e10vk

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, 2005


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. o

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, 2005		$	3,130,227,807

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, 2006		Common Stock, $0.01 par value per share		129,061,616 shares

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the definitive proxy statement relating to the 2006 Annual Meeting of Stockholders of Diamond Offshore Drilling, Inc., which will be filed within 120 days of December 31, 2005, are incorporated by reference in Part III of this report.

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, which we expect to be completed in the first quarter of 2008. Unless the context otherwise requires, references in this report to “Diamond Offshore,” “we,” “us” or “our” mean Diamond Offshore Drilling, Inc. and our consolidated subsidiaries. We were incorporated in Delaware in 1989.

The Fleet

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

Semisubmersibles. We own and operate 30 semisubmersibles (including nine high-specification and 21 intermediate semisubmersible rigs, of which 19 are currently operating and the remaining two units are currently undergoing or will commence a major upgrade). 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 30, 2006, 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, respectively.

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 30, 2006, we had 19 intermediate semisubmersible rigs, including the recently reactivated Ocean New Era, drilling offshore various locations around the world. Five of these semisubmersibles were located in the GOM; four were located offshore Mexico, or Mexican GOM, four were located in the North Sea and two each were located offshore Australia, Brazil and Malaysia, respectively.

In January 2006, we announced that we would begin a major upgrade of the Ocean Monarch (formerly the Enserch Garden Banks) in mid-2006. We acquired this Victory-class, intermediate semisubmersible rig in August 2005 and are currently preparing to mobilize the rig from the GOM to a shipyard in Singapore for an upgrade to ultra-deepwater capability. The Ocean Endeavor, also a Victory-class semisubmersible, is currently in a shipyard in Singapore for a similar upgrade. Victory-class semisubmersible rigs were originally constructed as intermediate class units with a cruciform hull configuration, which lends itself well to modernization because of the unit’s characteristically long fatigue-life and advantageous stress characteristics. 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 enjoyed higher dayrates and greater utilization compared to slot rigs.

As of January 30, 2006, 11 of our jack-up rigs were located in the GOM. Of these rigs, eight are independent-leg cantilevered units, two are mat-supported cantilevered units, and one is a mat-supported slot unit. Both of our remaining jack-up rigs are internationally based and are independent-leg cantilevered rigs; one was located offshore Indonesia and the other was located offshore Qatar as of January 30, 2006.

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

Drillship. We have one drillship, the Ocean Clipper, which was located offshore Brazil as of January 30, 2006. 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. One of our other Victory-class rigs is currently being upgraded and another is scheduled for upgrade later in 2006. We have two additional Victory-class rigs that are currently operating as intermediate semisubmersibles.

In January 2006, we announced the initiation of a major upgrade of the Victory-class semisubmersible, the Ocean Monarch, at an estimated cost of approximately $300 million. We acquired the Ocean Monarch and its related equipment in August 2005 for $20 million, and we expect to mobilize the rig and equipment to a shipyard in Singapore in mid-2006. The modernized rig will be designed to operate in up to 10,000 feet of water in a moored configuration. We expect the Ocean Monarch to be ready for deep water service in the fourth quarter of 2008.

In May 2005, we began a major upgrade of our Victory-class semisubmersible, the Ocean Endeavor, for ultra-deepwater service at a shipyard in Singapore. We estimate that the total cost of the upgrade will be approximately $250 million of which $54.5 million has been spent through December 31, 2005. The modernized rig is being designed to operate in up to 10,000 feet of water. The upgrade is on schedule, and the redesigned rig is expected to complete its commissioning in the second quarter of 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, will be constructed in Brownsville, Texas and in Singapore, respectively, at an aggregate expected cost of approximately $300 million of which $85.9 million has been spent through December 31, 2005. 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 units in 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.

Fleet Retirements. In August 2005 we removed from service one of our jack-up rigs, the Ocean Warwick, as a result of damages sustained during Hurricane Katrina. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Overview — Impact of 2005 Hurricanes” and Note 15 “Hurricane Damage” to

More detailed information concerning our fleet of mobile offshore drilling rigs, as of January 30, 2006, 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

ENI Petroleum

Ocean Valiant

5,500

SP; 15K; 3M

1988/1999

GOM

Kerr-McGee

Ocean Victory

5,500

VC; 15K; 3M

1972/1997

GOM

Murphy Exploration

Ocean Star

5,500

VC; 15K; 3M

1974/1999

GOM

Kerr-McGee

Ocean Alliance

5,000

DP; 15K; 3M

1988/1999

Brazil

Petrobras

Ocean Quest

3,500

VC; 15K; 3M

1973/1996

GOM

Noble Energy

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

Amerada Hess

Ocean Patriot

3,000

15K; 3M

1982/2003

Australia

Anzon

Ocean Yorktown

2,200

1976/1996

Mexican GOM

PEMEX

Ocean Concord

2,200

1975/1999

GOM

Woodside Energy

Ocean Lexington

2,200

1976/1995

GOM

ExxonMobil

Ocean Saratoga

2,200

1976/1995

GOM

LLOG

Ocean Epoch

1,640

1977/2000

Malaysia

Murphy Exploration

Ocean General

1,640

1976/1999

Malaysia

CTOC

Ocean Bounty

1,500

VC; 3M

1977/1992

Australia

Coogee Resources

Ocean Guardian

1,500

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

Mexican GOM

PEMEX

Ocean Vanguard

1,500

15K; 3M

1982

North Sea

ExxonMobil

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

Walter Oil & Gas

Ocean Tower

350

IC; 3M

1972/2003

GOM

Chevron

Ocean King

300

IC; 3M

1973/1999

GOM

Forest Oil

Ocean Nugget

300

1976/1995

GOM

Royal Production

Ocean Summit

300

1972/2003

GOM

Novus Louisiana

Ocean Heritage

300

1981/2002

Qatar

ConocoPhillips

Ocean Spartan

300

1980/2003

GOM

LLOG

Ocean Spur

300

1981/2003

GOM

Apache

Ocean Sovereign

300

1981/2003

Indonesia

Santos

Ocean Champion

250

1975/2004

GOM

Stone Energy

Ocean Columbia

250

1978/1990

GOM

Newfield Exploration

Ocean Crusader

200

1982/1992

GOM

Seneca Resources

Ocean Drake

200

1983/1986

GOM

Chevron

Under Construction (4):

Ocean Endeavor

2,000

VC; 15K; 4M

1975/2007

Singapore

Shipyard; Upgrade to 10,000’

Ocean Monarch

1,500

1974/2008

GOM

Preparing to mobilize to shipyard; Upgrade to 10,000’

Ocean Scepter

350

IC; 15K; 3M

2008

GOM

New; Under Construction

Ocean Shield

350

IC; 15K; 3M

2008

Singapore

New; Under Construction

Attributes

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 U.K and Norway; and Africa and Egypt;

	•		South America, principally in Brazil;

	•		Australia, Asia and Middle East, including Malaysia, Indonesia and Qatar.

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 2005, we performed services for 53 different customers with Petróleo Brasileiro S.A., or Petrobras, and Kerr-McGee Oil & Gas Corporation, 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. During 2003, we performed services for 52 different customers with Petrobras and BP p.l.c., or BP, accounting for 20.3% and 11.9% of our annual total consolidated revenues, respectively. During periods of low demand for offshore drilling rigs, the loss of a single significant customer could have a material adverse effect on our results of operations.

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 45%, 56% and 52% of our total consolidated revenues for the years ended December 31, 2005, 2004 and 2003, 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, 2005, we had approximately 4,500 workers, including international crew personnel furnished through independent labor contractors. We have experienced satisfactory labor relations and provide comprehensive benefit plans for our employees.

Access to Company Filings

We are subject to the informational requirements of the Securities Exchange Act of 1934, as amended, or the Exchange Act, and accordingly file annual, quarterly and current reports, any amendments to those reports, proxy statements and other information with the United States Securities and Exchange Commission, or SEC. You may read and copy the information we file with the SEC at the public reference facilities maintained by the SEC at 450 Fifth Street, N.W., 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.

Item 1A. Risk Factors.

Our business is subject to a variety of risks, including the risks described below. You should carefully consider these risks before investing in 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, cash flows and results of operations 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), 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.

Although oil and natural gas prices are currently significantly above historical averages, resulting in higher utilization and dayrates earned by our drilling units, generally beginning in the third quarter of 2004, 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 reactivation of cold-stacked drilling units could also intensify price competition. We believe that there are currently more than 60 drilling units, primarily jack-up rigs, on order for delivery between 2006 and 2009. We believe that approximately 15 additional jack-up and semisubmersible rigs are currently being reactivated or scheduled for reactivation, upgrade or conversion for drilling use. Improvements in dayrates and expectations of sustained improvements in rig utilization rates and dayrates may result in the construction of additional new rigs or additional reactivations. These increases in rig supply could result in depressed rig utilization and greater price competition. 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.

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.

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

The majority of our contracts with our customers for our drilling units provide for the payment of a fixed dayrate per rig operating day. However, 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. We may be unable to recover increased or unforeseen costs from our customers, which 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.

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 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 $550 million with expected delivery dates in mid-2007 and the fourth quarter of 2008. We also have 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 $300 million. 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.

Although we maintain insurance, 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. 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. In addition, 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.

As a result of underwriting losses suffered by the insurance industry over the past few years and damages caused by two recent hurricanes in the GOM, we could be faced with the prospect of significantly higher insurance premiums, as well as significantly increasing our deductibles to offset or mitigate premium increases. Our retention of liability for property damage is currently between $1.0 million and $2.5 million per incident, depending on the value of the equipment, with an additional aggregate annual deductible of $4.5 million. 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.

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;

	•		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.

In 2003, we entered into contracts to operate four of our intermediate semisubmersible rigs offshore Mexico for PEMEX, the national oil company of Mexico. The terms of these contracts expose us to greater risks than we normally assume, such as exposure to greater environmental liability. 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 are subject to litigation that could have an adverse effect on us.

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

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

We require highly skilled personnel to operate and provide technical services and support for our business. To the extent that demand for drilling services and the size of the worldwide industry fleet increase, 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.

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.

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 more stringent in recent years, 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 54.3% of our outstanding shares of common stock 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, 2006		Position
James S. Tisch		53	Chairman of the Board of Directors and Chief Executive Officer
Lawrence R. Dickerson		53	President, Chief Operating Officer and Director
David W. Williams		48	Executive Vice President
Rodney W. Eads		54	Senior Vice President — Worldwide Operations
John L. Gabriel, Jr.		52	Senior Vice President — Contracts & Marketing
John M. Vecchio		55	Senior Vice President — Technical Services
Gary T. Krenek		47	Vice President and Chief Financial Officer
Beth G. Gordon		50	Controller — Chief Accounting Officer
William C. Long		39	Vice President, General Counsel & Secretary

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, a 91% 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.

David W. Williams has served as our Executive Vice President since March 1998.

Rodney W. Eads has served as a Senior Vice President since May 1997.

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

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
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

2004
First Quarter	$	26.63	$	20.48
Second Quarter		24.53		21.55
Third Quarter		32.99		22.89
Fourth Quarter		40.29		32.06

As of February 20, 2006 there were approximately 263 holders of record of our common stock.

Dividend Policy

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 $.125 per share on September 1 and December 1. In 2004, we paid cash dividends of $0.0625 per share of our common stock on March 1, June 1, September 1 and December 1.

On January 24, 2006, we declared a quarterly cash dividend of $0.125 per share of our common stock and an annual special cash dividend of $1.50 per share of our common stock, both of which are payable March 1, 2006 to stockholders of record on February 3, 2006. 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, and capital spending plans and other relevant factors warrant such action at that time.

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,
	2005			2004			2003			2002			2001
	(In thousands, except per share and ratio data)
Income Statement Data:
Total revenues	$	1,221,002		$	814,662		$	680,941		$	752,561		$	924,300
Operating income (loss)		374,399			3,928			(38,323	)		51,984			225,410
Net income (loss)		260,337			(7,243	)		(48,414	)		62,520			173,823
Net income (loss) per share:
Basic		2.02			(0.06	)		(0.37	)		0.48			1.31
Diluted		1.91			(0.06	)		(0.37	)		0.47			1.26

Balance Sheet Data:
Drilling and other property and equipment, net	$	2,302,020		$	2,154,593		$	2,257,876		$	2,164,627		$	2,002,873
Total assets		3,606,922			3,379,386			3,135,019			3,256,308			3,493,071
Long-term debt (excluding current maturities) (1)		977,654			709,413			928,030			924,475			920,636

Other Financial Data:
Capital expenditures	$	293,829		$	89,229		$	272,026		$	340,805		$	268,617
Cash dividends declared per share		0.375			0.25			0.438			0.50			0.50
Ratio of earnings to fixed charges (2)		9.19	x		N/A			N/A			4.51	x		9.87	x


(1)		See “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Requirements” and Note 7 “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 August 2005, we purchased the Ocean Monarch (formerly the Enserch Garden Banks), a Victory-class semisubmersible drilling rig and related equipment, for $20 million and removed from service one of our jack-up rigs, the Ocean Warwick, as a result of damages it sustained during Hurricane Katrina. See “— Overview — Impact of 2005 Hurricanes.” In June 2005, we completed the sale of the Ocean Liberator and received net cash proceeds of $13.6 million.

Overview

Industry Conditions

The steadily rising demand for our mid-water (intermediate) and deepwater (high-specification) semisubmersible rigs that characterized the first nine months of 2005 continued during the fourth quarter of the year, while the market for our jack-up fleet reflected particular strength. Supported by solid fundamental market conditions for all classes of offshore drilling rigs, dayrates have in many cases more than doubled previous-cycle peaks, and our customers are increasingly seeking longer term contracts. As a result, we increased our revenue backlog from approximately $900 million, or 31.4 rig years, at the beginning of 2005 to a current backlog of approximately $4.5 billion, or 69.1 rig years, as of early February 2006. Generally rig utilization rates approach 95-98% during contracted periods; however, utilization rates can be adversely impacted by additional downtime due to various operating factors including, but not limited to, unscheduled repairs, maintenance and weather.

Gulf of Mexico. In the GOM, dayrates continue to escalate. A contract for one of our high-specification rigs has reached as high as $395,000 per day for work beginning in the first quarter of 2007 and extending until the first quarter of 2008. This contrasts with a dayrate of $150,000 that the unit is currently earning. Six of our seven high-specification semisubmersible rigs in the GOM, including the recently relocated Ocean Baroness, have future contracts or a letter of intent, or LOI, at dayrates at least 100 percent higher than the average dayrate these rigs earned during the first quarter of 2005. An LOI is subject to customary conditions, including the execution of a definitive agreement, and actual revenues received could be reduced by various operating factors, including utilization rates.

The dayrates for our five intermediate semisubmersibles currently operating in the GOM have reached as high as $200,000 for a one-well contract beginning in the third quarter of 2006. This contrasts with an average dayrate in the low $60,000 range earned during the first quarter of 2005 by our intermediate drilling units in the GOM. We continue to view the deepwater and intermediate markets in the GOM as under-supplied and believe that additional improvements in backlog and dayrates are possible in these market segments during 2006.

Our jack-up fleet in the GOM also continued to experience high utilization and improving dayrates during the fourth quarter of 2005, compared to the first nine months of 2005. Dayrates for our jack-up fleet operating in the GOM have reached as high as $125,000 for a two-well contract beginning late in the first quarter of 2006. This contrasts with an average dayrate in the low $40,000 range earned by our jack-up rigs in the GOM during the first quarter of 2005. Industry-wide, we believe that nine jack-up units were lost due to hurricanes in 2004 and 2005, and we expect up to six additional jack-up units to leave the GOM for other international markets by mid-2006. Among the six jack-up rigs that are expected to leave the GOM is the Ocean Spur. We expect to mobilize the rig from the GOM to Tunisia in the first quarter of 2006, where the unit has a commitment at a dayrate of $125,000 for a period of 12 months beginning in mid-March. We view the jack-up market in the GOM as under-supplied and believe that additional improvement in backlog and dayrates is possible in this market segment during 2006.

In the Mexican sector of the Gulf of Mexico, or Mexican GOM, our four intermediate semisubmersible rigs remain under long-term contracts that extend into late 2006 and 2007. We view the market for the Mexican GOM as firm and expect it to remain so during 2006.

Brazil. Two of our rigs operating in Brazil are currently working under term contracts that expire in 2009 and two additional rigs are operating under contracts expiring in 2010. We do not currently contemplate any change in our market position in Brazil. We view the Brazilian semisubmersible market as firm and expect it to remain so during 2006.

North Sea. Drilling activity in both the U.K. and Norwegian sectors of the North Sea has mirrored that in the GOM since mid-2004. Our three intermediate semisubmersible rigs in the U.K. sector are operating under one- to two-year term contracts at dayrates ranging from $100,000 to $160,000 for work that is now underway. Additionally, one of these three rigs, the Ocean Nomad, has received an 18-month contract extension beginning in the first quarter of 2007 at a dayrate of $285,000. In Norway, the Ocean Vanguard is working under a $140,000 per day contract that expires early in the fourth quarter of 2006, followed by options priced at $160,000 per day that expire in the first quarter of 2008. Effective industry utilization remains near 100 percent in the North Sea, and current dayrates exceed our present and future contract rates in both the U.K. and Norwegian sectors. We believe this market will continue to improve during 2006.

Australia/Asia/Middle East/Mediterranean. We currently have five semisubmersible rigs and one jack-up rig operating in the Australia/Asia, or Australasian, market. These rigs are operating under contracts or commitments for work extending well into 2006, and in some instances 2007 or 2008, at increasing dayrates, compared to dayrates averaging in the low $100,000 range at the end of 2005. A commitment for one of our intermediate rigs in the sector has reached as high as $235,000 per day for one well beginning in the second quarter of 2006. This contrasts with a dayrate of $90,000 that the unit is currently earning. With the relocation of the Ocean Heritage from Southeast Asia to Qatar in the second quarter of 2005 and the expected mobilization of the Ocean Spur to the Mediterranean in the first quarter of 2006, we are continuing to strategically redeploy our fleet in response to rising market demand and dayrates. We believe that the Australasian and Middle East/Mediterranean markets will continue to improve during 2006.

Impact of 2005 Hurricanes

In the third quarter of 2005, two major hurricanes, Katrina and Rita, struck the U.S. Gulf Coast and GOM. 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 sustained lesser damage in Hurricanes Katrina or Rita, or in some cases from both storms. We believe that the physical damage to our rigs, as well as related removal and recovery costs, are covered by insurance, after applicable deductibles. Our results for 2005 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, and received all insurance proceeds related to this insurance claim in 2005. Recovery and removal of the Ocean Warwick are subject to separate insurance deductibles totaling $2.5 million.

In the third quarter of 2005, we recorded a $33.6 million, pre-tax, net casualty gain ($21.8 million, after-tax, or $0.15 per share of common stock on a diluted basis) on 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 inventory, and $2.5 million in insurance deductibles for salvage and wreck removal as a result of Hurricanes Katrina and Rita. 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.

Damage to our other affected rigs and warehouse in New Iberia, Louisiana was less severe, and we believe that repair costs for such damage and lost equipment will be covered by insurance, less estimated deductibles. All of our damaged rigs have now been repaired and returned to service. Insurance deductibles relating to the remaining rigs damaged during Hurricane Katrina and our rigs and facility damaged by Hurricane Rita total $2.6 million in the aggregate, of which $1.2 million and $1.4 million have been 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.

In addition, in the third quarter of 2005, we wrote-off the net book value of approximately $4.2 million, pre-tax, 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 in 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, pre-tax, 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.

General

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

The two most significant variables affecting our revenues are dayrates for rigs and rig utilization rates, each of which is ultimately 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 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). We believe that the 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. If we had used this method of accounting in prior periods, our operating income (loss) and net income (loss) would not have changed and the impact on our 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” on our Consolidated Balance Sheets included in Item 8 of this report 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 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. Operating expenses generally are not affected by changes in dayrates and may not be significantly affected by 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.

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 and require downtime for the drilling rig, but normally do not require dry-docking or shipyard time. During 2006, we expect to spend an aggregate of $7.4 million for 5-year and intermediate surveys, excluding mobilization costs and any resulting repair and maintenance costs.

Critical Accounting Estimates

Our significant accounting policies are included in Note 1 “Summary of Significant Accounting Policies” 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.

The offshore drilling industry is a relatively young industry which began developing just over 50 years ago. We have based our estimates of useful lives and salvage values on the historical industry data available to us, as well as our own experience. In April 2003, we commissioned a study to evaluate the economic lives of our drilling rigs because several of our rigs had reached or were approaching the end of their depreciable lives, yet were still operating and were expected to operate for many more years. As a result of this study, effective April 1, 2003, we recorded changes in accounting estimates by increasing the estimated service lives to 25 years for our jack-ups and 30 years for our semisubmersibles and drillship and by increasing salvage values to 5% for most of our drilling rigs. We made the change in estimates to better reflect the remaining economic lives and salvage values of our fleet. The effect of this change in accounting estimates resulted in an increase in our net income for the year ended December 31, 2005 of $15.7 million, or $0.11 per share, and a reduction of our net loss for the years ended December 31, 2004 and 2003 of, $19.6 million, or $0.15 per share, and $14.9 million, or $0.11 per share, respectively.

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.

At December 31, 2005, we reviewed our single cold-stacked rig, the Ocean Monarch, for impairment. Based on our recent 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 do not consider this asset to be impaired.

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 our 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.

We were marketing another of our cold-stacked rigs, the Ocean Liberator, for sale to a third party in 2004, 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.

At December 31, 2003 we determined that all five of our cold-stacked rigs should be tested for impairment. The impairment analysis at December 31, 2003 consisted of a probability-weighted cash flow analysis for each of the five cold-stacked rigs. In all cases, the probability-weighted cash flows significantly exceeded the carrying value of each rig.

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

Personal Injury Claims. Our uninsured retention of liability for personal injury claims, which primarily results from Jones Act liability in the GOM, is $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 our historical experiences with similar past personal injury claims. Our claims department also estimates our liability for claims which are incurred but not reported by using historical data. Historically, our ultimate liability for personal injury claims has not differed materially from our recorded estimates. At December 31, 2005 our estimated liability for personal injury claims was $38.9 million. The eventual settlement or adjudication of these claims could differ materially from the 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 Statement of Financial Accounting Standards, or 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. 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.

At the end of 2004 we had established a valuation allowance of $10.3 million for certain of our foreign tax credit carryforwards which will begin to expire 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 now expect to be able to utilize $14.5 million of our available foreign tax credit carryforwards prior to their expiration dates and we believe that a valuation allowance is 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 believe that a valuation allowance is necessary and as a result have a valuation allowance of $0.8 million at December 31, 2005.

Results of Operations

Years Ended December 31, 2005 and 2004

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/
	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 rigs in the GOM increased $160.6 million, primarily due to higher average dayrates earned ($128.0 million) and higher utilization of our fleet in this market ($31.9 million) in 2005, 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 partly 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 partly 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, as compared to the prior year. The increase in costs in 2005 is 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 steel renewal 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 steel renewal project during 2005. These cost increases were partly 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 5 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 reflect the continued 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 is 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-ups 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-ups 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 jack-ups 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 Due July 1, 2015, or 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 Convertible Debentures due 2020, or Zero Coupon Debentures. This increase in interest cost was partially offset by lower interest expense on our Zero Coupon Debentures as a result of 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.

Certain of our rigs that operate internationally are owned and operated, directly or indirectly, by Diamond Offshore International Limited, a Cayman Island 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 2005 and 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 will begin to expire 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 now expect to be able to utilize $14.5 million of our available foreign tax credit carryforwards prior to their expiration dates, and we believe that a valuation allowance is 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

believe that a valuation allowance is necessary and as a result have 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 on 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 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.

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 provides us the potential opportunity to elect to apply this provision to qualifying earnings repatriations in 2005. Based on the existing language in the AJCA, 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.

Years Ended December 31, 2004 and 2003


	Year Ended
	December 31,						Favorable/
	2004			2003			(Unfavorable)

	(In thousands)
CONTRACT DRILLING REVENUE
High-Specification Floaters	$	281,866		$	290,844		$	(8,978	)
Intermediate Semisubmersibles		319,053			260,267			58,786
Jack-ups		178,391			97,774			80,617
Other		3,095			3,446			(351	)
Eliminations		—			(233	)		233

Total Contract Drilling Revenue	$	782,405		$	652,098		$	130,307


Revenues Related to Reimbursable Expenses	$	32,257		$	28,843		$	3,414

CONTRACT DRILLING EXPENSE
High-Specification Floaters	$	172,182		$	156,898		$	(15,284	)
Intermediate Semisubmersibles		277,728			229,811			(47,917	)
Jack-ups		114,466			97,305			(17,161	)
Other		4,252			4,058			(194	)
Eliminations		—			(233	)		(233	)

Total Contract Drilling Expense	$	568,628		$	487,839		$	(80,789	)


Reimbursable Expenses	$	28,899		$	26,050		$	(2,849	)

OPERATING INCOME (LOSS)
High-Specification Floaters	$	109,684		$	133,946		$	(24,262	)
Intermediate Semisubmersibles		41,325			30,456			10,869
Jack-ups		63,925			469			63,456
Other		(1,157	)		(612	)		(545	)
Reimbursables, net		3,358			2,793			565
Depreciation		(178,835	)		(175,578	)		(3,257	)
General and Administrative Expense		(32,759	)		(28,868	)		(3,891	)
(Loss) Gain on Sale and Disposition of Assets		(1,613	)		(929	)		(684	)

Total Operating Income (Loss)	$	3,928		$	(38,323	)	$	42,251

High-Specification Floaters.


	Year Ended
	December 31,				Favorable/
	2004		2003		(Unfavorable)

	(In thousands)
CONTRACT DRILLING REVENUE
GOM	$	144,077	$	164,303	$	(20,226	)
Australia/Asia		80,666		52,288		28,378
South America		57,123		74,253		(17,130	)

Total Contract Drilling Revenue	$	281,866	$	290,844	$	(8,978	)


CONTRACT DRILLING EXPENSE
GOM	$	81,083	$	84,512	$	3,429
Australia/Asia		40,732		29,691		(11,041	)
South America		50,367		42,695		(7,672	)

Total Contract Drilling Expense	$	172,182	$	156,898	$	(15,284	)



OPERATING INCOME	$	109,684	$	133,946	$	(24,262	)

GOM. Revenues for our high-specification floaters in the GOM decreased $20.2 million, primarily due to lower utilization of our fleet in this market ($7.2 million) and lower average dayrates earned ($13.0 million) in 2004, as compared to 2003. Utilization of this fleet in the GOM fell to 80% in 2004 compared to 84% in 2003, primarily due to rig downtime in 2004 for 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. This decline in utilization was partially offset by increased utilization for the Ocean Valiant, which worked all of 2004 as compared to 2003, when the rig was in a shipyard for approximately three months for a 5-year survey and scheduled maintenance.

The lower overall dayrates achieved for our high-specification floaters in the GOM reflected the soft-market conditions in the GOM during the first half of 2004 as several of these high-specification rigs accepted jobs in the mid-water depth market at lower dayrates. Average dayrates earned by high-specification floaters in the GOM fell to $82,000 in 2004 compared to $89,500 in 2003.

Operating costs for our high-specification floaters in the GOM during 2004 were slightly lower than our operating costs in 2003. Lower operating expenses for the Ocean Valiant were partially offset by additional costs to repair damages sustained by the Ocean America and Ocean Star during Hurricane Ivan in the latter half of 2004. Operating costs for the Ocean Valiant were higher during 2003, as compared to 2004, as a result of a 5-year survey and related repairs in 2003.

Australia/Asia. Revenues for the Ocean Baroness and Ocean Rover increased $28.4 million in 2004 to $80.7 million, as compared to revenues of $52.3 million earned by these rigs in 2003. This increase in revenue is primarily the result of $22.7 million in additional revenue generated by the Ocean Rover in 2004 as it continued its drilling program offshore Malaysia. The Ocean Rover began drilling operations in July 2003 after completion of its upgrade to high-specification capabilities, which began in 2002. An increase in average dayrate and utilization for the Ocean Baroness in 2004, as compared to 2003, resulted in $3.9 million and $1.8 million in additional revenues, respectively.

Contract drilling expense for these rigs increased $11.0 million in the Australia/Asia region in 2004, as compared to 2003, primarily due to additional, normal operating costs for the Ocean Rover offshore Malaysia, which worked all of 2004, compared to 2003 when most of this rig’s costs were capitalized in connection with its upgrade

South America. Revenues from our Brazilian operations decreased $17.1 million in 2004, as compared to 2003, primarily as a result of lower utilization of the Ocean Alliance in 2004 due to a series of sub-sea and electrical

problems, as well as a scheduled 5-year survey and sub-sea equipment upgrade that resulted in approximately five months of downtime for the rig.

Contract drilling expense for our Brazilian operations increased $7.7 million in 2004, as compared to the prior year, primarily due to repair costs for the Ocean Alliance resulting from a series of sub-sea and electrical problems and costs associated with its scheduled 5-year survey in 2004.

Intermediate Semisubmersibles.


	Year Ended
	December 31,				Favorable/
	2004		2003		(Unfavorable)

	(In thousands)
CONTRACT DRILLING REVENUE
GOM	$	42,425	$	49,196	$	(6,771	)
Mexican GOM		85,383		36,873		48,510
Australia/Asia		77,187		48,138		29,049
Europe		69,285		47,964		21,321
South America		44,773		78,096		(33,323	)

Total Contract Drilling Revenue	$	319,053	$	260,267	$	58,786


CONTRACT DRILLING EXPENSE
GOM	$	37,300	$	47,816	$	10,516
Mexican GOM		56,948		29,912		(27,036	)
Australia/Asia		63,969		49,277		(14,692	)
Europe		82,864		63,236		(19,628	)
South America		36,647		39,570		2,923

Total Contract Drilling Expense	$	277,728	$	229,811	$	(47,917	)



OPERATING INCOME	$	41,325	$	30,456	$	10,869

GOM. Revenues generated by our intermediate semisubmersible fleet operating in the GOM decreased $6.8 million in 2004 compared to 2003, primarily due to decreased utilization in this market. Overall utilization for our intermediate semisubmersibles in the GOM (excluding the Ocean Endeavor, which was cold-stacked during 2004) decreased from 54% in 2003 to 50% in 2004, primarily as a result of the relocation of the Ocean Ambassador and the Ocean Worker from the GOM to the Mexican GOM in the latter half of 2003 and a 5-year survey and maintenance projects that kept the Ocean Concord out of service for approximately six months in 2004. The overall decline in utilization in the GOM resulted in a $13.1 million decrease in revenues in 2004, as compared to 2003.

Average operating dayrates for our intermediate semisubmersibles increased in the GOM from $40,800 in 2003 to $44,600 in 2004 and resulted in the generation of $4.6 million in additional revenues in 2004 compared to the prior year. We also recognized $1.8 million in lump-sum mobilization fees for the Ocean Concord in 2004.

Contract drilling expense for these operations in the GOM decreased $10.5 million in 2004, as compared to 2003, primarily due to the relocation of the Ocean Ambassador and the Ocean Worker to the Mexican GOM in the second half of 2003. This decrease was partially offset by additional operating expense related to the reactivation of the Ocean Voyager from cold-stacked status during 2004 and normal operations during the fourth quarter of that year.

Mexican GOM. Revenues generated by our intermediate semisubmersibles in the Mexican GOM increased $48.5 million compared to the revenues earned in this region in 2003. We had four drilling units operating in this market throughout 2004, as compared to 2003 when the Ocean Ambassador, Ocean Whittington and Ocean Worker commenced operations for PEMEX in the Mexican GOM during the third quarter. The Ocean Yorktown was relocated to the Mexican GOM in July 2003 from Brazil and began operating under contract with PEMEX in the mid-fourth quarter of 2003.

In the Mexican GOM, our intermediate semisubmersibles incurred higher operating expenses in 2004 as compared to 2003, when two of these rigs operated in the GOM and another rig was stacked in Africa for the first five months of the year. The increased operating costs in 2004, which resulted from the increased utilization in 2004 compared to the prior year, included additional equipment rental expense in connection with the rigs’ contracts with PEMEX, travel costs and costs associated with maintaining a Mexican shore base. These increased operating expenses were partially offset by lower rig mobilization costs in 2004, as compared to 2003, when we incurred additional costs to relocate these rigs to the Mexican GOM.

Australia/Asia. Our intermediate semisubmersibles working offshore Australia/Asia generated revenues of $77.2 million in 2004 compared to revenues of $48.1 million in 2003. The $29.0 million increase in revenues was primarily due to increased utilization in 2004 compared to 2003. Utilization in this market increased to 91% in 2004 from 70% in 2003. In 2003, utilization in this region was reduced due to the ready-stacking of the Ocean Epoch for the majority of the year and nearly two months of unpaid downtime for the Ocean Bounty due to a scheduled 5-year survey and related repairs. In 2004, we relocated the Ocean Patriot to this region from South Africa, resulting in additional revenues of $11.5 million in this region, including $3.3 million in mobilization revenue.

The $14.7 million increase in contract drilling expense for our intermediate semisubmersibles in the Australia/Asia region in 2004, as compared to 2003, was primarily due to additional costs associated with preparing the Ocean Patriot for operations in New Zealand and Australia, including mobilization of the rig from South Africa. Our operating costs for 2004 also included normal operating expenses for the Ocean Epoch, as compared to reduced costs in 2003 when the rig was ready-stacked for most of the year.

Europe/Africa. Overall utilization of our actively-marketed intermediate semisubmersibles in this region increased from 67% in 2003 to 75% in 2004, reflecting the full utilization of the Ocean Princess and Ocean Guardian in 2004, as compared to 2003 when both rigs were ready-stacked for part of the year, and which was partially offset by reduced utilization due to our relocation of the Ocean Patriot to New Zealand in mid-2004. Excluding the results for the Ocean Vanguard, which operated under a bareboat charter arrangement with its previous owner for the first five months of 2003, the net favorable change in utilization in this region and modest increase in average operating dayrates during 2004, as compared to 2003, resulted in additional revenues of $2.5 million and $3.1 million, respectively.

The Ocean Vanguard generated $13.8 million in additional revenues in 2004, primarily as a result of a higher average operating dayrate earned in 2004 compared to 2003. The average operating dayrate for the Ocean Vanguard increased from $10,000 in 2003 to an average of $77,300 in 2004 as a result of the completion of its bareboat charter arrangement in June 2003.

Contract drilling expense for our intermediate semisubmersible rigs operating offshore Europe increased $19.6 million during 2004, as compared to 2003, primarily due to the inclusion of normal operating costs for the Ocean Vanguard in 2004, as compared to reduced costs incurred in 2003 when the rig operated under a bareboat charter to its previous owner. This increase also included costs associated with preparing the Ocean Vanguard for work in the North Sea. Additionally, contract drilling expenses for our rigs working offshore the U.K. were negatively impacted in 2004 by the cost of additional labor benefits mandated by legislation in the region and the recognition of mobilization costs related to the relocation of the Ocean Nomad from the U.K. to Gabon where the unit operated until the fourth quarter of 2004.

South America. Revenues generated by our intermediate semisubmersible fleet operating offshore Brazil decreased $33.3 million during 2004 compared to 2003, primarily due to the relocation of the Ocean Yorktown to the Mexican GOM in the third quarter of 2003 at a reduced dayrate and the renewal of our operating contract for the Ocean Yatzy in the latter part of 2003 at a significantly lower operating dayrate that reflected market conditions at the time.

Operating costs for our intermediate semisubmersible rigs offshore Brazil decreased $2.9 million in 2004 compared to 2003, primarily due to the relocation of the Ocean Yorktown to the Mexican GOM. The decrease in overall costs for our Brazilian operations was partially offset by higher rig inspection and related repair costs, as well as higher benefits costs for national employees, for our two remaining intermediate semisubmersibles in this region in 2004, as compared to 2003.

Jack-Ups.


	Year Ended
	December 31,				Favorable/
	2004		2003		(Unfavorable)

			(In thousands)
CONTRACT DRILLING REVENUE
GOM	$	138,886	$	84,795	$	54,091
Australia/Asia		21,290		12,979		8,311
South America		18,215		—		18,215

Total Contract Drilling Revenue	$	178,391	$	97,774	$	80,617


CONTRACT DRILLING EXPENSE
GOM	$	89,906	$	84,343	$	(5,563	)
Australia/Asia		15,546		12,962		(2,584	)
South America		9,014		—		(9,014	)

Total Contract Drilling Expense	$	114,466	$	97,305	$	(17,161	)



OPERATING INCOME	$	63,925	$	469	$	63,456

GOM. Excluding the Ocean Champion, which was reactivated from cold-stack status in 2004, utilization of our jack-ups in the GOM rose to 92% in 2004 from 80% in 2003, resulting in $12.9 million in additional revenues in 2004 compared to 2003. The increase in utilization in 2004 was primarily due to the nearly full utilization of the Ocean Tower and Ocean Titan, which were in shipyards undergoing major upgrades for a significant portion of 2003. Other changes in utilization were primarily due to the timing and duration of inspections and related repairs. The reactivated Ocean Champion generated revenues of $4.5 million in 2004.

All of our jack-ups in this region experienced an increase in average dayrate in 2004 primarily due to a tighter market for this class of equipment in the GOM. Average operating revenue per day increased from $26,400 in 2003 to $36,400 in 2004, resulting in $36.7 million in additional revenues in 2004.

Our operating costs for jack-ups in the GOM increased $5.6 million in 2004 compared to the prior year, primarily due to the inclusion of normal operating costs for the Ocean Titan during 2004, compared to 2003 when most of this rig’s costs were capitalized in connection with its cantilever upgrade, reactivation costs for the Ocean Champion and additional, normal operating costs associated with higher utilization of our jack-up fleet in the GOM.

Australia/Asia. Revenue improvements for our jack-ups in the Australia/Asia region are primarily due to the nearly full utilization of the Ocean Sovereign in 2004 compared to 2003, when this unit was out-of-service for a major upgrade for a significant portion of the year ($13.2 million). This increase was partially offset by lower revenues for the Ocean Heritage, which in 2004 operated in this region for only a portion of the fourth quarter. During 2003, the Ocean Heritage operated offshore Indonesia prior to being stacked for the latter half of the year in a Singapore shipyard. We mobilized this drilling unit to Ecuador in early 2004. We recognized $2.4 million in mobilization fees for jack-up rig moves in 2004.

Contract drilling expense for our jack-ups in this region increased in 2004 compared to 2003, primarily due to higher utilization and mobilization costs for the Ocean Sovereign in 2004 compared to 2003, when this rig was out–of-service for a major upgrade and then ready-stacked in Singapore. During 2003, a majority of operating costs for the Ocean Sovereign were capitalized as part of its upgrade.

Reimbursable expenses, net.

Revenues related to reimbursable items, offset by the related expenditures for these items, were $3.4 million in 2004 compared to $2.8 million in 2003. 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 we perform on their behalf at cost, plus a mark-up where applicable. Therefore, net reimbursables fluctuate based on customer requirements, which vary.

Depreciation.

Depreciation expense in 2004 increased $3.2 million to $178.8 million, compared to $175.6 million in 2003, primarily due to additional depreciation expense associated with upgrades to the Ocean Rover and two jack-up rigs completed in 2003 and another jack-up rig completed in early 2004, the Ocean Patriot, which we acquired in March 2003, and capital expenditures in the third quarter 2003 related to contracts for four of our rigs in Mexico.

On April 1, 2003, we adjusted the estimated service lives and salvage values for most of our drilling rigs to better reflect their remaining economic lives and salvage values. We incurred $5.3 million more in depreciation expense for the first quarter of 2003 than that which we would have incurred using the new service lives and salvage values. See “ — Critical Accounting Estimates.”

General and Administrative Expense.

Our general and administrative expense increased $3.9 million in 2004 to $32.8 million, as compared to $28.9 million for 2003. This increase was primarily due to higher payroll costs, our cost of compliance with the Sarbanes-Oxley Act of 2002, higher external audit fees and higher net building expenses due to lower rental income from our tenants.

Loss on Sale and Disposition of Assets.

During 2004, we wrote-off $1.6 million of equipment that was lost during Hurricane Ivan.

During 2003, we recognized net losses on the sale and disposition of assets of $0.9 million, primarily related to the sale of two of our semisubmersible drilling rigs, the Ocean Century and Ocean Prospector. These rigs, which had been cold-stacked since July 1998 and October 1998, respectively, were permanently retired from service as offshore drilling rigs and written down by $1.6 million to their fair market values in September 2003. We sold these rigs for $375,000 each (pre-tax) in December 2003.

Interest Expense.

We incurred interest expense of $30.3 million in 2004 compared to interest expense of $23.9 million in 2003. The $6.4 million increase in interest costs is primarily attributable to our 5.15% Senior Notes, which we issued on August 27, 2004, and was partially offset by lower interest expense in 2003 as a result of interest we capitalized relating to the upgrade of the Ocean Rover, which was completed in July 2003. See Note 1 “Summary of Significant Accounting Policies — Capitalized Interest” and Note 7 “Long-Term Debt” to our Consolidated Financial Statements in Item 8 of this report.

Gain (Loss) on Sale of Marketable Securities.

We recognized net gains on sales of marketable securities of $0.3 million in 2004 compared to a $6.9 million net loss on the sale of marketable securities in 2003. See Note 3 “Investments and Marketable Securities” to our Consolidated Financial Statements in Item 8 of this report.

Settlement of Litigation.

In December 2004, we recognized an $11.4 million gain as a result of the settlement of our lawsuit against an equipment manufacturer. This lawsuit was the result of an incident that occurred in 2002 on the Ocean Baroness.

Other Income and Expense (Other, net).

We reported other income of $1.1 million for the year ended December 31, 2004, which included $1.4 million in foreign currency transaction losses. During the year ended December 31, 2003, we recognized other income of $2.9 million primarily related to pre-tax gains on foreign exchange forward contracts. See Note 4 “Derivative Financial Instruments — Forward Exchange Contracts” to our Consolidated Financial Statements in Item 8 of this report.

Income Tax (Expense) Benefit.

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. We recognized income tax expense of $3.7 million on a pre-tax loss of $3.5 million for the year ended December 31, 2004, compared to a tax benefit of $5.8 million, which we recognized on a pre-tax loss of $54.2 million in 2003.

Certain of our rigs that operate internationally are owned and operated, directly or indirectly, by Diamond Offshore International Limited, a Cayman Island 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. tax benefits on losses during 2004 or 2003.

We recognized tax expense of $3.7 million for 2004 despite a $3.5 million pre-tax loss primarily as a result of $20.5 million of unrepatriated losses in international tax jurisdictions for which we did not recognize any U.S benefits. Our tax expense for 2004 also 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 our merger with Arethusa (Off-Shore) Limited in 1996 and a tax benefit of $4.5 million due to the reversal of a tax liability associated with the Ocean Alliance Lease-Leaseback.

In 2003, we recorded a valuation allowance of $10.2 million for certain of our foreign tax credit carryforwards which will begin to expire in 2011 as a charge against earnings. Under the “more likely than not” approach of evaluating the associated deferred tax asset, at that time we determined that a valuation allowance was necessary. See “— Overview — Critical Accounting Estimates — Income Taxes.” In addition, in 2003 we reduced our deferred tax liability by $3.7 million related to the deductibility of goodwill associated with a 1996 acquisition.

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. At December 31, 2005, we had $842.6 million in “Cash and cash equivalents” and $2.3 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.

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.

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, 2005.


	Payments Due By Period
Contractual Obligations	Total		Less than 1 year		1 – 3 years		4 – 5 years		After 5 years

					(In thousands)
Long-term debt — principal	$	977,654	$	—	$	459,987	$	18,720	$	498,947
Forward exchange contracts		122,493		116,846		5,647		—		—
Purchase obligations related to rig upgrade/modifications		411,000		259,000		152,000		—		—
Operating leases		2,474		1,892		582		—		—


Total obligations	$	1,513,621	$	377,738	$	618,216	$	18,720	$	498,947

As of December 31, 2005, we had purchase obligations aggregating approximately $411 million related to the major upgrade of the Ocean Endeavor and construction of two new jack-up rigs, the Ocean Scepter and Ocean Shield. We had no other purchase obligations for major rig upgrades or any other significant obligations at December 31, 2005, except for those related to our direct rig operations, which arise during the normal course of business.

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.

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, beginning January 1, 2006, 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, beginning March 1, 2005, 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.

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, under certain circumstances we will pay contingent interest to holders of our 1.5% Debentures during any six-month period commencing after April 14, 2008. See “1.5% Debentures” in Note 7 “Long-Term Debt” to our Consolidated Financial Statements in Item 8 of this report. The 1.5% Debentures are unsecured obligations of Diamond Offshore Drilling, Inc.

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.

We may 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.

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, 2005, the aggregate accreted value of our outstanding Zero Coupon Debentures was $18.7 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. 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.

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. The aggregate principal amount at maturity of those Zero Coupon Debentures will be $30.9 million assuming no additional conversions or redemptions occur prior to the maturity date.

Letters of Credit.

We are contingently liable as of December 31, 2005 in the amount of $47.9 million under certain performance, bid, supersedeas and custom bonds and letters of credit. Agreements relating to approximately $34.0 million of multi-year performance bonds can require cash collateral for the full line at any time for any reason. Issuers of a $0.5 million letter of credit have the option to require cash collateral due to the lowering of our credit rating in April 2004. As of December 31, 2005 we had not been required to make any cash collateral deposits with respect to these agreements. The remaining agreements cannot require cash collateral except in events of default. On our behalf, banks have issued letters of credit securing certain of these bonds.

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 could result in higher interest rates on future debt issuances.

Capital Expenditures.

In May 2005, we began a major upgrade of the Ocean Endeavor for ultra-deepwater service. The modernized rig will be capable of operating in up to 10,000 feet of water at an estimated upgrade cost of approximately $250 million. We spent approximately $54.5 million on this project in 2005 and expect to spend approximately $145 million in 2006. We expect delivery of the upgraded rig in mid-2007.

Additionally, 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 under construction in Brownsville, Texas and in Singapore, respectively, at an aggregate expected cost of approximately $300 million. We spent $85.9 million in 2005 related to the new construction and expect to spend approximately $114 million in 2006 on these two construction projects. We expect delivery of both units in the first quarter of 2008.

In January 2006, we announced that we will upgrade the currently cold-stacked Ocean Monarch for ultra-deepwater service at an aggregate estimated cost of approximately $300 million. We expect to mobilize the rig to a shipyard in Singapore for the upgrade in mid-2006 and expect to spend approximately $60 million on this project in 2006. We purchased the Ocean Monarch and its related equipment in August 2005 for $20.0 million.

We have budgeted approximately $215 million in additional capital expenditures in 2006 associated with our ongoing rig equipment replacement and enhancement programs, and other corporate requirements. We expect to finance our 2006 capital expenditures through the use of our existing cash balances or internally generated funds.

During 2005, we spent approximately $133.4 million on our continuing rig capital maintenance program (other than rig upgrades and new construction) and to meet other corporate capital expenditure requirements in 2005.

Off-Balance Sheet Arrangements.

At December 31, 2005 and 2004, 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, 2005 compared to 2004.

Net Cash Provided by Operating Activities.


	Year Ended December 31,
	2005			2004			Change

				(In thousands)
Net income (loss)	$	260,337		$	(7,243	)	$	267,580
Net changes in operating assets and liabilities		(81,039	)		22,385			(103,424	)
Loss (gain) on sale of marketable securities		1,180			(254	)		1,434
Depreciation and other non-cash items, net		208,093			193,394			14,699

	$	388,571		$	208,282		$	180,289

Our cash flows from operations in 2005 increased $180.3 million or 87% over cash generated by our operating activities in 2004. The increase in cash flow from operations in 2005 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. These favorable trends were negatively impacted by an increase in cash required to satisfy our working capital requirements, including a temporary increase in our trade accounts receivable, which will generate cash as the billing cycle is completed.

Net Cash Used in Investing Activities.


	Year Ended December 31,
	2005			2004			Change

				(In thousands)
Purchase of marketable securities	$	(4,956,560	)	$	(4,606,400	)	$	(350,160	)
Proceeds from sale of marketable securities		5,610,907			4,466,377			1,144,530
Capital expenditures		(293,829	)		(89,229	)		(204,600	)
Insurance proceeds from casualty loss of Ocean Warwick		50,500			—			50,500
Proceeds from sale/involuntary conversion of assets		26,047			6,900			19,147
Purchases of Australian dollar time deposits		—			(45,456	)		45,456
Proceeds from maturities of Australian dollar time deposits		11,761			34,120			(22,359	)
Proceeds from settlement of forward contracts		1,136			—			1,136

	$	449,962		$	(233,688	)	$	683,650

Our investing activities generated $450.0 million in 2005, as compared to a usage of $233.7 million in 2004. In 2005, we sold marketable securities, net of purchases, of $654.3 million compared to net purchases of $140.3 million during 2004. This increase in net sales activity is primarily the result of increased cash requirements in 2005 to partially fund our repurchase of $460.0 million accreted value of Zero Coupon Debentures in June 2005 and capital additions.

During 2005, we spent approximately $140.4 million related to the major upgrade of the Ocean Endeavor and construction of two new jack-up drilling rigs, the Ocean Scepter and Ocean Shield, in addition to $133.4 million related to our ongoing capital maintenance program and our purchase of the Ocean Monarch for $20.0 million. During 2004, our primary focus was on our ongoing capital maintenance program. 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.

In the second quarter of 2004, based on our expectation that higher interest rates could be achieved by investing in Australian dollar-based securities, we invested $42.1 million (equivalent to 60.0 million Australian dollars) in Australian dollar time deposits with expirations ranging from May 2004 to March 2005. During 2005 and 2004, $11.8 million and $34.1 million matured, respectively. Also during 2005, we entered into various foreign currency forward exchange contracts, which resulted in net realized gains totaling $1.1 million.

Net Cash Used in Financing Activities.


	Year Ended December 31,
	2005			2004			Change

				(In thousands)
Proceeds from issuance of senior notes	$	249,462		$	249,397		$	65
Payment of debt issuance costs		(1,866	)		(1,751	)		(115	)
Redemption of Zero Coupon Debentures		(460,015	)		—			(460,015	)
Payment of dividends		(48,260	)		(32,281	)		(15,979	)
Acquisition of treasury stock		—			(18,077	)		18,077
Ocean Alliance lease-leaseback agreement		(12,818	)		(11,969	)		(849	)
Proceeds from stock options exercised		11,547			168			11,379

	$	(261,950	)	$	185,487		$	(447,437	)

In June 2005 and August 2004, we issued $250.0 million principal amount of our 4.875% Senior Notes and our 5.15% Senior Notes, respectively, for net cash proceeds of $247.6 million for each issuance. We repurchased $460.0 million accreted value, or approximately 96%, of our then outstanding Zero Coupon Debentures for cash in June 2005.

During 2005, we received $11.5 million in proceeds from the exercise of stock options to purchase shares of our common stock. During 2004, we received $0.2 million in proceeds from the exercise of stock options.

We paid cash dividends to our stockholders of $48.3 million in 2005 compared to $32.3 million in 2004. On January 24, 2006, we declared a quarterly cash dividend and a special cash dividend of $0.125 and $1.50, respectively, per share of our common stock. Both the quarterly and special cash dividends are payable on March 1, 2006 to stockholders of record on February 3, 2006.

Depending on market conditions, we may, from time to time, purchase shares of our common stock in the open market or otherwise. 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 $23.11 average cost per share). We did not repurchase any shares of our outstanding common stock during the year ended December 31, 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, Indonesia 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 December 2004 the Financial Accounting Standards Board revised SFAS No. 123, “Accounting for Stock-Based Compensation,” or SFAS 123 (R). This statement supersedes Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees,” and its related implementation guidance. This statement requires that the compensation cost relating to share-based payment transactions be recognized in financial statements. That cost will be measured based on the fair value of the equity or liability instruments issued. SFAS 123 (R) is effective as of the first interim or annual reporting period beginning after June 15, 2005. This statement applies to all awards granted after the required effective date and to awards modified, repurchased, or cancelled after that date. We do not expect the adoption of SFAS 123 (R) to have a material impact on our consolidated results of operations, financial position or cash flows.

Forward-Looking Statements

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

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

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

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

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

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

	•		business strategy;

	•		growth opportunities;

	•		competitive position;

	•		expected financial position;

	•		future cash flows;

	•		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, 2005 and 2004 — Income Tax Expense” and “— Years Ended December 31, 2004 and 2003 — Income Tax (Expense) Benefit”);

	•		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”).

Such statements inherently are subject to a variety of risks and uncertainties that could cause actual results to differ materially from those expected, projected or expressed in forward-looking statements. Such 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

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, 2005 and December 31, 2004, 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, 2005 and December 31, 2004, 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, 2005 and December 31, 2004, 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 $173.8 million and $177.8 million as of December 31, 2005 and 2004, respectively. A 100-basis point decrease would result in an increase in market value of $40.0 million and $217.3 million as of December 31, 2005 and 2004, 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 2004 we invested in fixed-rate Australian dollar time deposits and 15.0 million Australian dollars (equivalent to $11.6 million) of time deposits were included in “Investments and marketable securities” in our Consolidated Balance Sheets at December 31, 2004. These time deposits matured during the first quarter of 2005.

During 2005 we entered into various forward exchange contracts requiring us to purchase predetermined amounts of foreign currencies at predetermined dates. As of December 31, 2005, we had foreign currency forward exchange contracts outstanding requiring 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 Reals at various times through March 2007. These forward exchange contracts were included in “Other assets” in our Consolidated Balance Sheets at December 31, 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, 2005 and 2004.

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,
	2005			2004			2005			2004
				(In thousands)
Interest rate:
Marketable securities	$	2,281	(a)	$	650,247	(a)	$	200	(c)	$	2,100	(c)
Long-term debt		(1,159,941	) (b)		(1,213,820	) (b)		—			—

Foreign Exchange:

Australian dollar time deposits		—			11,602	(d)		—			2,300	(d)
Forward exchange contracts		400	(d)		—			21,500	(d)		—


(a)		The fair market value of our investment in marketable securities is based on the quoted closing market prices on December 31, 2005 and 2004.

(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, 2005 and 2004. The fair value of our Ocean Alliance lease-leaseback agreement is based on the present value of estimated future cash flows using a discount rate of 4.27% for December 31, 2004.

(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, 2005 and 2004.

(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, 2005 and a decrease in foreign exchange rates of 20% at December 31, 2004.

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, 2005 and 2004, 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, 2005. 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, 2005 and 2004, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2005, 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, 2005, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 24, 2006 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 24, 2006

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, 2005, 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, 2005, 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, 2005, 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, 2005 of the Company and our report dated February 24, 2006 expressed an unqualified opinion on those financial statements.

Deloitte & Touche LLP

Houston, Texas
February 24, 2006

DIAMOND OFFSHORE DRILLING, INC.
AND SUBSIDIARIES

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


	December 31,
	2005			2004
ASSETS
Current assets:
Cash and cash equivalents	$	842,590		$	266,007
Investments and marketable securities		2,281			661,849
Accounts receivable		357,104			187,558
Rig inventory and supplies		47,196			47,590
Prepaid expenses and other		32,707			32,677

Total current assets		1,281,878			1,195,681
Drilling and other property and equipment, net of accumulated depreciation		2,302,020			2,154,593
Other assets		23,024			29,112

Total assets	$	3,606,922		$	3,379,386


LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Current portion of long-term debt	$	—		$	484,102
Accounts payable		60,976			27,530
Accrued liabilities		169,037			87,614
Taxes payable		38,973			14,661

Total current liabilities		268,986			613,907
Long-term debt		977,654			709,413
Deferred tax liability		445,094			369,722
Other liabilities		61,861			60,516

Total liabilities		1,753,595			1,753,558


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; 133,842,429 shares issued and 128,925,629 shares outstanding at December 31, 2005; 133,483,820 shares issued and 128,567,020 shares outstanding at December 31, 2004)		1,338			1,335
Additional paid-in capital		1,277,934			1,264,512
Retained earnings		688,459			476,382
Accumulated other comprehensive losses		9			(1,988	)
Treasury stock, at cost (4,916,800 shares at December 31, 2005 and 2004)		(114,413	)		(114,413	)

Total stockholders’ equity		1,853,327			1,625,828

Total liabilities and stockholders’ equity	$	3,606,922		$	3,379,386

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,
	2005			2004			2003
Revenues:
Contract drilling	$	1,179,015		$	782,405		$	652,098
Revenues related to reimbursable expenses		41,987			32,257			28,843

Total revenues		1,221,002			814,662			680,941


Operating expenses:
Contract drilling		638,540			568,628			487,839
Reimbursable expenses		35,549			28,899			26,050
Depreciation and amortization		183,724			178,835			175,578
General and administrative		37,162			32,759			28,868
Impairment of rigs		—			—			1,598
Casualty gain on Ocean Warwick		(33,605	)		—			—
(Gain) loss on disposition of assets		(14,767	)		1,613			(669	)

Total operating expenses		846,603			810,734			719,264


Operating income (loss)		374,399			3,928			(38,323	)

Other income (expense):
Interest income		26,028			12,205			12,007
Interest expense		(41,799	)		(30,257	)		(23,928	)
Gain (loss) on sale of marketable securities		(1,180	)		254			(6,884	)
Settlement of litigation		—			11,391			—
Other, net		(1,053	)		(1,054	)		2,891

Income (loss) before income tax expense		356,395			(3,533	)		(54,237	)

Income tax (expense) benefit		(96,058	)		(3,710	)		5,823


Net income (loss)	$	260,337		$	(7,243	)	$	(48,414	)


Earnings (loss) per share:
Basic	$	2.02		$	(0.06	)	$	(0.37	)

Diluted	$	1.91		$	(0.06	)	$	(0.37	)


Weighted-average shares outstanding:
Shares of common stock		128,690			129,021			130,253
Dilutive potential shares of common stock		12,661			—			—

Total weighted-average shares outstanding assuming dilution		141,351			129,021			130,253

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, 2003		133,457,055	$	1,335	$	1,263,692	$	621,342		$	(730	)		3,120,600	$	(78,125	)	$	1,807,514
Net loss		—		—		—		(48,414	)		—			—		—			(48,414	)
Treasury stock purchase		—		—		—		—			—			1,014,000		(18,211	)		(18,211	)
Dividends to stockholders ($0.438 per share)		—		—		—		(57,022	)		—			—		—			(57,022	)
Exchange rate changes, net		—		—		—		—			(288	)		—		—			(288	)
Loss on investments, net		—		—		—		—			(3,099	)		—		—			(3,099	)

December 31, 2003		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

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


		Page No.
Cover Page			1

Document Table of Contents			2

Part I
Item 1.	Business		3

Item 1A.	Risk Factors		9

Item 1B.	Unresolved Staff Comments		14

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		17

Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		18

Item 7A.	Quantitative and Qualitative Disclosures About Market Risk		47

Item 8.	Financial Statements and Supplementary Data		49

	Consolidated Financial Statements		51
	Notes to Consolidated Financial Statements		56

Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		83

Item 9A.	Controls and Procedures		83

Item 9B.	Other Information		84

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		84
Signatures			87

Exhibit Index			88
Statement re Computation of Ratios
List of Subsidiaries
Consent of Deloitte & Touche LLP
Powers of Attorney
Rule 13a-14a Certification of CEO
Rule 13a-14a Certification of CFO
Section 1350 Certification of CEO and CFO


	Year Ended December 31,
	2005			2004			2003
Net income (loss)	$	260,337		$	(7,243	)	$	(48,414	)

Other comprehensive gains (losses), net of tax:
Foreign currency translation gain (loss)		2,077			1,649			(288	)
Unrealized holding gain (loss) on investments		10			532			(311	)
Reclassification adjustment for loss included in net income		(90	)		(52	)		(2,788	)

Total other comprehensive gain (loss)		1,997			2,129			(3,387	)

Comprehensive income (loss)	$	262,334		$	(5,114	)	$	(51,801	)