DIAMOND OFFSHORE DRILLING INC - 10-K Annual Report

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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-K

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

FOR THE FISCAL YEAR ENDED DECEMBER 31, 2002

OR

[ ] 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 (I.R.S. Employer
of incorporation or organization) 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:

SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT: None

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 [X] No [ ]

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. [X]

Indicate by check mark whether the registrant is an accelerated filer (as
defined in Exchange Act Rule 12b-2). Yes [X] No [ ]

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, 2002 $3,749,264,918

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 28, 2003 Common Stock, $0.01 par value per share 130,336,455
shares

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the definitive proxy statement relating to the 2003 Annual
Meeting of Stockholders of Diamond Offshore Drilling, Inc., which will be filed
within 120 days of December 31, 2002, are incorporated by reference in Part III
of this form.

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DIAMOND OFFSHORE DRILLING, INC.
FORM 10-K FOR THE YEAR ENDED DECEMBER 31, 2002

TABLE OF CONTENTS

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PART I

ITEM 1. BUSINESS.

GENERAL

Diamond Offshore Drilling, Inc., incorporated in Delaware in 1989, engages
principally in the contract drilling of offshore oil and gas wells. Unless the
context otherwise requires, references herein to the "Company" mean Diamond
Offshore Drilling, Inc. and its consolidated subsidiaries. The Company is a
leader in deep water drilling with a fleet of 46 offshore rigs and has signed a
memorandum of agreement to purchase an additional offshore rig. The fleet
currently consists of 31 semisubmersibles, 14 jack-ups and one drillship.

THE FLEET

The Company's large, diverse fleet, which includes some of the most
technologically advanced rigs in the world, enables it to offer a broad range of
services worldwide in various markets, including the deep water market, the
harsh environment market, the conventional semisubmersible market and the
jack-up market.

Semisubmersibles. The Company owns and operates 31 semisubmersibles.
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. Three semisubmersible rigs in the Company's fleet
have this capability.

The Company owns and operates eight high specification semisubmersibles.
These semisubmersibles are larger than many other semisubmersibles, are capable
of working in water depths of 3,500 feet or greater or in harsh environments and
have other advanced features. As of February 3, 2003, six of the eight high
specification semisubmersibles were located in the Gulf of Mexico, the Ocean
Alliance was working offshore Brazil and the Ocean Baroness was offshore
Singapore undergoing modifications as part of a 400 day contract offshore
Indonesia. The Ocean Rover was in a shipyard in Singapore undergoing an upgrade
to high specification capabilities. Completion of this upgrade, expected in the
third quarter of 2003, will increase the number of high specification rigs to
nine. See "--Fleet Enhancements."

The Company owns and operates 22 other semisubmersibles which operate in
maximum water depths up to 3,500 feet. The diverse capabilities of many of these
semisubmersibles enable them to provide both shallow and deep water service in
the U.S. and in other markets outside the U.S. As of February 3, 2003, ten of
these semisubmersibles were located in the Gulf of Mexico; four were located in
the North Sea; three were located offshore Brazil; two were located offshore
Africa; and one each was located offshore Vietnam, Australia, and New Zealand.

Six of the Company's 22 other semisubmersible rigs have been cold stacked.
When the Company anticipates that a rig will be idle for an extended period of
time, it cold stacks the rig by ceasing to actively market the rig and
eliminates all expenditures associated with keeping the rig ready to go to work.

Jack-ups. The Company owns 14 jack-ups. 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. The Company's jack-ups are used extensively 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

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drilling operations, the hull is lowered until it rests in the water and then
the legs are retracted for relocation to another drillsite.

As of February 3, 2003, twelve of the Company's jack-up rigs were located
in the Gulf of Mexico. Of these jack-up rigs in the Gulf of Mexico, seven are
independent-leg cantilevered rigs, two are mat-supported cantilevered rigs, two
are independent-leg slot rigs and one is a mat-supported slot rig. One of the
independent-leg slot rigs was in a shipyard in Brownsville, Texas for
installation of a cantilever package which is expected to be completed in April
2003. Both of the Company's internationally based jack-ups are independent-leg
cantilevered rigs; one was located offshore Indonesia while the other one was in
a Singapore shipyard undergoing an upgrade. One jack-up has been cold stacked.

Drillship. 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. Deep water drillships compete in many of the same markets as do high
specification semisubmersible rigs. The Company has one drillship, the Ocean
Clipper, which is located offshore Brazil.

Fleet Enhancements. The Company's strategy is to maximize utilization and
dayrates by economically upgrading its fleet to meet customer demand for
advanced, efficient, high-tech rigs, particularly deepwater semisubmersibles.
Since 1995, the Company has increased the number of semisubmersibles capable of
operating in 3,500 feet of water or greater, from three to ten (eight of which
are high specification units), primarily by upgrading its existing fleet. Four
of these upgrades were to its Victory-class semisubmersible rigs; most recently
the Ocean Baroness which was completed in early 2002 at an approximate cost of
$169 million. The design of the Company's Victory-class semisubmersible rigs
with its cruciform hull configurations, long fatigue-life and advantageous
stress characteristics, makes this class of rig particularly well-suited for
significant upgrade projects.

The upgrade of the Ocean Rover, the fifth in a series of Victory-class
upgrades, began in January 2002. Once complete, the Ocean Rover will be the
Company's ninth high specification semisubmersible unit. The converted rig will
be able to operate in 7,000-foot water depths on a stand alone basis. Water
depths in excess of 7,000 feet should be achievable utilizing augmented mooring
systems on a case by case basis. The upgrade is estimated to cost approximately
$200 million with approximately $119.1 million spent project-to-date through
December 31, 2002. The upgrade is expected to take 19 months to complete with
delivery estimated in the third quarter of 2003. See "Management's Discussion
and Analysis of Financial Condition and Results of Operations -- Capital
Resources" in Item 7 of this report.

In 2002 the Company began a two year program to expand the capabilities of
its jack-up fleet by significantly upgrading six of its 14 jack-up rigs at a
total estimated cost of $100 million. The Ocean Titan and Ocean Tower, both
350-foot water depth capability independent-leg slot rigs, are to have
cantilever packages installed. The cantilever systems enable a 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. The Ocean Tower is in the latter stages of its upgrade with delivery
expected in April 2003. The upgrade planned for the Ocean Titan is expected to
commence in early 2003. The Ocean Spartan, Ocean Spur, and Ocean Heritage, each
had leg extensions installed (all completed during the fourth quarter of 2002)
enabling these rigs to work in water depths up to 300 feet, up from 250 feet
prior to the upgrades, at a combined approximate cost of $35.7 million. The
Ocean Sovereign, a 250-foot water depth independent-leg cantilever rig, is in a
shipyard undergoing leg extension installations to allow the rig to work in
water depths up to 300 feet.

Fleet Additions. Another of the Company's business strategies is to
acquire assets at depressed levels during cyclical downturns. In late 2002 the
Company purchased the Ocean Vanguard for $68.5 million. The semisubmersible rig
is a third-generation Bingo 3000 design rig that, in accordance with the sales
agreement, has been bare-boat chartered to its previous owner. The Company
anticipates the bare-boat charter will continue until mid-2003.

The Company has signed a memorandum of agreement to purchase the
semisubmersible drilling rig Omega for $65 million. The agreement is subject to
certain conditions and is expected to be completed in the

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first quarter of 2003. Subsequent to its purchase, the Company anticipates that
the rig initially will be working offshore South Africa.

The Company continues to evaluate further rig acquisition and upgrade
opportunities. However, there can be no assurance whether or to what extent rig
acquisitions or upgrades will continue to be made to the Company's fleet. See
"Management's Discussion and Analysis of Financial Condition and Results of
Operations -- Capital Resources" in Item 7 of this report.

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More detailed information concerning the Company's fleet of mobile offshore
drilling rigs, as of February 3, 2003, is set forth in the table below.

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(a) Such enhancements include the installation of top-drive drilling systems,
water depth upgrades, mud pump additions and increases in deckload
capacity.

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

(c) In Singapore shipyard for upgrade to high specification capabilities.

(d) Acquired rig in December 2002; bare-boat chartered rig back to seller for
completion of ongoing work in Norway.

(e) Scheduled to begin upgrade to install cantilever package in early 2003.

(f) In shipyard undergoing upgrade to install cantilever package; scheduled to
be completed in April 2003.

(g) In shipyard undergoing leg extension installations to work in water depths
up to 300'; scheduled to be completed in May 2003.

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MARKETS

The Company's principal markets for its offshore contract drilling services
are the Gulf of Mexico, Europe, including principally the U.K. and Norwegian
sectors of the North Sea, South America, Africa and Australia/Southeast Asia.
The Company actively markets its rigs worldwide. In the past, rigs in the
Company's fleet have also operated in various other markets throughout the
world. See Note 16 to the Company's Consolidated Financial Statements in Item 8
of Part II of this report.

The Company believes its presence in multiple markets is valuable in many
respects. For example, the Company believes that its 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 gained through Brazilian and North
Sea operations has potential application worldwide. Additionally, the Company
believes its performance for a customer in one market segment or area enables it
to better understand that customer's needs and better serve that customer in
different market segments or other geographic locations.

OFFSHORE CONTRACT DRILLING SERVICES

The Company's contracts to provide offshore drilling services vary in their
terms and provisions. The Company often obtains its contracts through
competitive bidding, although it is not unusual for the Company to be awarded
drilling contracts without competitive bidding. Drilling contracts generally
provide for a basic drilling rate on a fixed dayrate basis regardless of whether
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 the control of the Company. Under
dayrate contracts, the Company generally pays the operating expenses of the rig,
including wages and the cost of incidental supplies. Dayrate contracts have
historically accounted for a substantial portion of the Company's revenues. In
addition, the Company has worked some of its rigs under dayrate contracts
pursuant to which the customer also agrees to pay an incentive bonus 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 (a
"well-to-well contract") or a stated term (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. In addition, certain of the Company's 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 be extended by the customer
exercising options for the drilling of additional wells at fixed or mutually
agreed terms, including dayrates.

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 contractors 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, the Company seeks
to have a foundation of long-term contracts with a reasonable balance of
single-well, well-to-well and short-term contracts to minimize the downside
impact of a decline in the market while still participating in the benefit of
increasing dayrates in a rising market, although no assurance can be given that
the Company will be able to achieve or maintain such a balance from time to
time.

The Company, through its wholly owned subsidiary, Diamond Offshore Team
Solutions, Inc. ("DOTS"), offers a portfolio of drilling services to complement
the Company's offshore contract drilling business. These services include
overall project management, extended well tests, and drilling and completion
operations. From time to time, DOTS also selectively engages in drilling
services utilizing one of the Company's rigs pursuant to turnkey or
modified-turnkey contracts under which DOTS agrees to drill a well to

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a specified depth for a fixed price. In such cases, DOTS generally is not
entitled to payment unless the well is drilled to the specified depth and
profitability of the contract depends upon its ability to keep expenses within
the estimates used by DOTS in determining the contract price. Drilling a well
under a turnkey contract, therefore, typically requires a greater cash
commitment by the Company and exposes the Company to risks of potential
financial losses that generally are substantially greater than those that would
ordinarily exist when drilling under a conventional dayrate contract. During
2002, DOTS completed three turnkey projects in the Gulf of Mexico which resulted
in an operating loss of $0.6 million. During 2001, DOTS contributed operating
income of $0.6 million to the Company's consolidated results of operations
primarily from the completion of one international turnkey project, which began
in the last quarter of 2000, and three turnkey permanent plug and abandonment
projects in the Gulf of Mexico.

CUSTOMERS

The Company provides 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 the Company's
annual consolidated revenues, although the specific customers may vary from year
to year. During 2002, the Company performed services for 46 different customers
with Petrobraspetroleo Brasileiro S A ("Petrobras"), BP, and Murphy Exploration
and Production Company accounting for 19.0%, 18.9% and 10.4% of the Company's
annual total consolidated revenues, respectively. During 2001, the Company
performed services for 44 different customers with BP and Petrobras accounting
for 21.8% and 17.3% of the Company's annual total consolidated revenues,
respectively. During 2000, the Company performed services for 48 different
customers with Petrobras and BP accounting for 24.6% and 20.3% of the Company's
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 the Company's results of operations.

The Company's services in North America are marketed principally through
its Houston, Texas office, with support for U.S. Gulf of Mexico activities
coming from its regional office in New Orleans, Louisiana. The Company's
services in other geographic locations are marketed principally from its
regional offices in Aberdeen, Scotland, Perth, Western Australia and The Hague,
Netherlands. Technical and administrative support functions for the Company's
operations are provided by its Houston office.

COMPETITION

The offshore contract drilling industry is highly competitive and is
influenced by a number of factors, including the current and anticipated prices
of oil and natural gas, the expenditures by oil and gas companies for
exploration and development of oil and natural gas and the availability of
drilling rigs. In addition, demand for drilling services remains dependent on a
variety of political and economic factors beyond the Company's control,
including worldwide demand for oil and natural gas, the ability of the
Organization of Petroleum Exporting Countries ("OPEC") to set and maintain
production levels and pricing, the level of production of non-OPEC countries and
the policies of the various governments regarding exploration and development of
their oil and natural gas reserves.

Customers often award contracts on a competitive bid basis, and although a
customer selecting a rig may consider, among other things, a contractor's safety
record, crew quality, rig location and quality of service and equipment, the
historical oversupply of rigs has created an intensely competitive market in
which price is the primary factor in determining the selection of a drilling
contractor. In periods of increased drilling activity, rig availability has, in
some cases, also become a consideration, particularly with respect to
technologically advanced units. The Company believes competition for drilling
contracts will continue to be intense in the foreseeable future. Contractors are
also 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. Such movements, reactivations or a decrease in
drilling activity in any major market could depress dayrates and could adversely
affect utilization of the Company's rigs. See "-- Offshore Contract Drilling
Services."

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GOVERNMENTAL REGULATION

The Company's operations are subject to numerous federal, state and local
laws and regulations that relate directly or indirectly to its operations,
including certain regulations controlling the discharge of materials into the
environment, requiring removal and clean-up under certain circumstances, or
otherwise relating to the protection of the environment. For example, the
Company may be liable for damages and costs incurred in connection with oil
spills for which it is held responsible. Laws and regulations protecting the
environment have become increasingly stringent in recent years and may, in
certain circumstances, impose "strict liability" rendering a company liable for
environmental damage without regard to negligence or fault on the part of such
company. Liability under such laws and regulations may result from either
governmental or citizen prosecution. Such laws and regulations may expose the
Company to liability for the conduct of or conditions caused by others, or for
acts of the Company that were in compliance with all applicable laws at the time
such acts were performed. The application of these requirements or the adoption
of new requirements could have a material adverse effect on the Company.

The United States Oil Pollution Act of 1990 ("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 the Company 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.

INDEMNIFICATION AND INSURANCE

The Company's operations are subject to hazards inherent in the drilling of
oil and gas wells such as blowouts, reservoir damage, loss of production, loss
of well control, cratering or fires, the occurrence of which could result in the
suspension of drilling operations, injury to or death of rig and other personnel
and damage to or destruction of the Company's, the Company's customer's or a
third party's property or equipment. Damage to the environment could also result
from the Company's operations, particularly through oil spillage or uncontrolled
fires. In addition, offshore drilling operations are subject to perils peculiar
to marine operations, including capsizing, grounding, collision and loss or
damage from severe weather. The Company has insurance coverage and contractual
indemnification for certain risks, but there can be no assurance that such
coverage or indemnification will adequately cover the Company's loss or
liability in many circumstances or that the Company will continue to carry such
insurance or receive such indemnification.

In December 2002 the Company renewed its Hull and Machinery insurance
policy. The Company's retention of liability for property damage increased at
the time of renewal from approximately $0.2 million per incident to between $1.0
million and $2.5 million per incident, depending on the value of the equipment,
with an aggregate annual deductible of $5.0 million. In addition, the Company
retained 10% of its insured liability.

OPERATIONS OUTSIDE THE UNITED STATES

Operations outside the United States accounted for approximately 55.5%,
37.3% and 45.4% of the Company's total consolidated revenues for the years ended
December 31, 2002, 2001 and 2000, respectively. The Company's non-U.S.
operations are subject to certain political, economic and other uncertainties
not encountered in U.S. operations, including risks of war and civil
disturbances (or other risks that may limit or disrupt markets), expropriation
and the general hazards associated with the assertion of national sovereignty
over certain areas in which operations are conducted. 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 Company's operations
outside the United States may also face the additional risk of fluctuating
currency values, hard currency shortages, controls of currency exchange and
repatriation of income or capital. See "Management's Discussion and Analysis of
Financial Condition and Results of Operations -- Industry Conditions" and
"-- Other -- Currency Risk" in Item 7 of this report and Note 16 to the
Company's Consolidated Financial Statements in Item 8 of Part II of this report.

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EMPLOYEES

As of December 31, 2002, the Company had approximately 3,766 workers,
including international crew personnel furnished through independent labor
contractors. The Company has experienced satisfactory labor relations and
provides comprehensive benefit plans for its employees. The Company does not
currently consider the possibility of a shortage of qualified personnel to be a
material factor in its business.

ACCESS TO COMPANY FILINGS

Access to the Company's filings of its annual reports on Form 10-K,
quarterly reports on Form 10-Q and current reports on Form 8-K, and amendments
to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the
Securities Exchange Act of 1934, as amended (the "Exchange Act"), with the
United States Securities and Exchange Commission ("SEC") may be obtained through
the Company's website (http://www.diamondoffshore.com). The Company's 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 the
Company has electronically filed such material with the SEC. The contents of the
Company's website are not, and shall not be deemed to be, incorporated into this
report.

ITEM 2. PROPERTIES.

The Company owns 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 the Company has its corporate headquarters, a 18,000
square foot building and 20 acres of land in New Iberia, Louisiana, for its
offshore drilling warehouse and storage facility, and a 13,000-square foot
building and five acres of land in Aberdeen, Scotland, for its North Sea
operations. Additionally, the Company currently leases various office, warehouse
and storage facilities in Louisiana, Australia, Brazil, Indonesia, Scotland,
Vietnam, Singapore, Netherlands and Norway to support its offshore drilling
operations.

ITEM 3. LEGAL PROCEEDINGS.

Not applicable.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.

Not applicable.

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EXECUTIVE OFFICERS OF THE REGISTRANT

In reliance on General Instruction G (3) to Form 10-K, information on
executive officers of the Registrant is included in this Part I. The executive
officers of the Company are elected annually by the Board of Directors to serve
until the next annual meeting of the 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 the executive officers of the Company is set forth below.

James S. Tisch has served as Chief Executive Officer of the Company since
March 1998. Mr. Tisch has served as Chairman of the Board since 1995 and as a
director of the Company since June 1989. Mr. Tisch has served as Chief Executive
Officer of Loews Corporation ("Loews"), a diversified holding company and the
Company's controlling stockholder, since November 1998 and, prior thereto, as
President and Chief Operating Officer of Loews from 1994. Mr. Tisch, a director
of Loews since 1986, also serves as a director of CNA Financial Corporation, a
90% owned subsidiary of Loews, BKF Capital Group, Inc. and Vail Resorts, Inc.

Lawrence R. Dickerson has served as President, Chief Operating Officer and
Director of the Company since March 1998. Previously, Mr. Dickerson served as
Senior Vice President of the Company from April 1993. Mr. Dickerson has also
served on the United States Commission on Ocean Policy since 2001.

David W. Williams has served as Executive Vice President of the Company
since March 1998. Previously, Mr. Williams served as Senior Vice President of
the Company from December 1994.

Rodney W. Eads has served as Senior Vice President of the Company since May
1997.

John L. Gabriel, Jr. has served as Senior Vice President of the Company
since November 1999. Previously, Mr. Gabriel served as a Marketing Vice
President of the Company from April 1993.

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

Gary T. Krenek has served as Vice President and Chief Financial Officer of
the Company since March 1998. Previously, Mr. Krenek served as Controller of the
Company from February 1992.

Beth G. Gordon has served as Controller of the Company since April 2000.
Previously, Ms. Gordon was employed by Pool Energy Services Co. from December
1978 through March 2000 where her most recent position was Vice
President-Finance -- Pool Well Services Co.

William C. Long has served as Vice President, General Counsel and Secretary
of the Company since March 2001. Previously, Mr. Long served as General Counsel
and Secretary of the Company from March 1999, acting General Counsel and
Secretary of the Company from June 1998 through February 1999 and as a staff
attorney from January 1997 through May 1998.

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PART II

ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
MATTERS.

PRICE RANGE OF COMMON STOCK

The Company's common stock is listed on the New York Stock Exchange
("NYSE") under the symbol "DO." The following table sets forth, for the calendar
quarters indicated, the high and low closing prices of common stock as reported
by the NYSE.

On February 28, 2003 the closing price of the Company's common stock, as
reported by the NYSE, was $21.95 per share. As of February 28, 2003 there were
approximately 370 holders of record of the Company's common stock. This number
does not include the stockholders for whom shares are held in a "nominee" or
"street" name.

DIVIDEND POLICY

In 2002 the Company paid cash dividends of $0.125 per share of the
Company's common stock on March 1, June 3, September 3 and December 2 and has
declared a dividend of $0.125 per share payable March 3, 2003 to stockholders of
record on February 3, 2003. In 2001 the Company paid cash dividends of $0.125
per share of the Company's common stock on March 1, June 1, September 4 and
December 3. Any future determination as to payment of dividends will be made at
the discretion of the Board of Directors of the Company and will depend upon the
Company's operating results, financial condition, capital requirements, general
business conditions and such other factors that the Board of Directors deems
relevant.

EQUITY COMPENSATION PLAN INFORMATION

The following table provides information regarding securities authorized
for issuance under the Company's equity compensation plan as of December 31,
2002:

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ITEM 6. SELECTED FINANCIAL DATA.

The following table sets forth certain historical consolidated financial
data relating to the Company. The selected consolidated financial data are
derived from the financial statements of the Company as of and for the periods
presented. The selected consolidated financial data below should be read in
conjunction with "Management's Discussion and Analysis of Financial Condition
and Results of Operations" in Item 7 and the Company's Consolidated Financial
Statements (including the Notes thereto) in Item 8 of this report.

- ---------------

(1) Amounts include revenues and expenses related to reimbursements received
from the Company's customers. Prior periods have been reclassified to
conform to the classifications currently followed. Such reclassifications do
not affect earnings.

(2) In December 2002 the Company spent $68.5 million ($67.0 million capitalized
to rig equipment and $1.5 million added to inventory) for the acquisition of
the Ocean Vanguard, a third-generation semisubmersible drilling rig.

(3) 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) one-third of
rent expense, which the Company believes represents the interest factor
attributable to rent.

13

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS.

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

RESULTS OF OPERATIONS

General

Revenues. The Company's revenues vary based upon demand, which affects the
number of days the fleet is utilized and the dayrates earned. When a rig is
idle, generally no dayrate is earned and revenues will decrease as a result.
Revenues can also increase or decrease as a result of the acquisition or
disposal of rigs. In order to improve utilization or realize higher dayrates,
the Company may mobilize its rigs from one market to another. During periods of
mobilization, however, revenues may be adversely affected. As a response to
changes in demand, the Company may withdraw a rig from the market by stacking it
or may reactivate a rig stacked previously, which may decrease or increase
revenues, respectively.

Revenues from dayrate drilling contracts are recognized currently. The
Company may receive lump-sum payments in connection with specific contracts.
Such payments are recognized as revenues over the term of the related drilling
contract. Mobilization revenues, less costs incurred to mobilize an offshore rig
from one market to another, are recognized over the primary term of the related
drilling contract.

Revenues from offshore turnkey drilling contracts are accrued to the extent
of costs until the specified turnkey depth and other contract requirements are
met. Income is recognized on the completed contract method. Provisions for
future losses on turnkey contracts are recognized when it becomes apparent that
expenses to be incurred on a specific contract will exceed the revenue from that
contract.

Revenues from reimbursements received for the purchase of supplies,
equipment, personnel services and other services provided at the request of the
customer in accordance with a contract or agreement are recorded for the gross
amount billed to the customer, as "Revenues related to reimbursable expenses" in
the Consolidated Statements of Income. Prior to 2002 and the guidance provided
by the Emerging Issues Task Force ("EITF") 01-14 "Income Statement
Characterization of Reimbursements Received for "Out-of-Pocket" Expense
Incurred," the Company accounted for reimbursements, in most instances, as a
reduction of expenses incurred. All comparative periods presented have been
reclassified to comply with this guidance.

Operating Income. 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, the Company may realize few decreases
in operating expenses since the rig is typically maintained in a prepared state
with a full crew. In addition, when a rig is idle, the Company is responsible
for certain operating expenses such as rig fuel and supply boat costs, which are
typically a cost of the operator under drilling contracts. However, if the rig
is to be idle for an extended period of time, the Company 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. The Company recognizes as
operating expenses activities such as inspections, painting projects and routine
overhauls, which meet certain criteria, that maintain rather than upgrade its
rigs. These expenses vary from period to period. Costs of rig enhancements are
capitalized and depreciated over the expected useful lives of the enhancements.
Increased depreciation expense decreases operating income in periods subsequent
to capital upgrades.

Critical Accounting Estimates

The Company's significant accounting policies are included in Note 1 of its
Notes to Consolidated Financial Statements in Item 8 of this report.
Management's judgments, assumptions and estimates are inherent in the
preparation of the Company's financial statements and the application of its
significant accounting policies. The Company believes that its most critical
accounting estimates are as follows:

Property, Plant and Equipment. Drilling and other property and equipment
is carried at cost. Maintenance and routine repairs are charged to income
currently while replacements and betterments, which

14

meet certain criteria, are capitalized. Depreciation is amortized on the
straight-line method over the remaining estimated useful lives. Management makes
judgments, assumptions and estimates regarding capitalization, useful lives and
salvage values. Changes in these assumptions could produce results that differ
from those reported. The Company also evaluates its property and equipment for
impairment whenever changes in circumstances indicate that the carrying amount
of an asset may not be recoverable. Management's assumptions are an inherent
part of an asset impairment evaluation and the use of different assumptions
could produce results that differ from those reported.

Personal Injury Claims. The Company's retention of liability for personal
injury claims, which primarily results from Jones Act liability in the Gulf of
Mexico, is $0.5 million per claim with an aggregate annual deductible of $1.5
million. The Company estimates its liability for personal injury claims based on
the existing facts and circumstances in conjunction with historical experience
regarding past personal injury claims. Eventual settlement or adjudication of
these claims could differ significantly from the estimated amounts.

15

YEARS ENDED DECEMBER 31, 2002 AND 2001

Comparative data relating to the Company's revenues and operating expenses
by equipment type are listed below (eliminations offset (i) dayrate revenues
earned when the Company's rigs are utilized in its integrated services and (ii)
intercompany expenses charged to rig operations). Certain amounts applicable to
the prior periods have been reclassified to conform to the classifications
currently followed. Such reclassifications do not affect earnings.

High Specification Floaters.

Revenues. Revenues from high specification floaters decreased $35.0
million during the year ended December 31, 2002 from the same period in 2001.
Decreases in the average operating dayrate contributed $38.7 million to the
revenue decline as dayrates dropped from $117,700 per day during 2001 to
$105,500 per day during 2002 (excluding the Ocean Baroness). All of the rigs in
this classification, except the Ocean Confidence, experienced a decline in
dayrates during 2002. Most significantly, average dayrates went from $122,900 to
$81,400 for the Ocean Valiant, $124,100 to $96,800 for the Ocean Victory, and
$108,300 to $84,400 for the Ocean America.

Utilization fell from 95% in 2001 to 83% in 2002. Lower utilization in 2002
(excluding the Ocean Baroness which was in a shipyard undergoing an upgrade
during all of 2001) accounted for $32.0 million of

16

the overall decrease in revenue. The Ocean America was idle for approximately
five months during 2002 but worked most of 2001. In 2002 the Ocean Star and the
Ocean Victory spent three and one-half months and two months, respectively, in a
shipyard for inspections and repairs but both worked all of 2001.

Revenues generated by the Ocean Baroness, which began operations in
mid-March 2002 after completing an upgrade to high specification capabilities,
partially offset the overall decline in revenue for the year ended December 31,
2002 by $35.7 million.

Contract Drilling Expense. Contract drilling expense for high
specification floaters during the year ended December 31, 2002 increased $29.3
million from the same period in 2001. Operating expenses for the Ocean Baroness
added $16.7 million to 2002 contract drilling expense and included costs
incurred in connection with the recovery of its marine riser, net of insurance
recoveries, as well as its normal operating costs. Shipyard inspections and
repairs of the Ocean Star, Ocean Victory, and the Ocean Quest in 2002 resulted
in an increase in expenses of $4.9 million. Higher Brazilian customs fees in
2002 for the importation of spare parts and supplies for the Ocean Alliance and
the Ocean Clipper added $1.3 million to operating costs. Repairs to the Ocean
America and boat and fuel costs while the rig was idle, contributed an
additional $1.0 million to 2002 contract drilling expenses. The 2001 recognition
of a $1.8 million revision to an estimated insurance deductible for the Ocean
Clipper, which lowered costs in 2001, also contributed to the higher comparative
costs in 2002.

Other Semisubmersibles.

Revenues. Revenues from other semisubmersibles decreased $60.4 million
from the year ended December 31, 2001 to the same period of 2002. Lower
utilization accounted for $38.4 million of the decrease, dropping to 61% for the
year ended December 31, 2002 from 70% for the same period in 2001. The Ocean
Voyager and the Ocean Endeavor have both been cold stacked since March 2002
while both of these rigs worked the majority of 2001. The Ocean New Era was idle
or cold stacked all of 2002 but worked almost half of 2001. During part of 2002
the Ocean Worker was in a shipyard for inspection and repairs and the Ocean
Saratoga was in a shipyard for repairs. Both of these rigs worked most of 2001.
Improved utilization for the Ocean Bounty, which operated most of 2002 compared
to being stacked for approximately two months in 2001, was partially offsetting.

Lower overall average dayrates contributed $22.0 million to the decrease in
other semisubmersibles revenue. However, the average operating dayrate for this
fleet increased to $67,900 during the year ended December 31, 2002 from $66,900
during the same period of 2001. This occurred because several of the rigs that
were contracted at lower dayrates in 2001 were stacked throughout parts of 2002.
Consequently, the average operating dayrate rose in 2002 for the working rigs in
this class. Significant changes in average operating dayrates included the Ocean
Worker and the Ocean Whittington which decreased approximately $77,900 and
$30,700 respectively, and the Ocean Guardian and Ocean Princess which increased
approximately $28,300 and $20,800, respectively.

Contract Drilling Expense. Contract drilling expense for other
semisubmersibles was $12.1 million lower in 2002 than in 2001. The Ocean
Endeavor and the Ocean Voyager, which have been cold stacked since March 2002,
contributed cost savings of $14.5 million while the Ocean New Era and the Ocean
Ambassador, which were both stacked with reduced crews for most of 2002, lowered
costs by $4.3 million. Contract drilling expenses for the Ocean Whittington were
lower by $2.8 million in 2002 when compared to 2001 resulting from its
inspection, repairs and preparation for its mobilization to Namibia in December
2001. Partially offsetting was an increase in 2002 of contract drilling expenses
for the Ocean Nomad of $3.0 million. In 2001 the rig was in a shipyard for an
upgrade which resulted in lower operating costs. In addition, inspection and
repairs to the Ocean Worker added $2.1 million to contract drilling expense in
2002. Also, higher Brazilian customs fees in 2002 for the importation of spare
parts and supplies for the Ocean Yatzy, Ocean Yorktown and the Ocean Winner
resulted in a $1.4 million increase in contract drilling expense.

17

Jack-Ups.

Revenues. Revenues from jack-ups during the year ended December 31, 2002
decreased $75.1 million from the same period of 2001. A reduction in the average
operating dayrate from $41,000 in 2001 to $27,300 in 2002, contributed $48.6
million to the overall revenue decline. All of the Gulf of Mexico jack-up rigs
experienced lower average operating dayrates in 2002. Only the Ocean Heritage, a
rig which operated offshore Indonesia and Australia, saw a significant
improvement in its dayrate, from $34,700 in 2001 to $85,100 in 2002.

Revenues decreased $26.5 million as a result of a decline in utilization to
71% in 2002 from 83% in 2001. Utilization was down for the Ocean Champion, which
was idle and/or cold stacked throughout 2002, and for the Ocean Spartan, Ocean
Spur, Ocean Tower and the Ocean Heritage all of which spent time in shipyards
during 2002 undergoing upgrades. All five of these jack-ups worked most of 2001.
Higher utilization in 2002 for the Ocean Sovereign, which worked all of 2002 but
spent most of 2001 in a shipyard for repairs, was partially offsetting.

Contract Drilling Expense. Contract drilling expense for jack-ups
decreased $17.7 million in 2002 compared to 2001. Contract drilling expense was
$8.2 million lower in 2002 for the Ocean Spartan, Ocean Spur, Ocean Tower and
the Ocean Heritage as a result of a reduction in operating costs while these
rigs were in shipyards undergoing upgrades. Contract drilling expense was $8.0
million lower for the Ocean Champion which was idle and/or cold stacked during
all of 2002 but worked most of 2001. Increased contract drilling expense during
the first half of 2001 from repairs to the Ocean Nugget, the Ocean Crusader, and
the Ocean Summit also contributed to the lower comparative costs in 2002. Higher
expenses for the Ocean Heritage in 2002, primarily due to the mobilization of
the rig from Indonesia to Australia and higher labor costs in Australia, were
partially offsetting.

Integrated Services.

Operating income for integrated services decreased $1.2 million during the
year ended December 31, 2002 compared to the same period of 2001 resulting from
the difference in type and magnitude of projects during those periods. During
2002, an operating loss of $0.6 million resulted primarily from an unprofitable
turnkey project in the Gulf of Mexico. During the same period in 2001, operating
income of $0.6 million was primarily due to the completion of one international
turnkey project and three turnkey permanent plug and abandonment projects in the
Gulf of Mexico.

Other.

Other operating income of $7.3 million for the year ended December 31, 2002
increased $9.3 million from the same period in 2001. The increase resulted
primarily from a $5.9 million reimbursement of prior year foreign income tax to
be received by the Company from its customers and relates to a tax settlement
made between the Company and the Norwegian tax authorities in December 2002. The
corresponding income tax expense is reflected in "Income tax expense" in the
Company's Consolidated Statements of Income.

Also contributing to the higher Other operating income in 2002 was a $2.4
million reversal of an accrual made in a prior year for personal injury claims
and the elimination of a $1.0 million reserve for inventory obsolescence, from
prior years, that was deemed no longer necessary.

Reimbursables, net.

Revenues related to reimbursable items that the Company purchases and/or
services it performs at the request of its customers offset by the related
expenditures for these items were $2.5 million in 2002 compared to $2.8 million
in 2001.

Depreciation and Amortization Expense.

Depreciation and amortization expense for the year ended December 31, 2002
increased $7.5 million over the same period of 2001. Higher 2002 depreciation
resulted primarily from depreciation for 2002 capital

18

additions and additional depreciation for the Ocean Baroness, which completed
its deepwater upgrade and began operations in March 2002. The suspension of
goodwill amortization on January 1, 2002 partially offset this increase.
Goodwill amortization during the year ended December 31, 2001 was $3.3 million.
See Note 1 "-- Goodwill" and Note 6 to the Company's Consolidated Financial
Statements in Item 8 of Part II of this report.

General and Administrative Expense.

General and administrative expense was $3.5 million higher in 2002 than in
the comparable period in 2001 primarily due to higher personnel costs and
professional expenses, including legal fees, tax and accounting fees and
security consulting.

Interest Income.

Interest income of $29.8 million for the year ended December 31, 2002
decreased $18.9 million from $48.7 million for the same period in 2001 primarily
due to a reduction in marketable securities held and lower interest rates earned
on cash and marketable securities in 2002 compared to 2001.

Interest Expense.

Interest expense of $23.6 million for the year ended December 31, 2002 was
$14.5 million lower than in the same period of 2001 primarily due to a $11.9
million pre-tax charge that resulted from the April 2001 redemption of the
Company's 3.75% Convertible Subordinated Notes Due 2007 ("3.75% Notes"). In
addition, the Company's weighted average interest rate in 2002 was lower than in
2001 resulting from the redemption in 2001 of the 3.75% Notes and the issuance
of the 1.5% Convertible Senior Debentures due 2031 (the "1.5% Debentures") on
April 11, 2001. Interest expense was also lower in 2002 than in 2001 due to more
interest capitalized to rig upgrades in 2002. Interest capitalized to rig
upgrades was $2.9 million in 2002 compared to $2.6 million in 2001. In 2002
interest was capitalized to the Ocean Baroness during the final three months of
its upgrade and during the entire year for the Ocean Rover. See "-- Liquidity."

Gain on Sale of Marketable Securities.

Gain on sale of marketable securities of $36.5 million for the year ended
December 31, 2002 increased $9.4 million from $27.1 million for the same period
in 2001.

Other Income and Expense (Other, net).

Other income of $1.5 million for the year ended December 31, 2002 increased
$4.2 million from other expense of $2.7 million for the same period in 2001.
Other income in 2002 included a $1.1 million pre-tax gain on foreign exchange
forward contracts. See Note 4 "-- Derivative Financial Instruments -- Forward
Exchange Contracts" to the Company's Consolidated Financial Statements in Item 8
of Part II of this report. Other expense in 2001 included a $10.0 million
reserve established for a class action lawsuit which was ultimately settled in
June 2002 and was partially offset by a $7.3 million receipt for the settlement
of an unrelated lawsuit.

Income Tax Expense.

Income tax expense of $33.7 million for the year ended December 31, 2002
decreased $53.0 million from $86.7 million for the same period in 2001 primarily
as a result of a $164.3 million decrease in "Income before income tax expense"
in 2002. The annual effective tax rate increased from 33% in 2001 to 35% in
2002. In 2001 the Company made the decision to indefinitely reinvest part of the
earnings of its UK subsidiaries and the annual effective rate for the year 2001
reflects this decision. The effect of the indefinite reinvestment of the UK
earnings in 2002 was to lower the annual effective tax rate but this decline was
more than offset by prior year foreign tax expense recorded in 2002, primarily
$5.9 million for a Norwegian income tax settlement. See "--Other."

19

YEARS ENDED DECEMBER 31, 2001 AND 2000

Comparative data relating to the Company's revenues and operating expenses
by equipment type are listed below (eliminations offset (i) dayrate revenues
earned when the Company's rigs are utilized in its integrated services and (ii)
intercompany expenses charged to rig operations). Certain amounts applicable to
the prior periods have been reclassified to conform to the classifications
currently followed. Such reclassifications do not affect earnings.

High Specification Floaters.

Revenues. Revenues from high specification floaters increased $114.8
million during the year ended December 31, 2001 from the same period in 2000. Of
this increase, $61.5 million was attributable to the Ocean Confidence, which
began operations in early January 2001 after completion of a conversion to a
high specification drilling unit. The rig was undergoing this conversion
throughout 2000. Higher average operating dayrates contributed $41.9 million to
the revenue improvement from 2000 to 2001. Average operating dayrates increased
from $94,100 during 2000 to $109,200 (excluding the Ocean Confidence) during
2001. The Ocean Alliance and the Ocean America experienced the greatest
increases in dayrates with an average increase of $32,500 per day and $29,500
per day, respectively.

20

Improved utilization for high specification floaters in 2001 accounted for
$11.4 million of the increase in revenues over 2000. Utilization for this class
of rig rose to 95% in 2001 from 88% in 2000 (excluding the Ocean Confidence).
The greatest improvements were from the Ocean Quest, which was idle for almost
five months longer in 2000 than in 2001, and the Ocean Clipper, which had less
downtime for repairs during 2001.

Contract Drilling Expense. Contract drilling expense for high
specification floaters during the year ended December 31, 2001 increased $22.6
million from the same period in 2000. This increase resulted primarily from
costs incurred by the Ocean Confidence ($21.1 million) which began operations in
January 2001.

Other Semisubmersibles.

Revenues. Revenues from other semisubmersibles increased $64.4 million
during the year ended December 31, 2001 from the same period in 2000 primarily
due to higher average operating dayrates. Average dayrates increased to $66,900
per day in 2001 from $61,300 in 2000 and contributed an additional $52.3 million
to 2001 revenues. The greatest dayrate increases were for the Ocean General,
Ocean Nomad, Ocean Guardian and the Ocean Bounty. However, lower average
operating dayrates in 2001 for the Ocean Princess and the Ocean Whittington were
partially offsetting.

Improvements in utilization contributed $12.2 million to revenue during the
year ended December 31, 2001 compared to the same period in 2000. Overall,
utilization increased to 70% in 2001 from 61% in 2000. The Ocean Epoch spent
most of 2000 in a shipyard for water depth capability and variable deckload
upgrades while it worked most of 2001. The Ocean Voyager, Ocean New Era and the
Ocean Guardian were all idle approximately one half-year longer in 2000 compared
to 2001. However, utilization decreased in 2001 for the Ocean Whittington and
the Ocean Yorktown. The Ocean Whittington was stacked for almost four months in
2001 for a special survey, repairs and preparation for its December 2001
mobilization to Namibia. The Ocean Yorktown was in a shipyard for over two
months in 2001 for inspection and upgrades in connection with new contract
requirements.

Contract Drilling Expense. Contract drilling expense for other
semisubmersibles during the year ended December 31, 2001 increased $11.0 million
from the same period in 2000. Rig expenses increased $5.2 million for the Ocean
Epoch in 2001 from the same period in 2000 when most of the expenses were
associated with the rig's upgrade and were capitalized. The Ocean New Era's
expenses increased $3.0 million in 2001 as it operated during six months of 2001
but was stacked all of 2000. An additional $2.8 million in contract drilling
expense resulted from the mobilization of the Ocean Whittington from Brazil to
Namibia in late 2001. Also, contract drilling expense increased $2.6 million
from the 2001 inspections of the Ocean Yorktown, Ocean Whittington, Ocean Yatzy
and Ocean Princess and $1.8 million from higher Brazilian customs fees in 2001.
Partially offsetting these cost increases, contract drilling expenses were $5.5
million lower in 2001 due to Ocean Lexington and Ocean Saratoga repair projects
in 2000 not repeated in 2001.

Jack-Ups.

Revenues. Revenues from jack-ups during the year ended December 31, 2001
increased $55.6 million from 2000. All of the Company's jack-up rigs experienced
higher average operating dayrates with the overall average operating dayrate
improving from $26,000 in 2000 to $41,000 in 2001. This 58% improvement in
average operating dayrates resulted in an increase of $63.6 million in revenues.

Lower utilization in 2001 than in 2000 partially offset the revenue
improvements that resulted from the higher average operating dayrates. Revenue
declined $8.0 million in 2001 as a result of 83% utilization in 2001 compared to
89% in 2000. This decrease in utilization was primarily due to inspection and
repairs of the Ocean Summit, Ocean Sovereign, Ocean Crusader and Ocean Champion
during 2001. In addition, the Ocean Nugget was stacked for over one-half of 2001
and the Ocean King was in a shipyard for part of the last two months of 2001 for
inspections and repairs. All of these rigs worked most of 2000. Utilization
improvements which were partially offsetting resulted from the Ocean Heritage
and the Ocean Tower. The Ocean Heritage, which worked all of 2001, spent part of
2000 in a shipyard for repairs while the Ocean Tower worked most of 2001 but was
cold stacked for part of 2000.

21

Contract Drilling Expense. Contract drilling expense increased $11.1
million for jack-ups during the year ended December 31, 2001 compared to the
same period in 2000. Operating costs were higher in 2001 for the Ocean Champion,
Ocean Summit and Ocean Crusader due to inspection and repairs. In addition, rig
expenses were higher for the Ocean Tower which operated during most of 2001, but
was cold stacked during part of 2000. Contract drilling expense decreased in
2001 for the Ocean Heritage due to major repairs in 2000.

Integrated Services.

Operating income for integrated services decreased as a result of the
difference in number, type and magnitude of projects during 2001 compared to
2000. During 2001, integrated services contributed operating income of $0.6
million to the Company's consolidated results of operations primarily due to the
completion of one international turnkey project, which began in the last quarter
of 2000, and three turnkey permanent plug and abandonment projects in the Gulf
of Mexico. During 2000, DOTS contributed operating income of $1.0 million to the
Company's consolidated results of operations primarily from the completion of
four turnkey projects in the Gulf of Mexico, one international turnkey project
and integrated services provided in Aberdeen, Scotland.

Other.

Other operating expense of $2.0 million for the year ended December 31,
2001 decreased $4.1 million from the same period in 2000. Other operating
expense in 2001, primarily for rig crew training and maintenance and repair of
spare equipment, was lower by approximately $0.9 million compared to similar
expenditures in 2000. Other operating expense in 2000 also included $1.8 million
for settlements with the Company's customers related to prior years' disputes
including compliance audit findings.

Reimbursables, net.

Revenues related to reimbursable items that the Company purchases and/or
services it performs at the request of its customers offset by the related
expenditures for these items were $2.8 million in 2001 compared to $2.7 million
in 2000.

Depreciation and Amortization Expense.

Depreciation and amortization expense for the year ended December 31, 2001
increased $24.4 million over the prior year. Higher depreciation in 2001
resulted primarily from depreciation for the Ocean Confidence, which completed
its conversion from an accommodation vessel to a high specification
semisubmersible drilling unit and commenced operations in January 2001. Also,
2001 depreciation was higher due to an increase of $35.2 million in ordinary
capital expenditures compared to 2000.

General and Administrative Expense.

General and administrative expense increased $1.7 million in 2001 compared
to the same period in 2000 primarily due to an increase in personnel costs,
travel and professional expenses.

Gain on Sale of Marketable Securities.

Gain on sale of marketable securities of $27.1 million for the year ended
December 31, 2001 increased $25.0 million from $2.1 million for the same period
in 2000.

Gain on Sale of Assets

Gain on sale of assets of $0.3 million for the year ended December 31, 2001
decreased $14.0 million from $14.3 million for the same period in 2000 primarily
due to the January 2000 sale of the Company's jack-up drilling rig, Ocean
Scotian which had been cold stacked offshore The Netherlands prior to the sale.
The rig was sold for $32.0 million in cash which resulted in a gain of $13.9
million ($9.0 million after tax).

22

Interest Income.

Interest income of $48.7 million for the year ended December 31, 2001
decreased $0.8 million from $49.5 million for the same period in 2000. This
decrease resulted from the Company's investment in marketable securities with
lower interest rates in 2001 compared to 2000 and was partially offset by the
investment of higher cash balances generated by the sale of the Company's 1.5%
convertible senior debentures due 2031 (the "1.5% Debentures") on April 11,
2001, the sale of the Company's zero coupon convertible debentures due 2020 (the
"Zero Coupon Debentures") on June 6, 2000 and the December 2000 lease-leaseback
of the Ocean Alliance. Cash balances available for investment were partially
reduced as a result of the Company's redemption of all of its outstanding 3.75%
Notes on April 6, 2001. See "-- Liquidity."

Interest Expense.

Interest expense of $38.1 million for the year ended December 31, 2001
increased $27.8 million from $10.3 million for the same period in 2000 primarily
due to the $11.9 million pre-tax loss from the April 2001 redemption of the
Company's 3.75% Notes and less interest capitalized due to the completion of the
Ocean Confidence conversion ($2.6 million interest capitalized in 2001 compared
to $13.8 million interest capitalized in 2000). In addition, interest expense
increased with the issuance of the Zero Coupon Debentures on June 6, 2000, the
issuance of the 1.5% Debentures on April 11, 2001 and interest expense related
to the December 2000 lease-leaseback of the Ocean Alliance. This increase was
partially offset by a reduction in interest expense resulting from the Company's
redemption of all of its outstanding 3.75% Notes on April 6, 2001. See
"-- Liquidity."

Other Income and Expense (Other, net).

Other expense of $2.7 million for the year ended December 31, 2001
increased $0.7 million from other expense of $2.0 million for the same period in
2000. This increase resulted primarily from a $10.0 million reserve for the then
pending litigation in connection with a proposed class action suit filed against
major offshore drilling companies partially offset by a $7.3 million receipt of
a settlement payment for resolved litigation.

Income Tax Expense.

Income tax expense of $86.7 million for the year ended December 31, 2001
increased $48.1 million from $38.6 million in 2000 primarily as a result of the
increase in "Income before income taxes" of $149.6 million in 2001, which was
partially offset by a lower effective income tax rate in 2001. The lower
effective income tax rate in 2001 was primarily due to the Company's decision to
permanently reinvest part of the earnings of its U.K. subsidiaries.

INDUSTRY CONDITIONS

The Company operates in an industry that is historically extremely
competitive and deeply cyclical. The demand for its services has traditionally
been highly correlated with the price of oil and natural gas. However, the rise
in product prices that began in late 2001 and continued throughout 2002 did not
yield the expected improvements in utilization and dayrates for the Company's
equipment. The Company believes that its customers have been reluctant to
increase offshore drilling expenditures or to commit to long term contracts due
to uncertainties about the sustainability of current product prices as well as
general uncertainties surrounding the state of the economy and the effects of a
possible military conflict in Iraq.

In the Gulf of Mexico, well-to-well contracts are the norm for the
Company's deep water semisubmersible fleet, its mid-water semisubmersible fleet
and its jack-up fleet. With limited to no backlog of work for these fleets, the
Company does not anticipate any significant improvement in utilization or rates
until its customers regain confidence in the sustainability of product prices.

23

Absent a change in its customers' perception of the overall energy market,
the Company anticipates that the international markets in which it operates will
remain relatively flat and consequently expects utilization and rates for its
equipment in these markets to remain relatively unchanged.

LIQUIDITY

At December 31, 2002, the Company's cash and marketable securities totaled
$812.5 million, down from $1.1 billion at December 31, 2001. Cash of $199.1
million generated by repurchase agreements is included at December 31, 2001. See
Note 1 "-- Securities Sold Under Agreements to Repurchase" in Item 8 of Part II
of this report.

A discussion of the sources and uses of cash for the year ended December
31, 2002 compared to the same period in 2001 follows.

Cash generated by net income adjusted for non-cash items, including
depreciation and amortization, for the year ended December 31, 2002 decreased
$184.4 million compared to the same period in 2001 primarily due to a decline in
results of operations in 2002. Operating items provided $49.4 million during
2002 compared to a $42.1 million use of cash in 2001. The $91.5 million
fluctuation in operating items resulted primarily from a reduction in accounts
receivable related to the lower overall activity of the Company's fleet in 2002.

Net cash used in investing activities increased $308.7 million for the year
ended December 31, 2002 compared to the year ended December 31, 2001. This
increase in cash usage was primarily due to $199.1 million used for the
repurchase of securities in 2002 sold under repurchase agreements in 2001 and
the purchase of the Ocean Vanguard in December 2002 for $68.5 million ($67.0
million capitalized to rig equipment and $1.5 million added to inventory). Cash
used for capital expenditures in 2002 increased

24

$5.2 million primarily due to the completion of the Ocean Baroness upgrade and
the ongoing upgrade of the Ocean Rover. Cash provided by net investing
activities increased $160.8 million in 2002 compared to 2001 from the net sale
of certain of the Company's investments in marketable securities.

The Company spent $109.1 million of cash during 2002 primarily for the
payment of dividends to stockholders and the purchase of the Company's common
stock. During the year ended December 31, 2002, the Company purchased 1,716,700
shares of its common stock at an aggregate cost of $43.4 million, or at an
average cost of $25.30 per share. This includes the Company's purchase of
500,000 shares of its common stock at an aggregate cost of $20.0 million, or
$40.00 per share, upon the exercise of put options sold in February 2001. See
"-- Treasury Stock and Common Equity Put Options" in Note 1 to the Company's
Consolidated Financial Statements in Item 8 of Part II of this report. Depending
on market conditions, the Company may, from time to time, purchase shares of its
common stock or issue put options in the open market or otherwise.

Cash used in financing activities in 2002 and 2001 included payments of
$10.4 million and $9.7 million, respectively, for two of five annual
installments of $13.7 million (principal and interest) in accordance with the
Company's December 2000 lease-leaseback agreement with a European bank. The
lease-leaseback agreement provided for the Company to lease the Ocean Alliance,
one of the Company's high specification semisubmersible drilling rigs, to the
bank for a lump-sum payment of $55.0 million plus an origination fee of $1.1
million and for the bank to then sub-lease the rig back to the Company. This
financing arrangement has an effective interest rate of 7.13% and is an
unsecured obligation of the Company.

Cash used in financing activities in 2002 also included payments of $1.2
million for the settlement of put options which covered 1,000,000 shares of the
Company's common stock. Financing activities in 2001 provided cash from premiums
of $6.9 million received from the sale of put options covering 1,687,321 shares
of the Company's common stock. The options gave the holders the right to require
the Company to repurchase up to the contracted number of shares of its common
stock at the stated exercise price per share at any time prior to their
expiration. The Company had the option to settle in cash or shares of its common
stock. Put options sold in 2001, which covered 187,321 shares of the Company's
common stock, expired during 2002. There were no put options outstanding at
December 31, 2002. See "-- Treasury Stock and Common Equity Put Options" in Note
1 to the Company's Consolidated Financial Statements in Item 8 of Part II of
this report.

Cash used in financing activities in 2001 resulted primarily from the
Company's redemption of all of its outstanding 3.75% Notes in accordance with
the indenture under which they were issued. The Company redeemed the outstanding
3.75% Notes at 102.8% of the principal amount thereof plus accrued interest of
$2.1 million for a total cash payment of $397.7 million, resulting in an $11.9
million loss which is reported in "Interest expense" in the Consolidated
Statements of Income.

Additional cash used in financing activities during the year ended December
31, 2001 included $104.3 million for dividends paid to stockholders and the
purchase of treasury stock. During 2001, the

25

Company purchased 1,403,900 shares of its common stock at an aggregate cost of
$37.8 million, or at an average cost of $26.90 per share.

Cash provided by financing activities in 2001 consisted primarily of net
proceeds of $449.1 million from the issuance of $460.0 million principal amount
of the 1.5% Debentures on April 11, 2001.

Contractual Cash Obligations.

Other.

The Company has the ability to issue an aggregate of approximately $117.5
million in debt, equity and other securities under a shelf registration
statement. In addition, the Company may issue, from time to time, up to eight
million shares of common stock, shares which are registered under an acquisition
shelf registration statement (upon effectiveness of an amendment thereto
reflecting the effect of the two-for-one stock split declared in July 1997), in
connection with one or more acquisitions by the Company of securities or assets
of other businesses.

At December 31, 2002 and 2001, the Company had no off-balance sheet debt.

The Company anticipates that its insurance premiums will be approximately
$7.0 million higher in 2002 than in 2001. In December 2002 the Company renewed
its Hull and Machinery insurance policy. The Company's retention of liability
for property damage increased at the time of renewal from approximately $0.2
million per incident to between $1.0 million and $2.5 million per incident,
depending on the value of the equipment, with an aggregate annual deductible of
$5.0 million. In addition, the Company retained 10% of its insured liability.
The Company expects to be able to fund the higher premiums and retention through
its operating cash.

The Company believes it has the financial resources needed to meet its
business requirements in the foreseeable future, including capital expenditures
for rig upgrades and continuing rig enhancements, and working capital
requirements.

CAPITAL RESOURCES

Cash required to meet the Company's capital commitments is determined by
evaluating rig upgrades to meet specific customer requirements and by evaluating
the Company's ongoing rig equipment replacement and enhancement programs,
including water depth and drilling capability upgrades. It is management's
opinion that operating cash flows and the Company's cash reserves will be
sufficient to meet these capital commitments; however, periodic assessments will
be made based on industry conditions. In addition, the Company 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. The Company's ability to affect any such issuance will be
dependent on the Company's results of operations, its current financial
condition, current market conditions and other factors beyond its control.

During the year ended December 31, 2002, the Company spent $187.7 million,
including capitalized interest expense, for rig upgrades. These expenditures
were primarily for the deepwater upgrade of the Ocean Rover ($98.4 million)
which is expected to be completed in July 2003, upgrades to six of the Company's
jack-ups ($50.7 million) of which three were completed during 2002 and three are
expected to be completed during

26

2003, and the deepwater upgrade of the Ocean Baroness ($31.4 million) which was
completed in March 2002. The Company expects to spend approximately $123 million
for rig upgrade capital expenditures during 2003 for the completion of the Ocean
Rover upgrade ($80 million) and the three remaining jack-up upgrades ($43
million).

The upgrade of the Ocean Rover began in January 2002. The converted rig
will be able to operate in 7,000-foot water depths on a stand alone basis. Water
depths in excess of 7,000 feet should be achievable utilizing augmented mooring
systems on a case by case basis. The upgrade is expected to take 19 months to
complete with delivery estimated in the third quarter of 2003.

The significant upgrade of the Company's semisubmersible rig, the Ocean
Baroness, to high specification capabilities resulted in an enhanced version of
the Company's previous Victory-class upgrades. The upgrade was similar to the
upgrade being performed on the Ocean Rover. The Company took delivery of the
Ocean Baroness in January 2002. The approximate cost of the upgrade was $169.0
million.

In 2002 the Company began a two year program to expand the capabilities of
its jack-up fleet by significantly upgrading six of its 14 jack-up rigs. The
Company expects to spend approximately $100 million on the program, and as of
December 31, 2002, has spent $57 million. The Ocean Titan and Ocean Tower, both
350-foot water depth capability independent-leg slot rigs, were to have
cantilever packages installed. The cantilever systems enable a rig to cantilever
or extend its drilling package over the aft end of the rig. Currently, the Ocean
Tower is in the latter stages of its upgrade with delivery expected in April
2003. The upgrade planned for the Ocean Titan is expected to commence in early
2003. The Ocean Spartan, Ocean Spur, and Ocean Heritage, each had leg extensions
installed (all completed during the fourth quarter of 2002) enabling these rigs
to work in water depths up to 300 feet, up from 250 feet prior to the upgrades,
at a combined approximate cost of $35.7 million. The Ocean Sovereign, a 250-foot
water depth independent-leg cantilever rig, is currently in a shipyard
undergoing leg extension installations to allow the rig to work in water depths
up to 300 feet.

All of the Company's upgrade projects are subject to risks of delay or cost
overruns that are inherent in any large construction project.

The Company has signed a memorandum of agreement to purchase the
semisubmersible drilling rig Omega for $65 million. The agreement is subject to
certain conditions and is expected to be completed in the first quarter of 2003.
Subsequent to its purchase, the Company anticipates that the rig initially will
be working offshore South Africa. The purchase of the Omega is expected to be
funded from existing cash balances.

During the year ended December 31, 2002, the Company spent $86.1 million in
association with its ongoing rig equipment replacement and enhancement programs
and to meet other corporate requirements. In addition, the Company spent $68.5
million ($67.0 million capitalized to rig equipment) for the purchase of the
third-generation semisubmersible drilling rig, West Vanguard, renamed Ocean
Vanguard. The Company has budgeted $111.3 million for 2003 capital expenditures
associated with its ongoing rig equipment replacement and enhancement programs
and other corporate requirements.

INTEGRATED SERVICES

The Company's wholly owned subsidiary, DOTS, from time to time, selectively
engages in drilling services pursuant to turnkey or modified-turnkey contracts
under which DOTS agrees to drill a well to a specified depth for a fixed price.
In such cases, DOTS generally is not entitled to payment unless the well is
drilled to the specified depth and other contract requirements are met.
Profitability of the contract is dependent upon its ability to keep expenses
within the estimates used in determining the contract price. Drilling a well
under a turnkey contract therefore typically requires a greater cash commitment
by the Company and exposes the Company to risks of potential financial losses
that generally are substantially greater than those that would ordinarily exist
when drilling under a conventional dayrate contract. DOTS also offers a
portfolio of drilling services including overall project management, extended
well tests, and completion operations. During 2002, DOTS had an operating loss
of $0.6 million primarily from an unprofitable Gulf of Mexico turnkey project.
During 2001, DOTS contributed operating income of $0.6 million to the Company's

27

consolidated results of operations primarily from the completion of one
international turnkey project, which began in the last quarter of 2000, and
three turnkey permanent plug and abandonment projects in the Gulf of Mexico.

OTHER

Currency Risk. Certain of the Company's subsidiaries use the local
currency in the country where they conduct operations as their functional
currency. Currency environments in which the Company has material business
operations include Brazil, the U.K., Australia and Vietnam. The Company
generally attempts to minimize its currency exchange risk by seeking
international contracts payable in local currency in amounts equal to the
Company's estimated operating costs payable in local currency with the balance
of the contract payable in U.S. dollars. Because of this strategy, historically
the Company has minimized its unhedged net asset or liability positions
denominated in local currencies and has not experienced significant gains or
losses associated with changes in currency exchange rates. At present, however,
only contracts covering the Company's five rigs currently operating in Brazil
are payable both in U.S. dollars and the local currency. The Company has not
hedged its exposure to changes in the exchange rate between U.S. dollars and the
local currencies, except in Australia for operating costs payable in the local
currencies in which it operates, but it may seek to do so in the future.

Currency translation adjustments are accumulated in a separate section of
stockholders' equity. When the Company ceases its operations in a currency
environment, the accumulated adjustments are recognized currently in results of
operations. The effect on results of operations from these translation gains and
losses has not been material and are not expected to have a significant effect
in the future.

Forward Exchange Contracts. In some instances, a foreign exchange forward
contract is used to minimize the forward exchange risk. A forward exchange
contract obligates the Company to exchange predetermined amounts of specified
foreign currencies at specified foreign exchange rates on specified dates. In
June 2002 the Company entered into forward contracts to purchase 50.0 million
Australian dollars, 4.2 million Australian dollars to be purchased monthly from
August 29, 2002 through June 26, 2003 and 3.8 million to be purchased on July
31, 2003. In July 2001 the Company entered into twelve forward contracts to
purchase 3.5 million Australian dollars at each month end through July 31, 2002.

ACCOUNTING STANDARDS

In December 2002 the Financial Accounting Standards Board ("FASB") issued
Statement of Financial Accounting Standards ("SFAS") No. 148, "Accounting for
Stock-Based Compensation-Transition and Disclosure." SFAS No. 148 amends SFAS
No. 123, "Accounting for Stock-Based Compensation," to provide alternative
methods of transition for a voluntary change to the fair value based method of
accounting for stock-based employee compensation. In addition, SFAS No. 148
amends the disclosure requirements of SFAS No. 123 to require prominent
disclosures in both annual and interim financial statements regarding the method
of accounting for stock-based employee compensation and the effect of the method
used on reported results. SFAS No. 148 is effective for financial statements for
fiscal years ending after December 15, 2002. The Company accounts for
stock-based employee compensation in accordance with Accounting Principles Board
("APB") Opinion No. 25, "Accounting for Stock Issued to Employees." However, the
Company has adopted the provisions of SFAS No. 148 which require prominent
disclosure regarding the method of accounting for stock-based employee
compensation in its annual financial statements and will include such disclosure
in all of its future interim financial statements.

In July 2002 the FASB issued SFAS No. 146, "Accounting for Costs Associated
with Exit or Disposal Activities." SFAS No. 146 requires companies to recognize
costs associated with exit or disposal activities when they are incurred rather
than at the date of a commitment to an exit or disposal plan. SFAS No. 146 is to
be applied prospectively to exit or disposal activities initiated after December
31, 2002. The Company does not expect the adoption of SFAS No. 146 to have a
material impact on the Company's consolidated results of operations, financial
position or cash flows.

28

In April 2002 the FASB issued SFAS No. 145, "Rescission of FASB Statements
No. 4, 44, and 64, Amendment to FASB Statement No. 13, and Technical
Corrections." The rescission of SFAS No. 4 and 64 by SFAS No. 145 streamlines
the reporting of debt extinguishments and requires that only gains and losses
from extinguishments meeting the criteria in APB Opinion 30, "Reporting the
Results of Operations-Reporting the Effects of Disposal of a Segment of a
Business, and Extraordinary, Unusual and Infrequently Occurring Events and
Transactions" would be classified as extraordinary. Thus, gains or losses
arising from extinguishments that are part of a company's recurring operations
would not be reported as an extraordinary item. SFAS No. 145 is effective for
fiscal years beginning after May 15, 2002 with earlier adoption encouraged. The
Company adopted SFAS No. 145 in April 2002 and, accordingly, reclassified its
April 2001 loss of $7.7 million, net-of-tax, from early extinguishment of debt,
as a result of the Company's redemption of the outstanding 3.75% Notes, out of
extraordinary items. The pre-tax loss from early extinguishment of debt of $11.9
million was reclassified to "Interest expense" and the related tax benefit was
reclassified to "Income tax expense" in the Consolidated Statement of Income.
See Note 1 "-- Capitalized Interest" to the Company's Consolidated Financial
Statements in Item 8 of Part II of this report.

In October 2001 the FASB issued SFAS No. 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets." SFAS No. 144 replaces SFAS No.
121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived
Assets to Be Disposed Of" and provides updated guidance concerning the
recognition and measurement of an impairment loss for certain types of
long-lived assets. SFAS No. 144 is effective for fiscal years beginning after
December 15, 2001. The adoption of SFAS No. 144 in January 2002 by the Company
has not had, nor is it expected to have, a material impact on the Company's
consolidated results of operations, financial position or cash flows.

In August 2001 the FASB issued SFAS No. 143, "Accounting for Asset
Retirement Obligations." SFAS No. 143 addresses financial accounting and
reporting obligations associated with the retirement of tangible long-lived
assets and the associated asset retirement costs. SFAS No. 143 is effective for
fiscal years beginning after June 15, 2002 with early adoption encouraged.
Adoption of SFAS No. 143 in 2003 is not expected to have a material impact on
the Company's consolidated results of operations, financial position or cash
flows.

In June 2001 the FASB issued two new pronouncements, SFAS No. 141,
"Business Combinations" and SFAS No. 142, "Goodwill and Other Intangible
Assets." SFAS No. 141 requires that all business combinations be accounted for
by the purchase method and applies to all business combinations initiated after
June 30, 2001 and also applies to all business combinations accounted for using
the purchase method for which the date of acquisition is July 1, 2001 or later.
There are also transition provisions that apply to business combinations
completed before July 1, 2001, that were accounted for by the purchase method.
SFAS No. 142 is effective for fiscal years beginning after December 15, 2001 for
all goodwill and other intangible assets recognized in an entity's statement of
financial position at that date, regardless of when those assets were initially
recognized. The Company adopted SFAS No. 142 on January 1, 2002 and has
suspended amortization of goodwill which was $3.3 million and $4.5 million for
the years ended December 31, 2001 and 2000, respectively. SFAS No. 142 does not
change the SFAS No. 109 "Accounting for Income Taxes" requirement to reduce
goodwill for the excess of tax benefits not previously recognized. See Note 6 to
the Company's Consolidated Financial Statements in Item 8 of Part II of this
report. The adoption of SFAS No. 142 has not had, nor is it expected to have, a
material impact on the Company's consolidated results of operations, financial
position or cash flows.

FORWARD-LOOKING STATEMENTS

Certain written and oral statements made or incorporated by reference from
time to time by the Company or its representatives are "forward-looking
statements" within the meaning of Section 27A of the Securities Act of 1933, as
amended (the "Securities Act"), and Section 21E of 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 be," "will continue," "will
likely result," "project," "forecast," "budget" and similar expressions.
Statements

29

by the Company in this report that contain forward-looking statements include,
but are not limited to, information concerning possible or assumed future
results of operations of the Company and statements about the following
subjects:

- future market conditions and the effect of such conditions on the
Company's future results of operations (see "-- Industry Conditions");

- future uses of and requirements for financial resources, including, but
not limited to, expenditures related to the upgrades of the Ocean Rover
and three of the Company's jack-up rigs (see "Business -- The Fleet -
Fleet Enhancements", "-- Liquidity" and "-- Capital Resources");

- interest rate and foreign exchange risk (see "Quantitative and
Qualitative Disclosures About Market Risk");

- future contractual obligations (see "-- Liquidity -- Contractual Cash
Obligations");

- business strategy;

- growth opportunities;

- competitive position;

- expected financial position;

- future cash flows;

- future dividends;

- financing plans;

- budgets for capital and other expenditures;

- timing and cost of completion of rig upgrades and other capital projects;

- delivery dates and drilling contracts related to rig conversion and
upgrade projects;

- plans and objectives of management;

- performance of contracts;

- outcomes of legal proceedings;

- compliance with applicable laws; and

- adequacy of insurance or indemnification.

Such statements inherently are subject to a variety of risks and
uncertainties that could cause actual results to differ materially from those
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 the Organization of Petroleum Exporting Countries,
commonly called OPEC, to set and maintain production levels and pricing,
and the level of production in non-OPEC countries;

- policies of 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;

30

- 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;

- 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 the Company's sources of liquidity;

- risks inherent in turnkey operations, including the risk of failure to
complete a well and cost overruns;

- the availability of qualified personnel to operate and service the
Company's drilling rigs; and

- various other matters, many of which are beyond the Company's control.

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

31

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.

The Company's measure of market risk exposure represents an estimate of the
change in fair value of its financial instruments. Market risk exposure is
presented for each class of financial instrument held by the Company at December
31, 2002 and 2001 assuming immediate adverse market movements of the magnitude
described below. The Company believes 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 nor any expected actual loss, even under adverse conditions, because actual
adverse fluctuations would likely differ. In addition, since the Company's
investment portfolio is subject to change based on its portfolio management
strategy as well as in response to changes in the market, these estimates are
not necessarily indicative of the actual results which may occur.

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

INTEREST RATE RISK

The Company has exposure to interest rate risk arising from changes in the
level or volatility of interest rates. The Company's investments in marketable
securities are primarily in fixed maturity securities. The Company monitors its
sensitivity to interest rate risk by evaluating the change in the value of its
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 the Company's
investments and the resulting effect on shareholders' equity. The analysis
presents the sensitivity of the market value of the Company's financial
instruments to selected changes in market rates and prices which the Company
believes are reasonably possible over a one-year period.

The sensitivity analysis estimates the change in the market value of the
Company's interest sensitive assets and liabilities that were held on December
31, 2002 and 2001 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 of market interest rates on the Company's
earnings or shareholders' equity. Further, the computations do not contemplate
any actions the Company could undertake in response to changes in interest
rates.

The Company's long-term debt, as of December 31, 2002 and 2001 is
denominated in U.S. Dollars. The Company's 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 $153.8 and $154.3
million, respectively. A 100 basis point decrease would result in an increase in
market value of $192.7 and $195.3 million, 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.
As of December 31, 2002, the Company had contracted to purchase 50.0 million
Australian dollars, 4.2 million Australian dollars to be purchased monthly from

32

August 29, 2002 through June 26, 2003 and 3.8 million to be purchased on July
31, 2003. These foreign exchange forward contracts are recorded at their fair
value determined by discounting future cash flows at current forward rates. At
December 31, 2002, an asset of $0.2 million reflecting the fair value of the
forward contracts, was included with "Prepaid expenses and other" in the
Consolidated Balance Sheet. At December 31, 2001 the Company had contracted to
purchase 3.5 million Australian dollars each month through July 31, 2002. At
December 31, 2001, an asset of $0.1 million reflecting the fair value of the
forward contracts, was included with "Prepaid expenses and other" in the
Consolidated Balance Sheet. The sensitivity analysis assumes an instantaneous
20% change in the foreign currency exchange rates versus the U.S. Dollar from
their levels at December 31, 2002 and 2001, with all other variables held
constant.

The following table presents the Company's market risk by category
(interest rates and foreign currency exchange rates):

- ---------------

(a) The fair market value of the Company's investment in marketable securities
is based on the quoted closing market prices on December 31, 2002 and 2001.

(b) The fair values of the Company's 1.5% Debentures and Zero Coupon Debentures
are based on the quoted closing market prices on December 31, 2002 and 2001.
The fair value of the Company's Ocean Alliance lease-leaseback agreement is
based on the present value of estimated future cash flows using a discount
rate of 6.62% for 2002 and 7.59% for 2001.

(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, 2002 and 2001.

(d) The calculation of estimated market risk exposure is based on assumed
adverse changes in the underlying reference price or index of a decrease in
foreign exchange rates of 20% at December 31, 2002 and 2001.

33

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.

INDEPENDENT AUDITORS' REPORT

Board of Directors and Stockholders
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, 2002
and 2001, and the related consolidated statements of income, stockholders'
equity, comprehensive income and cash flows for each of the three years in the
period ended December 31, 2002. These financial statements are the
responsibility of the Company's management. Our responsibility is to express an
opinion on these financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally
accepted in the United States of America. 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, 2002 and 2001, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 2002, in conformity with accounting principles generally accepted
in the United States of America.

As discussed in Note 1 to the financial statements, in 2002 the Company
changed its method of accounting for goodwill to conform to Statement of
Financial Accounting Standards No. 142.

Deloitte & Touche LLP
Houston, Texas
January 28, 2003

34

DIAMOND OFFSHORE DRILLING, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS, EXCEPT SHARE AND PER SHARE DATA)

ASSETS

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

35

DIAMOND OFFSHORE DRILLING, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME
(IN THOUSANDS, EXCEPT PER SHARE DATA)

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

36

DIAMOND OFFSHORE DRILLING, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
(IN THOUSANDS, EXCEPT NUMBER OF SHARES)

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

37

DIAMOND OFFSHORE DRILLING, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(IN THOUSANDS)

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

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DIAMOND OFFSHORE DRILLING, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN THOUSANDS)

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

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DIAMOND OFFSHORE DRILLING, INC.
AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Organization and Business

Diamond Offshore Drilling, Inc. (the "Company") was incorporated in
Delaware on April 13, 1989. Loews Corporation ("Loews"), a Delaware corporation
of which the Company had been a wholly owned subsidiary prior to the initial
public offering in October 1995 (the "Common Stock Offering"), owns 53.8% of the
outstanding common stock of the Company at December 31, 2002.

The Company, through wholly owned subsidiaries, engages in the worldwide
contract drilling of offshore oil and gas wells and is a leader in deep water
drilling. Currently, the fleet is comprised of 31 semisubmersible rigs, 14
jack-up rigs and one drillship.

Principles of Consolidation

The consolidated financial statements include the accounts of the Company
and its subsidiaries after elimination of significant intercompany transactions
and balances.

Cash and Cash Equivalents and Marketable Securities

Short-term, highly liquid investments that have an original maturity of
three months or less and deposits in money market mutual funds that are readily
convertible into cash are considered cash equivalents. Cash equivalents at
December 31, 2001 included $199.1 million of invested cash deposits received in
connection with securities sold under repurchase agreements. There were no
securities sold under repurchase agreements at December 31, 2002. See
"Securities Sold Under Agreements to Repurchase."

The Company's investments are classified as available for sale and stated
at fair value. Accordingly, any unrealized gains and losses, net of taxes, are
reported in the Consolidated Balance Sheets in "Accumulated other comprehensive
losses" until realized. The cost of debt securities is adjusted for amortization
of premiums and accretion of discounts to maturity and such adjustments are
included in the Consolidated Statements of Income in "Interest income." The sale
and purchase of securities are recorded on the date of the trade. The cost of
debt securities sold is based on the specific identification method and the cost
of equity securities sold is based on the average cost method. Realized gains or
losses and declines in value, if any, judged to be other than temporary are
reported in the Consolidated Statements of Income in "Other income (expense)."

Securities Sold Under Agreements to Repurchase

The Company accounts for repurchase agreements in accordance with Statement
of Financial Accounting Standards ("SFAS") No. 140, "Accounting for Transfers
and Servicing of Financial Assets and Extinguishments of Liabilities." From time
to time the Company may lend securities to unrelated parties, primarily major
brokerage firms. Borrowers of these securities must transfer to the Company cash
collateral equal to the securities transferred. Cash deposits from these
transactions are invested in short-term investments and are included in the
Consolidated Balance Sheets in "Cash and cash equivalents." A liability is
recognized for the obligation to return the cash collateral. The Company
continues to receive interest income on the loaned debt securities, as
beneficial owner, and accordingly, the loaned debt securities are included in
the Consolidated Balance Sheets in "Marketable securities." Interest expense
associated with the related liability is recorded as an offset to "Interest
income" in the Consolidated Statements of Income. The Company did not have any
loaned debt securities outstanding at December 31, 2002. At December 31, 2001
the fair value of collateral from loaned debt securities was $198.7 million.

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Derivative Financial Instruments

The Company accounts for derivative financial instruments in accordance
with SFAS No. 133, "Accounting for Derivative Instruments and Hedging
Activities" and its corresponding amendments under SFAS No. 138. Derivative
financial instruments of the Company include forward exchange contracts and a
contingent interest provision that is embedded in the 1.5% convertible senior
debentures due 2031 (the "1.5% Debentures") issued on April 11, 2001. See Note
4.

Supplementary Cash Flow Information

Cash payments made for interest on long-term debt, including commitment
fees, totaled $10.2 million, $17.1 million, and $15.0 million during the years
ended December 31, 2002, 2001, and 2000, respectively.

Cash payments for foreign income taxes, net of foreign tax refunds, were
$14.7 million, $4.3 million, and $15.1 million during the years ended December
31, 2002, 2001, and 2000, respectively. A $17.3 million net cash refund of U.S.
income tax was received during the year ended December 31, 2002. Cash payments
for U.S. income taxes made during the years ended December 31, 2001 and 2000
were $28.8 and $10.7, respectively.

Rig Inventory and Supplies

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

Drilling and Other Property and Equipment

Drilling and other property and equipment is carried at cost. Maintenance
and routine repairs are charged to income currently while replacements and
betterments, which meet certain criteria, are capitalized. Costs incurred for
major rig upgrades are accumulated in construction work-in-progress, with no
depreciation recorded on the additions, until the month the upgrade is completed
and the rig is placed in service. Upon retirement or sale of a rig, the cost and
related accumulated depreciation are removed from the respective accounts and
any gains or losses are included in the results of operations. Depreciation is
provided on the straight-line method over the remaining estimated useful lives
from the year the asset is placed in service.

Capitalized Interest

Interest cost for construction and upgrade of qualifying assets is
capitalized. A reconciliation of the Company's total interest cost to "Interest
expense" as reported in the Consolidated Statements of Income is as follows:

Impairment of Long-Lived Assets

The Company reviews its long-lived assets for impairment when changes in
circumstances indicate that the carrying amount of an asset may not be
recoverable. The Company evaluated all of the cold stacked rigs in its fleet
during 2002 and no instance of impairment was noted.

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Goodwill

Prior to January 1, 2002, goodwill from the merger with Arethusa
(Off-Shore) Limited ("Arethusa") had been amortized on a straight-line basis
over 20 years. The Company adopted SFAS No. 142, "Goodwill and Other Intangible
Assets" on January 1, 2002 and, accordingly, has suspended amortization of
goodwill. On January 1, 2002, goodwill and accumulated amortization was $69.0
million and $30.7 million, respectively. Amortization charged to operating
expense during the years ended December 31, 2001 and 2000 totaled $3.3 million
and $4.5 million, respectively.

Adjustments of $13.6 million during each of the years ended December 31,
2002, 2001 and 2000 were recorded to reduce goodwill. The adjustments represent
the tax benefits not previously recognized for the excess of tax deductible
goodwill over book goodwill. The Company will continue to reduce goodwill in
future periods as the tax benefits of excess tax goodwill over book goodwill are
recognized. Goodwill is expected to be reduced to zero during the year 2004. See
Note 6.

Debt Issuance Costs

Debt issuance costs are included in the Consolidated Balance Sheets in
"Other assets" and are amortized over the term of the related debt.

Deferred Income Taxes

Deferred income taxes reflect the net tax effects of temporary differences
between the carrying amounts of assets and liabilities for financial reporting
purposes and the amounts used for income tax purposes. The Company's non-U.S.
income tax liabilities are based upon the results of operations of the various
subsidiaries and foreign branches in those jurisdictions in which they are
subject to taxation. Beginning in 2001, the Company decided to indefinitely
reinvest a portion of the earnings of its U.K. subsidiaries. Consequently, no
U.S. deferred taxes were provided on these earnings in 2002 or in 2001.

Treasury Stock and Common Equity Put Options

Depending on market conditions, the Company may, from time to time,
purchase shares of its common stock or issue put options in the open market or
otherwise. The purchase of treasury stock is accounted for using the cost method
which reports the cost of the shares acquired in "Treasury stock" as a deduction
from stockholders' equity in the Consolidated Balance Sheets.

During the year ended December 31, 2002 the Company purchased 1,716,700
shares of its common stock at an aggregate cost of $43.4 million, or at an
average cost of $25.30 per share. This includes the Company's purchase of
500,000 shares of its common stock at an aggregate cost of $20.0 million, or at
an average cost of $40.00 per share, upon the exercise of put options sold in
February 2001. The Company reduced "Additional paid-in-capital" in the
Consolidated Balance Sheet by $3.1 million, the amount of the premium received
for the sale of these put options, and reported the net cost of the shares,
$16.9 million, in "Treasury stock." During the year ended December 31, 2001, the
Company purchased 1,403,900 shares of its common stock at an aggregate cost of
$37.8 million, or at an average cost of $26.90 per share.

As of December 31, 2002, Loews owned 53.8% of the outstanding shares of
common stock of the Company. The Company had been a wholly owned subsidiary of
Loews prior to its initial public offering in October 1995. The increase of
Loews ownership from 53.1% at December 31, 2001 to 53.8% at December 31, 2002 is
a result of the Company's purchase of its common stock during 2002.

The Company settled put options which covered 1,000,000 shares of its
common stock during the year ended December 31, 2002 with cash payments totaling
$1.2 million and reduced "Additional paid-in-capital" in the Consolidated
Balance Sheet for amounts paid to settle these put options. The Company's
remaining put options sold in 2001, which covered 187,321 shares of the
Company's common stock, expired during 2002. There were no common equity put
options outstanding at December 31, 2002.

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During the year ended December 31, 2001, the Company received premiums of
$6.9 million for the sale of put options covering 1,687,321 shares of common
stock. The options gave the holders the right to require the Company to
repurchase up to the contracted number of shares of its common stock at the
stated exercise price per share at any time prior to their expiration. The
Company had the option to settle in cash or shares of common stock. Premiums
received for these options were recorded in "Additional paid-in-capital" in the
Consolidated Balance Sheets. As of December 31, 2001 there were put options
outstanding which covered 1,687,321 shares of the Company's common stock at
various stated exercise prices at various expiration dates.

Stock-Based Compensation

In 2000 the Company adopted a stock option plan ("2000 Stock Option Plan")
whereby certain of the Company's employees, consultants and non-employee
directors may be granted options to purchase stock. The Company accounts for the
2000 Stock Option Plan under Accounting Principles Board Opinion No. 25,
"Accounting for Stock Issued to Employees" and related Interpretations. See Note
13. No stock-based employee compensation cost is reflected in net income, as all
options granted under this plan had an exercise price equal to the market value
of the underlying common stock on the date of grant.

The following table illustrates the effect on net income and earnings per
share if the Company had applied the fair value recognition provisions of SFAS
No. 123, "Accounting for Stock-Based Compensation," to stock-based employee
compensation.

Comprehensive Income

Comprehensive income is the change in equity of a business enterprise
during a period from transactions and other events and circumstances except
those transactions resulting from investments by owners and distributions to
owners. Comprehensive income includes net income, foreign currency translation
gains and losses, minimum pension liability adjustments and unrealized holding
gains and losses on marketable securities. See Note 9.

Currency Translation

The Company's primary functional currency is the U.S. dollar. Certain of
the Company's subsidiaries use the local currency in the country where they
conduct operations as their functional currency. These subsidiaries translate
assets and liabilities at year-end exchange rates while income and expense
accounts are translated at average exchange rates. Translation adjustments are
reflected in the Consolidated Balance Sheets in "Accumulated other comprehensive
losses." Currency transaction gains and losses are included in the Consolidated
Statements of Income in "Other income (expense)." Additionally, translation
gains and losses of subsidiaries operating in hyperinflationary economies are
included in operating results.

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Revenue Recognition

Income from dayrate drilling contracts is recognized currently. In
connection with such drilling contracts, the Company may receive lump-sum fees
for the mobilization of equipment and personnel. The excess of mobilization fees
received over costs incurred to mobilize an offshore rig from one market to
another is recognized in income over the primary term of the related drilling
contract. Absent a contract, mobilization costs are recognized currently.
Lump-sum payments received from customers relating to specific contracts are
deferred and amortized to income over the primary term of the drilling contract.

Income from offshore turnkey drilling contracts is recognized on the
completed contract method, with revenues accrued to the extent of costs until
the specified turnkey depth and other contract requirements are met. Provisions
for future losses on turnkey drilling contracts are recognized when it becomes
apparent that expenses to be incurred on a specific contract will exceed the
revenue from that contract.

Income from reimbursements received for the purchase of supplies,
equipment, personnel services and other services provided at the request of the
customer in accordance with a contract or agreement is recorded, for the gross
amount billed to the customer, as "Revenues related to reimbursable expenses" in
the Consolidated Statements of Income. Prior to 2002 and the guidance provided
by the Emerging Issues Task Force ("EITF") 01-14 "Income Statement
Characterization of Reimbursements Received for "Out-of-Pocket" Expense
Incurred," the Company accounted for reimbursements, in most instances, as a
reduction of expenses incurred. All comparative periods presented have been
reclassified to comply with this guidance.

Accounting Pronouncements

In December 2002 the Financial Accounting Standards Board ("FASB") issued
SFAS No. 148, "Accounting for Stock-Based Compensation-Transition and
Disclosure." SFAS No. 148 amends SFAS No. 123, "Accounting for Stock-Based
Compensation," to provide alternative methods of transition for a voluntary
change to the fair value based method of accounting for stock-based employee
compensation. In addition, SFAS No. 148 amends the disclosure requirements of
SFAS No. 123 to require prominent disclosures in both annual and interim
financial statements regarding the method of accounting for stock-based employee
compensation and the effect of the method used on reported results. SFAS No. 148
is effective for financial statements for fiscal years ending after December 15,
2002. The Company accounts for stock-based employee compensation in accordance
with Accounting Principles Board ("APB") Opinion No. 25, "Accounting for Stock
Issued to Employees." However, the Company has adopted the provisions of SFAS
No. 148 which require prominent disclosure regarding the method of accounting
for stock-based employee compensation in its annual financial statements and
will be including such disclosure in its future interim financial statements.

In July 2002 the FASB issued SFAS No. 146, "Accounting for costs associated
with exit or disposal activities." SFAS No. 146 requires companies to recognize
costs associated with exit or disposal activities when they are incurred rather
than at the date of a commitment to an exit or disposal plan. SFAS No. 146 is to
be applied prospectively to exit or disposal activities initiated after December
31, 2002. The Company does not expect the adoption of SFAS No. 146 to have a
material impact on the Company's consolidated results of operations, financial
position or cash flows.

In April 2002 the FASB issued SFAS No. 145, "Rescission of FASB Statements
No. 4, 44, and 64, Amendment to FASB Statement No. 13, and Technical
Corrections." The rescission of SFAS No. 4 and 64 by SFAS No. 145 streamlines
the reporting of debt extinguishments and requires that only gains and losses
from extinguishments meeting the criteria in APB Opinion 30, "Reporting the
Results of Operations -- Reporting the Effects of Disposal of a Segment of a
Business, and Extraordinary, Unusual and Infrequently Occurring Events and
Transactions" would be classified as extraordinary. Thus, gains or losses
arising from extinguishments that are part of a company's recurring operations
would not be reported as an extraordinary item. SFAS No. 145 is effective for
fiscal years beginning after May 15, 2002 with earlier adoption encouraged. The
Company adopted SFAS No. 145 in April 2002 and, accordingly, reclassified its
April 2001 loss of $7.7 million, net-of-tax, from early extinguishment of debt,
as a result of the Company's redemption of the outstanding 3.75% Convertible
subordinated note due 2007 (the "3.75% Notes") out of extraordinary

44

items. The pre-tax loss from early extinguishment of debt of $11.9 million was
reclassified to "Interest expense" and the related tax benefit was reclassified
to "Income tax expense" in the Consolidated Statement of Income.

In October 2001 the FASB issued SFAS No. 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets." SFAS No. 144 replaces SFAS No.
121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived
Assets to Be Disposed Of" and provides updated guidance concerning the
recognition and measurement of an impairment loss for certain types of
long-lived assets. SFAS No. 144 is effective for fiscal years beginning after
December 15, 2001. The adoption of SFAS No. 144 by the Company in January 2002
has not had, nor is it expected to have, a material impact on the Company's
consolidated results of operations, financial position or cash flows.

In August 2001 the FASB issued SFAS No. 143, "Accounting for Asset
Retirement Obligations." SFAS No. 143 addresses financial accounting and
reporting obligations associated with the retirement of tangible long-lived
assets and the associated asset retirement costs. SFAS No. 143 is effective for
fiscal years beginning after June 15, 2002 with early adoption encouraged.
Adoption of SFAS No. 143 in 2003 is not expected to have a material impact on
the Company's consolidated results of operations, financial position or cash
flows.

In June 2001 the FASB issued two new pronouncements, SFAS No. 141,
"Business Combinations" and SFAS No. 142, "Goodwill and Other Intangible
Assets." SFAS No. 141 requires that all business combinations be accounted for
by the purchase method and applies to all business combinations initiated after
June 30, 2001 and also applies to all business combinations accounted for using
the purchase method for which the date of acquisition is July 1, 2001 or later.
There are also transition provisions that apply to business combinations
completed before July 1, 2001, that were accounted for by the purchase method.
SFAS No. 142 is effective for fiscal years beginning after December 15, 2001 for
all goodwill and other intangible assets recognized in an entity's statement of
financial position at that date, regardless of when those assets were initially
recognized. The Company adopted SFAS No. 142 on January 1, 2002 and has
suspended amortization of goodwill which was $3.3 million and $4.5 million for
the years ended December 31, 2001 and 2000, respectively. SFAS No. 142 does not
change the SFAS No. 109 "Accounting for Income Taxes" requirement to reduce
goodwill for the excess of tax benefits not previously recognized. See Note 6.
The adoption of SFAS No. 142 has not had, nor is it expected to have, a material
impact on the Company's consolidated results of operations, financial position
or cash flows.

Use of Estimates in the Preparation of Financial Statements

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

Reclassifications

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

Fair Value of Financial Instruments

The Company provides fair value information of its financial instruments in
the notes to the consolidated financial statements. See Note 11. The carrying
amount of the Company's current financial instruments approximate fair value
because of the short maturity of these instruments. For non-current financial
instruments the Company uses quoted market prices when available and discounted
cash flows to estimate fair value.

45

2. EARNINGS PER SHARE

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

The computation of diluted earnings per share ("EPS") for the years ended
December 31, 2002, 2001 and 2000 excludes approximately 6.9 million potentially
dilutive shares issuable upon conversion of the Company's zero coupon
convertible debentures due 2020 (the "Zero Coupon Debentures"), issued in June
2000. The inclusion of such shares would be antidilutive.

Put options covering 1,687,321 shares of common stock at various stated
exercise prices per share were outstanding during part of 2002 prior to their
expiration or settlement. All of these put options were outstanding at December
31, 2001. However, the computation of diluted EPS for the years ended December
31, 2002 and 2001 excluded put options covering 187,321 shares of common stock.
Put options covering 750,000 shares of common stock at an exercise price of
$37.85 per share were outstanding at December 31, 2000 but were excluded from
the computation of diluted EPS. Certain put options were excluded from the
computation of diluted EPS because the options' exercise prices were less than
the average market price per share of the common stock.

The computation of diluted EPS for the years ended December 31, 2002 and
2001 did not include stock options representing 377,525 shares and 182,700
shares of common stock, respectively. The incremental shares calculated from
non-qualified stock options included in the computation of diluted EPS for the
year ended December 31, 2000 were immaterial for presentation purposes. The
computation of diluted EPS for the year ended December 31, 2000 did not include
stock options representing 86,500 shares of common stock. Certain stock options
were excluded because the options' exercise prices were more than the average
market price per share of the common stock.

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3. MARKETABLE SECURITIES

Investments classified as available for sale are summarized as follows:

All of the Company's investments are included as current assets in the
Consolidated Balance Sheets in "Marketable securities," representing the
investment of cash available for current operations.

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

4. DERIVATIVE FINANCIAL INSTRUMENTS

Forward Exchange Contracts

The Company operates internationally, resulting in exposure to foreign
exchange risk. This risk is primarily associated with costs payable in foreign
currencies for employee compensation and for purchases from foreign suppliers.
The Company's primary technique for minimizing its foreign exchange risk
involves structuring customer contracts to provide for payment in both the U.S.
dollar and the foreign currency whenever possible. The payment portion
denominated in the foreign currency is based on anticipated foreign currency
requirements over the contract term. In some instances, when customer contracts
cannot be structured to generate a sufficient amount of foreign currency for
operating purposes, a foreign exchange forward contract may be used to minimize
the forward exchange risk. A forward exchange contract obligates the Company to
exchange predetermined amounts of specified foreign currencies at specified
foreign exchange rates on specified dates.

In June 2002 the Company entered into forward contracts to purchase 50.0
million Australian dollars, 4.2 million Australian dollars to be purchased
monthly from August 29, 2002 through June 26, 2003 and 3.8 million to be
purchased on July 31, 2003. In July 2001 the Company entered into twelve forward
contracts to purchase 3.5 million Australian dollars at each month end through
July 31, 2002. These forward contracts

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are derivatives as defined by SFAS No. 133. SFAS No. 133 requires that each
derivative be stated in the balance sheet at its fair value with gains and
losses reflected in the income statement except that, to the extent the
derivative qualifies for hedge accounting, the gains and losses are reflected in
income in the same period as offsetting losses and gains on the qualifying
hedged positions. SFAS No. 133 further provides specific criteria necessary for
a derivative to qualify for hedge accounting. The forward contracts purchased by
the Company in 2002 and 2001 do not qualify for hedge accounting.

Contingent Interest

On April 11, 2001, the Company issued 1.5% Debentures in the amount of
$460.0 million which are due April 15, 2031, and contain a contingent interest
provision. See Note 8. The contingent interest component is an embedded
derivative as defined by SFAS No. 133 and accordingly must be split from the
host instrument and recorded at fair value on the balance sheet. The contingent
interest component had no value at issuance or at December 31, 2002 and 2001.

5. DRILLING AND OTHER PROPERTY AND EQUIPMENT

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

Construction work-in-progress at December 31, 2002, included approximately
$119.1 million primarily for the significant upgrade of the Ocean Rover to high
specification capabilities.

In December 2002, Diamond Offshore Drilling Limited, a subsidiary of the
Company, completed the acquisition of the third-generation semisubmersible
drilling rig, West Vanguard, renamed Ocean Vanguard, for $68.5 million. The
Company capitalized $67.0 million to drilling rigs and equipment and $1.5
million to rig inventory.

In March 2002, approximately $157.4 million was reclassified from
construction work-in-progress to drilling rigs and equipment upon completion of
the significant upgrade of the Ocean Baroness to high specification
capabilities.

6. GOODWILL

Goodwill from the merger with Arethusa in 1996 was generated from an excess
of the purchase price over the net assets acquired. Prior to January 1, 2002 the
Company was amortizing goodwill on a straight-line basis over 20 years. The
Company adopted SFAS No. 142 on January 1, 2002 and, accordingly, has suspended
amortization of goodwill in 2002.

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The Company's net income and earnings per share, adjusted to exclude
amortization expense (net of its related tax benefit) for the years ended
December 31, 2002, 2001 and 2000 are as follows:

For purposes of applying SFAS No. 142, the Company determined that it has
one reporting unit to which to assign goodwill. As of January 1, 2002, the
Company performed the transitional goodwill impairment test and determined that
the fair value of the reporting unit exceeded its carrying value, and
accordingly, no further testing for goodwill impairment was required.

There were no recognized intangible assets other than goodwill associated
with the Arethusa merger.

During each of the years ended December 31, 2002, 2001 and 2000, an
adjustment of $13.6 million was recorded in each year to reduce goodwill before
accumulated amortization. The adjustments represent tax benefits not previously
recognized for the excess of tax deductible goodwill over the book goodwill
amount. The Company will continue to reduce goodwill in future periods as the
tax benefits of excess tax goodwill over book goodwill is recognized. Goodwill
is expected to be reduced to zero during the year 2004.

At December 31, 2002, the Company performed its annual impairment test and
no evidence of impairment was noted.

7. ACCRUED LIABILITIES

Accrued liabilities consist of the following:

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8. LONG-TERM DEBT

Long-term debt consists of the following:

The aggregate maturities of long-term debt for each of the five years
subsequent to December 31, 2002, are as follows:

Convertible Subordinated Notes

On April 6, 2001, the Company redeemed all of its outstanding 3.75% Notes
in accordance with the indenture under which the 3.75% Notes were issued. Prior
to April 6, 2001, $12.4 million principal amount of the 3.75% Notes had been
converted into 307,071 shares of the Company's common stock, par value $0.01 per
share, at the stated conversion price of $40.50 per share. The remaining $387.6
million principal amount of the 3.75% Notes was redeemed at 102.08% of the
principal amount thereof plus accrued interest for a total cash payment of
$397.7 million resulting in an after-tax charge of $7.7 million ($11.9 million
which is reported in "Interest expense" partially offset by a tax benefit of
$4.2 million recorded in "Income tax expense" in the Consolidated Statement of
Income.)

Convertible Senior Debentures

On April 11, 2001, the Company 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 the Company's common stock at an initial conversion
rate of 20.3978 shares per $1,000 principal amount of the 1.5% Debentures,
subject to adjustment in certain circumstances. Upon conversion, the Company has
the right to deliver cash in lieu of shares of the Company's common stock. The
transaction resulted in net proceeds of approximately $449.1 million.

Interest of 1.5% per year on the outstanding principal amount is payable
semiannually in arrears on April 15 and October 15 of each year, beginning
October 15, 2001. The 1.5% Debentures are unsecured obligations of the Company
and rank equally with all of the Company's other unsecured senior indebtedness.

The Company will pay contingent interest to holders of the 1.5% Debentures
during any six-month period commencing after April 15, 2008 if the average
market price of a 1.5% Debenture for a measurement period

50

preceding such six-month period equals 120% or more of the principal amount of
such 1.5% Debenture and the Company pays a regular cash dividend during such
six-month period. The contingent interest payable per $1,000 principal amount of
1.5% Debentures, in respect of any quarterly period, will equal 50% of regular
cash dividends paid by the Company per share on its common stock during that
quarterly period multiplied by the conversion rate. This contingent interest
component is an embedded derivative, which had no fair value at issuance or on
December 31, 2002 or December 31, 2001.

Holders may require the Company 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. The
Company may choose to pay the purchase price in cash or shares of the Company's
common stock or a combination of cash and common stock. In addition, holders may
require the Company to purchase, for cash, all or a portion of their 1.5%
Debentures upon a change in control (as defined).

The Company 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 Convertible Debentures

On June 6, 2000, the Company issued Zero Coupon Debentures due 2020 at a
price of $499.60 per $1,000 debenture, which represents a yield to maturity of
3.50% per year. The Company will not pay interest prior to maturity unless it
elects 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 the Company's common stock at a fixed conversion rate of 8.6075
shares of common stock per Zero Coupon Debenture, subject to adjustments in
certain events. The Zero Coupon Debentures are senior unsecured obligations of
the Company.

The Company has the right to redeem the Zero Coupon Debentures, in whole or
in part, after June 6, 2005, for a price equal to the issuance price plus
accrued original issue discount through the date of redemption. Holders have the
right to require the Company to repurchase the Zero Coupon Debentures on the
fifth, tenth and fifteenth anniversaries of issuance at the accreted value
through the date of repurchase. The Company may pay such repurchase price with
either cash or shares of the Company's common stock or a combination of cash and
shares of common stock.

Ocean Alliance Lease-Leaseback

In December 2000 the Company entered into a lease-leaseback agreement with
a European bank. The lease-leaseback agreement provides for the Company to lease
the Ocean Alliance, one of the Company's high specification semisubmersible
drilling rigs, to the bank for a lump-sum payment of $55.0 million plus an
origination fee of $1.1 million and for the bank to then sub-lease the rig back
to the Company. Under the agreement, which has a five-year term, the Company is
to make five annual payments of $13.7 million. Two of the five annual payments
have been made as of December 31, 2002. This financing arrangement has an
effective interest rate of 7.13% and is an unsecured subordinated obligation of
the Company.

51

9. COMPREHENSIVE INCOME

The income tax effects allocated to the components of other comprehensive
income are as follows:

10. COMMITMENTS AND CONTINGENCIES

The Company leases office facilities under operating leases, which expire
through the year 2007. Total rent expense amounted to $1.4 million, $1.0 million
and $1.2 million for the years ended December 31, 2002, 2001 and 2000,
respectively. Minimum future rental payments under leases are approximately $1.1
million, $0.4 million, $0.2 million, $0.1 million and $17,000 for the years 2003
to 2007, respectively. There are no minimum future rental payments under leases
after the year 2007.

The Company is contingently liable as of December 31, 2002 in the amount of
$16.1 million under certain performance, bid, customs and export bonds. On the
Company's behalf, banks have issued letters of credit securing certain of these
bonds.

Various claims have been filed against the Company in the ordinary course
of business, including claims by offshore workers alleging personal injuries. In
the opinion of management, no pending or threatened claims, actions or
proceedings against the Company are expected to have a material adverse effect
on the Company's consolidated financial position, results of operations, or cash
flows.

52

11. FINANCIAL INSTRUMENTS

Concentrations of Credit and Market Risk

Financial instruments which potentially subject the Company to significant
concentrations of credit or market risk consist primarily of periodic temporary
investments of excess cash and trade accounts receivable and investments in debt
securities, including treasury inflation-indexed protected bonds ("TIP's") and
collateralized mortgage obligations ("CMO's"). The Company places its temporary
excess cash investments in high quality short-term money market instruments
through several financial institutions. At times, such investments may be in
excess of the insurable limit. The Company's periodic evaluations of the
relative credit standing of these financial institutions are considered in the
Company's investment strategy.

Concentrations of credit risk with respect to trade accounts receivable are
limited primarily due to the entities comprising the Company's customer base.
Since the market for the Company's services is the offshore oil and gas
industry, this customer base consists primarily of major oil companies and
independent oil and gas producers. The Company provides allowances for potential
credit losses when necessary. No such allowances were deemed necessary for the
years presented and, historically, the Company has not experienced significant
losses on trade receivables. All of the Company's investments in debt securities
are U.S. government securities or government-backed with minimal credit risk.
However, the Company is exposed to market risk due to price volatility
associated with interest rate fluctuations.

Fair Values

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

The estimated fair value amounts have been determined by the Company using
appropriate valuation methodologies and information available to management as
of December 31, 2002 and 2001. Considerable judgment is required in developing
these estimates, and accordingly, no assurance can be given that the estimated
values are indicative of the amounts that would be realized in a free market
exchange. The following methods and assumptions were used to estimate the fair
value of each class of financial instrument for which it was practicable to
estimate that value:

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

Marketable securities -- The fair values of the debt securities,
including TIP's and CMO's, available for sale were based on the quoted
closing market prices on December 31, 2002 and 2001.

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

Long-term debt -- The fair value of the Zero Coupon Debentures and the
1.5% Debentures was based on the quoted closing market price on December
31, 2002 and 2001 from brokers of these instruments. The fair value of the
Ocean Alliance lease-leaseback agreement was based on the present value of
estimated future cash flows using a discount rate of 6.62%.

53

12. RELATED PARTY TRANSACTIONS

The Company and Loews entered into a services agreement which was effective
upon consummation of the Common Stock Offering (the "Services Agreement")
pursuant to which Loews agreed to continue to perform certain administrative and
technical services on behalf of the Company. Such services include personnel,
telecommunications, purchasing, internal auditing, accounting, data processing
and cash management services, in addition to advice and assistance with respect
to preparation of tax returns and obtaining insurance. Under the Services
Agreement, the Company is required to reimburse Loews for (i) allocated
personnel costs (such as salaries, employee benefits and payroll taxes) of the
Loews personnel actually providing such services and (ii) all out-of-pocket
expenses related to the provision of such services. The Services Agreement may
be terminated at the Company's option upon 30 days' notice to Loews and at the
option of Loews upon six months' notice to the Company. In addition, the Company
has agreed to indemnify Loews for all claims and damages arising from the
provision of services by Loews under the Services Agreement unless due to the
gross negligence or willful misconduct of Loews. The Company was charged $0.3
million, $0.3 million and $0.4 million by Loews for these support functions
during the years ended December 31, 2002, 2001 and 2000, respectively.

13. STOCK OPTION PLAN

The Company's 2000 Stock Option Plan provides for issuance of either
incentive stock options or non-qualified stock options to the Company's
employees, consultants and non-employee directors. Options may be granted to
purchase stock at no less than 100% of the market price of the stock on the date
the option is granted. Such plan reserved for issuance up to 750,000 shares of
the Company's common stock, none of which had been issued as of December 31,
2002. Unless otherwise specified by the Board of Directors at the time of the
grant, stock options have a maximum term of ten years, subject to earlier
termination under certain conditions and vest over four years.

The following table summarizes the stock option activity related to the
2000 Stock Option Plan:

The following table summarizes information for options outstanding and
exercisable at December 31, 2002:

The Company accounts for the 2000 Stock Option Plan in accordance with
Accounting Principle Board Opinion No. 25, "Accounting for Stock Issued to
Employees." Accordingly, no compensation expense has been recognized for the
options granted under the plan. Had compensation expense for the Company's stock
options been recognized based on the fair value of the options at the grant
dates, using the methodology

54

prescribed by SFAS No. 123, "Accounting for Stock-Based Compensation," the
Company's net income and earnings per share would have been reduced to the pro
forma amounts indicated below:

The per share weighted-average fair value of stock options granted during
2002, 2001 and 2000 was $10.59, $14.60 and $26.71, respectively. The fair value
of options granted in 2002, 2001 and 2000 has been estimated at the date of
grant using a Binomial Option Pricing Model with the following weighted average
assumptions:

14. INCOME TAXES

The components of income tax expense are as follows:

55

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

Significant components of the Company's deferred income tax assets and
liabilities are as follows:

- ---------------

(1) Reflected in "Prepaid expenses and other" in the Company's Consolidated
Balance Sheets.

Except for selective dividends, the Company's practice prior to 1997 was to
reinvest the unremitted earnings of all of its non-U.S. subsidiaries and
postpone their remittance indefinitely. Thus, no additional U.S. taxes were
provided on such earnings. Undistributed earnings of non-U.S. subsidiaries
generated prior to 1997 for which no U.S. deferred income tax provision has been
made for possible future remittances totaled approximately $33.0 million at
December 31, 2002. In addition, the Company has negative undistributed earnings
of non-U.S. subsidiaries generated prior to 1997 of $56.4 million at December
31, 2002, for which no deferred tax benefit has been recognized. It is not
practicable to estimate the amount of unrecognized U.S. deferred taxes, if any,
that might be payable on the actual or deemed remittance of such earnings. On
actual remittance, certain countries impose withholding taxes that, subject to
certain limitations, are then available for use as tax credits against a U.S.
tax liability, if any.

At the beginning of 2001, the Company decided to postpone remittance of a
portion of the earnings of its U.K. subsidiaries. The Company plans to reinvest
these earnings indefinitely and no U.S. taxes were provided

56

on these earnings in 2001 or 2002. Undistributed earnings of the U.K.
subsidiaries for which no U.S. deferred income tax provision has been made were
$21.1 million in 2002 and $14.9 million in 2001.

Deferred income taxes are not recorded on differences between financial
reporting and tax bases of investments in stock of the Company's subsidiaries,
unless realization of the effect is probable in the foreseeable future.

The Company believes it is probable that its deferred tax assets of $104.7
million will be realized through carrybacks to prior year tax returns or on
future tax returns, primarily from the generation of future taxable income
through both profitable operations and future reversals of existing taxable
temporary differences.

As of December 31, 2002, the Company had net operating loss ("NOL")
carryforwards of approximately $114.6 million available to offset taxable
income. Approximately $21.5 million of the NOL carryforwards were acquired in
1996 with the Arethusa merger. The utilization of the NOL carryforwards acquired
in the Arethusa merger is limited pursuant to Section 382 of the Internal
Revenue Code of 1986, as amended (the "Code"). None of the NOL carryforwards
acquired from Arethusa were utilized in 2002. The remaining $93.1 million of NOL
carryforwards were generated during 2002 and are not subject to a limitation
under Code Section 382. The Company expects to fully utilize this portion of the
NOL through a carryback to a prior taxable year. The Company has recognized a
tax benefit of $32.6 million related to the tax loss generated in 2002.

The Company has recorded a deferred tax asset of $40.1 million for the
benefit of the NOL carryforwards. The NOL carryforwards will expire as follows:

15. EMPLOYEE BENEFIT PLANS

Defined Contribution Plans

The Company maintains defined contribution retirement plans for its U.S.,
U.K. and third country national ("TCN") employees. The plan for U.S. employees
(the "401k Plan") is designed to qualify under Section 401(k) of the Code. Under
the 401k Plan, each participant may elect to defer taxation on a portion of his
or her eligible earnings, as defined by the 401k Plan, by directing the Company
to withhold a percentage of such earnings. A participating employee may also
elect to make after-tax contributions to the 401k Plan. The Company contributes
3.75% of a participant's defined compensation and matches 25% of the first 6% of
each employee's compensation contributed. Participants are fully vested
immediately upon enrollment in the plan. For the years ended December 31, 2002,
2001 and 2000, the Company's provision for contributions was $5.6 million, $6.9
million and $6.2 million, respectively.

The plan for U.K. employees provides that the Company contributes amounts
equivalent to the employee's contributions generally up to a maximum of 5.25% of
the employee's defined compensation per year. The Company's provision for
contributions for the years ended December 31, 2002, 2001 and 2000 was $0.7
million, $0.5 million and $0.4 million, respectively.

The plan for the Company's TCN employees was effective April 1, 1998 and is
similar to the 401k Plan. The Company contributes 3.75% of a participant's
defined compensation and matches 25% of the first 6% of each employee's
compensation contributed. For the years ended December 31, 2002 and 2001, the
Company's provision for contributions was $0.6 million, and $0.5 million for the
year ended December 31, 2000.

57

Deferred Compensation and Supplemental Executive Retirement Plan

The Company established its Deferred Compensation and Supplemental
Executive Retirement Plan in December 1996. The Company contributes to this plan
any portion of the 3.75% of the base salary contribution and the matching
contribution to the 401k Plan that cannot be contributed because of the
limitations within the Code and because of elective deferrals that the
participant makes under the plan. Additionally, the plan provides that
participants may defer up to 10% of base compensation and/or up to 100% of any
performance bonus. Participants in this plan are a select group of management or
highly compensated employees of the Company and are fully vested in all amounts
paid into the plan. The Company's provision for contributions for the years
ended December 31, 2002, 2001 and 2000 was not material.

Pension Plan

The defined benefit pension plan established by Arethusa effective October
1, 1992 was frozen on April 30, 1996. At that date, all participants were deemed
fully vested in the plan, which covered substantially all U.S. citizens and U.S.
permanent residents who were employed by Arethusa. Benefits are calculated and
paid based on an employee's years of credited service and average compensation
at the date the plan was frozen using an excess benefit formula integrated with
social security covered compensation.

Pension costs are determined actuarially and at a minimum funded as
required by the Code. During 2002 the Company made a voluntary contribution of
$3.7 million to this plan. The plan's assets are invested in cash and cash
equivalents, equity securities, government and corporate debt securities. As a
result of freezing the plan, no service cost has been accrued for the years
presented.

The following provides a reconciliation of benefit obligations and
significant actuarial assumptions:

Amounts recognized in the Consolidated Balance Sheets consist of:

16. SEGMENTS AND GEOGRAPHIC AREA ANALYSIS

The Company manages its business on the basis of one reportable segment,
contract drilling of offshore oil and gas wells. Although the Company provides
contract drilling services from different types of offshore drilling rigs and
provides such services in many geographic locations, these operations have been
aggregated into one reportable segment based on the similarity of economic
characteristics among all divisions and locations, including the nature of
services provided and the type of customers of such services.

Similar Services

Revenues from external customers for contract drilling and similar services
by equipment-type are listed below (eliminations offset dayrate revenues earned
when the Company's rigs are utilized in its integrated services):

59

Geographic Areas

At December 31, 2002, the Company had drilling rigs located offshore ten
countries outside of the United States. As a result, the Company is exposed to
the risk of changes in social, political and economic conditions inherent in
foreign operations and the Company's results of operations and the value of its
foreign assets are affected by fluctuations in foreign currency exchange rates.
Revenues by geographic area are presented by attributing revenues to the
individual country where the services were performed.

An individual foreign country may, from time to time, contribute a material
percentage of the Company's total revenues from unaffiliated customers. For the
years ended December 31, 2002, 2001 and 2000, individual countries that
contributed 5% or more of the Company's total revenues from unaffiliated
customers are listed below.

Long-lived tangible assets located in the United States and all foreign
countries in which the Company holds assets as of December 31, 2002, 2001 and
2000 are listed below. A substantial portion of the Company's assets are mobile,
therefore asset locations at the end of the period are not necessarily
indicative of the geographic distribution of the earnings generated by such
assets during the periods.

Besides the United States, Brazil and Singapore are currently the only
countries with a material concentration of the Company's assets. Approximately
15.3%, 18.8% and 20.1% of the Company's total drilling and other property and
equipment were located in or offshore Brazil and 13.9%, 8.9% and 3.1% were
located in or offshore Singapore as of December 31, 2002, 2001 and 2000,
respectively.

60

Major Customers

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

17. UNAUDITED QUARTERLY FINANCIAL DATA

Unaudited summarized financial data by quarter for the years ended December
31, 2002 and 2001 is shown below.

61

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE.

Not applicable.

PART III

Reference is made to the information responsive to Items 10, 11, 12 (other
than information concerning securities authorized for issuance under equity
compensation plans) and 13 of this Part III contained in the Company's
definitive proxy statement for its 2003 Annual Meeting of Stockholders, which is
incorporated herein by reference.

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.

ITEM 11. EXECUTIVE COMPENSATION.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND
RELATED STOCKHOLDER MATTERS.

For information concerning securities authorized for issuance under equity
compensation plans, see "Market for the Registrant's Common Equity and Related
Stockholder Matters -- Equity Compensation Plan Information" in Item 5 of Part
II of this report.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.

ITEM 14. CONTROLS AND PROCEDURES.

The Company's management formed a disclosure controls and procedures
committee (the "Disclosure Committee") in 2002. The purpose and responsibility
of the Disclosure Committee is to coordinate and review the process by which
information is recorded, processed and reported on a timely basis as required to
be disclosed by the Company in its reports filed, furnished or submitted under
the Exchange Act. In addition, the Disclosure Committee is responsible for
ensuring that this information is accumulated and communicated to the Company's
management, including its principal executive officer and principal financial
officer, as appropriate, to allow timely decisions regarding required
disclosure.

Evaluation of Disclosure Controls and Procedures

Based on their evaluation of the Company's disclosure controls and
procedures conducted within 90 days prior to the date of filing this report on
Form 10-K, the Company's principal executive officer and principal financial
officer have concluded that as of the date of their evaluation, the Company's
disclosure controls and procedures (as defined in Rules 13a-14(c) and 15d-14(c)
promulgated under the Exchange Act) are effective.

Changes in Internal Controls

There were no significant changes in the Company's internal controls or in
other factors that could significantly affect these controls subsequent to the
date of their evaluation.

62

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K.

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

(1) Financial Statements

(2) Financial Statement Schedules

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

(3) Index of Exhibits....................................... 64

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

(b) Reports on Form 8-K

The Company made the following reports on Form 8-K during the fourth
quarter of fiscal year 2002:

63

(c) Index of Exhibits

- ---------------

* Filed herewith.

+ Management contracts or compensatory plans or arrangements.

65

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized, on March 4, 2003.

DIAMOND OFFSHORE DRILLING, INC.

By: /s/ GARY T. KRENEK
----------------------------------
Gary T. Krenek
Vice President and Chief Financial
Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the dates indicated.

*By: /s/ WILLIAM C. LONG
-------------------------------
William C. Long
Attorney-in-fact

66

CERTIFICATIONS

I, James S. Tisch, certify that:

1. I have reviewed this annual report on Form 10-K of Diamond Offshore
Drilling, Inc.;

2. Based on my knowledge, this annual report does not contain any
untrue statement of a material fact or omit to state a material fact
necessary to make the statements made, in light of the circumstances under
which such statements were made, not misleading with respect to the period
covered by this annual report;

3. Based on my knowledge, the financial statements, and other
financial information included in this annual report, fairly present in all
material respects the financial condition, results of operations and cash
flows of the registrant as of, and for, the periods presented in this
annual report;

4. The registrant's other certifying officers and I are responsible
for establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and
have:

a) Designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this annual report is
being prepared;

b) Evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior to the filing
date of this annual report (the "Evaluation Date"); and

c) Presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;

5. The registrant's other certifying officers and I have disclosed,
based on our most recent evaluation, to the registrant's auditors and the
audit committee of the registrant's board of directors (or persons
performing the equivalent functions):

a) All significant deficiencies in the design or operation of
internal controls which could adversely affect the registrant's ability
to record, process, summarize and report financial data and have
identified for the registrant's auditors any material weaknesses in
internal controls; and

b) Any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrant's internal
controls; and

6. The registrant's other certifying officers and I have indicated in
this annual report whether there were significant changes in internal
controls or in other factors that could significantly affect internal
controls subsequent to the date of our most recent evaluation, including
any corrective actions with regard to significant deficiencies and material
weaknesses.

/s/ JAMES S. TISCH
--------------------------------------
James S. Tisch
Chief Executive Officer

Date 04-March-2003

67

CERTIFICATIONS

I, Gary T. Krenek, certify that:

1. I have reviewed this annual report on Form 10-K of Diamond Offshore
Drilling, Inc.;

2. Based on my knowledge, this annual report does not contain any
untrue statement of a material fact or omit to state a material fact
necessary to make the statements made, in light of the circumstances under
which such statements were made, not misleading with respect to the period
covered by this annual report;

3. Based on my knowledge, the financial statements, and other
financial information included in this annual report, fairly present in all
material respects the financial condition, results of operations and cash
flows of the registrant as of, and for, the periods presented in this
annual report;

4. The registrant's other certifying officers and I are responsible
for establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and
have:

a) Designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this annual report is
being prepared;

b) Evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior to the filing
date of this annual report (the "Evaluation Date"); and

c) Presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;

5. The registrant's other certifying officers and I have disclosed,
based on our most recent evaluation, to the registrant's auditors and the
audit committee of the registrant's board of directors (or persons
performing the equivalent functions):

a) All significant deficiencies in the design or operation of
internal controls which could adversely affect the registrant's ability
to record, process, summarize and report financial data and have
identified for the registrant's auditors any material weaknesses in
internal controls; and

b) Any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrant's internal
controls; and

6. The registrant's other certifying officers and I have indicated in
this annual report whether there were significant changes in internal
controls or in other factors that could significantly affect internal
controls subsequent to the date of our most recent evaluation, including
any corrective actions with regard to significant deficiencies and material
weaknesses.

/s/ GARY T. KRENEK
--------------------------------------
Gary T. Krenek
Chief Financial Officer

Date 04-March-2003

68

EXHIBIT INDEX

- ---------------

* Filed herewith.

+ Management contracts or compensatory plans or arrangements.

70