploration and development technology;

	•		the political environment of oil-producing regions;

	•		casualty losses;

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

	•		industry fleet capacity;

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

	•		competition;

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

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

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

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

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

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

	•		regulatory initiatives and compliance with governmental regulations;

	•		compliance with environmental laws and regulations;

	•		customer preferences;

	•		effects of litigation;

	•		cost, availability and adequacy of insurance;

	•		adequacy of our sources of liquidity;

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

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

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

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

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

Our measure of market risk exposure represents an estimate of the change in fair value of our financial instruments. Market risk exposure is presented for each class of financial instrument held by us at December 31, 2006 and December 31, 2005, assuming immediate adverse market movements of the magnitude described below. We believe that the various rates of adverse market movements represent a measure of exposure to loss under hypothetically assumed adverse conditions. The estimated market risk exposure represents the hypothetical loss to future earnings and does not represent the maximum possible loss or any expected actual loss, even under adverse conditions, because actual adverse fluctuations would likely differ. In addition, since our investment portfolio is subject to change based on our portfolio management strategy as well as in response to changes in the market, these estimates are not necessarily indicative of the actual results that may occur.

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

Interest Rate Risk

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

The sensitivity analysis estimates the change in the market value of our interest sensitive assets and liabilities that were held on December 31, 2006 and December 31, 2005, due to instantaneous parallel shifts in the yield curve of 100 basis points, with all other variables held constant.

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

Our long-term debt, as of December 31, 2006 and December 31, 2005, is denominated in U.S. dollars. Our debt has been primarily issued at fixed rates, and as such, interest expense would not be impacted by interest rate shifts. The impact of a 100-basis point increase in interest rates on fixed rate debt would result in a decrease in market value of $270.8 million and $173.8 million as of December 31, 2006 and 2005, respectively. A 100-basis point decrease would result in an increase in market value of $33.0 million and $40.0 million as of December 31, 2006 and 2005, respectively.

Foreign Exchange Risk

Foreign exchange rate risk arises from the possibility that changes in foreign currency exchange rates will impact the value of financial instruments. During 2006 and 2005, we entered into various foreign currency forward exchange contracts that required us to purchase predetermined amounts of foreign currencies at predetermined dates. As of December 31, 2006, we had foreign currency exchange contracts outstanding, which aggregated $22.5 million, that require us to purchase the equivalent of $5.7 million in Brazilian reais, $2.7 million in British pounds sterling, $10.3 million in Mexican pesos and $3.8 million in Norwegian kroner at various times through June 2007. At December 31, 2005, we had foreign currency forward exchange contracts outstanding, which aggregated $122.5 million, that required us to purchase the equivalent of $17.1 million in Mexican pesos, the equivalent of $7.7 million in Australian dollars, the equivalent of $67.2 million in British pounds sterling and the equivalent of $30.5 million in Brazilian reais at various times through March 2007. These forward exchange contracts were included in “Prepaid expenses and other” in our Consolidated Balance Sheets at December 31, 2006 and 2005 at fair value in accordance with SFAS No. 133, “Accounting for Derivatives and Hedging Activities.”

The sensitivity analysis assumes an instantaneous 20% change in foreign currency exchange rates versus the U.S. dollar from their levels at December 31, 2006 and 2005.

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


	Fair Value Asset (Liability)						Market Risk
	December 31,						December 31,
	2006			2005			2006			2005
	(In thousands)
Interest rate:
Marketable securities	$	301,159	(a)	$	2,281	(a)	$	400	(c)	$	200	(c)
Long-term debt		(1,231,689	) (b)		(1,159,941	) (b)		—			—

Foreign Exchange:
Forward exchange contracts		2,600	(d)		400	(d)		7,400	(d)		21,500	(d)


(a)		The fair market value of our investment in marketable securities, excluding repurchase agreements, is based on the quoted closing market prices on December 31, 2006 and 2005.

(b)		The fair values of our 4.875% Senior Notes, 5.15% Senior Notes, 1.5% Debentures and Zero Coupon Debentures are based on the quoted closing market prices on December 31, 2006 and 2005.

(c)		The calculation of estimated market risk exposure is based on assumed adverse changes in the underlying reference price or index of an increase in interest rates of 100 basis points at December 31, 2006 and 2005.

(d)		The calculation of estimated foreign exchange risk is based on assumed adverse changes in the underlying reference price or index of an increase in foreign exchange rates of 20% at December 31, 2006 and a decrease in foreign exchange rates of 20% at December 31, 2005.

Item 8. Financial Statements and Supplementary Data.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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

We have audited the accompanying consolidated balance sheets of Diamond Offshore Drilling, Inc. and subsidiaries (the “Company”) as of December 31, 2006 and 2005, and the related consolidated statements of operations, stockholders’ equity, comprehensive income (loss), and cash flows for each of the three years in the period ended December 31, 2006. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the financial statements based on our audits.

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

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Diamond Offshore Drilling, Inc. and subsidiaries as of December 31, 2006 and 2005, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2006, in conformity with accounting principles generally accepted in the United States of America.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of the Company’s internal control over financial reporting as of December 31, 2006, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 22, 2007 expressed an unqualified opinion on management’s assessment of the effectiveness of the Company’s internal control over financial reporting (such management assessment is included in Item 9A of this Form 10-K) and an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

Deloitte & Touche LLP

Houston, Texas

February 22, 2007

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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

We have audited management’s assessment, included in Item 9A of this Form 10-K under the heading “Management’s Annual Report on Internal Control Over Financial Reporting,” that Diamond Offshore Drilling, Inc. and subsidiaries (the “Company”) maintained effective internal control over financial reporting as of December 31, 2006, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of the Company’s internal control over financial reporting based on our audit.

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

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

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

In our opinion, management’s assessment that the Company maintained effective internal control over financial reporting as of December 31, 2006, is fairly stated, in all material respects, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2006, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) the consolidated financial statements as of and for the year ended December 31, 2006 of the Company and our report dated February 22, 2007 expressed an unqualified opinion on those financial statements.

Deloitte & Touche LLP

Houston, Texas
February 22, 2007

DIAMOND OFFSHORE DRILLING, INC.
AND SUBSIDIARIES

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


	December 31,
	2006			2005

ASSETS
Current assets:
Cash and cash equivalents	$	524,698		$	842,590
Marketable securities		301,159			2,281
Accounts receivable		567,474			357,104
Rig spare parts and supplies		48,801			47,196
Prepaid expenses and other		39,415			32,707

Total current assets		1,481,547			1,281,878
Drilling and other property and equipment, net of accumulated depreciation		2,628,453			2,302,020
Other assets		22,839			23,024

Total assets	$	4,132,839		$	3,606,922


LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	122,000		$	60,976
Accrued liabilities		184,978			169,037
Taxes payable		26,531			38,973

Total current liabilities		333,509			268,986
Long-term debt		964,310			977,654
Deferred tax liability		448,227			445,094
Other liabilities		67,285			61,861

Total liabilities		1,813,331			1,753,595


Commitments and contingencies		—			—

Stockholders’ equity:
Preferred stock (par value $0.01, 25,000,000 shares authorized, none issued and outstanding)		—			—
Common stock (par value $0.01, 500,000,000 shares authorized; 134,133,776 shares issued and 129,216,976 shares outstanding at December 31, 2006; 133,842,429 shares issued and 128,925,629 shares outstanding at December 31, 2005)		1,341			1,338
Additional paid-in capital		1,299,846			1,277,934
Retained earnings		1,137,151			688,459
Accumulated other comprehensive (losses) gains		(4,417	)		9
Treasury stock, at cost (4,916,800 shares at December 31, 2006 and 2005)		(114,413	)		(114,413	)

Total stockholders’ equity		2,319,508			1,853,327

Total liabilities and stockholders’ equity	$	4,132,839		$	3,606,922

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

DIAMOND OFFSHORE DRILLING, INC.
AND SUBSIDIARIES

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


	Year Ended December 31,
	2006			2005			2004
Revenues:
Contract drilling	$	1,987,114		$	1,179,015		$	782,405
Revenues related to reimbursable expenses		65,458			41,987			32,257

Total revenues		2,052,572			1,221,002			814,662


Operating expenses:
Contract drilling		812,057			638,540			568,628
Reimbursable expenses		57,465			35,549			28,899
Depreciation and amortization		200,503			183,724			178,835
General and administrative		41,551			37,162			32,759
Casualty gain on Ocean Warwick		(500	)		(33,605	)		—
(Gain) loss on disposition of assets		1,064			(14,767	)		1,613

Total operating expenses		1,112,140			846,603			810,734


Operating income		940,432			374,399			3,928

Other income (expense):
Interest income		37,880			26,028			12,205
Interest expense		(24,096	)		(41,799	)		(30,257	)
Gain (loss) on sale of marketable securities		(31	)		(1,180	)		254
Settlement of litigation		—			—			11,391
Other, net		12,147			(1,053	)		(1,054	)

Income (loss) before income tax expense		966,332			356,395			(3,533	)

Income tax expense		(259,485	)		(96,058	)		(3,710	)

Net income (loss)	$	706,847		$	260,337		$	(7,243	)


Earnings (loss) per share:
Basic	$	5.47		$	2.02		$	(0.06	)

Diluted	$	5.12		$	1.91		$	(0.06	)


Weighted-average shares outstanding:
Shares of common stock		129,129			128,690			129,021
Dilutive potential shares of common stock		9,652			12,661			—

Total weighted-average shares outstanding assuming dilution		138,781			141,351			129,021

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

DIAMOND OFFSHORE DRILLING, INC.
AND SUBSIDIARIES

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


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

January 1, 2004		133,457,055		1,335		1,263,692		515,906			(4,117	)		4,134,600		(96,336	)		1,680,480
Net loss		—		—		—		(7,243	)		—			—		—			(7,243	)
Treasury stock purchase		—		—		—		—			—			782,200		(18,077	)		(18,077	)
Dividends to stockholders ($0.25 per share)		—		—		—		(32,281	)		—			—		—			(32,281	)
Stock options exercised		26,765		—		820		—			—			—		—			820
Exchange rate changes, net		—		—		—		—			1,649			—		—			1,649
Gain on investments, net		—		—		—		—			480			—		—			480

December 31, 2004		133,483,820		1,335		1,264,512		476,382			(1,988	)		4,916,800		(114,413	)		1,625,828

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

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

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

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

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

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

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

DIAMOND OFFSHORE DRILLING, INC.
AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(In thousands)


	Year Ended December 31,
	2006			2005			2004

Net income (loss)	$	706,847		$	260,337		$	(7,243	)

Other comprehensive gains (losses), net of tax:
Foreign currency translation gain		—			2,077			1,649
Unrealized holding gain on investments		162			10			532
Reclassification adjustment for loss included in net income		(62	)		(90	)		(52	)

Total other comprehensive gain		100			1,997			2,129
Comprehensive income (loss) before adoption of SFAS 158, net of tax		706,947			262,334			(5,114	)

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

Comprehensive income (loss)	$	702,421		$	262,334		$	(5,114	)

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

DIAMOND OFFSHORE DRILLING, INC.
AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)


	Year Ended December 31,
	2006			2005			2004

Operating activities:
Net income (loss)	$	706,847		$	260,337		$	(7,243	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization		200,503			183,724			178,835
Casualty gain on Ocean Warwick		(500	)		(33,605	)		—
Loss (gain) on disposition of assets		1,064			(14,767	)		1,613
Loss (gain) on sale of marketable securities, net		31			1,180			(254	)
Deferred tax provision		610			65,159			726
Accretion of discounts on marketable securities		(14,090	)		(7,683	)		(4,979	)
Amortization of debt issuance costs		848			7,742			1,126
Amortization of debt discounts		392			7,523			16,073
Stock-based compensation expense		3,106			—			—
Excess tax benefits from stock-based payment arrangements		(1,313	)		—			—
Deferred income, net		13,373			935			4,240
Deferred expenses, net		6,317			(1,010	)		(6,275	)
Other Items, net		(3,031	)		3,942			9,730
Changes in operating assets and liabilities:
Accounts receivable		(190,054	)		(174,659	)		(32,828	)
Rig spare parts and supplies and other current assets		(12,078	)		(4,752	)		154
Accounts payable and accrued liabilities		58,762			66,011			39,464
Taxes payable		(10,698	)		28,494			7,900

Net cash provided by operating activities		760,089			388,571			208,282

Investing activities:
Capital expenditures (including rig acquisitions)		(551,237	)		(293,829	)		(89,229	)
Proceeds from casualty loss of Ocean Warwick		—			50,500			—
Proceeds from sale/involuntary conversion of assets		4,731			26,047			6,900
Proceeds from sale and maturities of marketable securities		2,187,766			5,610,907			4,466,377
Purchase of marketable securities		(2,472,431	)		(4,956,560	)		(4,606,400	)
Purchases of Australian dollar time deposits		—			—			(45,456	)
Proceeds from maturities of Australian dollar time deposits		—			11,761			34,120
Proceeds from settlement of forward contracts		7,289			1,136			—

Net cash (used in) provided by investing activities		(823,882	)		449,962			(233,688	)

Financing activities:
Issuance of 4.875% senior unsecured notes		—			249,462			—
Issuance of 5.15% senior unsecured notes		—			—			249,397
Debt issuance costs and arrangement fees		(520	)		(1,866	)		(1,751	)
Redemption of zero coupon debentures		—			(460,015	)		—
Acquisition of treasury stock		—			—			(18,077	)
Payment of dividends		(258,155	)		(48,260	)		(32,281	)
Payments under lease-leaseback agreement		—			(12,818	)		(11,969	)
Proceeds from stock options exercised		3,263			11,547			168
Excess tax benefits from share-based payment arrangements		1,313			—			—

Net cash (used in) provided by financing activities		(254,099	)		(261,950	)		185,487

Effect of exchange rate changes on cash		—			—			(419	)

Net change in cash and cash equivalents		(317,892	)		576,583			159,662
Cash and cash equivalents, beginning of year		842,590			266,007			106,345

Cash and cash equivalents, end of year	$	524,698		$	842,590		$	266,007

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

DIAMOND OFFSHORE DRILLING, INC.
AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. General Information

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

As of February 20, 2007, Loews Corporation, or Loews, owned 50.7% of the outstanding shares of our common stock.

Principles of Consolidation

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

Cash and Cash Equivalents, Marketable Securities

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

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

Derivative Financial Instruments

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

Supplementary Cash Flow Information

We paid interest totaling $32.5 million on long-term debt for the year ended December 31, 2006. For the year ended December 31, 2005, we paid interest totaling $94.1 million on long-term debt, which included $73.3 million in accreted interest paid in connection with the June 2005 partial redemption of our Zero Coupon Convertible Debentures due 2020, or Zero Coupon Debentures. See Note 8. For the year ended December 31, 2004 we paid interest totaling $8.7 million on long-term debt.

We paid $10.8 million, $5.3 million and $3.1 million in foreign income taxes, net of foreign tax refunds, during the years ended December 31, 2006, 2005 and 2004, respectively. We paid $262.4 million in U.S. income taxes during the year ended December 31, 2006. We received refunds of $13.7 million and $7.7 million in U.S. income taxes during the years ended December 31, 2006 and 2005, respectively. There were no U.S. income taxes paid or refunded during the year ended December 31, 2004.

We recorded income tax benefits of $1.7 million, $2.4 million and $0.1 million related to the exercise of

employee stock options in 2006, 2005 and 2004, respectively.

During 2006, the holders of $13.7 million accreted value, or $22.4 million in principal amount at maturity, of our Zero Coupon Debentures and $20,000 in principal amount of our 1.5% Debentures elected to convert their outstanding debentures into shares of our common stock. During 2005, the holders of $13,000 in principal amount of our 1.5% Debentures elected to convert their outstanding debentures into shares of our common stock. See Note 8.

Rig Spare Parts and Supplies

Rig spare parts and supplies consist primarily of replacement parts and supplies held for use in our operations and are stated at the lower of cost or estimated value.

Drilling and Other Property and Equipment

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

Capitalized Interest

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

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


	For the Year Ended December 31,
	2006			2005			2004

	(In thousands)
Total interest cost including amortization of debt issuance costs	$	33,892		$	42,541		$	30,257
Capitalized interest		(9,796	)		(742	)		—

Total interest expense as reported	$	24,096		$	41,799		$	30,257

Asset Retirement Obligations

Statement of Financial Accounting Standards, or SFAS, No. 143, “Accounting for Asset Retirement Obligations” requires the fair value of a liability for an asset retirement legal obligation to be recognized in the period in which it is incurred. At December 31, 2006 and 2005, we had no asset retirement obligations.

Impairment of Long-Lived Assets

	•		dayrate by rig;

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

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

	•		salvage value for each rig.

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

2005. In December 2005, we reviewed our single cold-stacked rig, the Ocean Monarch, for impairment. Based on our decision to upgrade this drilling unit to high-specification capabilities at an estimated cost of approximately $300 million and the low net book value of this rig, we did not consider this asset to be impaired.

2004. In December 2004, we reviewed our three cold-stacked rigs for impairment and determined that none of the drilling units was impaired. On January 10, 2005, we announced that we would upgrade one of these cold-stacked rigs, the Ocean Endeavor, to a high-specification drilling unit for an estimated cost of approximately $250 million. As a result of this decision and the low net book value of this rig, we did not consider this asset to be impaired.

During 2004, we were marketing another of our cold-stacked rigs, the Ocean Liberator, for sale to a third party, and we classified the rig as an asset-held-for-sale in our Consolidated Balance Sheets at December 31, 2004 included in Item 8 of this report. The estimated market value of this rig, based on offers from third parties, was higher than its current carrying value; therefore, no write-down was deemed necessary as a result of the reclassification to an asset-held-for-sale. We sold the Ocean Liberator in the second quarter of 2005 for a net gain of $8.0 million.

We evaluated our then remaining cold-stacked rig for impairment using the probability-weighted cash flow analysis discussed above. At December 31, 2004, the probability-weighted cash flow for the Ocean New Era significantly exceeded its net carrying value of $3.2 million. We reactivated the Ocean New Era from cold-stacked status in the fourth quarter of 2005 and it began operating under contract in the GOM in December 2005.

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

Fair Value of Financial Instruments

We believe that the carrying amount of our current financial instruments approximates fair value because of the short maturity of these instruments. For non-current financial instruments we use quoted market prices, when available, and discounted cash flows to estimate fair value. See Note 11.

Debt Issuance Costs

Debt issuance costs are included in our Consolidated Balance Sheets in “Other assets” and are amortized over

the respective terms of the related debt. Interest expense for the year ended December 31, 2005 includes $6.9 million in debt issuance costs that we wrote off in connection with the June 2005 redemption of approximately 96% of our then outstanding Zero Coupon Debentures.

Income Taxes

We account for income taxes in accordance with SFAS No. 109, “Accounting for Income Taxes,” which requires the recognition of the amount of taxes payable or refundable for the current year and an asset and liability approach in recognizing the amount of deferred tax liabilities and assets for the future tax consequences of events that have been currently recognized in our financial statements or tax returns. In each of our tax jurisdictions we recognize a current tax liability or asset for the estimated taxes payable or refundable on tax returns for the current year and a deferred tax asset or liability for the estimated future tax effects attributable to temporary differences and carryforwards. Deferred tax assets are reduced by a valuation allowance, if necessary, which is determined by the amount of any tax benefits that, based on available evidence, are not expected to be realized under a “more likely than not” approach. We make judgments regarding future events and related estimates especially as they pertain to the forecasting of our effective tax rate, the potential realization of deferred tax assets such as utilization of foreign tax credits, and exposure to the disallowance of items deducted on tax returns upon audit.

Our net income tax expense or benefit is a function of the mix between our domestic and international pre-tax earnings or losses, respectively, as well as the mix of international tax jurisdictions in which we operate. Certain of our international rigs are owned or operated, directly or indirectly, by Diamond Offshore International Limited, a Cayman Islands company which is one of our wholly owned subsidiaries. Earnings from this subsidiary are reinvested internationally and remittance to the U.S. is indefinitely postponed. See Note 13.

Treasury Stock

Depending on market conditions, we may, from time to time, purchase shares of our common stock in the open market or otherwise. We account for the purchase of treasury stock using the cost method, which reports the cost of the shares acquired in “Treasury stock” as a deduction from stockholders’ equity in our Consolidated Balance Sheets. We did not repurchase any shares of our outstanding common stock during 2006 or 2005. During the year ended December 31, 2004, we purchased 782,200 shares of our common stock at an aggregate cost of $18.1 million, or at an average cost of $23.11 per share.

Comprehensive Income (Loss)

Comprehensive income (loss) is the change in equity of a business enterprise during a period from transactions and other events and circumstances except those transactions resulting from investments by owners and distributions to owners. Comprehensive income (loss) for the three years ended December 31, 2006 includes net income (loss), foreign currency translation gains and losses, unrealized holding gains and losses on marketable securities and an adjustment to initially adopt SFAS No. 158, “Accounting for Defined Benefit Pension or Other Postretirement Plans,” or SFAS 158, in 2006. See Note 9.

Currency Translation

Our functional currency is the U.S. dollar. Effective October 1, 2005, we changed the functional currency of certain of our subsidiaries operating outside the United States to the U.S. dollar to more appropriately reflect the primary economic environment in which our subsidiaries operate. Prior to this date, these subsidiaries utilized the local currency of the country in which they conduct business as their functional currency. As a result of this change, currency translation adjustments and transaction gains and losses, including gains and losses on our forward currency exchange contracts, are reported as “Other income (expense)” in our Consolidated Statements of Operations. For the year ended December 31, 2006, we recognized net foreign currency exchange gains of $10.3 million. During the years ended December 31, 2005 and 2004, we recognized net foreign currency exchange losses of $0.8 million and $1.4 million, respectively. See Note 5.

Revenue Recognition

Revenue from our dayrate drilling contracts is recognized as services are performed. In connection with such drilling contracts, we may receive lump-sum fees for the mobilization of equipment. These fees are earned as services are performed over the initial term of the related drilling contracts. We previously accounted for the excess of mobilization fees received over costs incurred to mobilize an offshore rig from one market to another as revenue over the term of the related drilling contracts. Effective July 1, 2004 we changed our accounting to defer mobilization fees received, as well as direct and incremental mobilization costs incurred, and began to amortize each, on a straight line basis, over the term of the related drilling contracts (which is the period estimated to be benefited from the mobilization activity). Straight line amortization of mobilization revenues and related costs over the initial term of the related drilling contracts (which generally range from two to 60 months) is consistent with the timing of net cash flows generated from the actual drilling services performed. If we had used this method of accounting in periods prior to July 1, 2004, our previously reported operating income (loss) and net income (loss) would not have changed, and the impact on contract drilling revenues and expenses would have been immaterial. Absent a contract, mobilization costs are recognized currently.

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

We record reimbursements received for the purchase of supplies, equipment, personnel services and other services provided at the request of our customers in accordance with a contract or agreement, for the gross amount billed to the customer, as “Revenues related to reimbursable expenses” in our Consolidated Statements of Operations.

Use of Estimates in the Preparation of Financial Statements

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

Reclassifications

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

Recent Accounting Pronouncements

In September 2006, the United States Securities and Exchange Commission, issued Staff Accounting Bulletin, or SAB, No. 108, “Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements,” or SAB 108. SAB 108 requires a registrant to quantify the impact of correcting all misstatements on its current year financial statements using two approaches, the rollover and iron curtain approaches. A registrant is required to adjust its current year financial statements if either approach to accumulate and identify misstatements results in quantifying a misstatement that is material, after considering all relevant quantitative and qualitative factors. SAB 108 is required to be considered for financial statements for fiscal years ending after November 15, 2006; however, earlier application of the guidance in SAB 108 to interim financial statements issued for fiscal years ending after November 15, 2006 is encouraged. The adoption of SAB 108 had no impact on our consolidated results of operations, financial position or cash flows.

In September 2006, the Financial Accounting Standards Board, or FASB, issued SFAS 158. SFAS 158 amends existing guidance to require (1) balance sheet recognition of the funded status of defined benefit plans, (2) recognition in other comprehensive income of various items before they are recognized in periodic benefit cost, (3) the measurement date for plan assets and the benefit obligation to be the balance sheet date, and (4) additional disclosures regarding the effects on periodic benefit cost for the following fiscal year arising from delayed recognition in the

current period. SFAS 158 also includes guidance regarding selection of assumed discount rates for use in measuring the benefit obligation. SFAS 158 provides different effective dates for various aspects of the new rules. For public companies, requirements to recognize the funded status of the plan and to comply with the disclosure provisions of SFAS 158 are effective as of the end of the fiscal year ending after December 15, 2006, and the requirement to measure plan assets and benefit obligations as of the balance sheet date is effective for fiscal years ending after December 15, 2008. Early adoption of SFAS 158 is encouraged and must be applied to all of an entity’s benefit plans. During the fourth quarter of 2006, we adopted the requirement to recognize the funded status of our defined benefit pension plan, as well as the disclosure provisions. See Note 14.

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

In June 2006, the FASB issued FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes,” or FIN 48, which clarifies the accounting for uncertainty in income taxes recognized in financial statements in accordance with SFAS 109. FIN 48 prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return and also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. FIN 48 is effective for fiscal years beginning after December 15, 2006. We are currently evaluating the guidance provided in FIN 48 and expect to adopt FIN 48 in the first quarter of 2007. Although our assessment has not yet been finalized, upon adoption of FIN 48 we expect to recognize a cumulative effect adjustment for uncertain tax positions of approximately $30 million, which will be charged to results of operations and equity.

2. Stock-Based Compensation

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

Effective January 1, 2006, we adopted the FASB’s revised SFAS No. 123, “Accounting for Stock-Based Compensation,” or SFAS 123(R), using the modified prospective application transition method. SFAS 123(R) requires that compensation cost related to share-based payment transactions be recognized in financial statements. The effect of adopting SFAS 123(R) as of January 1, 2006 is as follows:


	Year Ended December 31, 2006
	(In thousands, except per
	share data)

Decrease in income from continuing operations	$	3,106
Decrease in income before income taxes		3,106
Decrease in income tax expense		(1,087	)
Decrease in net income		2,109

Decrease in cash flow from operations	$	(1,313	)
Increase in cash flow from financing activities		1,313

Decrease in earnings per share

Basic	$	0.02
Diluted		0.04

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


	Year Ended December 31,
	2005			2004
	(In thousands, except per share data)

Net income (loss) as reported	$	260,337		$	(7,243	)
Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effects		(1,411	)		(1,175	)

Pro forma net income (loss)	$	258,926		$	(8,418	)

Earnings (loss) per share of common stock:
As reported	$	2.02		$	(0.06	)

Pro forma	$	2.01		$	(0.07	)

Earnings (loss) per share of common stock-assuming dilution:
As reported	$	1.91		$	(0.06	)

Pro forma	$	1.90		$	(0.07	)

The fair value of options and SARs granted under the Stock Plan was estimated using the Binomial Option pricing model with the following weighted average assumptions:


	Year Ended December 31,
	2006			2005			2004
Expected life of stock options/SARs (in years)		6			7			7
Expected volatility		30.72	%		29.53	%		28.24	%
Dividend yield		.62	%		.56	%		.77	%
Risk free interest rate		4.85	%		4.16	%		3.93	%

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

A summary of the status of stock option and SARs transactions in 2006 follows:


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

Awards outstanding at January 1, 2006		556,590		$	36.79
Granted		183,900		$	82.03
Exercised		(97,796	)	$	34.05
Canceled		(47,404	)	$	54.53

Awards outstanding at December 31, 2006		595,290		$	49.81		7.7	$	17,838

Awards exercisable at December 31, 2006		224,844		$	34.33		5.6	$	10,218

The weighted-average grant date fair values of options granted during the years ended December 31, 2006, 2005 and 2004 were $39.24, $25.80 and $12.51, respectively. The total intrinsic value of options exercised during the years ended December 31, 2006, 2005 and 2004 was $5.0 million, $10.5 million and $0.3 million, respectively. As of December 31, 2006 there was $10.0 million of total unrecognized compensation cost related to nonvested stock options and SARs granted under the Stock Plan which we expect to recognize over a weighted average period of 3.09 years.

3. Earnings (Loss) Per Share

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


	Year Ended December 31,
	2006		2005		2004

	(In thousands, except per share data)

Net income (loss) — basic (numerator):	$	706,847	$	260,337	$	(7,243	)
Effect of dilutive potential shares
Zero Coupon Debentures		236		4,880		—
1.5% Debentures		3,293		4,583		—

Net income (loss) including conversions — diluted (numerator):	$	710,376	$	269,800	$	(7,243	)

Weighted-average shares — basic (denominator):		129,129		128,690		129,021
Effect of dilutive potential shares
Zero Coupon Debentures		119		3,114		—
1.5% Debentures		9,383		9,383		—
Stock options		150		164		—

Weighted-average shares including conversions — diluted (denominator):		138,781		141,351		129,021

Earnings (loss) per share:
Basic	$	5.47	$	2.02	$	(0.06	)

Diluted	$	5.12	$	1.91	$	(0.06	)

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

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

The computation of diluted EPS for the year ended December 31, 2004 excludes approximately 9.4 million and 6.9 million potentially dilutive shares of common stock issuable upon conversion of our 1.5% Debentures and our Zero Coupon Debentures, respectively. Such shares were not included in the EPS computations for 2004 because the inclusion of such potentially dilutive shares would have been antidilutive. See Note 8 for a description of our long-term debt.

For the year ended December 31, 2004 we excluded stock options representing 291,447 shares of common stock from the computation of diluted EPS because the options’ exercise prices were higher than the average market price per share of our common stock for the period. We also excluded other stock options representing 138,319 shares of common stock in 2004 with an average market price in excess of their exercise prices from the computation of diluted EPS because there was a net loss for the period.

4. Investments and Marketable Securities

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

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


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

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

Total	$	300,992	$	167		$	301,159


	December 31, 2005
			Unrealized		Market
	Cost		Gain		Value

	(In thousands)
Debt securities issued by the U.S. Treasury and other U.S. government agencies:
Mortgage-backed securities	$	2,267	$	14	$	2,281

In November 2005, the FASB issued FASB Staff Position, or FSP, No. 115-1 and 124-1, “The Meaning of Other-Than-Temporary Impairment and its Application to Certain Investments,” or FSP 115-1, which applies to debt and equity securities that are within the scope of SFAS No. 115, “Accounting for Certain Investments in Debt and Equity Securities.” FSP 115-1 replaces guidance set forth in Emerging Issues Task Force Issue No. 03-01, “The Meaning of Other-Than-Temporary Impairment and its Application to Certain Investments” and requires additional disclosure related to factors considered in concluding that an impairment is not other-than-temporary. FSP 115-1 was effective for reporting periods beginning after December 15, 2005, and we adopted this standard on January 1, 2006. Our adoption of this standard had no significant effect on our consolidated results of operations for the year ended December 31, 2006.

We considered the requirements of FSP 115-1 related to our unrealized loss position on our mortgage-backed securities at December 31, 2006 and determined that it was not significant.

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


	Year Ended December 31,
	2006			2005			2004

	(In thousands)
Proceeds from maturities	$	950,000		$	2,550,000		$	1,520,000
Proceeds from sales		1,237,766			3,060,907			2,946,377
Gross realized gains		188			220			2,781
Gross realized losses		(219	)		(1,400	)		(2,527	)

5. Derivative Financial Instruments

Forward Exchange Contracts

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

During 2006 and 2005, we entered into various foreign currency forward exchange contracts which resulted in net realized gains totaling $7.3 million and $1.1 million, respectively. As of December 31, 2006, we had foreign currency exchange contracts outstanding, which aggregated $22.5 million, that require us to purchase the equivalent of $5.7 million in Brazilian reais, $2.7 million in British pounds sterling, $10.3 million in Mexican pesos and $3.8 million in Norwegian kroner at various times through June 2007.

These forward contracts are derivatives as defined by SFAS No. 133, “Accounting for Derivatives and Hedging Activities,” or SFAS 133. SFAS 133 requires that each derivative be stated in the balance sheet at its fair value with gains and losses reflected in the income statement except that, to the extent the derivative qualifies for hedge accounting, the gains and losses are reflected in income in the same period as offsetting losses and gains on the qualifying hedged positions. The forward contracts we entered into in 2006 and 2005 did not qualify for hedge accounting. In accordance with SFAS 133, we recorded net unrealized gains of $2.6 million and $0.4 million in our Consolidated Statements of Operations for the years ended December 31, 2006 and 2005, respectively, as “Other income (expense)” to adjust the carrying value of these derivative financial instruments to their fair value. We have presented the $2.6 million and $0.4 million fair value of these foreign currency forward exchange contracts at December 31, 2006 and 2005, respectively, as “Prepaid expenses and other” in our Consolidated Balance Sheets.

Contingent Interest

Our 1.5% Debentures, of which an aggregate principal amount of $460.0 million were outstanding at December 31, 2006, contain a contingent interest provision. The contingent interest component is an embedded derivative as defined by SFAS 133 and accordingly must be split from the host instrument and recorded at fair value on the balance sheet. The contingent interest component had no fair value at issuance or at December 31, 2006 or at December 31, 2005.

6. Drilling and Other Property and Equipment

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


	December 31,
	2006			2005

	(In thousands)

Drilling rigs and equipment	$	3,896,585		$	3,639,239
Construction work-in-progress		459,824			195,412
Land and buildings		17,353			16,280
Office equipment and other		27,132			24,351

Cost		4,400,894			3,875,282
Less accumulated depreciation		(1,772,441	)		(1,573,262	)

Drilling and other property and equipment, net	$	2,628,453		$	2,302,020

Construction work-in-progress at December 31, 2006 consisted of $249.8 million, including accrued capital expenditures of $41.4 million, related to the major upgrade of the Ocean Endeavor to ultra-deepwater service and $176.1 million related to the construction of two new jack-up drilling units, the Ocean Scepter and the Ocean Shield. The shipyard portion of the upgrade of the Ocean Endeavor was complete at December 31, 2006 and we expect to relocate this rig from Singapore to the U.S. where it is scheduled to operate under a four-year contract beginning in

mid-2007. We anticipate that both the Ocean Scepter and Ocean Shield will be delivered during the first quarter of 2008. Construction work-in-progress related to these projects was $195.4 million at December 31, 2005.

At December 31, 2006, construction work-in-progress also included $33.9 million related to the major upgrade of the Ocean Monarch to ultra-deepwater service. We expect the project to be completed during the fourth quarter of 2008 and to relocate this rig to the U.S. where it is scheduled to operate under a four-year contract.

7. Accrued Liabilities

Accrued liabilities consist of the following:


	December 31,
	2006		2005

	(In thousands)
Payroll and benefits	$	42,496	$	27,265
Personal injury and other claims		9,934		8,284
Interest payable		11,823		12,384
Deferred revenue		13,794		8,732
Customer prepayments		93		21,390
Accrued project/upgrade expenses		67,308		62,628
Hurricane-related expenses and deferred gains		8,328		3,508
Other		31,202		24,846

Total	$	184,978	$	169,037

8. Long-Term Debt

Long-term debt consists of the following:


	December 31,
	2006		2005

	(In thousands)

Zero Coupon Debentures (due 2020)	$	5,302	$	18,720
1.5% Debentures (due 2031)		459,967		459,987
5.15% Senior Notes (due 2014)		249,513		249,462
4.875% Senior Notes (due 2015)		249,528		249,485

Total	$	964,310	$	977,654

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

The aggregate maturities of long-term debt for each of the five years subsequent to December 31, 2006, are as follows:


(Dollars in thousands)

2007	$	—
2008		459,967
2009		—
2010		5,302
2011		—
Thereafter		499,041


		964,310

Less: Current maturities		—

Total	$	964,310

$285 Million Revolving Credit Facility.

In November 2006, we entered into a $285 million syndicated, 5-year senior unsecured revolving credit facility, or Credit Facility, for general corporate purposes, including loans and performance or standby letters of credit.

4.875% Senior Notes

On June 14, 2005, we issued $250.0 million aggregate principal amount of 4.875% Senior Notes Due July 1, 2015, or 4.875% Senior Notes, at an offering price of 99.785% of the principal amount resulting in net proceeds to us of $247.6 million, exclusive of accrued issuance costs.

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

5.15% Senior Notes

On August 27, 2004, we issued $250.0 million aggregate principal amount of 5.15% Senior Notes Due September 1, 2014, or 5.15% Senior Notes, at an offering price of 99.759% of the principal amount resulting in net proceeds to us of $247.6 million.

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

Zero Coupon Debentures

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

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

As of December 31, 2006, the aggregate accreted value of our outstanding Zero Coupon Debentures was $5.3 million, which is classified as long-term debt in our Consolidated Balance Sheets. The aggregate principal amount at maturity of those Zero Coupon Debentures would be $8.4 million assuming no additional conversions or redemptions occur prior to the maturity date.

See Note 18 for a discussion of conversions of our long-term debt subsequent to December 31, 2006.

1.5% Debentures

circumstances. Upon conversion, we have the right to deliver cash in lieu of shares of our common stock. The 1.5% Debentures are senior unsecured obligations of Diamond Offshore Drilling, Inc.

We pay interest of 1.5% per year on the outstanding principal amount of the 1.5% Debentures, semiannually in arrears on April 15 and October 15 of each year. In addition we will pay contingent interest to holders of our 1.5% Debentures during any six-month period commencing after April 14, 2008, if the average market price of a 1.5% Debenture for a measurement period preceding such six-month period equals 120% or more of the principal amount of such 1.5% Debenture and we pay a regular cash dividend during such six-month period. The contingent interest payable per $1,000 principal amount of 1.5% Debentures, in respect of any quarterly period, will equal 50% of regular cash dividends we pay per share on our common stock during that quarterly period multiplied by the conversion rate. This contingent interest component is an embedded derivative, which had no fair value at issuance or at December 31, 2005 or December 31, 2004.

Holders may require us to purchase all or a portion of their 1.5% Debentures on April 15, 2008, at a price equal to 100% of the principal amount of the 1.5% Debentures to be purchased plus accrued and unpaid interest. We may choose to pay the purchase price in cash or shares of our common stock or a combination of cash and common stock. In addition, holders may require us to purchase, for cash, all or a portion of their 1.5% Debentures upon a change in control (as defined in the governing indenture) for a purchase price equal to 100% of the principal amount plus accrued and unpaid interest. Additionally, we have the option to redeem all or a portion of the 1.5% Debentures at any time on or after April 15, 2008, at a price equal to 100% of the principal amount plus accrued and unpaid interest.

See Note 18 for a discussion of conversions of our long-term debt subsequent to December 31, 2006.

9. Other Comprehensive Income (Loss)

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


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

	(In thousands)

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

Net unrealized gain		154			(54	)		100

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

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


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

	(In thousands)

Reversal of cumulative foreign currency translation loss	$	3,600		$	(1,523	)	$	2,077
Unrealized gain (loss) on investments:
Gain arising during 2005		14			(5	)		9
Reclassification adjustment		(137	)		48			(89	)

Net unrealized loss		(123	)		43			(80	)

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


	Year Ended December 31, 2004
	Before Tax			Tax Effect			Net-of-Tax

	(In thousands)

Foreign currency translation gain	$	2,346		$	(697	)	$	1,649
Unrealized gain (loss) on investments:
Gain arising during 2004		818			(286	)		532
Reclassification adjustment		(80	)		28			(52	)

Net unrealized gain		738			(258	)		480

Other comprehensive income	$	3,084		$	(955	)	$	2,129

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


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

Balance at January 1, 2004	$	(3,726	)	$	—		$	(391	)	$	(4,117	)
Other comprehensive gain		1,649			—			480			2,129

Balance at December 31, 2004		(2,077	)		—			89			(1,988	)
Other comprehensive gain		2,077			—			(80	)		1,997

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

Balance at December 31, 2006	$	—		$	(4,526	)	$	109		$	(4,417	)

10. Commitments and Contingencies

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

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

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

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

Other. Our operations in Brazil have exposed us to various claims and assessments related to our personnel, customs duties and municipal taxes, among other things, that have arisen in the ordinary course of business. At December 31, 2006, our loss reserves related to our Brazilian operations aggregated $14.2 million, of which $0.5 million and $13.7 million were recorded in “Accrued liabilities” and “Other liabilities,” respectively, in our Consolidated Balance Sheets. Loss reserves related to our Brazilian operations totaled $14.1 million at December 31, 2005, of which $0.8 million was recorded in “Accrued liabilities” and $13.3 million was recorded in “Other liabilities” in our Consolidated Balance Sheets.

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

Personal Injury Claims. Effective May 1, 2006, in conjunction with our insurance policy renewals, we increased our deductible for liability coverage for personal injury claims, which primarily result from Jones Act liability in the Gulf of Mexico, to $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. Prior to this renewal, our uninsured retention of liability for personal injury claims was $0.5 million per claim with an additional aggregate annual deductible of $1.5 million. Our in-house claims department estimates the amount of our liability for our retention. This department establishes a reserve for each of our personal injury claims by evaluating the existing facts and circumstances of each claim and comparing the circumstances of each claim to historical experiences with similar past personal injury claims. Our claims department also estimates our liability for personal injuries that are incurred but not reported by using historical data. From time to time, we may also engage experts to assist us in estimating our reserve for such personal injury claims. In 2006, we engaged an actuary to estimate our liability for personal injury claims based on our historical losses and utilizing various actuarial models. We reduced our reserve for personal injury claims by $8.0 million during the fourth quarter of 2006 based on an actuarial review from which we determined that our aggregate reserve for personal injury claims should be $35.0 million at December 31, 2006.

At December 31, 2006, our estimated liability for personal injury claims was $35.0 million, of which $9.9 million and $25.1 million were recorded in “Accrued liabilities” and “Other liabilities,” respectively, in our Consolidated Balance Sheets. At December 31, 2005, our estimated liability for personal injury claims was $38.9 million, of which $8.3 million and $30.6 million were recorded in “Accrued liabilities” and “Other liabilities,” respectively, in our Consolidated Balance Sheets. The eventual settlement or adjudication of these claims could differ materially from our estimated amounts due to uncertainties such as:

	•		the severity of personal injuries claimed;

	•		significant changes in the volume of personal injury claims;

	•		the unpredictability of legal jurisdictions where the claims will ultimately be litigated;

	•		inconsistent court decisions; and

	•		the risks and lack of predictability inherent in personal injury litigation.

Purchase Obligations. As of December 31, 2006, we had purchase obligations aggregating approximately $456 million related to the major upgrades of the Ocean Endeavor and Ocean Monarch and construction of two new jack-up rigs, the Ocean Scepter and Ocean Shield. We anticipate that expenditures related to these shipyard projects will be approximately $263 million and $193 million in 2007 and 2008, respectively. However, the actual timing of these expenditures will vary based on the completion of various construction milestones, which are beyond our control.

We had no other purchase obligations for major rig upgrades or any other significant obligations at December 31, 2006 and 2005, except for those related to our direct rig operations, which arise during the normal course of business.

Operating Leases. We lease office facilities and equipment under operating leases, which expire at various times through the year 2009. Total rent expense amounted to $3.8 million, $3.1 million and $2.9 million for the years ended December 31, 2006, 2005 and 2004, respectively. Future minimum rental payments under leases are

approximately $2.4 million, $0.7 million and $0.1 million for the years ending December 31, 2007, 2008 and 2009, respectively. There are no minimum future rental payments under leases after 2009.

Letters of Credit and Other. We are contingently liable as of December 31, 2006 in the amount of $122.0 million under certain performance, bid, supersedeas and custom bonds and letters of credit. We purchased three of these performance bonds totaling $73.2 million from a related party after obtaining competitive quotes. Agreements relating to approximately $107.3 million of performance bonds can require collateral at any time. As of December 31, 2006 we had not been required to make any collateral deposits with respect to these agreements. The remaining agreements cannot require collateral except in events of default. On our behalf, banks have issued letters of credit securing certain of these bonds.

11. Financial Instruments

Concentrations of Credit and Market Risk

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

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

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

Fair Values

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


	Year Ended December 31,
	2006				2005
	Fair Value		Carrying Value		Fair Value		Carrying Value

	(In millions)

Zero Coupon Debentures	$	5.0	$	5.3	$	19.6	$	18.7
1.5% Debentures		749.7		460.0		648.6		460.0
4.875% Senior Notes		234.9		249.5		242.9		249.5
5.15% Senior Notes		242.0		249.5		248.9		249.5

We have estimated the fair value amounts by using appropriate valuation methodologies and information available to management as of December 31, 2006 and 2005, respectively. Considerable judgment is required in developing these estimates, and accordingly, no assurance can be given that the estimated values are indicative of the amounts that would be realized in a free market exchange. The following methods and assumptions were used to estimate the fair value of each class of financial instrument for which it was practicable to estimate that value:

•

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

	•		Marketable securities — The fair values of the debt securities, including mortgage-backed securities, available for sale were based on the quoted closing market prices on December 31, 2006 and 2005, respectively.

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

	•		Long-term debt — The fair value of our Zero Coupon Debentures, 1.5% Debentures, 4.875% Senior Notes and 5.15% Senior Notes was based on the quoted closing market price on December 31, 2006 and 2005, respectively, from brokers of these instruments.

12. Related-Party Transactions

Transactions with Loews. We are party to a services agreement with Loews, or the Services Agreement, pursuant to which Loews performs certain administrative and technical services on our behalf. Such services include personnel, telecommunications, purchasing, internal auditing, accounting, data processing and cash management services, in addition to advice and assistance with respect to preparation of tax returns and obtaining insurance. Under the Services Agreement, we are required to reimburse Loews for (i) allocated personnel costs (such as salaries, employee benefits and payroll taxes) of the Loews personnel actually providing such services and (ii) all out-of-pocket expenses related to the provision of such services. The Services Agreement may be terminated at our option upon 30 days’ notice to Loews and at the option of Loews upon six months’ notice to us. In addition, we have agreed to indemnify Loews for all claims and damages arising from the provision of services by Loews under the Services Agreement unless due to the gross negligence or willful misconduct of Loews. We were charged $0.4 million, $0.4 million and $0.3 million by Loews for these support functions during the years ended December 31, 2006, 2005 and 2004, respectively.

In addition, during 2006 we purchased three performance bonds in support of our drilling operations offshore Mexico totaling $73.2 million from a majority-owned subsidiary of Loews after obtaining competitive quotes. Premiums and fees associated with these bonds totaled $1.0 million in 2006.

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

During the years ended December 31, 2006, 2005 and 2004 we made payments of $0.6 million, $1.2 million and $0.9 million, respectively, to Ernst & Young LLP for tax and other consulting services. The wife of our President and Chief Operating Officer is an audit partner at this firm.

13. Income Taxes

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


	Year Ended December 31,
	2006			2005		2004

	(In thousands)

U.S. — current	$	230,914		$	28,106	$	(2,753	)
Non-U.S. — current		27,961			2,793		5,737

Total current		258,875			30,899		2,984


U.S. — deferred		5,006			63,408		(3,611	)
U.S. — deferred to reduce goodwill		—			—		11,099
Non-U.S. — deferred		(4,396	)		1,751		(6,762	)

Total deferred		610			65,159		726


Total	$	259,485		$	96,058	$	3,710

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


	Year Ended December 31,
	2006			2005			2004

	(In thousands)

Income (loss) before income tax expense (benefit):
U.S.	$	765,583		$	324,390		$	16,770
Non — U.S.		200,749			32,005			(20,303	)

Worldwide	$	966,332		$	356,395		$	(3,533	)


Expected income tax expense (benefit) at federal statutory rate	$	338,216		$	124,738		$	(1,237	)
Foreign earnings indefinitely reinvested		(60,624	)		529			11,988
Foreign taxes — domestic companies		15,200			1,806			1,652
Foreign tax credits		(15,087	)		(1,811	)		—
Valuation allowance — foreign tax credits		(831	)		(9,574	)		104
Reduction of deferred tax liability related to Arethusa goodwill deduction		(8,850	)		(8,850	)		(5,175	)
Reduction of contingent tax liability related to Arethusa goodwill deduction		—			(8,850	)		—
Domestic production activities deduction		(8,339	)		—			—
Reduction of deferred tax liability related to the Ocean Alliance Lease-Leaseback		—			—			(4,538	)
East Timor — Indonesia tax settlement		—			(4,365	)		—
Revision of estimated tax balance		1,039			843			2,507
IRS audit adjustments		—			1,931			—
Amortization of deferred tax liability related to transfer of drilling rigs to different taxing jurisdictions		(1,580	)		(1,763	)		(1,748	)
Other		341			1,424			157

Income tax expense	$	259,485		$	96,058		$	3,710

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


	December 31,
	2006			2005

	(In thousands)
Deferred tax assets:
Net operating loss carryforwards	$	2,761		$	3,692
Capital loss carryback/carryforward		412
Goodwill		13,643			16,791
Worker’s compensation and other current accruals (1)		14,733			14,652
Foreign tax credits		—			15,345
Nonqualified stock options.		1,044
Other		7,269			5,898

Total deferred tax assets		39,862			56,378
Valuation allowance for foreign tax credits		—			(831	)

Net deferred tax assets		39,862			55,547

Deferred tax liabilities:
Depreciation and amortization		(418,703	)		(444,086	)
Contingent interest		(53,399	)		(42,593	)
Non-U.S. deferred taxes		(3,128	)		(7,524	)
Other		(3,253	)		(1,738	)

Total deferred tax liabilities		(478,483	)		(495,941	)

Net deferred tax liability	$	(438,621	)	$	(440,394	)


(1)		$9.6 million and $4.7 million reflected in “Prepaid expenses and other” in our Consolidated Balance Sheets at December 31, 2006 and 2005, respectively.

Certain of our international rigs are owned and operated, directly or indirectly, by Diamond Offshore International Limited, a Cayman Islands subsidiary which we wholly own. We do not intend to remit earnings from this subsidiary to the U.S. and we plan to indefinitely reinvest these earnings internationally. Consequently, no U.S. taxes have been provided on earnings and no U.S. tax benefits have been recognized on losses generated by this subsidiary.

We have certain other non-U.S. subsidiaries for which U.S. taxes have been provided to the extent a U.S. tax liability could arise upon remittance of earnings from the non-U.S. subsidiaries. As of December 31, 2006, we provided $0.3 million of U.S. taxes attributable to undistributed earnings of the non-U.S. subsidiaries. On actual remittance, certain countries may impose withholding taxes that, subject to certain limitations, are then available for use as tax credits against a U.S. tax liability, if any.

As of December 31, 2006, we had net operating loss, or NOL, carryforwards of approximately $7.9 million available to offset future taxable income. The NOL carryforwards consist entirely of losses that were acquired in our merger with Arethusa (Off-Shore) Limited, or Arethusa, in 1996. The utilization of the NOL carryforwards acquired in the Arethusa merger is limited pursuant to Section 382 of the Internal Revenue Code of 1986, as amended, or the Code. We expect to fully utilize all of the NOL carryforwards in future tax years. During 2006, we were able to utilize approximately $2.7 million of the NOL carryforwards.

We have recorded a deferred tax asset of $2.8 million for the benefit of the NOL carryforwards. The NOL carryforwards will expire as follows:


			Tax Benefit of
	Net Operating		Net Operating
Year	Losses		Losses

	(In millions)

2009		5.5		1.9
2010		2.4		0.9

Total	$	7.9	$	2.8

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

During 2005, we settled an income tax dispute in East Timor (formerly part of Indonesia) for approximately $0.2 million. At December 31, 2004, our books reflected an accrued liability of $4.4 million related to potential East Timor and Indonesian income tax liabilities covering the period 1992 through 2000. Subsequent to the tax settlement, we determined that the accrual was no longer necessary and wrote off the accrued liability in the fourth quarter of 2005.

14. Employee Benefit Plans

Defined Contribution Plans

We maintain defined contribution retirement plans for our U.S., U.K. and third-country national, or TCN, employees. The plan for our U.S. employees, or the 401k Plan, is designed to qualify under Section 401(k) of the Code. Under the 401k Plan, each participant may elect to defer taxation on a portion of his or her eligible earnings, as defined by the 401k Plan, by directing his or her employer to withhold a percentage of such earnings. A participating employee may also elect to make after-tax contributions to the 401k Plan. During the three years ended December 31, 2006 we contributed 3.75% of a participant’s defined compensation and matched 25% of the first 6% of each employee’s compensation contributed to the 401k Plan. Participants are fully vested immediately upon enrollment in the 401k Plan. For the years ended December 31, 2006, 2005 and 2004, our provision for contributions was $9.0 million, $7.3 million and $6.9 million, respectively.

The defined contribution retirement plan for our U.K. employees, or U.K. Plan, provides that we make annual contributions in an amount equal to the employee’s contributions, generally up to a maximum of 5.25% of the employee’s defined compensation per year for employees working in the U.K. sector of the North Sea and up to a maximum of 9% of the employee’s defined compensation per year for U.K. nationals working in the Norwegian sector of the North Sea. Our provision for contributions was $1.2 million, $0.8 million and $0.7 million for the years ended December 31, 2006, 2005 and 2004, respectively.

The defined contribution retirement plan for our TCN employees, or TCN Plan, is similar to the 401k Plan. During the three years ended December 31, 2006 we contributed 3.75% of a participant’s defined compensation and matched 25% of the first 6% of each employee’s compensation contributed to the TCN Plan. Our provision for contributions was $0.9 million, $0.8 million and $0.7 million for the years ended December 31, 2006, 2005 and 2004, respectively.

Deferred Compensation and Supplemental Executive Retirement Plan

We established our Deferred Compensation and Supplemental Executive Retirement Plan, or Supplemental Plan, in December 1996. Participants in the Supplemental Plan are a select group of our management or other highly compensated employees. During the three years ended December 31, 2006 we contributed to the Supplemental Plan any portion of the 3.75% base salary contribution and the matching contribution under our 401k Plan that could not be contributed to that plan because of limitations within the Code. The Supplemental Plan also provides that participants may defer up to 10% of their base compensation and/or up to 100% of any performance bonus. Each participant is fully vested in all amounts paid into the Supplemental Plan. Our provision for contributions for the years ended December 31, 2006, 2005 and 2004 was not material.

Pension Plan

The defined benefit pension plan established by Arethusa effective October 1, 1992 was frozen on April 30, 1996. At that date all participants were deemed fully vested in the plan, which covered substantially all U.S. citizens and U.S. permanent residents who were employed by Arethusa. Benefits are calculated and paid based on an employee’s years of credited service and average compensation at the date the plan was frozen using an excess benefit formula integrated with social security covered compensation. As a result of freezing the plan, no service cost has been accrued for the years presented.

Pension costs are determined actuarially and at a minimum funded as required by the Code. During 2005 we made a voluntary contribution to the plan of $0.2 million. During the fourth quarter of 2006 we began the process of terminating the plan and have entered into a letter agreement with an insurance company to transfer the responsibility for making payments of plan benefits to the insurance company. Under the terms of the agreement, all of the assets of the plan were transferred to the insurance company along with our additional payment of approximately $0.3 million. We are seeking Pension Benefit Guarantee Corporation, or PBGC, approval to terminate the plan which we expect to obtain in the second quarter of 2007. Once termination has been approved by the PBGC we will enter into an irrevocable contract with the insurance company. The insurance company will issue their annuity certificates to the plan participants and we will no longer have any benefit liability under the plan.

During the fourth quarter of 2006 we adopted the provision of SFAS 158 requiring that we recognize the funded status of our benefit plan. We did not adopt the requirement under SFAS 158 to measure our plan assets and benefit obligations as of December 31, our fiscal year-end, as this is not required until years ending after December 15, 2008. We expect our plan to be terminated in the second quarter of 2007 and we therefore continued to use a September 30 measurement date for the plan.

The incremental effect of applying SFAS 158 on individual line items in our Consolidated Balance Sheets at December 31, 2006 is as follows:


	Before					After
	Application of					Application of
	SFAS 158		Adjustments			SFAS 158

	(In thousands)
Other assets — prepaid benefit cost	$	7,734	$	(6,963	)	$	771
Total assets		4,139,802		(6,963	)		4,132,839
Deferred income taxes		450,664		(2,437	)		448,227
Total liabilities		1,815,768		(2,437	)		1,813,331
Accumulated other comprehensive income (losses)		109		(4,526	)		(4,417	)
Total stockholders’ equity		2,324,034		(4,526	)		2,319,508

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


	September 30,
	2006			2005
	(In thousands)
Change in benefit obligation:
Benefit obligation at beginning of year	$	19,467		$	17,615
Interest cost		1,054			1,040
Actuarial gain		275			1,470
Benefits paid		(681	)		(658	)

Benefit obligation at end of year	$	20,115		$	19,467


Change in plan assets:
Fair value of plan assets at beginning of year	$	19,770		$	17,735
Actual return (loss) on plan assets		1,797			2,493
Contributions		—			200
Benefits paid		(681	)		(658	)

Fair value of plan assets at end of year	$	20,886		$	19,770


Funded status of plan	$	771		$	304

Items not yet recognized as a component of net periodic pension cost:


	September 30,
	2006		2005
	(In thousands)

Net actuarial loss	$	6,963	$	7,426

The estimated net actuarial loss, prior service cost and transition obligation for our plan that we would expect to amortize from Other Comprehensive Income into net periodic pension cost during the 2007 fiscal year are $281,000, $0 and $0, respectively. However, when we terminate the plan, which we expect to do in 2007, the entire unamortized portion of the $7.0 million of net actuarial loss as of September 30, 2006, which is included in Other Comprehensive Losses (Gain) at December 31, 2006, will be recognized as periodic pension cost.

The accumulated benefit obligation was as follows:


	September 30,
	2006		2005
	(In thousands)

Accumulated benefit obligation	$	20,115	$	19,467

Amounts recognized in our Consolidated Balance Sheets consisted of prepaid benefit cost as follows:


	September 30,
	2006		2005
	(In thousands)

Other assets	$	771	$	7,730

Components of net periodic benefit costs were as follows:


	September 30,
	2006			2005			2004
	(In thousands)
Interest cost	$	1,054		$	1,040		$	1,022
Expected return on plan assets		(1,362	)		(1,222	)		(1,187	)
Amortization of unrecognized loss		303			306			306

Net periodic pension benefit (income) loss	$	(5	)	$	124		$	141

Amounts recognized in Other Comprehensive (Losses) Gains:


	September 30,
	2006		2005		2004
	(In thousands)
Net actuarial loss	$	6,963	$	—	$	—

Weighted-average assumptions used to determine benefit obligations were:


	September 30,
	2006			2005

Discount rate		5.75	%		5.50	%
Expected long-term rate		7.00	%		7.00	%

The long-term rate of return for plan assets is determined based on widely accepted capital market principles, long-term return analysis for global fixed income and equity markets as well as the active total return oriented portfolio management style. Long-term trends are evaluated relative to current market factors such as inflation, interest rates and fiscal and monetary policies, in order to assess the capital market assumptions as applied to the plan.

Weighted-average assumptions used to determine net periodic benefit costs were:


	September 30,
	2006			2005			2004

Discount rate		5.50	%		6.00	%		6.25	%
Expected long-term rate		7.00	%		7.00	%		7.25	%

The weighted-average asset allocation for our pension plan by asset category is as follows:


	September 30,
	2006			2005

Equity securities		—			64	%
Debt securities		—			29	%
Money market fund		—			6	%
Insurance contracts		100	%		—
Other		—			1	%

We have historically employed a total return approach whereby a mix of equities and fixed income investments were used to maximize the long-term return of plan assets for a prudent level of risk. The intent of the strategy was to minimize plan expenses by outperforming plan liabilities over the long run. During the fourth quarter of 2006, in anticipation of the 2007 termination of the plan, all of the assets of the plan were transferred to an insurance company.

The plan assets at September 30, 2006 and 2005 do not include any of our own securities.

The benefits expected to be paid by the pension plan by fiscal year are (in thousands):


2007	$	705
2008		753
2009		782
2010		813
2011		858
2012-2016		5,441

Under the terms of our letter agreement with an insurance company, these payments have become the responsibility of that insurance company until the plan is terminated. Once the plan is terminated, plan participants will receive annuity contracts from the insurance company and benefit payments will be made to the participants pursuant to the terms of those contracts.

We do not expect to make a contribution to our pension plan in 2007.

15. Hurricane Damage

2005 Storms

Ocean Warwick — The Ocean Warwick, with a net book value of $14.0 million, was declared a constructive total loss effective August 29, 2005. We issued a proof of loss in the amount of $50.5 million to our insurers, representing the insured value of the rig less a $4.5 million deductible. We received all insurance proceeds related to this claim in 2005. Recovery and removal of the Ocean Warwick are subject to separate insurance deductibles which were estimated at the time of loss to be $2.5 million in the aggregate.

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

In addition, in the third quarter of 2005 and during 2006, we wrote-off the aggregate net book value of approximately $14.3 million in rig equipment that was either lost or damaged beyond repair during these storms as loss on disposition of assets and recorded a corresponding insurance receivable in an amount equal to our expected recovery from insurers. The write-off of this equipment and recognition of insurance receivables had no net effect on our consolidated results of operations for the years ended December 31, 2006 and 2005.

In late 2006 we received $3.1 million from certain of our customers primarily related to the replacement or repair of equipment damaged during the 2005 hurricanes. We recorded $0.3 million of this recovery as a credit to contract drilling expense, $1.1 million as a gain on disposition of assets and the remaining $1.8 million as other income.

2004 Storm

During the third quarter of 2004, our operations in the Gulf of Mexico were impacted by Hurricane Ivan, resulting in damage to several of our rigs. During 2004, we recorded an insurance deductible of $6.1 million related to damage from this hurricane of which $4.5 million and $1.6 million were recorded as additional contract drilling expense and loss on disposition of assets, respectively.

Our insurance claim relating to damages sustained during Hurricane Ivan was settled in the fourth quarter of 2005, resulting in net insurance proceeds to us of $14.5 million. We recognized an insurance gain of $5.6 million as “Gain on disposition of assets” in our Consolidated Statements of Operations for the year ended December 31, 2005, resulting from the involuntary conversion of assets lost during the hurricane in 2004. We accounted for the remaining portion of the insurance proceeds as a reduction in an insurance receivable for hurricane-related repair costs which we believed were reimbursable by insurance.

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

16. Segments and Geographic Area Analysis

We manage our business on the basis of one reportable segment, contract drilling of offshore oil and gas wells. Although we provide contract drilling services with different types of offshore drilling rigs and also provide such services in many geographic locations, we have aggregated these operations into one reportable segment based on the similarity of economic characteristics among all divisions and locations, including the nature of services provided and the type of customers of such services.

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


	Year Ended December 31,
	2006		2005		2004
	(In thousands)

High-Specification Floaters	$	766,873	$	448,937	$	281,866
Intermediate Semisubmersibles		785,047		456,734		319,053
Jack-ups		435,194		271,809		178,391
Other		—		1,535		3,095

Total contract drilling revenues.		1,987,114		1,179,015		782,405
Revenues related to reimbursable expenses		65,458		41,987		32,257

Total revenues	$	2,052,572	$	1,221,002	$	814,662

Geographic Areas

At December 31, 2006, our drilling rigs were located offshore twelve countries in addition to the United States. As a result, we are exposed to the risk of changes in social, political and economic conditions inherent in foreign operations and our results of operations and the value of our foreign assets are affected by fluctuations in foreign currency exchange rates. Revenues by geographic area are presented by attributing revenues to the individual country or areas where the services were performed.


	Year Ended December 31,
	2006		2005		2004
	(In thousands)
United States	$	1,179,676	$	668,423	$	358,741

Foreign:
Europe/Africa		250,103		106,188		69,643
South America		203,338		129,524		120,112
Australia/Asia/Middle East		323,003		231,273		180,783
Mexico		96,452		85,594		85,383

		872,896		552,579		455,921


Total revenues	$	2,052,572	$	1,221,002	$	814,662

An individual foreign country may, from time to time, comprise a material percentage of our total contract drilling revenues from unaffiliated customers. For the years ended December 31, 2006, 2005 and 2004, individual countries that comprised 5% or more of our total contract drilling revenues from unaffiliated customers are listed below.


	Year Ended December 31,
	2006			2005			2004


Brazil		9.9	%		10.6	%		12.5	%
United Kingdom		7.5	%		6.3	%		5.5	%
Malaysia		6.3	%		6.9	%		5.2	%
Mexico		4.7	%		7.0	%		10.5	%
Australia		4.2	%		5.1	%		5.3	%
Indonesia		1.3	%		3.0	%		6.3	%

The following table presents our long-lived tangible assets by geographic location as of December 31, 2006 and 2005. A substantial portion of our assets are mobile, therefore asset locations at the end of the period are not necessarily indicative of the geographic distribution of the earnings generated by such assets during the periods.


	December 31,
	2006		2005
	(In thousands)
Drilling and other property and equipment, net:
United States	$	1,335,329	$	1,278,146
Foreign:
South America		269,821		279,284
Europe/Africa		183,242		136,378
Australia/Asia/Middle East		728,383		481,381
Mexico		111,678		126,831

		1,293,124		1,023,874


Total	$	2,628,453	$	2,302,020

Besides the United States, Brazil and Singapore are currently the only countries with a material concentration of our assets. Approximately 10.3% and 14.8% of our drilling and other property and equipment were located offshore Brazil and Singapore, respectively, as of December 31, 2006. Approximately 12.1% and 6.1% of our drilling and other property and equipment were located offshore Brazil and Singapore, respectively, as of December 31, 2005.

Major Customers

Our customer base includes major and independent oil and gas companies and government-owned oil companies. Revenues from our major customers for the periods presented that contributed more than 10% of our total revenues are as follows:


	Year Ended December 31,
Customer	2006			2005			2004


Anadarko Petroleum		10.6	%		10.3	%		3.5	%
Petróleo Brasileiro S.A.		10.4	%		10.7	%		12.6	%
PEMEX — Exploración Y Producción		4.7	%		7.0	%		10.5	%

17. Unaudited Quarterly Financial Data

Unaudited summarized financial data by quarter for the years ended December 31, 2006 and 2005 is shown below.


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

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

2005
Revenues	$	258,758	$	283,399	$	310,522	$	368,323
Operating income		48,006		64,897		120,579		140,917
Income before income tax expense		43,358		55,791		119,419		137,827
Net income		30,118		41,282		82,039		106,898
Net income per share:
Basic	$	0.23	$	0.32	$	0.64	$	0.83
Diluted	$	0.23	$	0.31	$	0.60	$	0.78

18. Subsequent Events

Debt Conversions. Subsequent to December 31, 2006 and through February 14, 2007, the holders of $438.4 million in aggregate principal amount of our 1.5% Debentures and the holders of $1.5 million accreted value through the date of conversion, or $2.4 million in aggregate principal amount, of our Zero Coupon Debentures elected to convert their outstanding debentures into shares of our common stock. We issued 8,963,942 shares of our common stock pursuant to these conversions in 2007. At February 14, 2007, there was $21.5 million in aggregate principal amount and $3.8 million accreted value, or $6.0 million aggregate principal amount at maturity, of our 1.5% Debentures and Zero Coupon Debentures, respectively, outstanding.

As a result of the conversions of our 1.5% Debentures, we will reverse in 2007 a non-current deferred tax liability of approximately $50 million related to interest expense imputed on these bonds for U.S. federal income tax return purposes.

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

Not applicable.

Item 9A. Controls and Procedures

Disclosure Controls and Procedures

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

Our principal executive officer and principal financial officer evaluated our disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) as of December 31, 2006 and concluded that our controls and procedures were effective.

Internal Control Over Financial Reporting

Management’s Annual Report on Internal Control Over Financial Reporting

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

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

Our management assessed the effectiveness of our internal control over financial reporting as of December 31, 2006. In making this assessment, our management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control — Integrated Framework. Based on management’s assessment our management believes that, as of December 31, 2006, our internal control over financial reporting was effective based on those criteria.

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

Changes in Internal Control Over Financial Reporting

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

Item 9B. Other Information.

Not applicable.

PART III

Reference is made to the information responsive to Items 10, 11, 12, 13 and 14 of this Part III contained in our definitive proxy statement for our 2007 Annual Meeting of Stockholders, which is incorporated herein by reference.

Item 10. Directors, Executive Officers and Corporate Governance.

Item 11. Executive Compensation.

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

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

Item 14. Principal Accountant Fees and Services.

PART IV

Item 15. Exhibits and Financial Statement Schedules.

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

(1) Financial Statements


			Page

Report of Independent Registered Public Accounting Firm			55
Consolidated Balance Sheets			56
Consolidated Statements of Operations			57
Consolidated Statements of Stockholders’ Equity			58
Consolidated Statements of Comprehensive Income (Loss)			59
Consolidated Statements of Cash Flows			60
Notes to Consolidated Financial Statements			61

(2) Financial Statement Schedules

No schedules have been included herein because the information required to be submitted has been included in our Consolidated Financial Statements or the notes thereto or the required information is inapplicable.


(3) Index of Exhibits			92

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


Exhibit No.		Description

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

	3.2	Amended and Restated By-laws of Diamond Offshore Drilling, Inc. (incorporated by reference to Exhibit 3.2 to our Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2001) (SEC File No. 1-13926).

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

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

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

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

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

	4.6	Exchange and Registration Rights Agreement, dated June 14, 2005, between Diamond Offshore Drilling, Inc. and the initial purchaser of the 4.875% Senior Notes (incorporated by reference to Exhibit 4.3 to our Current Report on Form 8-K filed June 16, 2005).

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

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

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

	10.4*+	Amended and Restated Diamond Offshore Management Company Supplemental Executive Retirement Plan effective as of January 1, 2007.

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

	10.6+	Second Amended and Restated Diamond Offshore Drilling, Inc. 2000 Stock Option Plan (incorporated by reference to Exhibit A attached to our definitive proxy statement on Schedule 14A filed on March 31, 2005).


Exhibit No.		Description

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

	10.8+	Form of Stock Option Certificate for grants to non-employee directors pursuant to the Second Amended and Restated Diamond Offshore Drilling, Inc. 2000 Stock Option Plan (incorporated by reference to Exhibit 10.2 to our Current Report on Form 8-K filed October 1, 2004).

	10.9+	Diamond Offshore Drilling, Inc. Incentive Compensation Plan for Executive Officers (incorporated by reference to Exhibit B attached to our definitive proxy statement on Schedule 14A filed on March 31, 2005).

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

	10.11	5-Year Revolving Credit Agreement, dated as of November 2, 2006, among Diamond Offshore Drilling, Inc., JPMorgan Chase Bank, N.A., as administrative agent, The Bank of Tokyo-Mitsubishi UFJ, Ltd. Houston Agency, Fortis Capital Corp., HSBC Bank USA, National Association, Wells Fargo Bank, N.A. and Bayerische Hypo-Und Vereinsbank AG, Munich Branch, as co-syndication agents, and the lenders named therein (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed November 3, 2006).

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

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

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

	10.15*+	Employment Agreement between Diamond Offshore Management Company and John M. Vecchio dated as of December 15, 2006.

	10.16*+	Employment Agreement between Diamond Offshore Management Company and William C. Long dated as of December 15, 2006.

	10.17*+	Employment Agreement between Diamond Offshore Management Company and Lyndol L. Dew dated as of December 15, 2006.

	10.18*+	Employment Agreement between Diamond Offshore Management Company and Mark F. Baudoin dated as of December 15, 2006.

	10.19*+	Employment Agreement between Diamond Offshore Management Company and Beth G. Gordon dated as of January 3, 2007.

	12.1*	Statement re Computation of Ratios.

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

	23.1*	Consent of Deloitte & Touche LLP.

	24.1*	Powers of Attorney.

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

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

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

		* Filed or furnished herewith.
		+ Management contracts or compensatory plans or arrangements.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on February 23, 2007.


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

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


Signature	Title	Date

/s/ JAMES S. TISCH*	Chairman of the Board and	February 23, 2007
James S. Tisch	Chief Executive Officer (Principal Executive Officer)

/s/ LAWRENCE R. DICKERSON*	President, Chief Operating Officer and	February 23, 2007
Lawrence R. Dickerson	Director

/s/ GARY T. KRENEK*	Senior Vice President and	February 23, 2007
Gary T. Krenek	Chief Financial Officer (Principal Financial Officer)

/s/ BETH G. GORDON*	Controller (Principal Accounting Officer)	February 23, 2007
Beth G. Gordon

/s/ ALAN R. BATKIN*	Director	February 23, 2007
Alan R. Batkin

/s/ JOHN R. BOLTON*	Director	February 23, 2007
John R. Bolton

/s/ CHARLES L. FABRIKANT*	Director	February 23, 2007
Charles L. Fabrikant

/s/ PAUL G. GAFFNEY II*	Director	February 23, 2007
Paul G. Gaffney II

/s/ HERBERT C. HOFMANN*	Director	February 23, 2007
Herbert C. Hofmann

/s/ ARTHUR L. REBELL*	Director	February 23, 2007
Arthur L. Rebell

/s/ RAYMOND S. TROUBH*	Director	February 23, 2007
Raymond S. Troubh


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

EXHIBIT INDEX


Exhibit No.		Description

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

	3.2	Amended and Restated By-laws of Diamond Offshore Drilling, Inc. (incorporated by reference to Exhibit 3.2 to our Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2001) (SEC File No. 1-13926).

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

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

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

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

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

	4.6	Exchange and Registration Rights Agreement, dated June 14, 2005, between Diamond Offshore Drilling, Inc. and the initial purchaser of the 4.875% Senior Notes (incorporated by reference to Exhibit 4.3 to our Current Report on Form 8-K filed June 16, 2005).

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

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

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

	10.4*+	Amended and Restated Diamond Offshore Management Company Supplemental Executive Retirement Plan effective as of January 1, 2007.

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

	10.6+	Second Amended and Restated Diamond Offshore Drilling, Inc. 2000 Stock Option Plan (incorporated by reference to Exhibit A attached to our definitive proxy statement on Schedule 14A filed on March 31, 2005).


Exhibit No.		Description

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

	10.8+	Form of Stock Option Certificate for grants to non-employee directors pursuant to the Second Amended and Restated Diamond Offshore Drilling, Inc. 2000 Stock Option Plan (incorporated by reference to Exhibit 10.2 to our Current Report on Form 8-K filed October 1, 2004).

	10.9+	Diamond Offshore Drilling, Inc. Incentive Compensation Plan for Executive Officers (incorporated by reference to Exhibit B attached to our definitive proxy statement on Schedule 14A filed on March 31, 2005).

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

	10.11	5-Year Revolving Credit Agreement, dated as of November 2, 2006, among Diamond Offshore Drilling, Inc., JPMorgan Chase Bank, N.A., as administrative agent, The Bank of Tokyo-Mitsubishi UFJ, Ltd. Houston Agency, Fortis Capital Corp., HSBC Bank USA, National Association, Wells Fargo Bank, N.A. and Bayerische Hypo-Und Vereinsbank AG, Munich Branch, as co-syndication agents, and the lenders named therein (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed November 3, 2006).

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

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

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

	10.15*+	Employment Agreement between Diamond Offshore Management Company and John M. Vecchio dated as of December 15, 2006.

	10.16*+	Employment Agreement between Diamond Offshore Management Company and William C. Long dated as of December 15, 2006.

	10.17*+	Employment Agreement between Diamond Offshore Management Company and Lyndol L. Dew dated as of December 15, 2006.

	10.18*+	Employment Agreement between Diamond Offshore Management Company and Mark F. Baudoin dated as of December 15, 2006.

	10.19*+	Employment Agreement between Diamond Offshore Management Company and Beth G. Gordon dated as of January 3, 2007.

	12.1*	Statement re Computation of Ratios.

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

	23.1*	Consent of Deloitte & Touche LLP.

	24.1*	Powers of Attorney.

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

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

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

		* Filed or furnished herewith.
		+ Management contracts or compensatory plans or arrangements.