Edgar Filing: TRANSOCEAN INC

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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
_________________

FORM 10-K
(MARK ONE)
[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 333-75899

_________________
TRANSOCEAN INC.
(EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER)
_________________

CAYMAN ISLANDS 66-0582307
(STATE OR OTHER JURISDICTION (I.R.S. EMPLOYER
OF INCORPORATION OR ORGANIZATION) IDENTIFICATION NO.)

4 GREENWAY PLAZA 77046
HOUSTON, TEXAS (ZIP CODE)
(ADDRESS OF PRINCIPAL EXECUTIVE OFFICES)

REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE: (713) 232-7500

SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:

TITLE OF CLASS EXCHANGE ON WHICH REGISTERED
---------------- ----------------------------
Ordinary Shares, par New York Stock Exchange, Inc.
value $0.01 per share

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. [ ]

Indicate by check mark whether the registrant is an accelerated filer. Yes
[x] No [ ]

As of June 28, 2002, 319,207,590 ordinary shares were outstanding and the
aggregate market value of such shares held by non-affiliates was approximately
$9.9 billion (based on the reported closing market price of the ordinary shares
on such date of $31.15 and assuming that all directors and executive officers of
the Company are "affiliates," although the Company does not acknowledge that any
such person is actually an "affiliate" within the meaning of the federal
securities laws). As of February 28, 2003, 319,764,712 ordinary shares were
outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the registrant's definitive Proxy Statement to be filed with
the Securities and Exchange Commission within 120 days of December 31, 2002, for
its 2003 annual general meeting of shareholders, are incorporated by reference
into Part III of this Form 10-K.

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TRANSOCEAN INC. AND SUBSIDIARIES
INDEX TO ANNUAL REPORT ON FORM 10-K
FOR THE YEAR ENDED DECEMBER 31, 2002

ITEM PAGE
---- ----

PART I
ITEM 1. Business. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3
Background of Transocean. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3
Drilling Fleet. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3
Markets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10
Management Services . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10
Drilling Contracts. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11
Significant Clients . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11
Regulation. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11
Employees . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12
Available Information . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12
ITEM 2. Properties. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12
ITEM 3. Legal Proceedings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13
ITEM 4. Submission of Matters to a Vote of Security Holders . . . . . . . . . . . . . . . . . 15
Executive Officers of the Registrant. . . . . . . . . . . . . . . . . . . . . . . . . 15

PART II
ITEM 5. Market for Registrant's Common Equity and Related Shareholder Matters . . . . . . . . 17
ITEM 6. Selected Consolidated Financial Data. . . . . . . . . . . . . . . . . . . . . . . . . 19
ITEM 7. Management's Discussion and Analysis of Financial Condition and Results of Operations 21
ITEM 7A. Quantitative and Qualitative Disclosures About Market Risk. . . . . . . . . . . . . . 48
ITEM 8. Financial Statements and Supplementary Data . . . . . . . . . . . . . . . . . . . . . 50
ITEM 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure. 93

PART III
ITEM 10. Directors and Executive Officers of the Registrant. . . . . . . . . . . . . . . . . . 93
ITEM 11. Executive Compensation. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 93
ITEM 12. Security Ownership of Certain Beneficial Owners and Management and Related
Shareholder Matters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 93
ITEM 13. Certain Relationships and Related Transactions. . . . . . . . . . . . . . . . . . . . 93
ITEM 14. Controls and Procedures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 93

PART IV
ITEM 15. Exhibits, Financial Statement Schedules and Reports on Form 8-K . . . . . . . . . . . 93

PART I

ITEM 1. BUSINESS

Transocean Inc. (formerly known as "Transocean Sedco Forex Inc.", together
with its subsidiaries and predecessors, unless the context requires otherwise,
the "Company," "Transocean," "we," "us" or "our") is a leading international
provider of offshore and inland marine contract drilling services for oil and
gas wells. As of March 1, 2003, we owned, had partial ownership interests in or
operated 158 mobile offshore and barge drilling units that we consider to be our
core assets. As of this date, our core assets consisted of 31
high-specification drillship and semisubmersibles (floaters), 29 other floaters,
55 jackup rigs, 35 drilling barges, five tenders and three submersible drilling
rigs. In addition, the fleet included non-core assets consisting of a mobile
offshore production unit, two platform drilling rigs and a land rig, as well as
nine land rigs and three lake barges in Venezuela.

Our mobile offshore drilling fleet is considered one of the most modern and
versatile fleets in the world. Our primary business is to contract these
drilling rigs, related equipment and work crews primarily on a dayrate basis to
drill oil and gas wells. We specialize in technically demanding segments of the
offshore drilling business with a particular focus on deepwater and harsh
environment drilling services. We also provide additional services, including
management of third-party well service activities. Our ordinary shares are
listed on the New York Stock Exchange under the symbol "RIG".

Transocean Inc. is a Cayman Islands exempted company with principal
executive offices in the U.S. located at 4 Greenway Plaza, Houston, Texas 77046.
Our telephone number at that address is (713) 232-7500.

BACKGROUND OF TRANSOCEAN

In June 1993, the Company, then known as "Sonat Offshore Drilling Inc.,"
completed an initial public offering of approximately 60 percent of the
outstanding shares of its common stock as part of its separation from Sonat
Inc., and in July 1995 Sonat Inc. sold its remaining 40 percent interest in the
Company through a secondary public offering. In September 1996, the Company
acquired Transocean ASA, a Norwegian offshore drilling company, and changed its
name to "Transocean Offshore Inc." On May 14, 1999, the Company completed a
corporate reorganization by which it changed its place of incorporation from
Delaware to the Cayman Islands.

On December 31, 1999, we completed our merger with Sedco Forex Holdings
Limited ("Sedco Forex"), the former offshore contract drilling business of
Schlumberger Limited ("Schlumberger"). Effective upon the merger, we changed
our name to "Transocean Sedco Forex Inc." The merger followed the spin-off of
Sedco Forex to Schlumberger shareholders on December 30, 1999. We accounted for
the merger using the purchase method of accounting with Sedco Forex treated as
the accounting acquiror. On January 31, 2001, we completed a merger transaction
(the "R&B Falcon merger") with R&B Falcon Corporation ("R&B Falcon", now known
as "TODCO"). We accounted for the R&B Falcon merger using the purchase method of
accounting with the Company treated as the acquiror. In May 2002, we changed our
name to "Transocean Inc."

DRILLING FLEET

We principally use four types of drilling rigs:

- drillships

- semisubmersibles

- jackups

- barge drilling rigs

Also included in our fleet are tenders, submersible rigs, a mobile offshore
production unit, platform drilling rigs, land drilling rigs and lake barges.

-3-

Most of our drilling equipment is suitable for both exploration and
development drilling, and we are normally engaged in both types of drilling
activity. Likewise, most of our drilling rigs are mobile and can be moved to
new locations in response to client demand, particularly the drillships,
semisubmersibles, jackups and tenders. All of our mobile offshore drilling
units are designed for operations away from port for extended periods of time
and most have living quarters for the crews, a helicopter landing deck and
storage space for pipe and drilling supplies.

As of February 28, 2003, our marine fleet of 158 core assets was located in
the U.S. Gulf of Mexico (75 units), Canada (one unit), Brazil (11 units),
Trinidad (two units), the North Sea (17 units), the Mediterranean and Middle
East (eight units), the Caspian Sea (one unit), Africa (21 units), India (six
units) and Asia and Australia (16 units).

Our operations are separated into two business segments. The International
and U.S. Floater Contract Drilling Services segment is comprised of drillships,
semisubmersibles and non-U.S. jackups and barge drilling rigs. Our Gulf of
Mexico Shallow and Inland Water segment consists of jackups and submersible
drilling rigs located in the U.S. Gulf of Mexico and Trinidad and U.S. inland
drilling barges, as well as land drilling units and lake barges located in
Venezuela.

INTERNATIONAL AND U.S. FLOATER CONTRACT DRILLING SERVICES FLEET

As of February 28, 2003, our International and U.S. Floater Contract
Drilling Services segment fleet consisted of 14 drillships, 46 semisubmersibles,
26 jackups, four drilling barges, five tenders, a platform drilling rig, a
mobile offshore production unit and a land rig.

DRILLSHIPS (14)

Drillships are generally self-propelled and designed to drill in the
deepest water in which offshore drilling rigs currently operate. Shaped like
conventional ships, they are the most mobile of the major rig types. Our
drillships are either dynamically positioned, which allows them to maintain
position without anchors through the use of their onboard propulsion and
station-keeping systems, or are operated in a moored configuration. Drillships
typically have greater load capacity than semisubmersible rigs. This enables
them to carry more supplies on board, which often makes them better suited for
drilling in remote locations where resupply is more difficult. However,
drillships are typically limited to calmer water conditions than those in which
semisubmersibles can operate. High-specification drillships are those that are
dynamically positioned and rated for drilling in water depths of at least 7,000
feet and are designed for ultra-deepwater exploration and development drilling
programs. Our three Discoverer Enterprise-class drillships are equipped for
dual-activity drilling, which is a well-construction technology we developed
that allows for drilling tasks associated with a single well to be accomplished
in a parallel rather than sequential manner by utilizing two complete drilling
systems under a single derrick. The dual-activity well-construction process is
designed to reduce critical path activity and improve efficiency in both
exploration and development drilling. Our Deepwater-class drillships are also
high-specification drillships and are designed with a high-pressure mud system.

The following table provides certain information regarding our
drillship fleet as of February 28, 2003:

HIGH-SPECIFICATION DRILLSHIPS (12)
Deepwater Discovery (c). . . . . . 2000 10,000 30,000 Benin ChevronTexaco December 2003
Deepwater Expedition (c) . . . . . 1999 10,000 30,000 Brazil Petrobras October 2005
Deepwater Frontier (c)(d). . . . . 1999 10,000 30,000 Brazil Petrobras November 2003
Deepwater Millennium . . . . . . . 1999 10,000 30,000 U.S. Gulf Anadarko June 2003
U.S. Gulf KerrMcGee December 2003
U.S. Gulf KerrMcGee December 2004
Deepwater Pathfinder (c)(e). . . . 1998 10,000 30,000 U.S. Gulf Conoco January 2004
Discoverer Deep Seas (c) . . . . . 2001 10,000 35,000 U.S. Gulf ChevronTexaco January 2006
Discoverer Enterprise (c). . . . . 1999 10,000 35,000 U.S. Gulf BP December 2004
Discoverer Spirit (c). . . . . . . 2000 10,000 35,000 U.S. Gulf Unocal September 2005
Deepwater Navigator (c). . . . . . 2000 7,200 25,000 Brazil Petrobras July 2003
Brazil Petrobras July 2004
Peregrine I (c). . . . . . . . . . 1982/1996 7,200 25,000 Brazil Petrobras June 2003

-4-

OTHER DRILLSHIPS (2)
Joides Resolution (c)(f) . . . . . 1978 27,000 30,000 Brazil Texas A&M September 2003
Peregrine III. . . . . . . . . . . 1976 4,200 25,000 U.S. Gulf - Idle

_______________________________
(a) Dates shown are the original service date and the date of the most recent upgrade, if any.
(b) Expiration dates represent our current estimate of the earliest date the contract for each rig is likely
to expire. Some rigs have two or more contracts in continuation, so the last line shows the estimated
earliest availability. Some contracts may permit the client to extend the contract.
(c) Dynamically positioned.
(d) The Deepwater Frontier is leased and operated by a limited liability company in which we own a 60
percent interest. See Note 19 to our consolidated financial statements.
(e) The Deepwater Pathfinder is leased and operated by a limited liability company in which we own a 50
percent interest. See Note 19 to our consolidated financial statements.
(f) The Joides Resolution is currently engaged in scientific geological coring activities and is owned by a
joint venture in which we have a 50 percent interest. See Note 19 to our consolidated financial statements.

SEMISUBMERSIBLES (46)

Semisubmersibles are floating vessels that can be submerged by means of a
water ballast system such that a substantial portion of the lower hull is below
the water surface during drilling operations. These rigs maintain their
position over the well through the use of an anchoring system or computer
controlled dynamic positioning thruster system. Some semisubmersible rigs are
self-propelled and move between locations under their own power when afloat on
the pontoons although most are relocated with the assistance of tugs.
Typically, semisubmersibles are better suited for operations in rough water
conditions than drillships. High-specification semisubmersibles are those that
were built or extensively upgraded since 1984 and have one or more of the
following characteristics: larger physical size than other semisubmersibles;
rated for drilling in water depths of over 4,000 feet; year-round harsh
environment capability; variable deck load capability of greater than 4,000
metric tons; dynamic positioning; and superior motion characteristics.

The following table provides certain information regarding our
semisubmersible fleet as of February 28, 2003:

HIGH-SPECIFICATION
SEMISUBMERSIBLES (19)
Deepwater Horizon (c) . 2001 10,000 30,000 U.S. Gulf BP September 2004
Cajun Express (c) . . . 2001 8,500 35,000 U.S. Gulf Dominion March 2003
Deepwater Nautilus (d). 2000 8,000 30,000 U.S. Gulf Shell June 2005
Sedco Energy (c). . . . 2001 7,500 25,000 Las Palmas ChevronTexaco May 2003
Nigeria ChevronTexaco October 2004
Sedco Express (c) . . . 2001 7,500 25,000 Brazil Petrobras August 2004
Transocean Marianas . . 1979/1998 7,000 25,000 U.S. Gulf Shell August 2003
Sedco 707 (c) . . . . . 1976/1997 6,500 25,000 Brazil Petrobras January 2004
Jack Bates. . . . . . . 1986/1997 5,400 30,000 U.K. North Sea - Idle
Sedco 709 (c) . . . . . 1977/1999 5,000 25,000 Nigeria Shell May 2003
Nigeria Shell May 2004
M. G. Hulme, Jr. (e). . 1983/1996 5,000 25,000 Nigeria TotalFinaElf March 2003
Nigeria TotalFinaElf May 2003
Transocean Richardson . 1988 5,000 25,000 U.S. Gulf KerrMcGee March 2003

-5-

YEAR WATER DRILLING
ENTERED DEPTH DEPTH
SERVICE/ CAPACITY CAPACITY ESTIMATED
TYPE AND NAME UPGRADED(a) (IN FEET) (IN FEET) LOCATION CUSTOMER EXPIRATION (b)
---------------------- ----------- --------- --------- ----------------- ------------- ---------------
Jim Cunningham. . . . . 1982/1995 4,600 25,000 Malta - Shipyard
Egypt IEOC July 2003
Transocean Leader . . . 1987/1997 4,500 25,000 U.K. North Sea BP March 2003
Transocean Rather . . . 1988 4,500 25,000 Enroute to ExxonMobil August 2004
Angola
Sovereign Explorer. . . 1984 4,500 25,000 Equatorial Guinea Amerada Hess March 2003
Ivory Coast CNR May 2003
Henry Goodrich. . . . . 1985 2,000 30,000 Canada Terra Nova February 2005
Paul B. Loyd, Jr. . . . 1990 2,000 25,000 U.K. North Sea BP March 2003
Transocean Arctic . . . 1986 1,650 25,000 Norwegian N. Sea - Idle
Polar Pioneer . . . . . 1985 1,500 25,000 Norwegian N. Sea Norsk Hydro December 2003

OTHER SEMISUBMERSIBLES (27)
Sedco 710 (c) . . . . . . . 1983/1997 4,500 25,000 Brazil Petrobras October 2006
Sedco 700 . . . . . . . . . 1973/1997 3,600 25,000 Equatorial Guinea Amerada Hess October 2003
Transocean Amirante . . . . 1978/1997 3,500 25,000 U.S. Gulf - Idle
Transocean Legend . . . . . 1983 3,500 25,000 Brazil Petrobras May 2004
C. Kirk Rhein, Jr.. . . . . 1976/1997 3,300 25,000 U.S. Gulf - Idle
Transocean Driller. . . . . 1991 3,000 25,000 Brazil El Paso August 2003
Falcon 100. . . . . . . . . 1974/1999 2,400 25,000 U.S. Gulf ChevronTexaco April 2003
Sedco 711 . . . . . . . . . 1982 1,800 25,000 U.K. North Sea Ramco April 2003
U.K. North Sea Marathon June 2003
U.K. North Sea Ramco July 2003
Transocean John Shaw. . . . 1982 1,800 25,000 U.K. North Sea TotalFinaElf April 2003
U.K. North Sea TotalFinaElf August 2003
Sedco 714 . . . . . . . . . 1983/1997 1,600 25,000 U.K. North Sea EnCana March 2003
U.K. North Sea BP May 2003
Sedco 712 . . . . . . . . . 1983 1,600 25,000 U.K. North Sea Shell March 2003
Actinia . . . . . . . . . . 1982 1,500 25,000 Egypt IEOC April 2003
J. W. McLean. . . . . . . . 1974/1996 1,250 25,000 U.K. North Sea - Idle
Sedco 600 . . . . . . . . . 1983/1994 1,500 25,000 Indonesia Conoco March 2003
Sedco 601 . . . . . . . . . 1983 1,500 25,000 Indonesia TotalFinaElf April 2003
Sedco 602 . . . . . . . . . 1983 1,500 25,000 Singapore - Idle
Sedco 702 . . . . . . . . . 1973/1992 1,500 25,000 Australia Esso March 2003
Sedco 703 . . . . . . . . . 1973/1995 2,000 25,000 Australia Woodside March 2003
Sedco 708 . . . . . . . . . 1976 1,500 25,000 Congo - Idle
Sedneth 701 . . . . . . . . 1972/1993 1,500 25,000 Angola ChevronTexaco April 2003
Transocean Prospect . . . . 1983/1992 1,500 25,000 U.K. North Sea - Idle
Transocean Searcher . . . . 1983/1988 1,500 25,000 Norwegian N. Sea Statoil June 2003
Norwegian N. Sea Statoil March 2004
Transocean Winner . . . . . 1983 1,500 25,000 Norwegian N. Sea - Idle
Transocean Wildcat. . . . . 1977/1985 1,300 25,000 U.K. North Sea - Idle
Transocean Explorer . . . . 1976 1,250 25,000 U.K. North Sea - Idle
Sedco 704 . . . . . . . . . 1974/1993 1,000 25,000 U.K. North Sea ChevronTexaco April 2003
U.K. North Sea Ramco September 2003
Sedco 706 . . . . . . . . . 1976/1994 1,000 25,000 U.K. North Sea - Idle

______________________________

(a) Dates shown are the original service date and the date of the most recent upgrade, if any.

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(b) Expiration dates represent our current estimate of the earliest date the contract for each rig is likely
to expire. Some rigs have two or more contracts in continuation, so the last line shows the estimated
earliest availability. Some contracts may permit the client to extend the contract.
(c) Dynamically positioned.
(d) The Deepwater Nautilus is leased from its owner, an unrelated third party, pursuant to a fully defeased
lease arrangement.
(e) The M. G. Hulme, Jr. is accounted for as an operating lease as a result of a sale/leaseback transaction
in November 1995.

JACKUP RIGS (26)

Jackup rigs are mobile self-elevating drilling platforms equipped with legs
that can be lowered to the ocean floor until a foundation is established to
support the drilling platform. Once a foundation is established, the drilling
platform is then jacked further up the legs so that the platform is above the
highest expected waves. These rigs are generally suited for water depths of 300
feet or less.

The following table provides certain information regarding our jackup rig
fleet in this segment as of February 28, 2003:

YEAR ENTERED WATER DEPTH DRILLING DEPTH
SERVICE/ CAPACITY CAPACITY
NAME UPGRADED(a) (IN FEET) (IN FEET) LOCATION STATUS
------------------- ------------- ------------ --------------- -------------------- ---------

Trident IX. . . . . 1982 400 21,000 Vietnam Operating
Trident 17. . . . . 1983 355 25,000 Indonesia Operating
Harvey H. Ward. . . 1981 300 25,000 Malaysia Operating
J. T. Angel . . . . 1982 300 25,000 India Operating
Roger W. Mowell . . 1982 300 25,000 Malaysia Operating
Ron Tappmeyer . . . 1978 300 25,000 Singapore Idle
D. R. Stewart . . . 1980 300 25,000 Italy Operating
Randolph Yost . . . 1979 300 25,000 Equatorial Guinea Operating
C. E. Thornton. . . 1974 300 25,000 India Operating
F. G. McClintock. . 1975 300 25,000 India Operating
Shelf Explorer. . . 1982 300 25,000 Enroute to Operating
Equatorial Guinea
Transocean III. . . 1978/1993 300 20,000 Oman Shipyard
Transocean Nordic . 1984 300 25,000 India Operating
Trident II. . . . . 1977/1985 300 25,000 India Operating
Trident IV. . . . . 1980/1999 300 25,000 Congo Operating
Trident VI. . . . . 1981 300 21,000 Nigeria Operating
Trident VIII. . . . 1981 300 21,000 Nigeria Operating
Trident XII . . . . 1982/1992 300 25,000 Vietnam Operating
Trident XIV . . . . 1982/1994 300 20,000 Angola Operating
Trident 15. . . . . 1982 300 25,000 Thailand Operating
Trident 16. . . . . 1982 300 25,000 Vietnam Operating
Trident 20 (b). . . 2000 350 25,000 Caspian Sea Operating
George H. Galloway. 1984 300 25,000 Italy Operating
Transocean Comet. . 1980 250 20,000 Egypt Operating
Transocean Mercury. 1969/1998 250 20,000 Egypt Operating
Transocean Jupiter. 1981/1997 170 16,000 United Arab Emirates Idle

______________________________

(a) Dates shown are the original service date and the date of the most recent upgrade, if any.
(b) Owned by a joint venture in which we have a 75 percent interest.

BARGE DRILLING RIGS (4)

Our barge drilling fleet in this segment consists of swamp barges. Swamp
barges are usually not self-propelled but can be moored alongside a platform and
contain crew quarters, mud pits, mud pumps, power generation and other
equipment. Swamp barges are generally suited for water depths of 25 feet or
less.

-7-

The following table provides certain information regarding our barge
drilling rig fleet in this segment as of February 28, 2003:

YEAR
ENTERED DRILLING
SERVICE/ CAPACITY
NAME UPGRADED(a) (IN FEET) LOCATION STATUS
------------ ----------- --------- --------- ---------

Searex 4 . . 1981/1989 25,000 Nigeria Idle
Searex 6 . . 1981/1991 25,000 Nigeria Idle
Searex 12. . 1982/1992 25,000 Nigeria Operating
Hibiscus (b) 1979/1993 16,000 Indonesia Operating

______________________________
(a) Dates shown are the original service date and the date of the most
recent upgrade, if any.
(b) The Hibiscus is owned by a joint venture in which we own more than 50
percent.

OTHER RIGS

In addition to the drillships, semisubmersibles, jackups and drilling
barges, we also own or operate several other types of rigs in this segment.
These rigs include five tenders, a platform drilling rig, a mobile offshore
production unit and a land rig.

Some of our idle rigs would require additional costs to return to service.
The actual cost, which could fluctuate over time, is dependent upon various
factors, including the availability and cost of shipyard facilities, cost of
equipment and materials and the extent of repairs and maintenance that may
ultimately be required. We would take these factors into consideration together
with market conditions, length of contract and the dayrate and other contract
terms in deciding whether to return a particular idle rig to service.

GULF OF MEXICO SHALLOW AND INLAND WATER FLEET

As of February 28, 2003, our Gulf of Mexico Shallow and Inland Water
segment fleet consisted of 29 jackups, 31 drilling barges, three submersible
rigs and a platform drilling rig, as well as nine land rigs and three lake
barges.

JACKUP RIGS (29)

The following table provides certain information regarding our jackup rig
fleet in this segment as of February 28, 2003:

WATER DEPTH RATED DRILLING
YEAR ENTERED CAPACITY DEPTH
NAME TYPE SERVICE (IN FEET) (IN FEET) LOCATION STATUS
----------- ---- ------------ ------------ --------------- --------- ---------

RBF 151 (a) ILC 1981 150 20,000 U.S. Gulf Idle
RBF 156 . . ILC 1983 150 20,000 U.S. Gulf Operating
RBF 185 . . ILC 1982 120 20,000 U.S. Gulf Idle
RBF 150 . . ILC 1979 150 20,000 U.S. Gulf Operating
RBF 155 . . ILC 1980 150 20,000 U.S. Gulf Idle
RBF 154 . . ILC 1979 150 16,000 U.S. Gulf Idle
RBF 110 . . MC 1982 100 20,000 Trinidad Operating
RBF 152 . . MC 1980 150 20,000 U.S. Gulf Idle
RBF 153 . . MC 1980 150 20,000 U.S. Gulf Idle
RBF 200 . . MC 1979 200 20,000 U.S. Gulf Idle
RBF 201 . . MC 1981 200 20,000 U.S. Gulf Operating
RBF 202 . . MC 1982 200 20,000 U.S. Gulf Operating
RBF 203 . . MC 1981 200 20,000 U.S. Gulf Idle
RBF 204 . . MC 1981 200 20,000 U.S. Gulf Idle
RBF 205 . . MC 1979 200 20,000 U.S. Gulf Idle
RBF 206 . . MC 1980 200 20,000 U.S. Gulf Idle
RBF 207 . . MC 1981 200 20,000 U.S. Gulf Idle
RBF 208 (a) MC 1980 200 20,000 Trinidad Idle
RBF 100 . . MC 1982 100 20,000 U.S. Gulf Idle
RBF 190 . . MS 1978 160 20,000 U.S. Gulf Idle

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WATER DEPTH RATED DRILLING
YEAR ENTERED CAPACITY DEPTH
NAME TYPE SERVICE (IN FEET) (IN FEET) LOCATION STATUS
----------- ---- ------------ ------------ --------------- --------- ---------
RBF 191 . . MS 1978 160 20,000 U.S. Gulf Idle
RBF 192 . . MS 1981 160 20,000 U.S. Gulf Idle
RBF 250 . . MS 1974 250 20,000 U.S. Gulf Idle
RBF 251 . . MS 1978 250 20,000 U.S. Gulf Idle
RBF 252 . . MS 1978 250 20,000 U.S. Gulf Idle
RBF 253 . . MS 1982 250 20,000 U.S. Gulf Idle
RBF 254 . . MS 1976 250 20,000 U.S. Gulf Idle
RBF 255 . . MS 1976 250 20,000 U.S. Gulf Idle
RBF 256 . . MS 1975 250 20,000 U.S. Gulf Idle

______________________________
"ILC" means an independent leg cantilevered jackup rig.
"MC" means a mat-supported cantilevered jackup rig.
"MS" means a mat-supported slot-type jackup rig.

(a) This rig is currently unable to operate in the U. S. Gulf of Mexico due to
regulatory restrictions.

BARGE DRILLING RIGS (31)

Our barge drilling fleet in this segment consists of conventional and
posted barge rigs. Our conventional and posted barge drilling rigs are mobile
drilling platforms that are submersible and are built to work in eight to 20
feet of water. A posted barge is identical to a conventional barge except that
the hull and superstructure are separated by 10 to 14 foot columns, which
increases the water depth capabilities of the rig.

The following table provides certain information regarding our barge
drilling rig fleet in this segment as of February 28, 2003:

RATED
DRILLING
YEAR ENTERED HORSEPOWER DEPTH
NAME TYPE SERVICE RATING (IN FEET) LOCATION STATUS
------ ------ ------------ ---------- --------- --------- ---------

11 Conv. 1982 3,000 30,000 U.S. Gulf Operating
28 Conv. 1979 3,000 30,000 U.S. Gulf Idle
29 Conv. 1980 3,000 30,000 U.S. Gulf Idle
30 Conv. 1981 3,000 30,000 U.S. Gulf Idle
31 Conv. 1981 3,000 30,000 U.S. Gulf Idle
32 Conv. 1982 3,000 30,000 U.S. Gulf Idle
15 Conv. 1981 2,000 25,000 U.S. Gulf Idle
1 Conv. 1980 2,000 20,000 U.S. Gulf Idle
21 Conv. 1982 1,500 15,000 U.S. Gulf Idle
19 Conv. 1996 1,000 14,000 U.S. Gulf Operating
20 Conv. 1998 1,000 14,000 U.S. Gulf Operating
23 Conv. 1995 1,000 14,000 U.S. Gulf Idle
55 Posted 1981 3,000 30,000 U.S. Gulf Operating
17 Posted 1981 3,000 30,000 U.S. Gulf Operating
27 Posted 1978 3,000 30,000 U.S. Gulf Operating
41 Posted 1981 3,000 30,000 U.S. Gulf Operating
46 Posted 1981 3,000 30,000 U.S. Gulf Operating
47 Posted 1982 3,000 30,000 U.S. Gulf Idle
48 Posted 1982 3,000 30,000 U.S. Gulf Operating
49 Posted 1980 3,000 30,000 U.S. Gulf Operating
61 Posted 1978 3,000 30,000 U.S. Gulf Idle
62 Posted 1978 3,000 30,000 U.S. Gulf Operating
64 Posted 1979 3,000 30,000 U.S. Gulf Operating
75 (a) Posted 1979 3,000 30,000 U.S. Gulf Idle
52 Posted 1981 2,000 25,000 U.S. Gulf Operating
56 Posted 1973 2,000 25,000 U.S. Gulf Idle
57 Posted 1975 2,000 25,000 U.S. Gulf Operating

-9-

RATED
DRILLING
YEAR ENTERED HORSEPOWER DEPTH
NAME TYPE SERVICE RATING (IN FEET) LOCATION STATUS
------ ------ ------------ ---------- --------- --------- ---------
9 Posted 1981 2,000 25,000 U.S. Gulf Operating
10 Posted 1981 2,000 25,000 U.S. Gulf Idle
7 Posted 1978 2,000 25,000 U.S. Gulf Idle
74 (a) Posted 1981 2,000 25,000 U.S. Gulf Idle

____________________________

"Conv." means a conventional rig.
"Posted" means a posted barge rig.

(a) These rigs are not owned by us but are bareboat chartered from a third
party. Each charter expires in February 2006.

OTHER RIGS

In addition to the jackups and drilling barges, we also own or operate
several other types of rigs in this segment. These rigs include three
submersible rigs and a platform drilling rig. We also have nine land rigs and
three lake barges in Venezuela.

MARKETS

Our operations are geographically dispersed in oil and gas exploration and
development areas throughout the world. Rigs can be moved from one region to
another, but the cost of moving a rig and the availability of rig-moving vessels
may cause the supply and demand balance to vary somewhat between regions.
However, significant variations between regions do not tend to exist long-term
because of rig mobility. Because our drilling rigs are mobile assets and are
able to be moved according to prevailing market conditions, we cannot predict
the percentage of our revenues that will be derived from particular geographic
or political areas in future periods.

In recent years, there has been increased emphasis by oil companies on
exploring for hydrocarbons in deeper waters. This is, in part, because of
technological developments that have made such exploration more feasible and
cost-effective. The deepwater and mid-depth market segments are serviced by our
semisubmersibles and drillships. While the use of the term "deepwater" as used
in the drilling industry to denote a particular segment of the market can vary
and continues to evolve with technological improvements, we generally view the
deepwater market segment as that which begins in water depths of approximately
3,000 feet and extends to the maximum water depths in which rigs are capable of
drilling, which is currently approximately 10,000 feet. The mid-depth market
segment begins in water depths of about 300 feet and extends to water depths of
about 3,000 feet.

The global shallow water market segment is serviced by our jackups,
submersibles and drilling tenders. This market segment begins at the outer
limit of the transition zone and extends to water depths of about 300 feet. It
has been developed to a significantly greater degree than the deepwater market
segment, as technology required to explore for and produce hydrocarbons in these
water depths is not as demanding as in the deepwater market segment and,
accordingly, the costs are lower.

Our barge rig fleet operates in marshes, rivers, lakes and shallow bay and
coastal water areas that are referred to as the "transition zone." Our principal
barge market segment is the shallow water areas of the U.S. Gulf of Mexico.
This area historically has been the world's largest market segment for barge
rigs. International market segments for our barge rigs include West Africa and
Southeast Asia.

We conduct land rig operations in Venezuela.

MANAGEMENT SERVICES

We use our engineering and operating expertise to provide management of
third party drilling service activities. These services are provided through
service teams generally consisting of our personnel and third-party
subcontractors and

-10-

we frequently serve as lead contractor. The work generally consists of
individual contractual agreements to meet specific client needs and may be
provided on either a dayrate or fixed price basis. As of March 1, 2003, we
performed such services only in the North Sea. These management service revenues
did not represent a material portion of our revenues during 2002.

DRILLING CONTRACTS

Our contracts to provide offshore drilling services are individually
negotiated and vary in their terms and provisions. We obtain most of our
contracts through competitive bidding against other contractors. Drilling
contracts generally provide for payment on a dayrate basis, with higher rates
while the drilling unit is operating and lower rates for periods of mobilization
or when drilling operations are interrupted or restricted by equipment
breakdowns, adverse environmental conditions or other conditions beyond our
control.

A dayrate drilling contract generally extends over a period of time
covering either the drilling of a single well or group of wells or covering a
stated term. These contracts typically can be terminated by the client under
various circumstances such as the loss or destruction of the drilling unit or
the suspension of drilling operations for a specified period of time as a result
of a breakdown of major equipment. The contract term in some instances may be
extended by the client exercising options for the drilling of additional wells
or for an additional term, or by exercising a right of first refusal. In
reaction to depressed market conditions, our clients may seek renegotiation of
firm drilling contracts to reduce their obligations or may seek to suspend or
terminate their contracts. Some drilling contracts permit the customer to
terminate the contract at the customer's option without paying a termination
fee. Suspension of drilling contracts results in loss of the dayrate for the
period of the suspension. If our customers cancel some of our significant
contracts and we are unable to secure new contracts on substantially similar
terms, or if contracts are suspended for an extended period of time, it could
adversely affect our results of operations.

SIGNIFICANT CLIENTS

During the past five years, we have engaged in offshore drilling for most
of the leading international oil companies (or their affiliates) in the world,
as well as for many government-controlled and independent oil companies. Major
clients included BP, Shell, Petrobras, ChevronTexaco, TotalFinaElf, AGIP,
Unocal, Amerada Hess and Statoil. Our largest unaffiliated clients in 2002 were
BP and Shell accounting for 14.1 percent and 11.6 percent, respectively, of our
2002 operating revenues. No other unaffiliated client accounted for 10 percent
or more of our 2002 operating revenues (see Note 20 to our consolidated
financial statements). The loss of any of these significant clients could, at
least in the short term, have a material adverse effect on our results of
operations.

REGULATION

Our operations are affected from time to time in varying degrees by
governmental laws and regulations. The drilling industry is dependent on demand
for services from the oil and gas exploration industry and, accordingly, is
affected by changing tax and other laws generally relating to the energy
business.

International contract drilling operations are subject to various laws and
regulations in countries in which we operate, including laws and regulations
relating to the equipping and operation of drilling units, currency conversions
and repatriation, oil and gas exploration and development, taxation of offshore
earnings and earnings of expatriate personnel and use of local employees and
suppliers by foreign contractors. Governments in some foreign countries are
active in regulating and controlling the ownership of concessions and companies
holding concessions, the exportation of oil and gas and other aspects of the oil
and gas industries in their countries. In addition, government action, including
initiatives by the Organization of Petroleum Exporting Countries ("OPEC"), may
continue to cause oil price volatility. In some areas of the world, this
governmental activity has adversely affected the amount of exploration and
development work done by major oil companies and may continue to do so.

In the U.S., regulations applicable to our operations include certain
regulations controlling the discharge of materials into the environment,
requiring removal and cleanup of materials that may harm the environment or
otherwise relating to the protection of the environment.

The U.S. Oil Pollution Act of 1990 ("OPA") and related regulations impose a
variety of requirements on "responsible parties" related to the prevention of
oil spills and liability for damages resulting from such spills. Few defenses
exist to the liability imposed by OPA, and such liability could be substantial.
Failure to comply with ongoing requirements or inadequate cooperation in a spill
event could subject a responsible party to civil or criminal enforcement action.

-11-

The U.S. Outer Continental Shelf Lands Act authorizes regulations relating
to safety and environmental protection applicable to lessees and permittees
operating on the Outer Continental Shelf. Specific design and operational
standards may apply to Outer Continental Shelf vessels, rigs, platforms,
vehicles and structures. Violations of environmental related lease conditions or
regulations issued pursuant to the Outer Continental Shelf Lands Act can result
in substantial civil and criminal penalties, as well as potential court
injunctions curtailing operations and canceling leases. Such enforcement
liabilities can result from either governmental or citizen prosecution.

The Comprehensive Environmental Response Compensation and Liability Act
("CERCLA"), also known as the "Superfund" law, imposes liability without regard
to fault or the legality of the original conduct on some classes of persons that
are considered to have contributed to the release of a "hazardous substance"
into the environment. These persons include the owner or operator of a facility
where a release occurred and companies that disposed or arranged for the
disposal of the hazardous substances found at a particular site. Persons who
are or were responsible for releases of hazardous substances under CERCLA may be
subject to joint and several liability for the costs of cleaning up the
hazardous substances that have been released into the environment and for
damages to natural resources. It is not uncommon for third parties to file
claims for personal injury and property damage allegedly caused by the hazardous
substances released into the environment. We could be subject to liability
under CERCLA principally in connection with our onshore activities.

Certain of the other countries in whose waters we are presently operating
or may operate in the future have regulations covering the discharge of oil and
other contaminants in connection with drilling operations.

Although significant capital expenditures may be required to comply with
these governmental laws and regulations, such compliance has not materially
adversely affected our earnings or competitive position.

EMPLOYEES

At January 31, 2003, we had approximately 13,200 employees, including
approximately 2,300 persons contracted through contract labor providers. We
require highly skilled personnel to operate our drilling units. As a result, we
conduct extensive personnel recruiting, training and safety programs.

On January 31, 2003, we had approximately 10 percent of our employees
worldwide working under collective bargaining agreements, most of whom were
working in Norway, U.K., Nigeria and Trinidad. Of these represented employees,
a majority are working under agreements that are subject to salary negotiation
in 2003. These ongoing negotiations could result in higher personnel expenses,
other increased costs or increased operating restrictions.

AVAILABLE INFORMATION

Our website address is www.deepwater.com. We make our website content
-----------------
available for information purposes only. It should not be relied upon for
investment purposes, nor is it incorporated by reference in this Form 10-K. We
make available on this website under "Investor Relations-Financial Reports",
free of charge, our annual reports on Form 10-K, quarterly reports on Form 10-Q,
current reports on Form 8-K and amendments to those reports as soon as
reasonably practicable after we electronically file those materials with, or
furnish those materials to, the Securities and Exchange Commission ("SEC"). The
SEC also maintains a website at www.sec.gov that contains reports, proxy
-----------
statements and other information regarding SEC registrants, including us.

ITEM 2. PROPERTIES

The description of our property included under "Item 1. Business" is
incorporated by reference herein.

We maintain offices, land bases and other facilities worldwide, including
our principal executive offices in Houston, Texas and regional operational
offices in the U.S., Brazil, U.K., France, Dubai and Indonesia. Our remaining
offices and bases are located in various countries in North America, South
America, the Caribbean, Europe, Africa, the Middle East and Asia. We lease most
of these facilities.

We acquired our oil and gas business in the R&B Falcon merger described
under "Item 1. Business." The only properties of any significance to this
business remaining in 2002 were interests in production sharing contracts
covering two concessions in Gabon. We terminated our interest in one of the two
concessions in January 2003 and have also given notice to terminate our interest
in the second concession. We incurred a non-cash impairment charge of
approximately $1 million in the first quarter of 2003 as a result of the
termination of these two interests.

-12-

ITEM 3. LEGAL PROCEEDINGS

In 1990 and 1991, two of our subsidiaries were served with various
assessments collectively valued at approximately $7 million from the
municipality of Rio de Janeiro, Brazil to collect a municipal tax on services.
We believe that neither subsidiary is liable for the taxes and have contested
the assessments in the Brazilian administrative and court systems. The Brazil
Supreme Court rejected our appeal of an adverse lower court's ruling with
respect to a June 1991 assessment, which was valued at approximately $6 million.
We plan to challenge the assessment in a separate proceeding. We have received
adverse rulings at various levels in connection with a disputed August 1990
assessment that is still pending before the Brazil Superior Court of Justice. We
also are awaiting a ruling from the Taxpayer's Council in connection with an
October 1990 assessment. If our defenses are ultimately unsuccessful, we believe
that the Brazilian government-controlled oil company, Petrobras, has a
contractual obligation to reimburse us for municipal tax payments required to be
paid by them. We do not expect the liability, if any, resulting from these
assessments to have a material adverse effect on our business or consolidated
financial position.

The Indian Customs Department, Mumbai, filed a "show cause notice" against
one of our subsidiaries and various third parties in July 1999. The show cause
notice alleged that the initial entry into India in 1988 and other subsequent
movements of the Trident II jackup rig operated by the subsidiary constituted
imports and exports for which proper customs procedures were not followed and
sought payment of customs duties of approximately $31 million based on an
alleged 1998 rig value of $49 million, with interest and penalties, and
confiscation of the rig. In January 2000, the Customs Department issued its
order, which found that we had imported the rig improperly and intentionally
concealed the import from the authorities, and directed us to pay a redemption
fee of approximately $3 million for the rig in lieu of confiscation and to pay
penalties of approximately $1 million in addition to the amount of customs
duties owed. In February 2000, we filed an appeal with the Customs, Excise and
Gold (Control) Appellate Tribunal ("CEGAT") together with an application to have
the confiscation of the rig stayed pending the outcome of the appeal. In March
2000, the CEGAT ruled on the stay application, directing that the confiscation
be stayed pending the appeal. The CEGAT issued its opinion on our appeal on
February 2, 2001, and while it found that the rig was imported in 1988 without
proper documentation or payment of duties, the redemption fee and penalties were
reduced to less than $0.1 million in view of the ambiguity surrounding the
import practice at the time and the lack of intentional concealment by us. The
CEGAT further sustained our position regarding the value of the rig at the time
of import as $13 million and ruled that subsequent movements of the rig were not
liable to import documentation or duties in view of the prevailing practice of
the Customs Department, thus limiting our exposure as to custom duties to
approximately $6 million. Following the CEGAT order, we tendered payment of
redemption, penalty and duty in the amount specified by the order by offset
against a $0.6 million deposit and $10.7 million guarantee previously made by
us. The Customs Department attempted to draw the entire guarantee, alleging the
actual duty payable is approximately $22 million based on an interpretation of
the CEGAT order that we believe is incorrect. This action was stopped by an
interim ruling of the High Court, Mumbai on writ petition filed by us. We and
the Customs Department both filed appeals with the Supreme Court of India
against the order of the CEGAT, and both appeals have been admitted. We applied
for an expedited hearing, which was denied. We and our customer agreed to pursue
and obtained the issuance of documentation from the Ministry of Petroleum that,
if accepted by the Customs Department, would reduce the duty to nil. The
agreement with the customer further provided that if this reduction was not
obtained by the end of 2001, our customer would pay the duty up to a limit of
$7.7 million. The Customs Department did not accept the documentation or agree
to refund the duties already paid. We have requested the refund from our
customer, who has refused. We are pursuing our remedies against the Customs
Department and our customer. We do not expect, in any event, that the ultimate
liability, if any, resulting from the matter will have a material adverse effect
on our business or consolidated financial position.

In January 2000, a pipeline in the U.S. Gulf of Mexico was damaged by an
anchor from one of our drilling rigs while the rig was under tow. The incident
resulted in damage to offshore facilities, including a crude oil pipeline, the
release of hydrocarbons from the damaged section of the pipeline and the
shutdown of the pipeline and allegedly affected production platforms. All
appropriate governmental authorities were notified, and we cooperated fully with
the operator and relevant authorities in support of the remediation efforts.
Certain owners and operators of the pipeline (Poseidon Oil Pipeline Company LLC,
Equilon Enterprises LLC, Poseidon Pipeline Company, LLC and Marathon Oil
Company) filed suit in March 2000 in federal court, Eastern District of
Louisiana, alleging various damages in excess of $30 million. A second suit was
filed by Walter Oil & Gas Corporation and certain other plaintiffs in Harris
County, Texas alleging various damages in excess of $1.8 million, and we
obtained a summary judgment against Walter Oil & Gas Corporation and Amerada
Hess. We filed a limitation of liability proceeding in federal court, Eastern
District of Louisiana, claiming benefit of various statutes providing limitation
of liability for vessel owners, the result of which was to stay the first two
suits and to cause potential claimants (including the plaintiffs in the existing
suits) to file claims in this proceeding. El Paso Energy Corporation, the
owner/operator of the platform from which a riser was allegedly damaged, and
Texaco Exploration and Production Inc. filed claims in the limitation of
liability proceeding as well. All claims arising out of the loss have been
settled and the terms of the settlement have been reflected in our results of
operations for the year ended December 31, 2002. The settlement did not have a
material adverse effect on our business or consolidated financial position.

-13-

In November 1988, a lawsuit was filed in the U.S. District Court for the
Southern District of West Virginia against Reading & Bates Coal Co., a wholly
owned subsidiary of R&B Falcon, by SCW Associates, Inc. claiming breach of an
alleged agreement to purchase the stock of Belva Coal Company, a wholly owned
subsidiary of Reading & Bates Coal Co. with coal properties in West Virginia.
When those coal properties were sold in July 1989 as part of the disposition of
R&B Falcon's coal operations, the purchasing joint venture indemnified Reading &
Bates Coal Co. and R&B Falcon against any liability Reading & Bates Coal Co.
might incur as a result of this litigation. A judgment for the plaintiff of
$32,000 entered in February 1991 was satisfied and Reading & Bates Coal Co. was
indemnified by the purchasing joint venture. On October 31, 1990, SCW
Associates, Inc., the plaintiff in the above-referenced action, filed a separate
ancillary action in the Circuit Court, Kanawha County, West Virginia against R&B
Falcon, Caymen Coal, Inc. (the former owner of R&B Falcon's West Virginia coal
properties), as well as the joint venture, Mr. William B. Sturgill (the former
President of Reading & Bates Coal Co.) personally, three other companies in
which we believe Mr. Sturgill holds an equity interest, two employees of the
joint venture, First National Bank of Chicago and First Capital Corporation. The
lawsuit sought to recover compensatory damages of $50 million and punitive
damages of $50 million for alleged tortious interference with the contractual
rights of the plaintiff and to impose a constructive trust on the proceeds of
the use and/or sale of the assets of Caymen Coal, Inc. as they existed on
October 15, 1988. The lawsuit was settled in August 2002, and the terms of the
settlement have been reflected in our results of operations for the year ended
December 31, 2002. The settlement did not have a material adverse effect on our
business or consolidated financial position.

In March 1997, an action was filed by Mobil Exploration and Producing U.S.
Inc. and affiliates, St. Mary Land & Exploration Company and affiliates and
Samuel Geary and Associates, Inc. against us, the underwriters and insurance
broker in the 16th Judicial District Court of St. Mary Parish, Louisiana. The
plaintiffs alleged damages amounting to in excess of $50 million in connection
with the drilling of a turnkey well in 1995 and 1996. The case was tried before
a jury in January and February 2000, and the jury returned a verdict of
approximately $30 million in favor of the plaintiffs for excess drilling costs,
loss of insurance proceeds, loss of hydrocarbons and interest. We have appealed
such judgment, and the Louisiana Court of Appeals has reduced the amount for
which we may be responsible to less than $10 million. The plaintiffs have
requested that the Supreme Court of Louisiana consider the matter and reinstate
the original verdict. We believe that all but potentially the portion of the
verdict representing excess drilling costs of approximately $4.7 million is
covered by relevant primary and excess liability insurance policies. However,
the insurers and underwriters have denied coverage. We have instituted
litigation against those insurers and underwriters to enforce our rights under
the relevant policies. We do not expect that the ultimate outcome of this case
will have a material adverse effect on our business or consolidated financial
position.

In October 2001, we were notified by the U.S. Environmental Protection
Agency ("EPA") that the EPA had identified a subsidiary of ours as a potentially
responsible party in connection with the Palmer Barge Line superfund site
located in Port Arthur, Jefferson County, Texas. Based upon the information
provided by the EPA and our review of our internal records to date, we dispute
our designation as a potentially responsible party and do not expect that the
ultimate outcome of this case will have a material adverse effect on our
business or consolidated financial position.

We are involved in a number of other lawsuits, all of which have arisen in
the ordinary course of our business. We do not believe that ultimate liability,
if any, resulting from any such other pending litigation will have a material
adverse effect on our business or consolidated financial position. We cannot
predict with certainty the outcome or effect of any of the litigation matters
specifically described above or of any such other pending litigation. There can
be no assurance that our beliefs or expectations as to the outcome or effect of
any lawsuit or other litigation matter will prove correct and the eventual
outcome of these matters could materially differ from management's current
estimates.

-14-

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

The Company did not submit any matter to a vote of its security holders
during the fourth quarter of 2002.

EXECUTIVE OFFICERS OF THE REGISTRANT

AGE AS OF
OFFICER OFFICE MARCH 1, 2003
----------------------- ----------------------------------------------------------------- -------------

J. Michael Talbert Chairman of the Board 56
Robert L. Long President and Chief Executive Officer 57
Jean P. Cahuzac Executive Vice President and Chief Operating Officer 49
Donald R. Ray Executive Vice President, Quality, Health, Safety and Environment 56
Eric B. Brown Senior Vice President, General Counsel and Corporate Secretary 51
Gregory L. Cauthen Senior Vice President, Chief Financial Officer and Treasurer 45
Barbara S. Koucouthakis Vice President and Chief Information Officer 44
Ricardo H. Rosa Vice President and Controller 46
Tim Juran Vice President, Human Resources 44
Michael I. Unsworth Vice President, Marketing 44
Jan Rask President and Chief Executive Officer of TODCO 47

The officers of the Company are elected annually by the Board of
Directors. There is no family relationship between any of the above-named
executive officers.

J. Michael Talbert is Chairman of the Board of the Company. Mr. Talbert
served as Chief Executive Officer of the Company from August 1994 to October
2002, at which time he assumed his current position, and has been a member of
the Board of Directors since August 1994. Mr. Talbert also served as Chairman
of the Board of the Company from August 1994 until the time of the Sedco Forex
merger and as President of the Company from the time of such merger until
December 2001. Prior to assuming his duties with the Company, Mr. Talbert was
President and Chief Executive Officer of Lone Star Gas Company, a natural gas
distribution company and a division of Ensearch Corporation.

Robert L. Long is President, Chief Executive Officer and a member of the
Board of Directors of the Company. Mr. Long served as President of the Company
from December 2001 to October 2002, at which time he assumed the additional
position of Chief Executive Officer and became a member of the Board of
Directors. Mr. Long served as Chief Financial Officer of the Company from
August 1996 until December 2001. Mr. Long served as Senior Vice President of
the Company from May 1990 until the time of the Sedco Forex merger, at which
time he assumed the position of Executive Vice President. Mr. Long also served
as Treasurer of the Company from September 1997 until March 2001. Mr. Long has
been employed by the Company since 1976 and was elected Vice President in 1987.

Jean P. Cahuzac is Executive Vice President and Chief Operating Officer of
the Company. Mr. Cahuzac served as Executive Vice President, Operations of the
Company from February 2001 until October 2002, at which time he assumed his
current position. Mr. Cahuzac served as President of Sedco Forex from January
1999 until the time of the Sedco Forex merger, at which time he assumed the
positions of Executive Vice President and President, Europe, Middle East and
Africa with the Company. Mr. Cahuzac served as Vice President-Operations
Manager of Sedco Forex from May 1998 to January 1999, Region Manager-Europe,
Africa and CIS of Sedco Forex from September 1994 to May 1998 and Vice
President/General Manager-North Sea Region of Sedco Forex from February 1994 to
September 1994. He had been employed by Schlumberger since 1979.

Donald R. Ray is Executive Vice President, Quality, Health, Safety &
Environment of the Company. Mr. Ray served as Executive Vice President,
Technical Services of the Company from February 2001 until October 2002, at
which time he assumed his current position. Mr. Ray served as Senior Vice
President, Technical Services of the Company from the time of the Sedco Forex
merger until February 2001 and served as Senior Vice President, with
responsibility for technical services, from December 1, 1996 until the time of
the Sedco Forex merger. Mr. Ray has been employed by the Company since 1972 and
has served as a Vice President of the Company since 1986.

Eric B. Brown is Senior Vice President, General Counsel and Corporate
Secretary of the Company. Mr. Brown served as Vice President and General Counsel
of the Company since February 1995 and Corporate Secretary of the Company since
September 1995. He assumed the position of Senior Vice President in February
2001. Prior to assuming his duties with the Company, Mr. Brown served as
General Counsel of Coastal Gas Marketing Company.

Gregory L. Cauthen is Senior Vice President, Chief Financial Officer and
Treasurer of the Company. Mr. Cauthen served as Vice President, Chief Financial
Officer and Treasurer since December 2001 and was elected in July 2002

-15-

as Senior Vice President. Mr. Cauthen served as Vice President, Finance from
March 2001 to December 2001. Prior to joining the Company, he served as
President and Chief Executive Officer of WebCaskets.com, Inc., a provider of
death care services, from June 2000 until February 2001. Prior to June 2000, he
was employed at Service Corporation International, a provider of death care
services, where he served as Senior Vice President, Financial Services from July
1998 to August 1999, Vice President, Treasurer from July 1995 to July 1998, was
assigned to various special projects from August 1999 to May 2000 and had been
employed in various other positions since February 1991.

Barbara S. Koucouthakis is Vice President and Chief Information Officer of
the Company. Ms. Koucouthakis served as Controller of the Company from January
1990 and Vice President from April 1993 until the time of the Sedco Forex
merger, at which time she assumed her current position. She has been employed
by the Company since 1982.

Ricardo H. Rosa is Vice President and Controller of the Company. Mr. Rosa
served as Controller of Sedco Forex from September 1995 until the time of the
Sedco Forex merger, at which time he assumed his current position with the
Company. Mr. Rosa had been employed in various positions by Schlumberger since
1983. Prior to joining Schlumberger in 1983, he served as an Audit Manager for
the accounting firm, Price Waterhouse.

Tim L. Juran is Vice President, Human Resources of the Company. Mr. Juran
served as Region Manager, North America of the Company from February 2001 until
August 2002, at which time he assumed his current position. Mr. Juran served as
Vice President & Regional Manager, North America & Europe for R&B Falcon from
June 1999 to February 2001 and as Vice President & Regional Manager, Europe from
January 1997 to May 1999. Prior to the R&B Falcon merger, Mr. Juran had been
employed by R&B Falcon since 1980.

Michael I. Unsworth is Vice President, Marketing of the Company. Mr.
Unsworth served as Region Manager, Asia for the Company from the time of the
Sedco Forex merger until February 2001, at which time he assumed his present
position with the Company. Previously, he served as Region Manager, Asia for
Sedco Forex from 1998 through 1999 and had been employed by Schlumberger since
1981.

Jan Rask is President and Chief Executive Officer of TODCO, with
responsibility for our Shallow & Inland Water business segment. Mr. Rask was
Managing Director, Acquisitions and Special Operations, of Pride International,
Inc., a contract drilling company, from September 2001 to July 2002, when he
joined the Company. From July 1996 to September 2001, Mr. Rask was President,
Chief Executive Officer and a director of Marine Drilling Companies, Inc., a
contract drilling company. Mr. Rask served as President and Chief Executive
Officer of Arethusa (Off-Shore) Limited from May 1993 until the acquisition of
Arethusa (Off-Shore) Limited by Diamond Offshore Drilling in May 1996. Mr. Rask
joined Arethusa (Off-Shore) Limited's principal operating subsidiary in 1990 as
its President and Chief Executive Officer.

We have also elected Brenda S. Masters to become our Vice President and
Controller effective as of April 1, 2003, replacing Mr. Rosa, who will assume a
new management position within our company. Ms. Masters has been our Assistant
Controller since November 1996. She joined the Company in April 1996 as Director
of Accounting and served in that capacity until November 1996 at which time she
was promoted to her current position. Before joining the Company, she served as
Senior Manager with Ernst & Young LLP.

-16-

PART II

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

Our ordinary shares are listed on the New York Stock Exchange (the "NYSE")
under the symbol "RIG." The following table sets forth the high and low sales
prices of our ordinary shares for the periods indicated as reported on the NYSE
Composite Tape.

PRICE
--------------
HIGH LOW
------ ------

2001 First Quarter . . . . . . . . . . . $54.50 $40.00
Second Quarter. . . . . . . . . . . 57.69 40.35
Third Quarter . . . . . . . . . . . 41.98 23.05
Fourth Quarter. . . . . . . . . . . 34.22 24.20

2002 First Quarter . . . . . . . . . . . $34.66 $26.51
Second Quarter. . . . . . . . . . . 39.33 30.00
Third Quarter . . . . . . . . . . . 31.75 19.60
Fourth Quarter. . . . . . . . . . . 25.89 18.10

2003 First Quarter (through February 28) $24.36 $20.75

On February 28, 2003, the last reported sales price of our ordinary shares
on the NYSE Composite Tape was $22.70 per share. On such date, there were
24,398 holders of record of the Company's ordinary shares and 319,764,712
ordinary shares outstanding.

We discontinued the payment of a quarterly cash dividend, and the final
payment of $0.03 per share was paid on June 13, 2002. Prior to the elimination
of the cash dividend, we had paid quarterly cash dividends of $0.03 per ordinary
share since the fourth quarter of 1993. Any future declaration and payment of
dividends will be (i) dependent upon our results of operations, financial
condition, cash requirements and other relevant factors, (ii) subject to the
discretion of the Board of Directors, (iii) subject to restrictions contained in
our bank credit agreements and note purchase agreement and (iv) payable only out
of our profits or share premium account in accordance with Cayman Islands law.

There is currently no reciprocal tax treaty between the Cayman Islands and
the United States regarding withholding.

We are a Cayman Islands exempted company. Our authorized share capital is
$13,000,000, divided into 800,000,000 ordinary shares, par value $0.01, and
50,000,000 preference shares, par value $0.10, which shares may be designated
and created as shares of any other classes or series of shares with the
respective rights and restrictions determined by action of our board of
directors. On February 28, 2003, no preference shares were outstanding.

The holders of ordinary shares are entitled to one vote per share other
than on the election of directors.

With respect to the election of directors, each holder of ordinary shares
entitled to vote at the election has the right to vote, in person or by proxy,
the number of shares held by him for as many persons as there are directors to
be elected and for whose election that holder has a right to vote. The directors
are divided into three classes, with only one class being up for election each
year. Directors are elected by a plurality of the votes cast in the election.
Cumulative voting for the election of directors is prohibited by our articles of
association.

There are no limitations imposed by Cayman Islands law or our articles of
association on the right of nonresident shareholders to hold or vote their
ordinary shares.

The rights attached to any separate class or series of shares, unless
otherwise provided by the terms of the shares of that class or series, may be
varied only with the consent in writing of the holders of all of the issued
shares of that class or series or by a special resolution passed at a separate
general meeting of holders of the shares of that class or series. The necessary
quorum for that meeting is the presence of holders of at least a majority of the
shares of that class or series. Each holder of shares of the class or series
present, in person or by proxy, will have one vote for each share of the class
or series

-17-

of which he is the holder. Outstanding shares will not be deemed to be varied by
the creation or issuance of additional shares that rank in any respect prior to
or equivalent with those shares.

Under Cayman Islands law, some matters, like altering the memorandum or
articles of association, changing the name of a company, voluntarily winding up
a company or resolving to be registered by way of continuation in a jurisdiction
outside the Cayman Islands, require approval of shareholders by a special
resolution. A special resolution is a resolution (1) passed by the holders of
two-thirds of the shares voted at a general meeting or (2) approved in writing
by all shareholders entitled to vote at a general meeting of the company.

The presence of shareholders, in person or by proxy, holding at least a
majority of the issued shares generally entitled to vote at a meeting, is a
quorum for the transaction of most business. However, different quorums are
required in some cases to approve a change in our articles of association.

Our board of directors is authorized, without obtaining any vote or consent
of the holders of any class or series of shares unless expressly provided by the
terms of issue of that class or series, to provide from time to time for the
issuance of classes or series of preference shares and to establish the
characteristics of each class or series, including the number of shares,
designations, relative voting rights, dividend rights, liquidation and other
rights, redemption, repurchase or exchange rights and any other preferences and
relative, participating, optional or other rights and limitations not
inconsistent with applicable law.

Our articles of association contain provisions that could prevent or delay
an acquisition of our company by means of a tender offer, proxy contest or
otherwise.

The foregoing description is a summary. This summary is not complete and is
subject to the complete text of our memorandum and articles of association. For
more information regarding our ordinary shares and our preference shares, see
our Current Report on Form 8-K dated May 14, 1999 and our memorandum and
articles of association. Our memorandum and articles of association are filed as
exhibits to this Report.

-18-

ITEM 6. SELECTED CONSOLIDATED FINANCIAL DATA

The selected consolidated financial data as of December 31, 2002 and 2001
and for each of the three years in the period ended December 31, 2002 has been
derived from the audited consolidated financial statements included elsewhere
herein. The selected consolidated financial data as of December 31, 2000, 1999
and 1998, and for the years ended December 31, 1999 and 1998 has been derived
from audited consolidated financial statements not included herein. The
following data should be read in conjunction with "Item 7. Management's
Discussion and Analysis of Financial Condition and Results of Operations" and
the audited consolidated financial statements and the notes thereto included
under "Item 8. Financial Statements and Supplementary Data."

On January 31, 2001, we completed a merger transaction with R&B Falcon. As
a result of the merger, R&B Falcon became our indirect wholly owned subsidiary
and subsequently changed its name to TODCO. The merger was accounted for as a
purchase and we were treated as the accounting acquiror. The balance sheet data
as of December 31, 2001 represents the consolidated financial position of the
combined company. The statement of operations and other financial data for the
year ended December 31, 2001 include eleven months of operating results and cash
flows for TODCO.

On December 31, 1999, the merger of Transocean Offshore Inc. and Sedco
Forex was completed. Sedco Forex was the offshore contract drilling service
business of Schlumberger and was spun-off immediately prior to the merger
transaction. As a result of the merger, Sedco Forex became a wholly owned
subsidiary of Transocean Offshore Inc., which changed its name to Transocean
Sedco Forex Inc. The merger was accounted for as a purchase with Sedco Forex
treated as the accounting acquiror. The balance sheet data as of December 31,
2000 and 1999 and the statement of operations and other financial data for the
year ended December 31, 2000 represent the consolidated financial position, cash
flows and results of operations of the merged company. The balance sheet data,
statement of operations and other financial data for the periods prior to the
merger, represent the financial position, cash flows and results of operations
of Sedco Forex and not those of historical Transocean Offshore Inc.

YEARS ENDED DECEMBER 31,
-----------------------------------------------------
2002 2001 2000 1999 1998
-------- -------- ------- ------- -------
(IN MILLIONS, EXCEPT PER SHARE DATA)

STATEMENT OF OPERATIONS
Operating revenues . . . . . . . . . . . . . . . . . . . . $ 2,674 $ 2,820 $1,230 $ 648 $1,091
Operating income (loss). . . . . . . . . . . . . . . . . . (2,310) 550 133 49 377
Income (loss) before extraordinary items and
cumulative effect of a change in accounting principle. (2,368) 272 107 58 342
Income (loss) before extraordinary items and cumulative
effect of a change in accounting principle per share
Basic. . . . . . . . . . . . . . . . . . . . . . . . . $ (7.42) $ 0.88 $ 0.51 $ 0.53 (a) $ 3.12 (a)
Diluted. . . . . . . . . . . . . . . . . . . . . . . . $ (7.42) $ 0.86 $ 0.50 $ 0.53 (a) $ 3.12 (a)

BALANCE SHEET DATA (AT END OF PERIOD)
Total assets . . . . . . . . . . . . . . . . . . . . . . . $12,665 $17,048 $6,359 $6,140 $1,473
Total debt . . . . . . . . . . . . . . . . . . . . . . . . 4,678 5,024 1,453 1,266 100
Total equity . . . . . . . . . . . . . . . . . . . . . . . 7,141 10,910 4,004 3,910 564
Dividends per share. . . . . . . . . . . . . . . . . . . . $ 0.06 $ 0.12 $ 0.12 - -

OTHER FINANCIAL DATA
Cash provided by operating activities. . . . . . . . . . . $ 937 $ 560 $ 196 $ 241 $ 473
Cash used in investing activities. . . . . . . . . . . . . (45) (26) (493) (90) (422)
Cash provided by (used in) financing activities. . . . . . (531) 285 166 (159) 27
Capital expenditures . . . . . . . . . . . . . . . . . . . 141 506 575 537 425
Adjusted EBITDA (b). . . . . . . . . . . . . . . . . . . . 1,122 1,175 383 187 508
Operating Margin . . . . . . . . . . . . . . . . . . . . . N/M 20% 11% 8% 35%
Adjusted EBITDA Margin (c) . . . . . . . . . . . . . . . . 42% 42% 31% 29% 47%

_________________________
"N/M" means not meaningful due to loss on impairments of long-lived assets.

-19-

(a) Unaudited pro forma earnings per share was calculated using the Transocean
Inc. ordinary shares issued pursuant to the Sedco Forex merger agreement
and the dilutive effect of Transocean Inc. stock options granted to former
Sedco Forex employees at the time of the Sedco Forex merger, as applicable.
(b) Adjusted EBITDA means income (loss) before minority interest, interest,
taxes, depreciation, amortization, impairment loss on long-lived assets,
net gain (loss) from sale of assets, extraordinary items and cumulative
effect of a change in accounting principle. Adjusted EBITDA is presented
here because it is an indication of our operating performance and our
ability to incur and service debt and is commonly used by investors as an
analytical indicator in our industry. Adjusted EBITDA measures presented
may not be comparable to similarly titled measures used by other companies.
Adjusted EBITDA is not a measurement presented in accordance with generally
accepted accounting principles ("GAAP"), and we do not intend Adjusted
EBITDA to represent cash flows from operations as defined by GAAP. You
should not consider Adjusted EBITDA to be an alternative to net income,
cash flows from operations or any other items calculated in accordance with
GAAP or an indicator of our operating performance. The following are the
components of our Adjusted EBITDA (in millions):

YEARS ENDED DECEMBER 31,
----------------------------------------
2002 2001 2000 1999 1998
-------- ------ ------ ------ ------

Net income (loss). . . . . . . . . . . . . . . . . . . $(3,732) $ 253 $ 108 $ 58 $ 342
Cumulative effect of a change in accounting principle. 1,364 - - - -
(Gain) loss on extraordinary items, net of tax . . . . - 19 (1) - -
Minority interest. . . . . . . . . . . . . . . . . . . 3 3 - - -
Income tax expense (benefit) . . . . . . . . . . . . . (123) 86 37 (9) 32
Interest expense, net of amounts capitalized . . . . . 212 224 3 10 13
Interest income. . . . . . . . . . . . . . . . . . . . (26) (19) (6) (5) (4)
(Gain) loss from sale of assets, net . . . . . . . . . (3) (56) (18) 1 -
Impairment loss on long-lived assets . . . . . . . . . 2,927 40 - - -
Goodwill amortization. . . . . . . . . . . . . . . . . - 155 27 - -
Depreciation . . . . . . . . . . . . . . . . . . . . . 500 470 233 132 125

Operating revenues and long-lived assets by country are as follows (in
millions):

YEARS ENDED DECEMBER 31,
------------------------
2002 2001 2000
------- ------- ------

OPERATING REVENUES
United States . . . . . . $ 753 $ 980 $ 265
United Kingdom. . . . . . 346 355 159
Brazil. . . . . . . . . . 283 356 154
Norway. . . . . . . . . . 145 228 248
Rest of the World . . . . 1,147 901 404
------- ------- ------
Total Operating Revenues. $ 2,674 $ 2,820 $1,230
======= ======= ======

AS OF DECEMBER 31,
------------------
2002 2001
------- -------
LONG-LIVED ASSETS
United States . . . . . . $ 3,905 $ 3,882
Goodwill (a). . . . . . . 2,218 6,467
Rest of the World . . . . 4,630 4,962
------- -------
Total Long-Lived Assets . $10,753 $15,311
======= =======

______________________
(a) Goodwill resulting from the Sedco Forex and R&B Falcon mergers has not
been allocated to individual countries.

-20-

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

The following information should be read in conjunction with the
information contained in the audited consolidated financial statements and the
notes thereto included under "Item 8. Financial Statements and Supplementary
Data" elsewhere in this annual report.

OVERVIEW

Transocean Inc. (formerly known as "Transocean Sedco Forex Inc.", together
with its subsidiaries and predecessors, unless the context requires otherwise,
the "Company," "Transocean," "we," "us" or "our") is a leading international
provider of offshore and inland marine contract drilling services for oil and
gas wells. As of March 1, 2003, we owned, had partial ownership interests in or
operated 158 mobile offshore and barge drilling units that we consider to be our
core assets. As of this date, our core assets consisted of 31
high-specification drillships and semisubmersibles ("floaters"), 29 other
floaters, 55 jackup rigs, 35 drilling barges, five tenders and three submersible
drilling rigs. In addition, the fleet included non-core assets consisting of a
mobile offshore production unit, two platform drilling rigs and a land rig, as
well as nine land rigs and three lake barges in Venezuela. We contract our
drilling rigs, related equipment and work crews primarily on a dayrate basis to
drill oil and gas wells. We also provide additional services, including
management of third-party well service activities.

General uncertainty over world economic and political events translated
into decreased demand for our rigs during the year. While the overall average
fleet dayrate increased from $66,000 in 2001 to $77,600 in 2002, utilization was
down substantially from 72% in 2001 to 61% in 2002. Revenues in 2002 were down
$146 million from 2001, but we also brought costs down by more than $100 million
by responding rapidly to reduce costs when rigs were idled. Our efforts to
reduce costs by implementing standardized purchasing through negotiated
agreements, nationalization of our labor force where appropriate and improved
operating performance on our newbuild high-specification rigs contributed to the
reduction of costs year over year. Our 2002 financial results included the
recognition of a number of non-cash charges pertaining substantially to goodwill
impairment. We generated significant cash during 2002 and brought our net debt
down from $4.2 billion at the end of 2001 to $3.3 billion at the end of 2002
(see "-Liquidity and Capital Resources-Sources of Liquidity").

On January 31, 2001, we completed a merger transaction (the "R&B Falcon
merger") with R&B Falcon Corporation ("R&B Falcon"). At the time of the merger,
R&B Falcon owned, had partial ownership interests in, operated or had under
construction more than 100 mobile offshore drilling units and other units
utilized in the support of offshore drilling activities. As a result of the
merger, R&B Falcon became our indirect wholly owned subsidiary and subsequently
changed its name to TODCO. The merger was accounted for as a purchase and we
were the accounting acquiror. The consolidated balance sheet as of December 31,
2001 represents the consolidated financial position of the combined company. The
consolidated statements of operations and cash flows for the year ended December
31, 2001 include eleven months of operating results and cash flows for TODCO.

Prior to the R&B Falcon merger, we operated in one industry segment. As a
result of acquiring shallow and inland water drilling units in the R&B Falcon
merger, our operations have been aggregated into two reportable segments: (i)
International and U.S. Floater Contract Drilling Services and (ii) Gulf of
Mexico Shallow and Inland Water. The International and U.S. Floater Contract
Drilling Services segment consists of high-specification floaters, other
floaters, non-U.S. jackups, other mobile offshore drilling units, other assets
used in support of offshore drilling activities and other offshore support
services. The Gulf of Mexico Shallow and Inland Water segment consists of
jackups and submersible drilling rigs located in the U.S. Gulf of Mexico and
Trinidad and U.S. inland drilling barges, as well as land drilling units and
lake barges located in Venezuela.

Effective January 1, 2002, we changed the composition of our reportable
segments with the move of the responsibility for our Venezuela operations to the
Gulf of Mexico Shallow and Inland Water segment. Prior periods have been
restated to reflect the change.

On May 9, 2002, we changed our name from Transocean Sedco Forex Inc. to
Transocean Inc.

On May 9, 2002, our Board of Directors voted to discontinue the payment of
a cash dividend after the cash dividend payable on June 13, 2002 to shareholders
of record on May 30, 2002.

In July 2002, we announced plans to pursue a divestiture of our Gulf of
Mexico Shallow and Inland Water business. In December 2002, our subsidiary,
TODCO, filed a registration statement with the Securities and Exchange
Commission ("SEC") relating to our previously announced initial public offering
of our Gulf of Mexico Shallow and Inland Water business. We expect to separate
this business from Transocean and establish TODCO as a publicly traded company.

-21-

We are proceeding to reorganize TODCO as the entity that owns that business in
preparation of the offering. We plan to transfer assets not used in this
business from TODCO to our other subsidiaries, and these internal transfers will
not affect the consolidated financial statements of Transocean. We expect to
complete the initial public offering when market conditions warrant, subject to
various factors. Given the current general uncertainty in the equity and U.S.
natural gas drilling markets, we are unsure when the transaction could be
completed on terms acceptable to us. We do not expect to sell all of our
interest in TODCO in the initial public offering. Until we complete the initial
public offering transaction, we will continue to operate and account for TODCO
as our Gulf of Mexico Shallow and Inland Water segment.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

Our discussion and analysis of our financial condition and results of
operations are based upon our consolidated financial statements, which have been
prepared in accordance with accounting principles generally accepted in the
United States. The preparation of these financial statements requires us to make
estimates and judgments that affect the reported amounts of assets, liabilities,
revenues and expenses and related disclosure of contingent assets and
liabilities. On an on-going basis, we evaluate our estimates, including those
related to bad debts, materials and supplies obsolescence, investments, property
and equipment, intangible assets and goodwill, income taxes, financing
operations, workers' insurance, pensions and other post-retirement and
employment benefits and contingent liabilities. We base our estimates on
historical experience and on various other assumptions that are believed to be
reasonable under the circumstances, the results of which form the basis for
making judgments about the carrying values of assets and liabilities that are
not readily apparent from other sources. Actual results may differ from these
estimates under different assumptions or conditions.

We believe the following are our most critical accounting policies. These
policies require significant judgments and estimates used in the preparation of
our consolidated financial statements.

Allowance for doubtful accounts-We establish reserves for doubtful accounts
on a case-by-case basis when we believe the required payment of specific amounts
owed to us is unlikely to occur. We derive a majority of our revenue from
services to international oil companies and government-owned or
government-controlled oil companies. Our receivables are concentrated in certain
oil-producing countries. We generally do not require collateral or other
security to support customer receivables. If the financial condition of our
customers was to deteriorate or their access to freely convertible currency was
restricted, resulting in impairment of their ability to make the required
payments, additional allowances may be required.

Valuation allowance for deferred tax assets-We record a valuation allowance
to reduce our deferred tax assets to the amount that is more likely than not to
be realized. While we have considered future taxable income and ongoing prudent
and feasible tax planning strategies in assessing the need for the valuation
allowance, should we determine that we would more likely than not be able to
realize our deferred tax assets in the future in excess of our net recorded
amount, an adjustment to the valuation allowance would increase income in the
period such determination was made. Likewise, should we determine that we would
more likely than not be unable to realize all or part of our net deferred tax
asset in the future, an adjustment to the valuation allowance would reduce
income in the period such determination was made.

Goodwill impairment-We perform a test for impairment of our goodwill
annually as of October 1 as prescribed by Statement of Financial Accounting
Standards ("SFAS") 142, Goodwill and Other Intangibles. Because our business is
cyclical in nature, goodwill could be significantly impaired depending on when
the assessment is performed in the business cycle. Fair value of our reporting
units is based on a blend of estimated discounted cash flows, publicly traded
company multiples and acquisition multiples. Estimated discounted cash flows are
based on projected utilization and dayrates. Publicly traded company multiples
and acquisition multiples are derived from information on traded shares and
analysis of recent acquisitions in the marketplace, respectively, for companies
with operations similar to ours. Changes in the assumptions used in the fair
value calculation could result in an estimated reporting unit fair value that is
below the carrying value, which may give rise to an impairment of goodwill. In
addition to the annual review, we also test for impairment should an event occur
or circumstances change that may indicate a reduction in the fair value of a
reporting unit below its carrying value.

Property and equipment-Our property and equipment represents more than 60
percent of our total assets. We determine the carrying value of these assets
based on our property and equipment accounting policies, which incorporate our
estimates, assumptions and judgments relative to capitalized costs, useful lives
and salvage values of our rigs. We review our property and equipment for
impairment when events or changes in circumstances indicate that the carrying
value of such assets may be impaired or when reclassifications are made between
property and equipment and assets held for sale as prescribed by SFAS 144,
Accounting for Impairment or Disposal of Long-Lived Assets. Asset impairment
evaluations are based on estimated undiscounted cash flows for the assets being
evaluated. Our estimates, assumptions and judgments used in the application of
our property and equipment accounting policies reflect both historical
experience and expectations regarding future industry conditions and operations.
Using different estimates, assumptions and judgments,

-22-

especially those involving the useful lives of our rigs and expectations
regarding future industry conditions and operations, could result in different
carrying values of assets and results of operations.

Pension and Other Postretirement Benefits-Our defined benefit pension and
other postretirement benefit (retiree life insurance and medical benefits)
obligations and the related benefit costs are accounted for in accordance with
SFAS 87, Employers' Accounting for Pensions, and SFAS 106, Employers' Accounting
for Postretirement Benefits Other than Pensions. Pension and postretirement
costs and obligations are actuarially determined and are affected by assumptions
including expected return on plan assets, discount rates, compensation
increases, employee turnover rates and health care cost trend rates. We evaluate
our assumptions periodically and make adjustments to these assumptions and the
recorded liabilities as necessary.

Two of the most critical assumptions are the expected long-term rate of
return on plan assets and the assumed discount rate. We evaluate our assumptions
regarding the estimated long-term rate of return on plan assets based on
historical experience and future expectations on investment returns, which are
calculated by our third party investment advisor utilizing the asset allocation
classes held by the plan's portfolios. We utilize the Moody's Aa long-term
corporate bond yield as a basis for determining the discount rate for a majority
of our plans. Changes in these and other assumptions used in the actuarial
computations could impact our projected benefit obligations, pension
liabilities, pension expense and other comprehensive income. We base our
determination of pension expense on a market-related valuation of assets that
reduces year-to-year volatility. This market-related valuation recognizes
investment gains or losses over a five-year period from the year in which they
occur. Investment gains or losses for this purpose are the difference between
the expected return calculated using the market-related value of assets and the
actual return based on the market-related value of assets.

Contingent liabilities-We establish reserves for estimated loss
contingencies when we believe a loss is probable and the amount of the loss can
be reasonably estimated. Revisions to contingent liabilities are reflected in
income in the period in which different facts or information become known or
circumstances change that affect our previous assumptions with respect to the
likelihood or amount of loss. Reserves for contingent liabilities are based upon
our assumptions and estimates regarding the probable outcome of the matter.
Should the outcome differ from our assumptions and estimates, revisions to the
estimated reserves for contingent liabilities would be required.

HISTORICAL 2002 COMPARED TO 2001

Although our 2002 results of operations include a full year of operations
from the assets acquired in the R&B Falcon merger compared to 11 months in 2001,
our revenues and operating and maintenance expense decreased in 2002 by $146.2
million and $109.1 million, respectively. These decreases were mainly
attributable to a decline in overall market conditions and resulted from a
general uncertainty over world economic and political events. While our overall
average fleet dayrate increased from $66,000 in 2001 to $77,600 in 2002, the
resulting increase in revenues was more than offset by a substantial decrease in
utilization, which was 73% in 2001 compared to 61% in 2002. Our 2002 financial
results included the recognition of a number of non-cash charges pertaining
substantially to goodwill impairment. Following is a detailed analysis of our
International and U.S. Floater Contract Drilling Services segment and Gulf of
Mexico Shallow and Inland Water segment operating results, as well as an
analysis of income and expense categories that we have not allocated to our two
segments.

-23-

International and U.S. Floater Contract Drilling Services Segment

YEARS ENDED
DECEMBER 31,
---------------------
2002 2001 CHANGE % CHANGE
---------- --------- ---------- ---------
(IN MILLIONS, EXCEPT DAY AMOUNTS AND % CHANGE)

Operating days (a) . . . . . . . . . . . . . . . . . . . . . . . . 25,938 27,060 (1,122) (4.1)%
Utilization (a) (b). . . . . . . . . . . . . . . . . . . . . . . . 78% 81% N/A (3.7)%
Average dayrate (a) (c). . . . . . . . . . . . . . . . . . . . . . $ 94,500 $ 83,700 $ 10,800 12.9%

Operating revenues . . . . . . . . . . . . . . . . . . . . . . . . $ 2,486.1 $2,385.2 $ 100.9 4.2%
Operating and maintenance. . . . . . . . . . . . . . . . . . . . . 1,291.3 1,326.7 (35.4) (2.7)%
Depreciation . . . . . . . . . . . . . . . . . . . . . . . . . . . 408.4 373.5 34.9 9.3%
Goodwill amortization. . . . . . . . . . . . . . . . . . . . . . . - 114.2 (114.2) N/M
Impairment loss on long-lived assets . . . . . . . . . . . . . . . 2,528.1 39.4 2,488.7 N/M
Gain from sale of assets, net. . . . . . . . . . . . . . . . . . . (2.7) (50.7) 48.0 94.7%
---------- --------- ---------- ---------
Operating income (loss) before general and administrative expense. $(1,739.0) $ 582.1 $(2,321.1) (398.7)%
========== ========= ========== =========

_________________
"N/A" means not applicable
"N/M" means not meaningful

(a) Applicable to core assets only defined as high specification drillships and semisubmersibles (floaters),
other floaters, jackup rigs, drilling barges and tenders.
(b) Utilization is the total actual number of revenue earning days as a percentage of total calendar
days.
(c) Average dayrate is defined as revenue earned per revenue earning day.

The increase in this segment's operating revenues resulted from a $97.6
million increase from core assets acquired in the R&B Falcon merger representing
a full year of revenues in 2002 compared to 11 months of operations in 2001, a
$122.6 million increase from four newbuild drilling units placed into service
during 2001 and a $36.4 million increase from three rigs transferred into this
segment from the Gulf of Mexico Shallow and Inland Water segment late in 2001
and mid-2002. In addition, operating revenues relating to historical Transocean
core assets totaled $1.5 billion for 2002, representing a $32.9 million, or two
percent, increase over 2001. Average dayrates for these historical Transocean
core assets increased from $87,500 for 2001 to $92,900 for 2002 and utilization
of these core assets decreased from 84 percent for 2001 to 81 percent for 2002.
These increases were partially offset by a $33.5 million decrease related to the
Deepwater Frontier following the expiration of our lease with a related party
late in 2001, a $32.5 million decrease from four leased rigs returned to their
owners, a $23.9 million decrease related to two rigs removed from our active
fleet and marketed for sale and a $20.4 million decrease related to rigs sold
during 2001 and 2002. Revenues from non-core assets decreased $36.4 million for
2002 compared to 2001. The decrease in revenues from these non-core assets
resulted from the sale of RBF FPSO L.P., which owned the Seillean ($29.5
million), and a decrease in average dayrates and utilization of the remaining
non-core assets from $88,900 and 61 percent, respectively, for 2001 to $82,000
and 57 percent, respectively, for 2002. A decrease of $38.2 million resulting
from the winding up of our turnkey drilling business early in 2001 and loss of
hire proceeds of $10.7 million in 2001 for the Jack Bates was partially offset
by a settlement of a contract dispute in 2002.

A large portion of our operating and maintenance expense consists of
employee-related costs and is fixed or only semi-variable. Accordingly,
operating and maintenance expense does not vary in direct proportion to activity
or dayrates.

The decrease in this segment's operating and maintenance expense resulted
from a decrease of $40.5 million related to the Deepwater Frontier following the
expiration of our lease with a related party late in 2001, a $22.7 million
decrease related to four leased rigs returned to their owners, a $13.6 million
decrease related to two rigs removed from our active fleet and marketed for
sale, a $9.8 million decrease related to rigs sold during 2001 and 2002, a
decrease of $5.1 million related to legal disputes and a $10.1 million decrease
primarily related to a reduction in rig utilization, which resulted in certain
rigs becoming idle with a reduced crew complement. Operating and maintenance
expense also decreased $5.5 million during 2002 for two newbuilds placed into
service during 2001. The decrease resulted from additional startup costs
incurred during 2001 with no comparable costs in 2002. In addition, operating
and maintenance expense in this segment decreased $39.9 million as a result of
the winding up of our turnkey drilling business in 2001. These decreases were
partially offset by an increase of $35.7 million in operating and maintenance
expenses from core assets acquired in the

-24-

R&B Falcon merger for the full year ended 2002 compared to 11 months of activity
in 2001, an increase of $21.6 million resulting from the activation of two
newbuild drilling units during 2001 and an increase of $22.6 million resulting
from three jackup rigs transferred into this segment from the Gulf of Mexico
Shallow and Inland Water segment in late 2001 and mid-2002. In addition,
accelerated amortization of deferred gain on the Pride North Atlantic's
(formerly, the Drill Star) during 2001 produced incremental gains for 2001 of
$36.6 million with no equivalent expense reduction during 2002.

The increase in this segment's depreciation expense resulted primarily from
four newbuild drilling units placed into service during 2001 ($17.5 million),
the transfer of three jackup rigs into this segment from the Gulf of Mexico
Shallow and Inland Water segment ($13.3 million) and a full year of depreciation
in 2002 on rigs acquired in the R&B Falcon merger compared to 11 months in 2001
($18.8 million). These increases were partially offset by lower depreciation
expense following the suspension of depreciation on certain rigs transferred to
assets held for sale ($4.6 million), the sale of various rigs classified as
assets held and used during 2001 ($11.4 million) and an asset classified as held
for sale in 2002 that was subsequently transferred to the Gulf of Mexico Shallow
and Inland Water segment ($0.7 million).

The absence of goodwill amortization in 2002 resulted from our adoption of
SFAS 142, Goodwill and Other Intangible Assets, as of January 1, 2002. Goodwill
is no longer amortized but is reviewed for impairment at least annually as more
fully described in Note 2 to our consolidated financial statements.

The increase in impairment loss in this segment resulted primarily from our
annual impairment test of goodwill conducted as of October 1, 2002 ($2,494.1
million). In addition, we recorded non-cash impairment charges in this segment
of $34.0 million in 2002, representing a decrease of $5.4 million over 2001,
primarily related to assets reclassified from held for sale to our active fleet
($28.5 million) because they no longer met the held for sale criteria under SFAS
144. See Note 7 to our consolidated financial statements.

During 2002, this segment recognized net pre-tax gains of $5.5 million
related to the sale of the Transocean 96, Transocean 97, a mobile offshore
production unit, the partial settlement of an insurance claim and the sale of
other assets. These net gains were partially offset by net pre-tax losses of
$2.8 million from the sale of the RBF 209 and an office building. During 2001,
this segment recognized net pre-tax gains of $26.3 million related to the sale
of RBF FPSO L.P., which owned the Seillean, $18.5 million related to the
accelerated amortization of the deferred gain on the sale of the Sedco Explorer,
$3.7 million related to the sale of two Nigerian-based land rigs and $2.2
million from the sale of other assets.

Gulf of Mexico Shallow and Inland Water Segment

YEARS ENDED
DECEMBER 31,
------------------
2002 2001 CHANGE % CHANGE
-------- -------- -------- ----------

(IN MILLIONS, EXCEPT DAY AMOUNTS AND % CHANGE)
Operating days (a) . . . . . . . . . . . . . . . . . . . . . . . . 7,710 13,100 5,390 (41.1)%
Utilization (a) (b). . . . . . . . . . . . . . . . . . . . . . . . 34% 60% N/A (43.3)%
Average dayrate (a) (c). . . . . . . . . . . . . . . . . . . . . . $20,800 $29,500 $(8,700) (29.5)%

Operating revenues . . . . . . . . . . . . . . . . . . . . . . . . $ 187.8 $ 434.9 $(247.1) (56.8)%
Operating and maintenance. . . . . . . . . . . . . . . . . . . . . 202.9 276.6 (73.7) (26.6)%
Depreciation . . . . . . . . . . . . . . . . . . . . . . . . . . . 91.9 96.6 (4.7) (4.9)%
Goodwill amortization. . . . . . . . . . . . . . . . . . . . . . . - 40.7 (40.7) N/M
Impairment loss on long-lived assets . . . . . . . . . . . . . . . 399.3 1.0 398.3 N/M
Gain from sale of assets, net. . . . . . . . . . . . . . . . . . . (1.0) (5.8) 4.8 82.8%
-------- -------- -------- ----------
Operating income (loss) before general and administrative expense. $(505.3) $ 25.8 $(531.1) (2,058.5)%
======== ======== ======== ==========

_________________
"N/A" means not applicable
"N/M" means not meaningful

(a) Applicable to core assets only defined as jackup rigs, drilling barges and submersible drilling
rigs.
(b) Utilization is the total actual number of revenue earning days as a percentage of total calendar
days.
(c) Average dayrate is defined as revenue earned per revenue earning day.

-25-

Although this segment's operating revenues represent a full year of
operations in 2002 compared to 11 months of operations in 2001, revenues
decreased mainly due to the further weakening of the Gulf of Mexico shallow and
inland water market segment, a decline that began in mid-2001. In addition, the
transfer of three jackup rigs from this segment into the International and U.S.
Floater Contract Drilling Services segment resulted in a $23.7 million decrease.
Excluding the three jackup rigs transferred into the International and U.S.
Floater Contract Drilling Services segment, average dayrates and utilization for
core assets in this segment decreased from $28,800 and 60 percent, respectively,
for 2001 to $20,900 and 34 percent, respectively, for 2002. Revenues from
non-core assets in this segment decreased $28.0 million and related primarily to
Venezuela ($27.9 million) where average dayrates and utilization decreased from
$19,500 and 77 percent, respectively, for 2001 to $18,300 and 26 percent,
respectively, for 2002.

Although this segment's operating and maintenance expense represents a full
year of operations in 2002 compared to 11 months of operations in 2001,
operating and maintenance expense in this segment decreased primarily from the
further weakening of the Gulf of Mexico Shallow and Inland Water market segment,
which resulted in additional idle rigs during 2002. The additional idle rigs
resulted in a $39.5 million decrease in personnel related expenses related to
reduced employee count, a $15.3 million reduction of repair and maintenance
costs, a $4.7 million decrease in leased rigs and other equipment rental expense
and a $6.1 million decrease in insurance expense due in part to the additional
idle rigs and related reduction in employee headcount. In addition, three
jackup rigs were transferred out of this segment into the International and U.S.
Floater Contract Drilling Services segment in late 2001 and mid-2002 and
resulted in a decrease of $15.4 million in operating and maintenance expense.
These decreases were partially offset by an increase in expenses of $4.4 million
resulting from severance-related costs and other restructuring charges related
to our decision to close an administrative office and warehouse in Louisiana and
relocate most of the operations and administrative functions previously
conducted at that location, as well as compensation-related expenses resulting
from executive management changes in the third quarter of 2002.

The decrease in this segment's depreciation expense resulted primarily from
the transfer of three jackup rigs out of this segment into the International and
U.S. Floater Contract Drilling Services segment ($12.2 million) and suspension
of depreciation on rigs sold, scrapped or classified as held for sale during
2002 ($2.6 million). These decreases were partially offset by increased expense
due to a full year of depreciation in 2002 on rigs acquired in the R&B Falcon
merger compared to 11 months in 2001 ($9.0 million).

The increase in impairment loss in this segment resulted primarily from our
annual impairment test of goodwill conducted as of October 1, 2002 ($381.9
million). In addition, we recorded non-cash impairment charges in this segment
of $17.4 million in 2002, representing an increase of $16.4 million over 2001,
primarily related to assets reclassified from held for sale to our active fleet
because they no longer met the held for sale criteria under SFAS 144. See Note
7 to our consolidated financial statements.

During 2002, this segment recognized net pre-tax gains of $2.4 million on
the sale of a land rig and other assets partially offset by net pre-tax losses
of $1.4 million related to the sale of two mobile offshore production units and
a land rig. During 2001, this segment recognized net pre-tax gains of $2.1
million related to the disposal of an inland drilling barge and $3.7 million
related to the sale of other assets.

-26-

Total Company Results of Operations

YEARS ENDED
DECEMBER 31,
------------------
2002 2001 CHANGE % CHANGE
--------- ------- --------- ---------

(IN MILLIONS, EXCEPT % CHANGE)
General and Administrative Expense . . . . . . . . . . $ 65.6 $ 57.9 $ 7.7 13.3%
Other (Income) Expense, net
Equity in earnings of joint ventures . . . . . . . . (7.8) (16.5) 8.7 52.7%
Interest income. . . . . . . . . . . . . . . . . . . (25.6) (18.7) (6.9) (36.9)%
Interest expense, net of amounts capitalized . . . . 212.0 223.9 (11.9) (5.3)%
Other, net . . . . . . . . . . . . . . . . . . . . . 0.3 0.8 (0.5) (62.5)%
Income Tax Expense (Benefit) . . . . . . . . . . . . . (123.0) 85.7 (208.7) N/M
Loss on Extraordinary Items, net of tax - 19.3 (19.3) N/M
Cumulative Effect of a Change in Accounting Principle. 1,363.7 - 1,363.7 N/M

_________________________
"N/M" means not meaningful

The increase in general and administrative expense was primarily
attributable to $3.9 million of costs related to the exchange of our notes for
TODCO's notes in March 2002 (see "Liquidity and Capital ResourcesSources of
Liquidity"). The results from 2001 included a $1.3 million reduction in expense
related to the favorable settlement of an unemployment tax assessment with no
corresponding reduction in 2002. In addition, expense increased due to the R&B
Falcon merger and reflected additional costs to manage a larger, more complex
organization for a full year in 2002 compared to 11 months in 2001.

The decrease in equity in earnings of joint ventures was primarily related
to our 25 percent share of losses from Delta Towing Holdings, L.L.C. ($4.1
million) and to the reduced earnings attributable to our 60 percent share of the
earnings of Deepwater Drilling II L.L.C. ("DDII LLC"), which owns the Deepwater
Frontier ($4.5 million), and our 50 percent share of Deepwater Drilling L.L.C.
("DD LLC"), which owns the Deepwater Pathfinder ($1.6 million). Both the
Deepwater Frontier and the Deepwater Pathfinder experienced increased downtime
and decreased utilization during 2002. These decreases were partially offset by
losses recorded in February 2001 on the sale of the Drill Star and Sedco
Explorer by a joint venture in which we own a 25 percent interest ($2.6
million). The increase in interest income was primarily due to interest earned
on higher average cash balances for 2002 compared to 2001. The decrease in
interest expense was attributable to reductions in interest expense of $33.2
million associated with debt that was refinanced, repaid or retired during and
subsequent to 2001 and a decrease in the London Interbank Offered Rate ("LIBOR")
of approximately 226 basis points that resulted in a $9.0 million reduction on
floating rate bank debt. Additionally, our fixed to floating interest rate swaps
resulted in reduced interest expense of $39.6 million. Offsetting these
decreases were $26.4 million of additional interest expense on debt issued
during the second quarter of 2001, $8.6 million of interest expense on debt
acquired in the R&B Falcon merger, which represents additional interest for the
full year 2002 compared to 11 months in 2001, and the absence of capitalized
interest in 2002 due to the completion of our newbuild projects in 2001 compared
to $34.9 million of capitalized interest in 2001. The increase in other, net was
due primarily to a loss on sale of securities during 2001 with no comparable
activity in 2002.

We operate internationally and provide for income taxes based on the tax
laws and rates in the countries in which we operate and earn income. There is no
expected relationship between the provision for income taxes and income before
income taxes as more fully described in Note 15 to our consolidated financial
statements. The year ended December 31, 2002 included a non-U.S. tax benefit of
$175.7 million attributable to the restructuring of certain non-U.S. operations.

During 2001, we recognized a $19.3 million extraordinary loss, net of tax,
related to the early retirement of certain debt as more fully described in Note
8 to our consolidated financial statements.

During 2002, we recognized a $1,363.7 million goodwill impairment charge as
a cumulative effect of a change in accounting principle in our Gulf of Mexico
Shallow and Inland Water segment related to the implementation of SFAS 142 as
more fully described in Note 2 to our consolidated financial statements.

-27-

HISTORICAL 2001 COMPARED TO 2000

Our 2001 results of operations include 11 months of operations from the
assets acquired in the R&B Falcon merger, which was completed January 21, 2001.
The addition of these assets is reflected in the $1.6 billion and $790.7 million
increase in our revenues and operating and maintenance expense, respectively, in
2001 compared to 2000. Although our revenues increased during 2001, our overall
average fleet dayrate and utilization decreased from $70,400 and 74%,
respectively, in 2000 to $66,000 and 73%, respectively, in 2001. Following is a
detailed analysis of our International and U.S. Floater Contract Drilling
Services segment and Gulf of Mexico Shallow and Inland Water segment operating
results, as well as an analysis of income and expense categories that we have
not allocated to our two segments.

International and U.S. Floater Contract Drilling Services Segment

YEARS ENDED
DECEMBER 31,
--------------------
2001 2000 CHANGE % CHANGE
--------- --------- --------- ---------
(IN MILLIONS, EXCEPT DAY AMOUNTS AND % CHANGE)

Operating days (a) . . . . . . . . . . . . . . . . . . . . . . . . 27,060 16,454 10,606 64.5%
Utilization (a) (b). . . . . . . . . . . . . . . . . . . . . . . . 81% 74% N/A 9.5%
Average dayrate (a) (c). . . . . . . . . . . . . . . . . . . . . . $ 83,700 $ 70,400 $ 13,300 18.9%

Operating revenues . . . . . . . . . . . . . . . . . . . . . . . . $2,385.2 $1,229.5 $1,155.7 94.0%
Operating and maintenance. . . . . . . . . . . . . . . . . . . . . 1,326.7 812.6 514.1 63.3%
Depreciation . . . . . . . . . . . . . . . . . . . . . . . . . . . 373.5 232.8 140.7 60.4%
Goodwill amortization. . . . . . . . . . . . . . . . . . . . . . . 114.2 26.7 87.5 327.7%
Impairment loss on long-lived assets . . . . . . . . . . . . . . . 39.4 - 39.4 N/M
Gain from sale of assets, net. . . . . . . . . . . . . . . . . . . (50.7) (17.8) (32.9) (184.8)%
--------- --------- --------- ---------
Operating income (loss) before general and administrative
expense. . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 582.1 $ 175.2 $ 406.9 232.2%
========= ========= ========= =========

_________________________
"N/A" means not applicable
"N/M" means not meaningful

(a) Applicable to core assets only, defined as high specification drillships and semisubmersibles
(floaters), other floaters, jackup rigs, drilling barges and tenders.
(b) Utilization is the total actual number of revenue earning days as a percentage of total calendar
days.
(c) Average dayrate is defined as revenue earned per revenue earning day.

The increase in this segment's operating revenues reflected the inclusion
of operating revenues from core assets acquired in the R&B Falcon merger of
$806.7 million, revenues of $210.7 million from five newbuild drilling units
placed into service during and subsequent to 2000, recognition of $10.7 million
related to a recovery from a loss-of-hire claim for an incident that occurred in
November 2000 and an increase in activity reflected in higher utilization and
average dayrates. Operating revenues relating to historical Transocean core
assets totaled $1,359.7 million for 2001, representing a $213.9 million, or 19
percent, increase over the comparable 2000 period. Average dayrates and
utilization for these core assets increased from $68,300 and 66 percent,
respectively, for 2000 to $75,600 and 79 percent, respectively, for 2001. These
increases were partially offset by decreases in comparable revenues attributed
to less activity for non-core assets and lower revenue earned from managed rigs
no longer operated in 2001. Revenues for 2000 included a cash settlement of
$25.1 million relating to an agreement with a unit of BP to cancel the remaining
14 months of firm contract time on the semisubmersible Transocean Amirante.

The increase in 2001 in this segment's operating and maintenance expense
was primarily attributable to assets acquired in the R&B Falcon merger ($369.8
million), the activation of five newbuild drilling units during and subsequent
to 2000 ($77.7 million) and one newbuild drilling unit that was placed into
service during September 2000 ($15.9 million), offset by $36.6 million related
to accelerated amortization of the deferred gain on the Pride North Atlantic
(formerly the Drill Star) during 2001. See Note 6 to our consolidated financial
statements. A large portion of our operating and maintenance expense consists of
employee-related costs and is fixed or only semi-variable. Accordingly,
operating and maintenance expense does not vary in direct proportion to activity
or dayrates.

-28-

This segment's depreciation expense increased primarily due to depreciation
expense for the rigs acquired in the R&B Falcon merger ($129.4 million) and
depreciation expense in 2001 for six newbuild drilling units placed into service
during and subsequent to 2000 ($35.4 million). This increase was partially
offset by a reduction of approximately $23 million for 2001 as a result of
conforming our policies for estimated rig lives in conjunction with the R&B
Falcon merger.

The increase in this segment's goodwill amortization expense resulted from
the R&B Falcon merger.

During the fourth quarter of 2001, we recorded non-cash impairment charges
in this segment of $39.4 million related to certain assets held for sale and
certain non-core assets held and used. The impairments resulted from
deterioration in current market conditions with the fair value of these assets
determined based on projected cash flows, industry knowledge and third-party
appraisals.

During 2001, we recognized a pre-tax gain of $26.3 million related to the
sale of RBF FPSO L.P., which owned the Seillean, and $18.5 million related to
accelerated amortization of the deferred gain on the sale of the Sedco Explorer.
In addition, we recognized a pre-tax gain of $5.9 million during the year ended
December 31, 2001 related to sales of certain non-strategic assets acquired in
the R&B Falcon merger and certain other assets held for sale. During the year
ended December 31, 2000, we recognized a pre-tax gain of $12.9 million on the
sale of three drilling units, the semisubmersible Transocean Discoverer, the
multi-purpose service vessel Mr. John and the tender Searex V.

Gulf of Mexico Shallow and Inland Water Segment

YEARS ENDED
DECEMBER 31,
---------------
2001 2000 CHANGE % CHANGE
-------- ----- -------- --------
(IN MILLIONS, EXCEPT DAY AMOUNTS
AND % CHANGE)

Operating days (a) . . . . . . . . . . . . . . . . . . . . . . . . 13,100 - 13,100 N/M
Utilization (a) (b). . . . . . . . . . . . . . . . . . . . . . . . 60% - N/A N/M
Average dayrate (a) (c). . . . . . . . . . . . . . . . . . . . . . $29,500 $ - $29,500 N/M

Operating revenues . . . . . . . . . . . . . . . . . . . . . . . . $ 434.9 $ - $ 434.9 N/M
Operating and maintenance. . . . . . . . . . . . . . . . . . . . . 276.6 - (276.6) N/M
Depreciation . . . . . . . . . . . . . . . . . . . . . . . . . . . 96.6 - (96.6) N/M
Goodwill amortization. . . . . . . . . . . . . . . . . . . . . . . 40.7 - (40.7) N/M
Impairment loss on long-lived assets . . . . . . . . . . . . . . . 1.0 - (1.0) N/M
Gain from sale of assets, net. . . . . . . . . . . . . . . . . . . (5.8) - 5.8 N/M
-------- ----- -------- --------
Operating income (loss) before general and administrative expense. $ 25.8 $ - $ 25.8 N/M
======== ===== ======== ========

_________________________
"N/A" means not applicable
"N/M" means not meaningful

(a) Applicable to core assets only, defined as jackup rigs, drilling barges and submersible
drilling rigs.
(b) Utilization is the total actual number of revenue earning days as a percentage of total
calendar days.
(c) Average dayrate is defined as revenue earned per revenue earning day.

This segment's operating results were attributable to operations acquired
in the R&B Falcon merger. Prior to January 31, 2001, we operated in one segment,
the International and U.S. Floater Contract Drilling Services segment.

During 2001, we recorded a non-cash impairment charge in this segment of
$1.0 million related to an asset held and used. The impairment resulted from
deterioration in current market conditions with the fair value of this asset
determined based on projected cash flows, industry knowledge and third-party
appraisals.

During 2001, we recognized a net pre-tax gain of $5.8 million related to
sales of certain other assets acquired in the R&B Falcon merger and
certain other assets held for sale.

-29-

Total Company Results of Operations

YEARS ENDED
DECEMBER 31,
----------------
2001 2000 CHANGE % CHANGE
------- ------ -------- --------

(IN MILLIONS, EXCEPT % CHANGE)
General and Administrative Expense. . . . . . . $ 57.9 $42.1 $ 15.8 37.5%
Other (Income) Expense, net
Equity in earnings of joint ventures. . . . . (16.5) (9.4) (7.1) (75.5)%
Interest income . . . . . . . . . . . . . . . (18.7) (6.2) (12.5) (201.6)%
Interest expense, net of amounts capitalized. 223.9 3.0 220.9 N/M
Other, net. . . . . . . . . . . . . . . . . . 0.8 1.3 (0.5) (38.5)%
Income Tax Expense. . . . . . . . . . . . . . . 85.7 36.7 49.0 133.5%
(Gain) Loss on Extraordinary Items, net of tax. 19.3 (1.4) 20.7 N/M

_________________________
"N/M" means not meaningful

The increase in general and administrative expense reflects the costs to
manage a larger and more complex organization as a result of the R&B Falcon
merger.

The increase in equity in earnings of joint ventures was due primarily to
equity in earnings of joint ventures acquired in the R&B Falcon merger. The
increase in interest income was primarily due to interest earned on secured
contingent notes from a related party acquired as part of the R&B Falcon merger
(see "-Related Party Transactions") and higher average cash balances for 2001
compared to 2000. The increase in interest expense during 2001 was due to higher
debt levels arising from the additional debt assumed in the R&B Falcon merger
and additional borrowings to complete newbuild construction projects. Total
interest capitalized relating to construction projects was $34.9 million for
2001 compared to $86.6 million for 2000, a decrease of $51.7 million, or 60
percent, resulting from the completion of six newbuild drilling units during and
subsequent to 2000.

During 2001, we recognized a $19.3 million extraordinary loss, net of tax,
related to the early retirement of certain debt as more fully described in Note
8 to our consolidated financial statements. During 2000, we recognized a $1.4
million extraordinary gain, net of tax, related to the early retirement of
certain debt.

FINANCIAL CONDITION

DECEMBER 31, 2002 COMPARED TO DECEMBER 31, 2001

DECEMBER 31,
--------------------
2002 2001 CHANGE % CHANGE
--------- --------- ---------- ---------
(IN MILLIONS, EXCEPT % CHANGE)

TOTAL ASSETS
International and U.S. Floater Contract Drilling Services. $11,804.1 $14,247.3 $(2,443.2) (17.1)%
Gulf of Mexico Shallow and Inland Water. . . . . . . . . . 861.0 2,800.5 (1,939.5) (69.3)%
--------- --------- ---------- ---------
$12,665.1 $17,047.8 $(4,382.7) (25.7)%
========= ========= ========== =========

The decrease in the International and U.S. Floater Contract Drilling
Services segment was primarily due to the impairment of goodwill of $2.5 billion
resulting from our annual impairment test of goodwill in accordance with SFAS
142, which was performed as of October 1. The decrease in the Gulf of Mexico
Shallow and Inland Water segment of $1.9 billion was primarily due to the
impairment of goodwill of $1.4 billion, which resulted from our initial test of
goodwill impairment upon adoption of SFAS 142, and $0.4 billion from our annual
impairment test of goodwill performed as of October 1.

-30-

RESTRUCTURING CHARGES

In September 2002, we committed to a restructuring plan to eliminate our
engineering department located in Montrouge, France. We established a liability
of $2.8 million for the estimated severance-related costs associated with the
involuntary termination of 15 employees pursuant to this plan. The charge was
reported as operating and maintenance expense in the International and U.S.
Floater Contract Drilling Services segment in our consolidated statements of
operations. As of December 31, 2002, $1.7 million had been paid to employees
whose positions were eliminated as a result of this plan. We anticipate that
substantially all amounts will be paid by the end of the first quarter of 2003.

In September 2002, we committed to a restructuring plan for a staff
reduction in Norway as a result of a decline in activity in that region. We
established a liability of $1.2 million for the estimated severance-related
costs associated with the involuntary termination of eight employees pursuant to
this plan. The charge was reported as operating and maintenance expense in the
International and U.S. Floater Contract Drilling Services segment in our
consolidated statements of operations. As of December 31, 2002, $0.1 million had
been paid to employees whose positions are being eliminated as a result of this
plan. We anticipate that substantially all amounts will be paid by the end of
the first quarter of 2004.

In September 2002, we committed to a restructuring plan to consolidate
certain functions and offices utilized in our Gulf of Mexico Shallow and Inland
Water segment. The plan resulted in the closure of an administrative office and
warehouse in Louisiana and relocation of most of the operations and
administrative functions previously conducted at that location. We established a
liability of $1.2 million for the estimated severance-related costs associated
with the involuntary termination of 57 employees pursuant to this plan. The
charge was reported as operating and maintenance expense in our consolidated
statements of operations. As of December 31, 2002, no amounts had been paid to
employees whose employment is being terminated as a result of this plan. We
anticipate that substantially all amounts will be paid by the end of the first
quarter of 2003.

In conjunction with the R&B Falcon merger, we established a liability of
$16.5 million for the estimated severance-related costs associated with the
involuntary termination of 569 R&B Falcon employees pursuant to management's
plan to consolidate operations and administrative functions post-merger.
Included in the 569 planned involuntary terminations were 387 employees engaged
in our land and barge drilling business in Venezuela. We suspended active
marketing efforts to divest this business and, as a result, the estimated
liability was reduced by $4.3 million in the third quarter of 2001 with an
offset to goodwill. As of December 31, 2002, all required severance-related
costs have been paid to 182 employees whose positions were eliminated as a
result of this plan.

2001 PRO FORMA OPERATING RESULTS

Our unaudited pro forma consolidated results for the year ended December
31, 2001, giving effect to the R&B Falcon merger, reflected net income of $260.2
million or $0.80 per diluted share on pro forma operating revenues of $2,946.0
million. The pro forma operating results assume the merger was completed as of
January 1, 2001 (see Note 4 to our consolidated financial statements). These
pro forma results do not reflect the effects of reduced depreciation expense
related to conforming the estimated lives of our drilling rigs. The pro forma
financial data should not be relied on as an indication of operating results
that we would have achieved had the merger taken place earlier or of the future
results that we may achieve.

DEFINED BENEFIT PENSION PLANS

We maintain a qualified defined benefit pension plan (the "Retirement
Plan") covering substantially all U.S. employees except for TODCO employees,
and an unfunded plan (the "Supplemental Benefit Plan") to provide certain
eligible employees with benefits in excess of those allowed under the Retirement
Plan. In conjunction with the R&B Falcon merger, we acquired three defined
benefit pension plans that were frozen prior to the merger for which benefits no
longer accrue (the "Frozen Plans"), but the pension obligations have not been
fully paid out. We refer to the Retirement Plan, the Supplemental Benefit Plan
and the Frozen Plans collectively as the U.S. Plans.

In addition, the Company provides several defined benefit plans, primarily
group pension schemes with life insurance companies covering our Norway
operations (the "Norway Plans"). Certain of the Norway plans are funded in part
by employee contributions. Our contributions to the Norway Plans are determined
primarily by the respective life insurance companies based on the terms of the
plan. For the insurance-based plans, annual premium payments are considered to
represent a reasonable approximation of the service costs of benefits earned
during the period. We also have an unfunded defined benefit plan (the "Nigeria
Plan") that provides retirement and severance benefits for certain of our
Nigerian employees. The defined benefit pension benefits we provide (the
"Transocean Plans") are comprised of the U.S.

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Plans, the Norway Plans and the Nigeria Plan. The following information
regarding the Transocean Plans was obtained from the information used to prepare
Note 18 to our consolidated financial statements.

SUPPLEMENTAL SUBTOTAL- TOTAL
RETIREMENT RETIREMENT FROZEN U.S. NORWAY NIGERIA TRANSOCEAN
PLAN PLAN PLANS PLANS PLANS PLAN PLANS
------------ -------------- -------- ----------- -------- --------- ------------
(in millions)

PROJECTED BENEFIT OBLIGATION
At December 31, 2002 $ 131.2 $ 7.6 $ 95.8 $ 234.6 $ 50.4 $ 10.6 $ 295.6
At December 31, 2001 97.4 7.6 90.4 195.4 38.2 9.1 242.7

FAIR VALUE OF PLAN ASSETS
At December 31, 2002 $ 80.9 $ - $ 79.6 $ 160.5 $ 28.0 $ - $ 188.5
At December 31, 2001 91.6 - 93.2 184.8 25.6 - 210.4

FUNDED STATUS
At December 31, 2002 $ (50.3) $ (7.6) $ (16.2) $ (74.1) $(22.4) $(10.6) $ (107.1)
At December 31, 2001 (5.8) (7.6) 2.8 (10.6) (12.6) (9.1) (32.3)

NET PERIODIC BENEFIT COST (INCOME)
Year Ending December 31, 2002 $ 11.6 $ 2.6 $ (3.7) $ 10.5 $ 3.4 $ 3.2 $ 17.1 (b)
Year Ending December 31, 2001 5.7 1.5 (3.3) (a) 3.9 2.8 3.1 9.8 (b)

CHANGE IN ACCUMULATED OTHER COMPREHENSIVE INCOME
Year Ending December 31, 2002 $ 8.2 $ - $ 37.5 $ 45.7 $ - $ - $ 45.7
Year Ending December 31, 2001 - - - - - - -

EMPLOYER CONTRIBUTIONS
Year Ending December 31, 2002 $ - $ 2.4 $ 0.3 $ 2.7 $ 3.0 $ 0.9 $ 6.6
Year Ending December 31, 2002 - - 0.4 (a) 0.4 4.2 0.2 4.8

WEIGHTED-AVERAGE ASSUMPTIONS DISCOUNT RATE
At December 31, 2002 6.50% 6.50% 6.50% 6.00% 20.00% 6.90% (c)
At December 31, 2001 7.00% 7.00% 7.00% 6.00% 20.00% 7.45% (c)

EXPECTED RETURN ON PLAN ASSETS
At December 31, 2002 9.00% - 9.00% 7.00% - 8.73% (d)
At December 31, 2001 9.00% - 10.00% 7.00% - 9.24% (d)

RATE OF COMPENSATION INCREASE
At December 31, 2002 5.50% 5.50% - 3.50% 15.00% 5.53% (c)
At December 31, 2001 5.50% 5.50% - 3.50% 15.00% 5.71% (c)

(a) Represents 11 months of activity in 2001 subsequent to the R&B Falcon merger.
(b) Pension costs were reduced by expected returns on plan assets of $20.7 million and
$7.5 million for the years ended December 31, 2002 and 2001, respectively.
(c) Weighted-average based on relative average projected benefit obligation for the year.
(d) Weighted-average based on relative average fair value of plan assets for the year.

For the U.S. Plans, our funding policy is to review amounts annually and
contribute an amount at least equal to the minimum contribution required under
the Employee Retirement Income Security Act of 1974 (ERISA). Employer
contributions to the funded U.S. Plans are based on actuarial computations that
establish the minimum contribution required under ERISA and the maximum
deductible contribution for income tax purposes. No contributions were made to
the funded U.S. Plans during 2002 or 2001. Contributions to the Supplemental
Retirement Plan in 2002 and the Frozen Plans in 2002 and 2001 were to fund
benefit payments from our unfunded U.S. Plans.

Plan assets of the funded U.S. Plans have been adversely impacted by
declines in equity market values. During 2002, the market value of the
investments in the Transocean Plans declined by $21.9 million or 10.4 percent.
The decline is due to benefit plan payments in excess of employee and employer
contributions and $14.4 million of net investment losses, primarily in the U.S.
Plans, resulting from the poor performance of the equity markets in 2002. We
expect to begin

-32-

making annual contributions to the Retirement Plan in 2003 and that the 2003
contribution will be approximately $11 million. We believe the required
contributions can be funded from cash flow from operations. We have generated
unrecognized net actuarial losses due to the effect of the unfavorable
performance of the equity markets on the plan assets of the U.S. Plans. As of
December 31, 2002 we had cumulative losses of approximately $39.6 million that
remain to be recognized in the calculation of the market-related value of
assets. These unrecognized net actuarial losses may result in increases in our
future pension expense depending on several factors, including whether such
losses at each measurement date exceed certain amounts in accordance with SFAS
No. 87, Employers' Accounting for Pensions.

We account for the Transocean Plans in accordance with SFAS 87. This
statement requires us to calculate our pension expense and liabilities using
assumptions based on a market-related valuation of assets, which reduces
year-to-year volatility using actuarial assumptions. Changes in these
assumptions can result in different expense and liability amounts, and future
actual experience can differ from these assumptions. In accordance with SFAS No.
87, changes in pension obligations and assets may not be immediately recognized
as pension costs in the statement of operations, but generally are recognized in
future years over the remaining average service period of plan participants. As
such, significant portions of pension costs recorded in any period may not
reflect the actual level of benefit payments provided to plan participants.

Two of the most critical assumptions used in calculating our pension
expense and liabilities are the expected long-term rate of return on plan assets
and the assumed discount rate. Primarily due to the decline in the market value
of the U.S. Plans' assets and increased benefit obligations associated with a
reduction in the discount rate, the value of the U.S. Plans' assets is less than
the accumulated benefit obligation. As a result, we recorded a non-cash minimum
liability adjustment related to the U.S. Plans, which resulted in a charge to
other comprehensive income during the fourth quarter of 2002 of $32.5 million,
net of tax. The minimum liability adjustment did not affect our results of
operations during 2002 nor our ability to meet any financial covenants related
to our debt facilities. We changed our expected long-term rate of return on plan
assets for our Frozen Plans to 9.0 percent as of December 31, 2002 from 10.0
percent as of December 31, 2001 due to a change in the asset allocation of plan
assets. For all U.S. Plans, we changed our discount rate as of December 31, 2002
to 6.50 percent from 7.0 percent as of December 31, 2001. The change in the
expected long-term rate of return on plan assets assumption was developed by
reviewing each plan's targeted asset allocation and asset class long-term rate
of return expectations. Pension expense related to the Transocean Plans for 2003
is estimated to increase by approximately $7 million based on the change in the
expected long-term rate of return assumptions, discount rate assumptions and
other factors. Continued poor performance in the equity markets could result in
additional significant changes to the accumulated other comprehensive loss
component of shareholders' equity and additional increases in future pension
expense and funding requirements.

We regularly review our actual asset allocation and periodically rebalance
plan assets as appropriate. For each percentage point the expected long-term
rate of return assumption is lowered, pension expense would increase
approximately $1.0 million. For each one-half percentage point the discount rate
is lowered, pension expense would increase by approximately $3.5 million.

Future changes in plan asset returns, assumed discount rates and various
other factors related to the pension will impact our future pension expense and
liabilities. We cannot predict with certainty what these factors will be in the
future.

OUTLOOK

Fleet utilization decreased and average dayrates improved within our
International and U.S. Floater Contract Drilling Services business segment
during the fourth quarter of 2002 compared with the third quarter of 2002. Both
fleet utilization and average dayrates decreased slightly within our Gulf of
Mexico Shallow and Inland Water business segment during the fourth quarter of
2002 compared with the third quarter of 2002.

-33-

THREE MONTHS ENDED
-----------------------------------------------
DECEMBER 31, SEPTEMBER 30, DECEMBER 31,
2002 2002 2001
-------------- --------------- --------------

Average Dayrates (a) (b)

International and U.S. Floater Contract
Drilling Services Segment
High-Specification Floaters . . . . $ 147,700 $ 144,600 $ 145,000
Other Floaters. . . . . . . . . . . 78,800 81,300 71,100
Jackups - Non-U.S.. . . . . . . . . 57,700 60,400 52,800
Other . . . . . . . . . . . . . . . 40,500 55,100 41,300
-------------- --------------- --------------
Segment Total. . . . . . . . . . . . . . 97,200 95,500 88,200
-------------- --------------- --------------

Gulf of Mexico Shallow and Inland Water
Segment
Jackups and Submersibles. . . . . . 21,900 23,000 30,600
Inland Barges . . . . . . . . . . . 19,600 20,700 22,800
-------------- --------------- --------------
Segment Total. . . . . . . . . . . . . . 20,600 21,600 25,600
-------------- --------------- --------------
Total Mobile Offshore Drilling Fleet . . $ 77,200 $ 76,400 $ 74,000
============== =============== ==============

Utilization (a) (c)

International and U.S. Floater Contract
Drilling Services Segment
High-Specification Floaters . . . . 93% 85% 90%
Other Floaters. . . . . . . . . . . 56% 76% 89%
Jackups - Non-U.S.. . . . . . . . . 83% 84% 89%
Other . . . . . . . . . . . . . . . 47% 51% 54%
-------------- --------------- --------------
Segment Total. . . . . . . . . . . . . . 75% 79% 86%
-------------- --------------- --------------

Gulf of Mexico Shallow and Inland Water
Segment
Jackups and Submersibles. . . . . . 33% 34% 27%
Inland Barges . . . . . . . . . . . 44% 47% 49%
-------------- --------------- --------------
Segment Total. . . . . . . . . . . . . . 39% 40% 38%
-------------- --------------- --------------
Total Mobile Offshore Drilling Fleet . . 60% 63% 67%
============== =============== ==============

_________________
(a) Applicable to core assets only, defined as high specification drillships and
semisubmersibles (floaters), other floaters, jackup rigs, drilling barges, tenders
and submersible drilling rigs.
(b) Average dayrate is defined as revenue earned per revenue earning day.
(c) Utilization is the total actual number of revenue earning days as a percentage of
total calendar days.

Commodity prices have increased significantly in the first quarter of 2003.
Concern created by the prospect of a war with Iraq and the political turmoil in
Venezuela resulting in lost production have both contributed to higher crude oil
prices. Cold weather and lower inventory levels have similarly helped push U.S.
natural gas prices significantly higher during the first quarter of 2003.
However, demand for our drilling rigs is driven largely by our clients'
perception of future commodity prices, and whether the current strong commodity
prices will translate into increased drilling activity in the face of the
general uncertainty over world political events remains unclear. We believe our
customers still see too much political and commercial uncertainty to materially
increase demand for drilling rigs in the near future.

Although we do not expect a significant increase in activity during 2003
within our International and U.S. Floater Contract Drilling Services segment, we
remain optimistic about the longer-term deepwater outlook. There is a slight
oversupply of deepwater rigs in the U.S. Gulf of Mexico, and we expect this
trend to continue in 2003. The substantial number of large discoveries in West
Africa combined with continuing exploratory interest in that region and growing
demand for rigs in India and the Far East are positive developments supporting
long-term deepwater activity.

-34-

The non-U.S. jackup market sectors remain strong. We look for this
activity level to continue through 2003. There has been some slowdown in
activity in Nigeria but we expect it to be offset by increased activity in
Mexico and India.

The mid-water floater business remains extremely weak. This segment is
significantly oversupplied globally with mid-water rig activity levels
particularly low in the North Sea. At February 28, 2003, eight of our 17 rigs in
the North Sea were idle but we anticipate putting three of these rigs back to
work in the second quarter of 2003. It is uncertain if the expected increase in
activity during the second quarter of 2003 will be sustained past the summer
season, as substantial oversupply is expected to continue through 2003.

The U.S. Gulf of Mexico shallow and inland water jackup market segment
remains depressed, despite historically high North American natural gas prices.
Jackup rigs continue to leave the U.S. Gulf of Mexico for long-term drilling
opportunities in other regions and, based on recently announced jackup rig needs
in Mexico and India, we expect this trend to continue. With this expected
decline in the jackup rig supply in the U.S. Gulf of Mexico market segment, a
slight increase in activity could cause substantial improvement in our U.S. Gulf
of Mexico shallow water business.

The contract drilling market historically has been highly competitive and
cyclical, and we are unable to predict the extent to which current market
conditions will continue. A decline in oil or gas prices could further reduce
demand for our contract drilling services and adversely affect both utilization
and dayrates.

We conduct our worldwide operations through various subsidiaries and branch
offices. Consequently, we are subject to changes in tax laws and the
interpretations of those tax laws in the jurisdictions in which we operate. This
includes tax laws directed toward companies organized in jurisdictions with low
tax rates. A material change in the tax laws of any country in which we have
operations, including the United States, could result in a higher effective tax
rate on our worldwide earnings.

As a result of our reorganization in 1999, we became a Cayman Islands
company in a transaction commonly referred to as an "inversion." Legislation in
various forms has been introduced in the U.S. House of Representatives and
Senate that would change the tax law applicable to companies that have completed
inversion transactions. Some of the proposals would have retroactive application
and would treat us as a U.S. corporation. Other proposals would impose
additional limitations on the deductibility, for U.S. federal income tax
purposes, of intercompany interest expense and could also make it more difficult
to integrate acquired U.S. businesses with existing operations or to undertake
internal restructuring. We cannot provide any assurance as to what form, if any,
final legislation will take or the impact such legislation will ultimately have.

Following the terrorist attacks on September 11, 2001, insurance
underwriters increased insurance premiums charged for many of the coverages
historically maintained by the Company, and the underwriters issued general
notices of cancellations to their customers for war risk, terrorism and
political risk coverages with respect to a wide variety of insurance products,
including but not limited to, property damage, liability and aviation coverages.
Our insurance underwriters renegotiated substantially higher premium rates for
war risk coverage, which can be canceled by the underwriters on short notice.
Our directors and officers liability coverage was renewed in the second quarter
of 2002 with a substantial increase in premium and we expect it to increase
significantly in the second quarter of 2003. Our current property insurance
program was renewed at the beginning of 2003, and we have substantially higher
deductibles for property claims, which will result in lower insurance recovery
for property claims. Our principal insurance programs providing our occupational
injury and illness coverages were renewed at the end of 2002 with no substantial
increase in premiums but with significantly higher deductibles. If our property
and occupational illness claim experience in 2003 is comparable to 2002, we
expect our total insurance expense to increase between $10 million and $14
million. Because of the substantial increase in our deductible exposure for
2003, an increase in our loss experience would result in higher insurance
expense for the period.

As a result of the implementation of Emerging Issues Task Force Issue No.
99-19, Reporting Revenue Gross as a Principal versus Net as an Agent, costs we
incur that are charged to our customers on a reimbursable basis will be
recognized as operating and maintenance expense in 2003. In addition, the
amounts billed to our customers associated with these reimbursable costs will be
recognized as operating revenue. We expect the increase in operating revenues
and operating and maintenance expenses to be between $60 million and $80 million
for the year 2003. This change in the accounting treatment for client
reimbursables will have no effect on our results of operations or consolidated
financial position. We previously recorded these charges and related
reimbursements on a net basis in operating and maintenance expense. Prior period
amounts are not reclassified as the amounts are not material.

In January 2003, we will begin recognizing stock compensation expense
effective with new options granted to employees in 2003. See "New Accounting
Pronouncements."

-35-

As of February 28, 2003, approximately 55 percent of our International and
U.S. Floater Contract Drilling Services segment fleet days were committed for
the remainder of 2003 and approximately 24 percent for the year 2004. For our
Gulf of Mexico Shallow and Inland Water segment, which has traditionally
operated under short-term contracts, committed fleet days were approximately 2
percent for the remainder of 2003 and none are currently committed for the year
2004.

OTHER FACTORS AFFECTING OPERATING RESULTS AND FINANCIAL CONDITION

Our business depends on the level of activity in oil and gas exploration,
development and production in market segments worldwide, with the U.S. and
international offshore and U.S. inland marine areas being our primary market
segments. Oil and gas prices and market expectations of potential changes in
these prices significantly affect this level of activity. However, higher
commodity prices do not necessarily translate into increased drilling activity
since our customers' expectation of future commodity prices typically drives
demand for our rigs. Worldwide military, political and economic events have
contributed to oil and gas price volatility and are likely to do so in the
future. Oil and gas prices are extremely volatile and are affected by numerous
factors, including the following:

- worldwide demand for oil and gas,

- the ability of the Organization of Petroleum Exporting Countries,
commonly called "OPEC," to set and maintain production levels and
pricing,

- the level of production in non-OPEC countries,

- the policies of various governments regarding exploration and
development of their oil and gas reserves,

- advances in exploration and development technology, and

- the worldwide military and political environment, including
uncertainty or instability resulting from an escalation or additional
outbreak of armed hostilities or other crises in the Middle East or
other geographic areas or further acts of terrorism in the United
States, or elsewhere.

The offshore and inland marine contract drilling industry is highly
competitive with numerous industry participants, none of which has a dominant
market share. Drilling contracts are traditionally awarded on a competitive bid
basis. Intense price competition is often the primary factor in determining
which qualified contractor is awarded a job, although rig availability and the
quality and technical capability of service and equipment may also be
considered. Recent mergers among oil and natural gas exploration and production
companies have reduced the number of available customers.

Our industry has historically been cyclical and is impacted by oil and gas
price levels and volatility. There have been periods of high demand, short rig
supply and high dayrates, followed by periods of low demand, excess rig supply
and low dayrates. Changes in commodity prices can have a dramatic effect on rig
demand, and periods of excess rig supply intensify the competition in the
industry and often result in rigs being idle for long periods of time. We may
be required to idle rigs or enter into lower rate contracts in response to
market conditions in the future.

We undertook a significant newbuild program that was completed in 2001.
While we experienced some start-up difficulties with most of our newbuild rigs,
we believe our newbuild fleet operations have progressed to a point where our
newbuild fleet's average downtime should be generally comparable to industry
norms. However, the deepwater environments in which these newbuild rigs operate
continue to present technological and engineering challenges so we are unable to
provide assurances that future operational problems will not arise. Should
problems occur that cause significant downtime or significantly affect a
newbuild rig's performance or safety, our clients may attempt to terminate or
suspend the drilling contract, particularly any of the long-term contracts
associated with most of these rigs. In the event of termination of a drilling
contract for one of these rigs, it is unlikely that we would be able to secure a
replacement contract on as favorable terms.

Our customers may terminate or suspend some of our term drilling contracts
under various circumstances such as the loss or destruction of the drilling
unit, downtime caused by equipment problems or sustained periods of downtime due
to force majeure events. Some drilling contracts permit the customer to
terminate the contract at the customer's option without paying a termination
fee. Suspension of drilling contracts results in loss of the dayrate for the
period of the suspension. If our customers cancel some of our significant
contracts and we are unable to secure new contracts on

-36-

substantially similar terms, it could adversely affect our results of
operations. In reaction to depressed market conditions, our customers may also
seek renegotiation of firm drilling contracts to reduce their obligations.

We plan to continue our restructuring of the ownership of a portion of the
assets held by TODCO and its subsidiaries in connection with the planned initial
public offering of our Gulf of Mexico Shallow and Inland Water business. Any
transfer of assets by TODCO or one of its subsidiaries to Transocean or one of
its other subsidiaries in this restructuring could, in some cases, result in the
imposition of additional taxes.

Our operations are subject to the usual hazards inherent in the drilling of
oil and gas wells, such as blowouts, reservoir damage, loss of production, loss
of well control, punchthroughs, craterings and fires. The occurrence of these
events could result in the suspension of drilling operations, damage to or
destruction of the equipment involved and injury or death to rig personnel. We
may also be subject to personal injury and other claims of rig personnel as a
result of our drilling operations. Operations also may be suspended because of
machinery breakdowns, abnormal drilling conditions, and failure of
subcontractors to perform or supply goods or services or personnel shortages. In
addition, offshore drilling operators are subject to perils peculiar to marine
operations, including capsizing, grounding, collision and loss or damage from
severe weather. Damage to the environment could also result from our operations,
particularly through oil spillage or extensive uncontrolled fires. We may also
be subject to property, environmental and other damage claims by oil and gas
companies. Our insurance policies and contractual rights to indemnity may not
adequately cover losses, and we may not have insurance coverage or rights to
indemnity for all risks.

We maintain broad insurance coverage, including insurance against general
and marine third-party liabilities. Our offshore drilling equipment is covered
by physical damage insurance policies, which cover against marine and other
perils, including losses due to capsizing, grounding, collision, fire,
lightning, hurricanes, wind, storms, action of waves, punchthroughs, cratering,
blowouts, explosions and war risks. We also carry employer's liability and other
insurance customary in the offshore contract drilling business. We do not
normally carry loss of hire or business interruption insurance.

Consistent with standard industry practice, our clients generally assume,
and indemnify us against, well control and subsurface risks under dayrate
contracts. These risks are those associated with the loss of control of a well,
such as blowout or cratering, the cost to regain control or redrill the well and
associated pollution. However, there can be no assurance that these clients will
necessarily be financially able to indemnify us against all these risks.

We believe we are adequately insured in accordance with industry standards
against normal risks in our operations; however, such insurance coverage may not
in all situations provide sufficient funds to protect us from all liabilities
that could result from our drilling operations. Although our current practice is
to insure the majority of our drilling units for their approximate fair value,
our insurance would not completely cover the costs that would be required to
replace certain of our units, including certain high-specification
semisubmersibles and drillships. We may also change our deductibles from time to
time in a manner that significantly limits the available recovery for an
individual property claim.

We operate in various regions throughout the world that may expose us to
political and other uncertainties, including risks of:

- terrorist acts, war and civil disturbances;

- expropriation or nationalization of equipment; and

- the inability to repatriate income or capital.

We are protected to a substantial extent against loss of capital assets,
but generally not loss of revenue, from most of these risks through insurance,
indemnity provisions in our drilling contracts, or both. The necessity of
insurance coverage for risks associated with political unrest, expropriation and
environmental remediation for operating areas not covered under our existing
insurance policies is evaluated on an individual contract basis. Although we
maintain insurance in the areas in which we operate, pollution and environmental
risks generally are not totally insurable. If a significant accident or other
event occurs and is not fully covered by insurance or a recoverable indemnity
from a client, it could adversely affect our consolidated financial position or
results of operations. Moreover, no assurance can be made that we will be able
to maintain adequate insurance in the future at rates we consider reasonable or
be able to obtain insurance against certain risks, particularly in light of the
instability and developments in the insurance markets following the recent
terrorist attacks. As of February 28, 2003, all areas in which we were operating
were covered by existing insurance policies.

-37-

Many governments favor or effectively require the awarding of drilling
contracts to local contractors or require foreign contractors to employ citizens
of, or purchase supplies from, a particular jurisdiction. These practices may
adversely affect our ability to compete.

Our non-U.S. contract drilling operations are subject to various laws and
regulations in countries in which we operate, including laws and regulations
relating to the equipment and operation of drilling units, currency conversions
and repatriation, oil and gas exploration and development and taxation of
offshore earnings and earnings of expatriate personnel. Governments in some
foreign countries have become increasingly active in regulating and controlling
the ownership of concessions and companies holding concessions, the exploration
of oil and gas and other aspects of the oil and gas industries in their
countries. In addition, government action, including initiatives by OPEC, may
continue to cause oil or gas price volatility. In some areas of the world, this
governmental activity has adversely affected the amount of exploration and
development work done by major oil companies and may continue to do so.

We are a Cayman Islands company as a result of our reorganization from a
Delaware corporation in May 1999. We operate worldwide through our various
subsidiaries. Consequently, we are subject to changing taxation policies in the
jurisdictions in which we operate, which could include policies directed toward
companies organized in jurisdictions with low tax rates. A material change in
the tax laws of any country in which we have significant operations, including
the U.S., could result in a higher effective tax rate on our worldwide earnings

Another risk inherent in our operations is the possibility of currency
exchange losses where revenues are received and expenses are paid in
nonconvertible currencies. We may also incur losses as a result of an inability
to collect revenues because of a shortage of convertible currency available to
the country of operation. We seek to limit these risks by structuring contracts
such that compensation is made in freely convertible currencies and, to the
extent possible, by limiting acceptance of non-convertible currencies to amounts
that match our expense requirements in local currency (see "Item 7A.
Quantitative and Qualitative Disclosures About Market Risk-Foreign Exchange
Risk"). Venezuela has recently implemented foreign exchange controls that limit
our ability to convert local currency into U.S. dollars and transfer excess
funds out of Venezuela. Our drilling contracts in Venezuela typically call for
payments to be made in local currency, even when the dayrate is denominated in
U.S. dollars. The exchange controls could also result in an artificially high
value being placed on the local Venezuela currency.

We require highly skilled personnel to operate and provide technical
services and support for our drilling units. To the extent that demand for
drilling services and the size of the worldwide industry fleet increase,
shortages of qualified personnel could arise, creating upward pressure on wages.
We are continuing our recruitment and training programs as required to meet our
anticipated personnel needs.

Our operations are subject to regulations controlling the discharge of
materials into the environment, requiring removal and cleanup of materials that
may harm the environment or otherwise relating to the protection of the
environment. For example, as an operator of mobile offshore drilling units in
navigable U.S. waters and some offshore areas, we may be liable for damages and
costs incurred in connection with oil spills related to those operations. Laws
and regulations protecting the environment have become more stringent in recent
years, and may in some cases impose strict liability, rendering a person liable
for environmental damage without regard to negligence. These laws and
regulations may expose us to liability for the conduct of or conditions caused
by others or for acts that were in compliance with all applicable laws at the
time they were performed. The application of these requirements or the adoption
of new requirements could have a material adverse effect on our consolidated
financial position and results of operations.

We have generally been able to obtain some degree of contractual
indemnification pursuant to which our clients agree to protect and indemnify us
against liability for pollution, well and environmental damages; however, there
is no assurance that we can obtain such indemnities in all of our contracts or
that, in the event of extensive pollution and environmental damages, the clients
will have the financial capability to fulfill their contractual obligations to
us. Also, these indemnities may not be enforceable in all instances.

-38-

On September 11, 2001, the U.S. was the target of terrorist attacks of
unprecedented scope. Recent world political events have resulted in military
action in Afghanistan and Iraq, and increasing military tension involving North
Korea. Military action by the U.S. or other nations could escalate and further
acts of terrorism in the U.S. or elsewhere may occur. Such acts of terrorism
could be directed against companies such as ours. These developments have caused
instability in the world's financial and insurance markets and will likely
significantly increase political and economic instability in the geographic
areas in which we currently operate. In addition, these developments could lead
to increased volatility in prices for crude oil and natural gas and could affect
the markets for drilling services. Insurance premiums have increased and could
rise further and coverages may be unavailable in the future. See "Outlook".

U.S. government regulations may effectively preclude us from actively
engaging in business activities in certain countries. These regulations could be
amended to cover countries where we currently operate or where we may wish to
operate in the future. These developments could subject the worldwide operations
of our company to increased risks and, depending on their magnitude, could have
a material adverse effect on our business.

The general rate of inflation in the majority of the countries in which we
operate has been moderate over the past several years and has not had a material
impact on our results of operations. An increase in the demand for offshore
drilling rigs usually leads to higher labor, transportation and other operating
expenses as a result of an increased need for qualified personnel and services.

MERGER PURCHASE PRICE ALLOCATION

The purchase price allocation for the R&B Falcon merger included, at
estimated fair value, total assets of $4.8 billion and the assumption of total
liabilities of $3.8 billion. The excess of the purchase price over the estimated
fair value of net assets acquired of approximately $5.6 billion was accounted
for as goodwill. At December 31, 2002, the remaining goodwill balance of $1.2
billion represented approximately 10 percent of total assets and 17 percent of
total shareholders' equity. Prior to our January 1, 2002 adoption of SFAS 142,
goodwill was amortized using a 40-year life based on the nature of the offshore
drilling industry, long-lived drilling equipment and long-standing relationships
with core customers. See "-New Accounting Pronouncements".

The purchase price allocation for the merger of Transocean Offshore Inc.
and Sedco Forex included, at estimated fair value, total assets of $3.8 billion
and the assumption of total liabilities of $1.9 billion. The excess of the
purchase price over the estimated fair value of net assets acquired of
approximately $1.1 billion was accounted for as goodwill. At December 31, 2002,
the remaining goodwill balance of $1.0 billion represented approximately eight
percent of total assets and 14 percent of total shareholders' equity. Prior to
our January 1, 2002 adoption of SFAS 142, goodwill was amortized using a 40-year
life based on the nature of the offshore drilling industry, long-lived drilling
equipment and long-standing relationships with core customers. See "-New
Accounting Pronouncements".

LIQUIDITY AND CAPITAL RESOURCES

SOURCES AND USES OF CASH

YEARS ENDED DECEMBER 31,
------------------------
2002 2001 CHANGE
-------------- -------- ----------

(IN MILLIONS)
NET CASH PROVIDED BY OPERATING ACTIVITIES
Net income (loss). . . . . . . . . . . . $ (3,731.9) $ 252.6 $(3,984.5)
Non-cash items . . . . . . . . . . . . . 4,547.5 416.0 4,131.5
Working capital. . . . . . . . . . . . . 121.0 (108.2) 229.2
-------------- -------- ----------
$ 936.6 $ 560.4 $ 376.2
============== ======== ==========

Cash generated from net income items adjusted for non-cash activity in 2002
increased $147.0 million over 2001. For 2002, we recognized non-cash losses on
impairments of goodwill and long-lived assets in the amount of $4,239.7 million
and $51.4 million, respectively, while we recognized $40.4 million of non-cash
impairments on long-lived assets and $154.9 million of goodwill amortization in
2001. The increase in cash provided by working capital items for 2002 compared
to 2001 was primarily due to lower activity and improved accounts receivable
collections.

-39-

YEARS ENDED DECEMBER 31,
------------------------
2002 2001 CHANGE
-------------- -------- --------
(IN MILLIONS)

NET CASH USED IN INVESTING ACTIVITIES
Capital expenditures . . . . . . . . . . . $ (141.0) $(506.2) $ 365.2
Proceeds from sale of securities . . . . . - 17.2 (17.2)
Proceeds from disposal of assets . . . . . 88.3 201.7 (113.4)
Merger costs paid. . . . . . . . . . . . . - (24.4) 24.4
Cash acquired in merger, net of cash paid. - 264.7 (264.7)
Other, net . . . . . . . . . . . . . . . . 7.4 20.6 (13.2)
-------------- -------- --------
$ (45.3) $ (26.4) $ (18.9)
============== ======== ========

Net cash used in investing activities was greater in 2002 compared to 2001
as a result of lower proceeds in 2002 from asset sales and cash received in 2001
in connection with the R&B Falcon merger, partially offset by lower capital
expenditures in 2002 due to the completion of our newbuild program in 2001.

YEARS ENDED DECEMBER 31,
-------------------------
2002 2001 CHANGE
-------------- --------- -----------
(IN MILLIONS)

NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES
Net borrowings (repayments) under commercial paper program $ (326.4) $ 326.4 $ (652.8)
Net proceeds from issuance of debt . . . . . . . . . . . . - 1,693.5 (1,693.5)
Repayments on other debt instruments . . . . . . . . . . . (189.3) (1,551.0) 1,361.7
Net repayments on revolving credit agreements. . . . . . . - (180.1) 180.1
Other, net . . . . . . . . . . . . . . . . . . . . . . . . (14.8) (3.9) (10.9)
-------------- ---------- ----------
$ (530.5) $ 284.9 $ (815.4)
============== ========== ==========

During 2002, we had no borrowings under our revolving credit agreements and
we repaid the $326.4 million that we borrowed under our commercial paper program
in 2001. The decrease in repayments of debt instruments of $1,361.7 million was
primarily due to repayments of TODCO debt instruments totaling $1,458.0 million
in the second quarter of 2001 as more fully described in Note 8 to our
consolidated financial statements. Also in 2002, we made early repayments of
the secured rig financings on the Trident IX and Trident 16 of $50.6 million in
aggregate and scheduled debt payments of $138.6 million. The increase in cash
used in other, net mainly reflects $8.3 million in consent payments related to
the exchange of our notes for TODCO notes, no exercise of warrants in 2002 and
lower proceeds from stock option exercises in 2002, partially offset by the
discontinuance of cash dividend payments after the second quarter of 2002 and
financing costs paid in 2001 in connection with debt issuances. In the second
quarter of 2001, we received net proceeds of $1,693.5 million primarily due to
the issuance of our 6.625% Notes, 7.5% Notes and 1.5% Convertible Debentures.

CAPITAL EXPENDITURES

Capital expenditures totaled $141.0 million during the year ended December
31, 2002. During 2003, we expect to spend between $130 million and $150 million
on our existing fleet, corporate infrastructure and major upgrades. A
substantial majority of our expected capital expenditures in 2003 relates to our
International and U.S. Floater Contract Drilling Services segment.

We intend to fund the cash requirements relating to our capital
expenditures through available cash balances, cash generated from operations and
asset sales. We also have available credit under our revolving credit
agreements and commercial paper program (see "-Sources of Liquidity") and may
engage in other commercial bank or capital market financings.

ACQUISITIONS AND DISPOSITIONS

From time to time, we review possible acquisitions of businesses and
drilling units and may in the future make significant capital commitments for
such purposes. Any such acquisition could involve the payment by us of a
substantial amount of cash or the issuance of a substantial number of additional
ordinary shares or other securities. We would likely fund the cash portion of
any such acquisition through cash balances on hand, the incurrence of additional
debt, sales of assets, ordinary shares or other securities or a combination
thereof. In addition, from time to time, we review possible dispositions of
drilling units. See "-Outlook."

-40-

In March 2002, in our International and U.S. Floater Contract Drilling
Services segment, we sold two semisubmersible rigs, the Transocean 96 and
Transocean 97, for net proceeds of $30.7 million and recognized net after-tax
gains of $1.3 million. In June 2002, in our International and U.S. Floater
Contract Drilling Services segment, we sold a jackup rig, the RBF 209, and
recognized a net after-tax loss of $1.5 million. During the year ended December
31, 2002, we also partially settled an insurance claim and sold certain other
non-strategic assets and certain other assets held for sale for net proceeds of
approximately $38.9 million and recognized net after-tax gains of $2.7 million
and $0.6 million in our International and U.S. Floater Contract Drilling
Services and Gulf of Mexico Shallow and Inland Water segments, respectively.

In January 2003, we completed the sale of the RBF 160 to a third party for
net proceeds of $13.0 million and recognized a net after-tax gain on sale of
$0.2 million. The proceeds were received in December 2002 and were reflected as
deferred income and proceeds from asset sales in the consolidated balance sheet
and consolidated statement of cash flow, respectively.

We continue to proceed with our previously announced plans to pursue an
initial public offering of our Gulf of Mexico Shallow and Inland Water business.
Our plan is to separate this business from Transocean and establish it as a
publicly traded company. We are proceeding with our plans to reorganize TODCO
as the entity that owns this business in preparation of the offering. We expect
to effect the initial public offering when market conditions warrant, subject to
various factors. Given the current general uncertainty in the equity and U.S.
natural gas drilling markets, we are unsure when the transaction could be
completed on terms acceptable to us. See "-Overview."

Our plans to sell certain other individual assets have been impeded by
difficult market conditions. We expect the pace of these asset sales to remain
slow until market conditions improve. We received $207 million in 2001 and $79
million in 2002 from the sale of these assets. Future sales will be dependent
upon obtaining an acceptable sale price. We may evaluate our decision to sell
these assets from time to time depending upon market conditions and may decide
to discontinue our sales efforts, in whole or in part.

SOURCES OF LIQUIDITY

Our primary sources of liquidity in 2002 were our cash flows from
operations and asset sales. Primary uses of cash were debt repayment and
capital expenditures. At December 31, 2002, we had $1,214.2 million in cash and
cash equivalents.

We anticipate that we will rely primarily upon existing cash balances and
internally generated cash flows to maintain liquidity in 2003, as cash flows
from operations are expected to be positive and, together with existing cash
balances, adequate to fulfill anticipated obligations, including the potential
obligation to repurchase the Zero Coupon Convertible Debentures at the option of
the holders. See Note 8 to our consolidated financial statements. From time to
time, we may also use bank lines of credit and commercial paper to maintain
liquidity for short-term cash needs.

We intend to use the proceeds from the initial public offering of our Gulf
of Mexico Shallow and Inland Water business as well as any proceeds from asset
sales (see "-Acquisitions and Dispositions") to further reduce our debt
balances.

We intend to use cash from operations primarily to pay debt as it comes due
and to fund capital expenditures. If we seek to reduce our debt other than
through scheduled maturities, we could do so through repayment of bank
borrowings or through repurchases or redemptions of, or tender offers for, debt
securities. We have significantly reduced capital expenditures compared to
prior years due to the completion of our newbuild program in 2001. During 2002,
we have reduced net debt, defined as total debt less swap receivables and cash
and cash equivalents, by $873 million. The components of net debt at carrying
value were as follows (in millions):

DECEMBER 31,
---------------------
2002 2001
---------- ---------

Total Debt. . . . . . . . . . . $ 4,678.0 $5,023.8
Less: Cash and cash equivalents (1,214.2) (853.4)
Swap receivables . . . . . (181.3) (15.1)

Because we intend to pay debt with cash on hand, we use net debt to
represent debt that is anticipated to be paid with future cash flows. The net
debt measure also allows us to measure the cash flow that has been generated to
date to fund our major obligations. Net debt since 2001 has been on a downward
trend as cash flows, primarily from operations and asset sales, have been
greater than that needed for capital expenditures.

-41-

Our internally generated cash flow is directly related to our business and
the market segments in which we operate. Should the drilling market deteriorate
further, or should we experience poor results in our operations, cash flow from
operations may be reduced. To date, however, we have continued to generate
positive cash flow from operations.

We have access to $800 million in bank lines of credit under two revolving
credit agreements, a 364-day revolving credit agreement providing for $250
million in borrowings and expiring in December 2003 and a five-year revolving
credit agreement providing for $550 million in borrowings and expiring in
December 2005. These credit lines are used primarily to back our $800 million
commercial paper program and may also be drawn on directly. As of December 31,
2002, none of the credit line capacity was utilized, leaving $800 million of
availability under the bank lines of credit for commercial paper issuance or
drawdowns.

The bank credit lines require compliance with various covenants and
provisions customary for agreements of this nature, including an interest
coverage ratio and leverage ratio, both as defined by the credit agreements, of
not less than three to one and not greater than 40 percent, respectively. In
calculating the leverage ratio, the credit agreements specifically exclude the
impact on total capital of all non-cash goodwill impairment charges recorded in
compliance with SFAS 142 (see Note 2 to our consolidated financial statements).
Other provisions of the credit agreements include limitations on creating liens,
incurring debt, transactions with affiliates, sale/leaseback transactions and
mergers and sale of substantially all assets. Should we fail to comply with
these covenants, we would be in default and may lose access to these facilities.
A loss of the bank facilities would also cause us to lose access to the
commercial paper markets. We are also subject to various covenants under the
indentures pursuant to which our public debt was issued, including restrictions
on creating liens, engaging in sale/leaseback transactions and engaging in
merger, consolidation or reorganization transactions. A default under our
public debt could trigger a default under our credit lines and cause us to lose
access to these facilities. See Note 8 to our consolidated financial statements
for a description of our credit agreements and debt securities.

In April 2001, the SEC declared effective our shelf registration statement
on Form S-3 for the proposed offering from time to time of up to $2.0 billion in
gross proceeds of senior or subordinated debt securities, preference shares,
ordinary shares and warrants to purchase debt securities, preference shares,
ordinary shares or other securities. In May 2001, we issued $400.0 million
aggregate principal amount of 1.5% Convertible Debentures due May 15, 2021 under
the shelf registration statement. At February 28, 2003, $1.6 billion in gross
proceeds of securities remained unissued under the shelf registration statement.

Our access to commercial paper, debt and equity markets may be reduced or
closed to us due to a variety of events, including, among others, downgrades of
ratings of our debt and commercial paper, industry conditions, general economic
conditions, market conditions and market perceptions of us and our industry.

Our contractual obligations in the table below include our debt obligations
at face value.

FOR THE YEARS ENDING DECEMBER 31,
------------------------------------------------------
TOTAL 2003 2004-2005 2006-2007 THEREAFTER
-------- -------- ---------- ---------- -----------
(IN MILLIONS)

CONTRACTUAL OBLIGATIONS
Debt . . . . . . . . . . $4,476.3 $1,062.0 $ 614.3 $ 500.0 $ 2,300.0
Operating Leases . . . . 113.7 32.2 45.5 13.5 22.5
-------- -------- ---------- ---------- -----------
Total Obligations. . . $4,590.0 $1,094.2 $ 659.8 $ 513.5 $ 2,322.5
======== ======== ========== ========== ===========

The bondholders may, at their option, require us to repurchase, or put,
the Zero Coupon Convertible Debentures due 2020, the 1.5% Convertible Debentures
due 2021 and the 7.45% Notes due 2027 in May 2003, May 2006 and April 2007,
respectively. With regard to both series of the Convertible Debentures, we have
the option to pay the repurchase price in cash, ordinary shares or any
combination of cash and ordinary shares. The chart above assumes that the
holders of these convertible debentures and notes exercise the options at the
first available date. We expect that most, if not all, of the holders of the
Zero Coupon Convertible Debentures will exercise their put option in May 2003
and, at that time, we would recognize additional expense of approximately $11
million as a loss on retirement of debt to fully amortize the remaining debt
issue costs related to these debentures. We expect to satisfy the May 2003 put
option in cash. We are also required to repurchase the convertible debentures at
the option of the holders at other later dates as more fully described in Note 8
to our consolidated financial statements.

At December 31, 2002, we had other commitments that we are contractually
obligated to fulfill with cash should the obligations be called. These
obligations consisted primarily of standby letters of credit and surety bonds
that guarantee our performance as it relates to our drilling contracts,
insurance, tax and other obligations in various jurisdictions. These
obligations are not normally called as we typically comply with the underlying
performance requirement. The table below

-42-

provides a list of these obligations in U.S. dollar equivalents and their time
to expiration. It should be noted that these obligations could be called at any
time prior to the expiration dates.

FOR THE YEARS ENDING DECEMBER 31,
----------------------------------------------------
TOTAL 2003 2004-2005 2006-2007 THEREAFTER
------ ------ ---------- ---------- -----------

(IN MILLIONS)
OTHER COMMERCIAL COMMITMENTS
Standby Letters of Credit. . $ 54.0 $ 40.2 $ 9.4 $ 4.4 $ -
Surety Bonds . . . . . . . . 215.8 152.5 63.3 - -
Purchase Option Guarantees -
Joint Ventures (a) . . . . 208.9 92.5 116.4 - -
Other Commitments. . . . . . 0.1 - 0.1 - -
------ ------ ---------- ---------- -----------
Total . . . . . . . . . . $478.8 $285.2 $ 189.2 $ 4.4 $ -
====== ====== ========== ========== ===========

____________________________
(a) See "-Special Purpose Entities".

Letters of credit are issued under a number of facilities provided by
several banks. The obligations that are the subject of these surety bonds are
geographically concentrated in the United States, Brazil and Nigeria, of which
93 percent are concentrated in five bonds.

In March 2002, we completed an exchange offer where TODCO's 6.5% Senior
Notes due April 15, 2003, 6.75% Senior Notes due April 15, 2005, 6.95% Senior
Notes due April 15, 2008, 7.375% Senior Notes due April 15, 2018, 9.125% Senior
Notes due December 15, 2003 and 9.5% Senior Notes due December 15, 2008, whose
holders accepted the offer, were exchanged for our newly issued notes. The new
notes were issued in six series corresponding to the six series of TODCO notes
and have the same principal amount, interest rate, redemption terms and payment
and maturity dates as the corresponding series of TODCO notes. The aggregate
principal amount of the new notes issued was approximately $1.4 billion.
Because the holders of a majority in principal amount of each of these series of
notes consented to the proposed amendments to the applicable indenture pursuant
to which the notes were issued, some covenants, restrictions and events of
default were eliminated from the indentures with respect to these series of
notes. The notes not exchanged, with an aggregate principal amount of $38.8
million, remain the obligation of TODCO. In connection with the exchange
offers, TODCO paid $8.3 million in consent payments to holders of TODCO's notes
whose notes were exchanged.

DERIVATIVE INSTRUMENTS

We have established policies and procedures for derivative instruments that
have been approved by our Board of Directors. These policies and procedures
provide for the prior approval of derivative instruments by our Chief Financial
Officer. From time to time, we may enter into a variety of derivative financial
instruments in connection with the management of our exposure to fluctuations in
foreign exchange rates and interest rates. We do not enter into derivative
transactions for speculative purposes; however, for accounting purposes, certain
transactions may not meet the criteria for hedge accounting.

Gains and losses on foreign exchange derivative instruments that qualify as
accounting hedges are deferred as accumulated other comprehensive income and
recognized when the underlying foreign exchange exposure is realized. Gains and
losses on foreign exchange derivative instruments that do not qualify as hedges
for accounting purposes are recognized currently based on the change in market
value of the derivative instruments. At December 31, 2002, we had no material
open foreign exchange derivative instruments.

From time to time, we may use interest rate swaps to manage the effect of
interest rate changes on future income. Interest rate swaps are designated as a
hedge of underlying future interest payments. The interest rate differential to
be received or paid under the swaps is recognized over the lives of the swaps as
an adjustment to interest expense (see "Item 7A. Quantitative and Qualitative
Disclosures About Market Risk-Interest Rate Risk"). If an interest rate swap is
terminated, the gain or loss is amortized over the life of the underlying debt.
At December 31, 2002, we had a $3.6 million gain related to a terminated
interest rate swap that was included in accumulated other comprehensive income
in our consolidated balance sheet and is being amortized over the life of the
underlying debt.

-43-

DD LLC, an unconsolidated joint venture in which we have a 50% ownership
interest, has entered into interest rate swaps associated with the operating
lease for the Deepwater Pathfinder. At December 31, 2002, the aggregate market
values of these swaps netted to a liability of $6.7 million. The effect of the
swap has been to convert the interest portion of the operating lease payments
from a floating rate of one-month LIBOR plus a margin to a fixed rate of 5.7175
percent per annum. We report our share of the fair value of the interest rate
swaps in accumulated other comprehensive income with a corresponding reduction
to investments in and advances to joint ventures in our consolidated balance
sheet. At December 31, 2002, this amount was an unrealized loss of $2.0
million, net of tax.

In June 2001, we entered into $700 million aggregate notional amount of
interest rate swaps as a fair value hedge against our 6.625% Notes due April
2011. In February 2002, we entered into $900 million aggregate notional amount
of interest rate swaps as a fair value hedge against our 6.75% Senior Notes due
April 2005, 6.95% Senior Notes due April 2008 and 9.5% Senior Notes due December
2008. The swaps effectively converted the fixed interest rate on each of the
four series of notes into a floating rate of LIBOR plus a margin of 50, 246, 171
and 413 basis points, respectively. The market value of the swaps was carried
as an asset or a liability in our consolidated balance sheet and the carrying
value of the hedged debt was adjusted accordingly. At December 31, 2002, the
swaps had a market value of $181.3 million that was recorded as an increase to
other assets and long-term debt in our consolidated balance sheets.

In January 2003, we terminated the swaps with respect to our 6.75% Senior
Notes due April 2005, 6.95% Senior Notes due April 2008 and 9.5% Senior Notes
due December 2008. In March 2003, we terminated the swaps with respect to our
6.625% Notes due April 2011. As a result of these terminations, we will have an
aggregate fair value adjustment of approximately $173.5 million included in
long-term debt in our consolidated balance sheet, which will be amortized as an
adjustment to interest expense over the life of the underlying debt. For the
year 2003, we expect this reduction to interest expense will be approximately
$23.1 million.

SPECIAL PURPOSE ENTITIES

As a result of the R&B Falcon merger, we have ownership interests in two
unconsolidated joint ventures, 50 percent in DD LLC, and 60 percent in DDII LLC.
Subsidiaries of ConocoPhillips ("Conoco") own the remaining interests in DD LLC
and DDII LLC. We share management of the joint ventures equally with Conoco.
Each of the joint ventures is a lessee in a synthetic lease financing facility
entered into in connection with the construction of the Deepwater Pathfinder, in
the case of DD LLC, and the Deepwater Frontier, in the case of DDII LLC.
Pursuant to the lease financings, the rigs are owned by special purpose entities
and leased to the joint ventures. We do not own, manage or control the special
purpose entities. The lease payments under both synthetic leases are supported
by drilling contracts between the two respective joint ventures and Conoco and,
in the case of DDII LLC, one of our subsidiaries. Conoco is responsible for all
of the remaining commitment to DD LLC and most of the remaining commitment to
DDII LLC under these drilling contracts.

We, together with Conoco, provide the joint ventures with certain
operational support services. For each of the joint ventures, we and Conoco
guarantee the obligation of the joint venture to pay certain contingent lease
obligations in proportion to their respective ownership interests in the joint
ventures.

DD LLC's annual rent payments for the Deepwater Pathfinder, totaling
approximately $29 million in 2002, are substantially fixed due to the interest
rate swap described above. DDII LLC's annual rent payments for the Deepwater
Frontier are subject to changes in market interest rates and totaled
approximately $24 million in 2002.

If an event of default occurs under the applicable lease documents, each
joint venture may be required to pay an amount equal to the amount of debt and
equity financing owed by the applicable special purpose entity plus certain
expenses. The debt and equity financing outstanding as of December 31, 2002,
applicable to the owner of Deepwater Pathfinder and of Deepwater Frontier, was
$203 million and $217 million, respectively. We, together with Conoco, have
guaranteed our respective share of each joint venture's obligations to pay these
amounts.

The scheduled expiration of the lease is December 2003, in the case of the
Deepwater Pathfinder, and March 2004, in the case of the Deepwater Frontier.
Each of the leases is subject to certain extension options of DD LLC and DDII
LLC, respectively. At the expiration of the leases, each joint venture may
purchase the rig for $185 million, in the case of the Deepwater Pathfinder, and
$194 million, in the case of the Deepwater Frontier, or return the rig to the
special purpose entities. If a joint venture purchases the rig, we would be
obligated to pay only the portion of such price equal to our percentage
ownership interest in the applicable joint venture. Our proportionate share for
each such purchase option is $93 million and $116 million, respectively. Under
each joint venture agreement, the consent of each venturer is generally required
to approve actions of the joint venture, including the exercise of this purchase
option. If a joint venture returns the rig at the end of the lease, the special
purpose entity may sell the rig. In connection with the return, DD LLC may be
required to pay an amount up to $138 million, and DDII LLC may be required to
pay an amount up to $145 million, plus certain expenses in each case. These
payments may be reduced by a portion of the proceeds of the sale of the
applicable rig.

-44-

These leases contain ratings triggers that are invoked only if we are
involved in a change of control and the acquiror has a credit rating lower than
BBB or Baa2. Should these triggers be invoked, the acquiring company would, at
the option of the investors, be obligated to pay our share of the outstanding
investments under the leases.

SALE/LEASEBACK

We lease the M. G. Hulme, Jr. from Deep Sea Investors, L.L.C., a special
purpose entity formed by several leasing companies to acquire the rig from one
of our subsidiaries in November 1995 in a sale/leaseback transaction. We are
obligated to pay rent of approximately $13 million per year through December
2005. At the termination of the lease, we may purchase the rig for approximately
$35 million. Effective September 2002, the lease neither requires that
collateral be maintained nor contains any credit rating triggers.

RELATED PARTY TRANSACTIONS

Delta Towing - In connection with the R&B Falcon merger, TODCO formed a
joint venture to own and operate its U.S. inland marine support vessel business
(the "Marine Business"). As part of the joint venture formation in January
2001, the Marine Business was transferred by a subsidiary of TODCO to Delta
Towing LLC ("Delta Towing") in exchange for a 25 percent equity interest in
Delta Towing Holdings, LLC, the parent of Delta Towing, and certain secured
notes payable from Delta Towing in a principal amount of $144 million. These
notes were valued at $80 million immediately prior to the closing of the R&B
Falcon merger. In December 2001, the note agreement was amended to provide for a
$4 million, three year-revolving credit facility (the "Delta Towing Revolver").

As part of the formation of the joint venture on January 31, 2001, TODCO
entered into a charter arrangement with Delta Towing under which we committed to
charter certain vessels for a period of one year ending January 31, 2002, and
committed to charter for a period of 2.5 years from date of delivery 10
crewboats then under construction, all of which have been placed into service as
of March 1, 2003. TODCO also entered into an alliance agreement with Delta
Towing under which we agreed to treat Delta Towing as a preferred supplier for
the provision of marine support services.

In 2002, we incurred charges totaling $10.7 million from Delta Towing for
services rendered, of which $1.6 million was rebilled to our customers and $9.1
million was reflected in operating and maintenance expense. As of March 1, 2003,
the carrying value of the notes was $78.9 million and $3.9 million was
outstanding under the Delta Towing Revolver. In January 2003, Delta Towing
failed to make its scheduled quarterly interest payment of $1.7 million. We
granted a 90-day waiver of this payment. As of February 28, 2003, a total of
$2.7 million unpaid interest was outstanding.

Delta Towing operates in the Gulf of Mexico in support of the oil and gas
industry and faces similar market conditions as we do with our Gulf of Mexico
Shallow and Inland Water business segment. Should weakened market conditions
persist or should market conditions deteriorate further, Delta Towing's ability
to pay its debts to us as they come due may be adversely affected. A failure by
Delta Towing to service its debt obligations to us may result in an impairment
of the carrying value of the notes, the Delta Towing Revolver and related
accrued interest.

DD LLC and DDII LLC - We are a party to drilling services agreements with
DD LLC and DDII LLC for the operation of the Deepwater Pathfinder and Deepwater
Frontier, respectively. In 2002, we earned $1.6 million for such drilling
services from each of DD LLC and DDII LLC.

ODL - We own a 50 percent interest in an unconsolidated joint venture
company, Overseas Drilling Limited ("ODL"). ODL owns the Joides Resolution, for
which we provide certain operational and management services. In 2002, we
earned $1.2 million for those services.

NEW ACCOUNTING PRONOUNCEMENTS

In July 2001, the Financial Accounting Standards Board's ("FASB") issued
SFAS 142, Goodwill and Other Intangible Assets, which is effective for fiscal
years beginning after December 15, 2001. Under SFAS 142, goodwill and intangible
assets with indefinite lives are no longer amortized but are reviewed at least
annually for impairment. The amortization provisions of SFAS 142 apply to
goodwill and intangible assets acquired after June 30, 2001. With respect to
goodwill and intangible assets acquired prior to July 1, 2001, we adopted SFAS
142 effective January 1, 2002 and selected October 1 as our annual test date for
impairment of goodwill. In conjunction with the adoption of this statement, we
discontinued the amortization of goodwill. Application of the non-amortization
provisions of SFAS 142 for goodwill resulted in an increase in operating income
of approximately $155 million in 2002. During 2002, we recognized non-cash
impairment charges of $4.2 billion as a result of the adoption and application
of this statement. See Note 2 to our consolidated financial statements.

-45-

In August 2001, the FASB issued SFAS 144, Accounting for Impairment or
Disposal of Long-Lived Assets. SFAS 144 supersedes SFAS 121, Accounting for
Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed of, and
the accounting and reporting provisions of Accounting Principles Board Opinion
("APB") 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. SFAS 144 retains the accounting and
reporting provisions of SFAS 121 for recognition and measurement of long-lived
asset impairment and for the measurement of long-lived assets to be disposed of
by sale and the accounting and reporting provisions of APB 30. In addition to
these accounting and reporting provisions, SFAS 144 provides guidance for
determining whether long-lived assets should be tested for impairment and
specific criteria for classifying assets to be disposed of as held for sale.
The statement is effective for fiscal years beginning after December 15, 2001.
We adopted this statement as of January 1, 2002. The adoption of this statement
had no material effect on our consolidated financial position or results of
operations.

In April 2002, the FASB issued SFAS 145, Rescission of FASB Statements No.
4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections.
This statement eliminates the requirement under SFAS 4 to aggregate and classify
all gains and losses from extinguishment of debt as an extraordinary item, net
of related income tax effect. This statement also amends SFAS 13 to require
certain lease modifications with economic effects similar to sale-leaseback
transactions be accounted for in the same manner as sale-leaseback transactions.
In addition, SFAS 145 requires reclassification of gains and losses in all prior
periods presented in comparative financial statements related to debt
extinguishment that do not meet the criteria for extraordinary item in APB 30.
The statement is effective for fiscal years beginning after May 15, 2002 with
early adoption encouraged. We adopted SFAS 145 effective January 1, 2003. We do
not expect adoption of this statement to have a material effect on our
consolidated financial position or results of operations.

In July 2002, the FASB issued SFAS 146, Obligations Associated with
Disposal Activities, which is effective for disposal activities initiated after
December 15, 2002, with early application encouraged. SFAS 146 addresses
financial accounting and reporting for costs associated with exit or disposal
activities and nullifies Emerging Issues Task Force Issue No. 94-3, Liability
Recognition for Certain Employee Termination Benefits and Other Costs to Exit an
Activity (including Certain Costs Incurred in a Restructuring). Under this
statement, a liability for a cost associated with an exit or disposal activity
would be recognized and measured at its fair value when it is incurred rather
than at the date of commitment to an exit plan. Under SFAS 146, severance pay
would be recognized over time rather than up front provided the benefit
arrangement requires employees to render future service beyond a minimum
retention period, which would be based on the legal notification period, or if
there is no such requirement, 60 days, thereby allowing a liability to be
recorded over the employees' future service period. We will adopt SFAS 146
effective with disposal activities initiated after December 15, 2002. We do not
expect adoption of this statement to have a material effect on our consolidated
financial position or results of operations.

In December 2002, the FASB issued SFAS 148, Accounting for Stock-Based
Compensation - Transition and Disclosure, which is effective for fiscal years
ending after December 15, 2002. SFAS 148 amends SFAS 123, Accounting for
Stock-Based Compensation, to permit two additional transition methods for a
voluntary change to the fair value based method of accounting for stock-based
employee compensation from the intrinsic method under APB 25, Accounting for
Stock Issued to Employees. The prospective method of transition under SFAS 123
is an option for entities adopting the recognition provisions of SFAS 123 in a
fiscal year beginning before December 15, 2003. In addition, SFAS 148 amends the
disclosure requirements of SFAS 123 to require prominent disclosures in both
annual and interim financial statements concerning the method of accounting used
for stock-based employee compensation and the effects of that method on reported
results of operations. Under SFAS 148, pro forma disclosures are required in a
specific tabular format in the "Summary of Significant Accounting Policies". We
adopted the disclosure requirements of this statement as of December 31, 2002.
The adoption had no effect on our consolidated financial position or results of
operations. We adopted the fair value method of accounting for stock-based
compensation using the prospective method of transition under SFAS 123 effective
January 1, 2003. We expect compensation expense in 2003 will increase by
approximately $6 million as a result of adoption. See Note 2 to our consolidated
financial statements.

In December 2002, the FASB issued Interpretation ("FIN") 45, Guarantor's
Accounting and Disclosure Requirements for Guarantees, Including Indirect
Guarantees of Indebtedness of Others. FIN 45 requires that at the time a
company issues a guarantee, the company must recognize an initial liability for
the fair value, or market value, of the obligations it assumes under that
guarantee. This interpretation is applicable on a prospective basis to
guarantees issued or modified after December 31, 2002. We do not expect
adoption of this interpretation to have a material effect on our consolidated
financial position or results of operations.

-46-

the guidance could result in the consolidation of a variable interest entity. We
are evaluating the impact of this interpretation on our consolidated financial
position and results of operations.

FORWARD-LOOKING INFORMATION

The statements included in this annual report regarding future financial
performance and results of operations and other statements that are not
historical facts are forward-looking statements within the meaning of Section
27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act
of 1934. Statements to the effect that the Company or management "anticipates,"
"believes," "budgets," "estimates," "expects," "forecasts," "intends," "plans,"
"predicts," or "projects" a particular result or course of events, or that such
result or course of events "could," "might," "may," "scheduled" or "should"
occur, and similar expressions, are also intended to identify forward-looking
statements. Forward-looking statements in this annual report include, but are
not limited to, statements involving payment of severance costs, contract
commencements, potential revenues, increased expenses, customer drilling
programs, supply and demand, utilization rates, dayrates, planned shipyard
projects, expected downtime, effect of technical difficulties with newbuild
rigs, future activity in the deepwater, mid-water and the shallow and inland
water markets, market outlooks for our various geographical operating sectors,
the U.S. gas drilling market, rig classes and business segments, the planned
initial public offering of our Gulf of Mexico Shallow and Inland Water business
(including the timing of the offering and portion sold), planned asset sales,
timing of asset sales, proceeds from asset sales, reactivation of stacked units,
timing of and results of negotiations with the labor union representing U.K.
employees, future labor costs, the contracting of jackup rigs in Mexico and
India, the Company's other expectations with regard to market outlook,
operations in international markets, expected capital expenditures, results and
effects of legal proceedings and governmental audits and assessments, adequacy
of insurance, receipt of loss of hire insurance proceeds, liabilities for tax
issues, liquidity, positive cash flow from operations, the exercise of the
option of holders of Zero Coupon Convertible Debentures, the 1.5% Convertible
Debentures or the 7.45% Notes to require the Company to repurchase the notes and
debentures, and the satisfaction of such obligation in cash, adequacy of cash
flow for 2003 obligations, effects of accounting changes, and the timing and
cost of completion of capital projects. Such statements are subject to numerous
risks, uncertainties and assumptions, including, but not limited to, worldwide
demand for oil and gas, uncertainties relating to the level of activity in
offshore oil and gas exploration and development, exploration success by
producers, oil and gas prices (including U.S. natural gas prices), securities
market conditions, demand for offshore and inland water rigs, competition and
market conditions in the contract drilling industry, our ability to successfully
integrate the operations of acquired businesses, delays or terminations of
drilling contracts due to a number of events, delays or cost overruns on
construction and shipyard projects and possible cancellation of drilling
contracts as a result of delays or performance, our ability to enter into and
the terms of future contracts, the availability of qualified personnel, labor
relations and the outcome of negotiations with unions representing workers,
operating hazards, political and other uncertainties inherent in non-U.S.
operations (including exchange and currency fluctuations), risks of war,
terrorism and cancellation or unavailability of certain insurance coverage, the
impact of governmental laws and regulations, the adequacy of sources of
liquidity, the effect and results of litigation, audits and contingencies and
other factors discussed in this annual report and in the Company's other filings
with the SEC, which are available free of charge on the SEC's website at
www.sec.gov. Should one or more of these risks or uncertainties materialize, or
should underlying assumptions prove incorrect, actual results may vary
materially from those indicated. You should not place undue reliance on
forward-looking statements. Each forward-looking statement speaks only as of the
date of the particular statement, and we undertake no obligation to publicly
update or revise any forward-looking statements.

-47-

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

INTEREST RATE RISK

Our exposure to market risk for changes in interest rates relates primarily
to our long-term and short-term debt obligations. The table below presents
scheduled debt maturities and related weighted-average interest rates for each
of the years ended December 31 relating to debt obligations as of December 31,
2002. Weighted-average variable rates are based on LIBOR rates at December 31,
2002, plus applicable margins.

At December 31, 2002 (in millions, except interest rate percentages):

SCHEDULED MATURITY DATE (a) (b) FAIR VALUE
-------------------------------------------------------------------- ----------
2003 2004 2005 2006 2007 THEREAFTER TOTAL 12/31/02
------- ------- ------- ------- ------- ------------ --------- ---------

Total debt
Fixed Rate . . . . . . . . $911.8 $ 44.7 $ 69.6 $400.0 $100.0 $ 1,050.0 $2,576.1 $ 2,739.3
Average interest rate 4.6% 7.3% 8.8% 1.5% 7.5% 7.6% 5.6%
Variable Rate. . . . . . . $150.2 $150.0 - - - - $ 300.2 $ 300.2
Average interest rate 2.1% 2.1% - - - - 2.1%
Receive Fixed/Pay Variable
Swaps (c) . . . . . . . - - $350.0 - - $ 1,250.0 $1,600.0 $ 1,809.0
Average interest rate - - 4.2% - - 3.1% 3.3%

__________________________
(a) Maturity dates of the face value of our debt assumes the put options on the Zero Coupon Convertible
Debentures, 1.5% Convertible Debentures and 7.45% Notes will be exercised in May 2003, May 2006
and April 2007, respectively.
(b) Expected maturity amounts are based on the face value of debt and do not reflect fair market value of
debt.
(c) The 6.625%, 6.75%, 6.95% and 9.5% Notes are considered variable as a result of the interest rate
swaps. See Notes 8 and 26 to our consolidated financial statements.

At December 31, 2002, we had approximately $1.9 billion of variable rate
debt at face value (42 percent of total debt at face value). Of that variable
rate debt, $1.6 billion resulted from interest rate swaps with the remainder
representing term bank debt. Given outstanding amounts as of that date, a one
percent rise in interest rates would result in an additional $14.5 million in
interest expense per year. Offsetting this, a large part of our cash investments
would earn commensurately higher rates of return. Using December 31, 2002 cash
investment levels, a one percent increase in interest rates would result in
approximately $12.1 million of additional interest income per year. Based on
December 31, 2002 balances, our net variable debt balance at face value, defined
as variable rate debt less swap receivables and cash and cash equivalents,
totaled $504.7 million (16 percent of net total debt at face value). Because we
intend to pay debt with cash on hand, we use net debt and net variable rate debt
to represent debt that is anticipated to be paid with future cash flows. The net
debt and net variable rate debt measure also allows us to measure the cash flow
that has been generated to date to fund our major obligations. We use variable
rate debt to measure effects of changes in interest rates on interest expense
associated with outstanding variable rate debt.

The components of net variable rate debt at face value were as follows (in
millions):

DECEMBER 31,
2002
------------
Total Debt . . . . . . . . . . . $ 4,476.3
Less: Fixed rate debt. . . . . . 2,576.1
Cash and cash equivalents . (1,214.2)
Swap receivables. . . . . . (181.3)

The components of net debt at face value were as follows (in millions):

DECEMBER 31,
2002
-------------
Total Debt . . . . . . . . . . . $ 4,476.3
Less: Cash and cash equivalents (1,214.2)
Swap receivables. . . . . . (181.3)

-48-

As a result of the January 2003 and March 2003 interest rate swap
terminations and payment of variable rate debt of $0.2 million (see "Item 7.
Management's Discussion and Analysis of Financial Condition and Results of
Operations-Liquidity and Capital Resources"), our variable rate debt at face
value decreased to $300.0 million.

FOREIGN EXCHANGE RISK

Our international operations expose us to foreign exchange risk. We use a
variety of techniques to minimize the exposure to foreign exchange risk. Our
primary foreign exchange risk management strategy involves structuring customer
contracts to provide for payment in both U.S. dollars and local currency. The
payment portion denominated in local currency is based on anticipated local
currency requirements over the contract term. Due to various factors, including
local banking laws, other statutory requirements, local currency convertibility
and the impact of inflation on local costs, actual foreign exchange needs may
vary from those anticipated in the customer contracts, resulting in partial
exposure to foreign exchange risk. Fluctuations in foreign currencies have
minimal impact on overall results. In situations where the primary strategy is
not entirely attainable, foreign exchange derivative instruments, specifically
foreign exchange forward contracts or spot purchases, may be used. We do not
enter into derivative transactions for speculative purposes. At December 31,
2002, we had no material open foreign exchange contracts.

Venezuela has recently implemented foreign exchange controls that limit our
ability to convert local currency into U.S. dollars and transfer excess funds
out of Venezuela. Our drilling contracts in Venezuela typically call for
payments to be made in local currency, even when the dayrate is denominated in
U.S. dollars. The exchange controls could also result in an artificially high
value being placed on the local currency.

-49-

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

REPORT OF INDEPENDENT AUDITORS

To the Shareholders and Board of Directors
Transocean Inc.

We have audited the accompanying consolidated balance sheets of Transocean
Inc. and Subsidiaries as of December 31, 2002 and 2001, and the related
consolidated statements of operations, comprehensive income (loss), equity, and
cash flows for each of the three years in the period ended December 31, 2002.
Our audits also included the financial statement schedule listed in the Index at
Item 15. These financial statements and schedule are the responsibility of the
Company's management. Our responsibility is to express an opinion on these
financial statements and schedule based on our audits.

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

In our opinion, the financial statements referred to above present fairly,
in all material respects, the consolidated financial position of Transocean Inc.
and Subsidiaries at December 31, 2002 and 2001, and the consolidated 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. Also, in our opinion, the related financial
statement schedule, when considered in relation to the basic financial
statements taken as a whole, presents fairly in all material respects the
information set forth therein.

As discussed in Note 2 to the consolidated financial statements, the
Company adopted Statement of Financial Accounting Standard 142, Goodwill and
Other Intangible Assets, in 2002.

/s/ Ernst & Young LLP

Houston, Texas
January 27, 2003

-50-

TRANSOCEAN INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(In millions, except per share data)

YEARS ENDED DECEMBER 31,
--------------------------------
2002 2001 2000
---------- --------- ---------

OPERATING REVENUES . . . . . . . . . . . . . . . . . . . . . . . $ 2,673.9 $2,820.1 $1,229.5

COSTS AND EXPENSES
Operating and maintenance . . . . . . . . . . . . . . . . . . 1,494.2 1,603.3 812.6
Depreciation. . . . . . . . . . . . . . . . . . . . . . . . . 500.3 470.1 232.8
Goodwill amortization . . . . . . . . . . . . . . . . . . . . - 154.9 26.7
General and administrative. . . . . . . . . . . . . . . . . . 65.6 57.9 42.1
Impairment loss on long-lived assets. . . . . . . . . . . . . 2,927.4 40.4 -
Gain from sale of assets, net . . . . . . . . . . . . . . . . (3.7) (56.5) (17.8)
---------- --------- ---------
4,983.8 2,270.1 1,096.4
---------- --------- ---------
OPERATING INCOME (LOSS). . . . . . . . . . . . . . . . . . . . . (2,309.9) 550.0 133.1
---------- --------- ---------

OTHER INCOME (EXPENSE), NET
Equity in earnings of joint ventures. . . . . . . . . . . . . 7.8 16.5 9.4
Interest income . . . . . . . . . . . . . . . . . . . . . . . 25.6 18.7 6.2
Interest expense, net of amounts capitalized. . . . . . . . . (212.0) (223.9) (3.0)
Other, net. . . . . . . . . . . . . . . . . . . . . . . . . . (0.3) (0.8) (1.3)
---------- --------- ---------
(178.9) (189.5) 11.3
---------- --------- ---------
INCOME (LOSS) BEFORE INCOME TAXES, MINORITY
INTEREST, EXTRAORDINARY ITEMS AND CUMULATIVE EFFECT
OF A CHANGE IN ACCOUNTING PRINCIPLE . . . . . . . . . . . . . (2,488.8) 360.5 144.4
Income Tax Expense (Benefit) . . . . . . . . . . . . . . . . . . (123.0) 85.7 36.7
Minority Interest. . . . . . . . . . . . . . . . . . . . . . . . 2.4 2.9 0.6
---------- --------- ---------
INCOME (LOSS) BEFORE EXTRAORDINARY ITEMS AND CUMULATIVE
EFFECT OF A CHANGE IN ACCOUNTING PRINCIPLE. . . . . . . . . . (2,368.2) 271.9 107.1
Gain (Loss) on Extraordinary Items, net of tax . . . . . . . . . - (19.3) 1.4
Cumulative Effect of a Change in Accounting Principle. . . . . . (1,363.7) - -
---------- --------- ---------
NET INCOME (LOSS). . . . . . . . . . . . . . . . . . . . . . . . $(3,731.9) $ 252.6 $ 108.5
========== ========= =========

BASIC EARNINGS (LOSS) PER SHARE
Income (Loss) Before Extraordinary Items and
Cumulative Effect of a Change in Accounting Principle. . . . $ (7.42) $ 0.88 $ 0.51
Gain (Loss) on Extraordinary Items, net of tax . . . . . . . . - (0.06) 0.01
Loss on Cumulative Effect of a Change in Accounting
Principle . . . . . . . . . . . . . . . . . . . . . . . . . . (4.27) - -
---------- --------- ---------
Net Income (Loss). . . . . . . . . . . . . . . . . . . . . . $ (11.69) $ 0.82 $ 0.52
========== ========= =========

DILUTED EARNINGS (LOSS) PER SHARE
Income (Loss) Before Extraordinary Items and
Cumulative Effect of a Change in Accounting Principle . . . . $ (7.42) $ 0.86 $ 0.50
Gain (Loss) on Extraordinary Items, net of tax. . . . . . . . . - (0.06) 0.01
Loss on Cumulative Effect of a Change in Accounting
Principle . . . . . . . . . . . . . . . . . . . . . . . . . . (4.27) - -
---------- --------- ---------
Net Income (Loss). . . . . . . . . . . . . . . . . . . . . . $ (11.69) $ 0.80 $ 0.51
========== ========= =========

WEIGHTED AVERAGE SHARES OUTSTANDING
Basic . . . . . . . . . . . . . . . . . . . . . . . . . . . . 319.1 309.2 210.4
---------- --------- ---------
Diluted . . . . . . . . . . . . . . . . . . . . . . . . . . . 319.1 314.8 211.7
---------- --------- ---------

DIVIDENDS PAID PER SHARE . . . . . . . . . . . . . . . . . . . . $ 0.06 $ 0.12 $ 0.12

See accompanying notes.

-51-

TRANSOCEAN INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(In millions)

YEARS ENDED DECEMBER 31,
---------------------------
2002 2001 2000
---------- ------- ------

Net income (loss) . . . . . . . . . . . . . . . . . . . . . .$(3,731.9) $252.6 $108.5
---------- ------- ------
Other comprehensive income (loss), net of tax
Gain on terminated interest rate swaps. . . . . . . . . . . - 4.1 -
Amortization of gain on terminated interest rate swaps. . . (0.3) (0.2) -
Change in unrealized loss on securities available for sale. - (0.6) -
Share of unrealized loss in unconsolidated joint venture's
interest rate swaps . . . . . . . . . . . . . . . . . . . - (5.6) -
Change in share of unrealized loss in unconsolidated joint
venture's interest rate swaps . . . . . . . . . . . . . . 3.6 - -
Minimum pension liability . . . . . . . . . . . . . . . . . (32.5) - -
---------- ------- ------
(29.2) (2.3) -
---------- ------- ------
Total comprehensive income (loss) . . . . . . . . . . . . . .$(3,761.1) $250.3 $108.5
========== ======= ======

See accompanying notes.

-52-

TRANSOCEAN INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(In millions, except share data)

DECEMBER 31,
----------------------
2002 2001
---------- ----------

ASSETS
Cash and Cash Equivalents. . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 1,214.2 $ 853.4
Accounts Receivable
Trade. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 437.6 602.9
Other. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 61.7 72.8
Materials and Supplies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 155.8 158.8
Deferred Income Taxes. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21.9 21.0
Other Current Assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20.5 27.9
---------- ----------
Total Current Assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,911.7 1,736.8
---------- ----------

Property and Equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10,198.0 10,081.4
Less Accumulated Depreciation. . . . . . . . . . . . . . . . . . . . . . . . . . . 2,168.2 1,713.3
---------- ----------
Property and Equipment, net. . . . . . . . . . . . . . . . . . . . . . . . . . . 8,029.8 8,368.1
---------- ----------
Goodwill, net. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,218.2 6,466.7
Investments in and Advances to Joint Ventures. . . . . . . . . . . . . . . . . . . 108.5 107.1
Deferred Income Taxes. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26.2 28.0
Other Assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 370.7 341.1
---------- ----------
Total Assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $12,665.1 $17,047.8
========== ==========

LIABILITIES AND SHAREHOLDERS' EQUITY

Accounts Payable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 134.1 $ 188.4
Accrued Income Taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 59.5 118.3
Debt Due Within One Year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,048.1 484.4
Other Current Liabilities. . . . . . . . . . . . . . . . . . . . . . . . . . . . . 262.2 283.4
---------- ----------
Total Current Liabilities. . . . . . . . . . . . . . . . . . . . . . . . . . . 1,503.9 1,074.5
---------- ----------

Long-Term Debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3,629.9 4,539.4
Deferred Income Taxes. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 107.2 345.1
Other Long-Term Liabilities. . . . . . . . . . . . . . . . . . . . . . . . . . . . 282.7 178.5
---------- ----------
Total Long-Term Liabilities. . . . . . . . . . . . . . . . . . . . . . . . . . 4,019.8 5,063.0
---------- ----------

Commitments and Contingencies

Preference Shares, $0.10 par value; 50,000,000 shares authorized, none issued and
outstanding. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . - -
Ordinary Shares, $0.01 par value; 800,000,000 shares authorized, 319,219,072 and
318,816,035 shares issued and outstanding at December 31, 2002 and 2001,
respectively . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.2 3.2
Additional Paid-in Capital . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10,623.1 10,611.7
Accumulated Other Comprehensive Loss . . . . . . . . . . . . . . . . . . . . . . . (31.5) (2.3)
Retained Earnings (Deficit). . . . . . . . . . . . . . . . . . . . . . . . . . . . (3,453.4) 297.7
---------- ----------
Total Shareholders' Equity . . . . . . . . . . . . . . . . . . . . . . . . . . 7,141.4 10,910.3
---------- ----------
Total Liabilities and Shareholders' Equity . . . . . . . . . . . . . . . . . . $12,665.1 $17,047.8
========== ==========

See accompanying notes.

-53-

TRANSOCEAN INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF EQUITY
(In millions, except per share data)

ACCUMULATED
ORDINARY SHARES ADDITIONAL OTHER RETAINED
---------------- PAID-IN COMPREHENSIVE EARNINGS TOTAL
SHARES AMOUNT CAPITAL INCOME (LOSS) (DEFICIT) EQUITY
------- ------- ---------- -------------- ---------- ----------

Balance at December 31, 1999. . . . . . . 210.1 $ 2.1 $ 3,908.0 $ - $ - $ 3,910.1
Net income. . . . . . . . . . . . . . . - - - - 108.5 108.5
Issuance of ordinary shares under
stock-based compensation plans. . . . 0.6 - 16.6 - - 16.6
Cash dividends ($0.12 per share). . . . - - - - (25.2) (25.2)
Other . . . . . . . . . . . . . . . . . - - (5.9) - - (5.9)
------- ------- ---------- -------------- ---------- ----------

Balance at December 31, 2000. . . . . . . 210.7 2.1 3,918.7 - 83.3 4,004.1
Net income. . . . . . . . . . . . . . . - - - - 252.6 252.6
Shares issued for R&B Falcon
merger. . . . . . . . . . . . . . . . 106.1 1.1 6,654.9 - - 6,656.0
Issuance of ordinary shares under
stock-based compensation plans. . . . 1.6 - 45.2 - - 45.2
Issuance of ordinary shares upon
exercise of warrants. . . . . . . . . 0.6 - 10.6 - - 10.6
Cash dividends ($0.12 per share). . . . - - - - (38.2) (38.2)
Gain on terminated interest rate swaps. - - - 3.9 - 3.9
Fair value adjustment on marketable
securities held for sale. . . . . . . - - - (0.6) - (0.6)
Other comprehensive income
related to joint venture. . . . . . . - - - (5.6) - (5.6)
Other . . . . . . . . . . . . . . . . . (0.2) - (17.7) - - (17.7)
------- ------- ---------- -------------- ---------- ----------

Balance at December 31, 2001. . . . . . . 318.8 3.2 10,611.7 (2.3) 297.7 10,910.3
Net loss. . . . . . . . . . . . . . . . - - - - (3,731.9) (3,731.9)
Issuance of ordinary shares under
stock-based compensation plans. . . . 0.4 - 10.9 - - 10.9
Cash dividends ($0.06 per share). . . . - - - - (19.2) (19.2)
Gain on terminated interest rate swaps. - - - (0.3) (0.3)
Other comprehensive income
related to joint venture. . . . . . . - - - 3.6 - 3.6
Minimum pension liability . . . . . . . - - - (32.5) - (32.5)
Other . . . . . . . . . . . . . . . . . - - 0.5 - - 0.5
------- ------- ---------- -------------- ---------- ----------

Balance at December 31, 2002. . . . . . . 319.2 $ 3.2 $10,623.1 $ (31.5) $(3,453.4) $ 7,141.4
======= ======= ========== ============== ========== ==========

See accompanying notes.

-54-

TRANSOCEAN INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In millions)

YEARS ENDED DECEMBER 31,
-------------------------------
2002 2001 2000
---------- -------- --------

CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $(3,731.9) $ 252.6 $ 108.5
Adjustments to reconcile net income (loss) to net cash provided by
operating activities
Depreciation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 500.3 470.1 232.8
Goodwill amortization. . . . . . . . . . . . . . . . . . . . . . . . . . . . - 154.9 26.7
Impairment loss on goodwill. . . . . . . . . . . . . . . . . . . . . . . . . 4,239.7 - -
Deferred income taxes. . . . . . . . . . . . . . . . . . . . . . . . . . . . (224.4) (98.2) (30.1)
Equity in earnings of joint ventures . . . . . . . . . . . . . . . . . . . . (7.8) (16.5) (9.4)
Net (gain) loss from disposal of assets. . . . . . . . . . . . . . . . . . . 3.9 (52.5) (15.0)
Impairment loss on long-lived assets . . . . . . . . . . . . . . . . . . . . 51.4 40.4 -
Amortization of debt-related discounts/premiums, fair value
adjustments and issue costs, net . . . . . . . . . . . . . . . . . . . . . 6.2 (4.0) 9.4
Deferred income, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . (6.0) (46.5) (20.7)
Deferred expenses, net . . . . . . . . . . . . . . . . . . . . . . . . . . . (20.0) (53.8) (18.6)
Extraordinary (gain) loss on debt extinguishment, net of tax 19.3 (1.4)
Tax benefit from exercise of stock options . . . . . . . . . . . . . . . . . 0.3 9.6 1.9
Other, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.9 (6.8) (7.0)
Changes in operating assets and liabilities, net of effects from the R&B Falcon
merger
Accounts receivable. . . . . . . . . . . . . . . . . . . . . . . . . . . . . 179.4 (55.2) (5.9)
Accounts payable and other current liabilities . . . . . . . . . . . . . . . (78.8) (95.9) (58.6)
Income taxes receivable/payable, net . . . . . . . . . . . . . . . . . . . . 8.9 48.2 1.2
Other current assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11.5 (5.3) (17.9)
---------- -------- --------
Net Cash Provided by Operating Activities. . . . . . . . . . . . . . . . . . . . . 936.6 560.4 195.9
---------- -------- --------

CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (141.0) (506.2) (574.7)
Proceeds from sale of coiled tubing drilling services business . . . . . . . . . - - 24.9
Proceeds from sale of securities . . . . . . . . . . . . . . . . . . . . . . . . - 17.2 -
Proceeds from sale of subsidiary . . . . . . . . . . . . . . . . . . . . . . . . - 85.6 -
Proceeds from disposal of assets, net. . . . . . . . . . . . . . . . . . . . . . 88.3 116.1 56.3
Merger costs paid. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . - (24.4) (4.5)
Cash acquired in merger, net of cash paid. . . . . . . . . . . . . . . . . . . . - 264.7 -
Joint ventures and other investments, net. . . . . . . . . . . . . . . . . . . . 7.4 20.6 5.1
---------- -------- --------
Net Cash Used in Investing Activities. . . . . . . . . . . . . . . . . . . . . . . (45.3) (26.4) (492.9)
---------- -------- --------

See accompanying notes.

-55-

TRANSOCEAN INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS (CONTINUED)
(In millions)

YEARS ENDED DECEMBER 31,
--------------------------------
2002 2001 2000
--------- ---------- --------

CASH FLOWS FROM FINANCING ACTIVITIES
Net borrowings (repayments) under commercial paper program . . . . . . . . . (326.4) 326.4 -
Net proceeds from issuance of debt . . . . . . . . . . . . . . . . . . . . . - 1,693.5 489.1
Net repayments on revolving credit agreements. . . . . . . . . . . . . . . . - (180.1) (54.9)
Repayments on other debt instruments . . . . . . . . . . . . . . . . . . . . (189.3) (1,551.0) (254.9)
Net proceeds from issuance of ordinary shares under stock-based compensation
plans. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.2 29.6 13.7
Proceeds from issuance of ordinary shares upon exercise of warrants. . . . . - 10.6 -
Dividends paid . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (19.1) (38.2) (25.3)
Financing costs. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (8.5) (15.2) (2.6)
Decrease in cash dedicated to debt service . . . . . . . . . . . . . . . . . - 6.4 -
Other, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.6 2.9 0.7
--------- ---------- --------
Net Cash Provided by (Used in) Financing Activities. . . . . . . . . . . . . . (530.5) 284.9 165.8
--------- ---------- --------

Net Increase (Decrease) in Cash and Cash Equivalents . . . . . . . . . . . . . 360.8 818.9 (131.2)
--------- ---------- --------
Cash and Cash Equivalents at Beginning of Period . . . . . . . . . . . . . . . 853.4 34.5 165.7
--------- ---------- --------
Cash and Cash Equivalents at End of Period . . . . . . . . . . . . . . . . . . $1,214.2 $ 853.4 $ 34.5
========= ========== ========

See accompanying notes.

-56-

TRANSOCEAN INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1-NATURE OF BUSINESS AND PRINCIPLES OF CONSOLIDATION

Transocean Inc. (formerly known as "Transocean Sedco Forex Inc.", together
with its subsidiaries and predecessors, unless the context requires otherwise,
the "Company") is a leading international provider of offshore and inland marine
contract drilling services for oil and gas wells. The Company's mobile offshore
drilling fleet is considered one of the most modern and versatile fleets in the
world. The Company specializes in technically demanding segments of the
offshore drilling business with a particular focus on deepwater and harsh
environment drilling services. At December 31, 2002, the Company owned, had
partial ownership interests in or operated 159 mobile offshore and barge
drilling units that it considers to be its core assets. As of this date, the
Company's core assets consisted of 31 high-specification semisubmersibles and
drillships ("floaters"), 29 other floaters, 56 jackup rigs, 35 drilling barges,
five tenders and three submersible drilling rigs. In addition, the fleet
included non-core assets consisting of a mobile offshore production unit, two
platform drilling rigs and a land rig as well as nine land rigs and three lake
barges in Venezuela. The Company contracts its drilling rigs, related equipment
and work crews primarily on a dayrate basis to drill oil and gas wells.

On January 31, 2001, we completed a merger transaction (the "R&B Falcon
merger") with R&B Falcon Corporation ("R&B Falcon", now known as "TODCO"). At
the time of the merger, TODCO owned, had partial ownership interests in,
operated or had under construction more than 100 mobile offshore drilling units
and other units utilized in the support of offshore drilling activities. As a
result of the merger, TODCO became an indirect wholly owned subsidiary of the
Company. The merger was accounted for as a purchase with the Company as the
accounting acquiror. The consolidated balance sheet as of December 31, 2001
represents the financial position of the merged company. The consolidated
statements of operations and of cash flows for the year ended December 31, 2001
include 11 months of operating results and cash flows for TODCO.

Intercompany transactions and accounts have been eliminated. The equity
method of accounting is used for investments in joint ventures where the
Company's ownership is between 20 percent and 50 percent and for investments in
joint ventures owned more than 50 percent where the Company does not have
control of the joint venture. The cost method of accounting is used for
investments in joint ventures where the Company's ownership is less than 20
percent and the Company does not have control of the joint venture.

NOTE 2-SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Accounting Estimates-The preparation of financial statements in conformity
with accounting principles generally accepted in the United States ("U.S.")
requires management to make estimates and assumptions that affect the reported
amounts of assets, liabilities, revenues, expenses and disclosure of contingent
assets and liabilities. On an ongoing basis, the Company evaluates its
estimates, including those related to bad debts, materials and supplies
obsolescence, investments, intangible assets and goodwill, property and
equipment and other long-lived assets, income taxes, financing operations,
workers' insurance, pensions and other post-retirement and employment benefits
and contingent liabilities. The Company bases its estimates on historical
experience and on various other assumptions that are believed to be reasonable
under the circumstances, the results of which form the basis for making
judgments about the carrying values of assets and liabilities that are not
readily apparent from other sources. Actual results could differ from such
estimates.

Segments-The Company's operations have been aggregated into two reportable
business segments: (i) International and U.S. Floater Contract Drilling Services
and (ii) Gulf of Mexico Shallow and Inland Water. The Company provides services
with different types of drilling equipment in several geographic regions. The
location of the Company's operating assets and the allocation of resources to
build or upgrade drilling units is determined by the activities and needs of
customers. See Note 20.

Cash and Cash Equivalents-Cash equivalents are stated at cost plus accrued
interest, which approximates fair value. Cash equivalents are highly liquid debt
instruments with an original maturity of three months or less and may consist of
time deposits with a number of commercial banks with high credit ratings,
Eurodollar time deposits, certificates of deposit and commercial paper. The
Company may also invest excess funds in no-load, open-end, management investment
trusts ("mutual funds"). The mutual funds invest exclusively in high quality
money market instruments. Generally, the maturity date of the Company's
investments is the next business day.

As a result of the Deepwater Nautilus project financing in 1999, the
Company is required to maintain in cash an amount to cover certain principal and
interest payments. Such restricted cash, classified as other assets in the
consolidated balance sheets, was $13.2 million at December 31, 2002 and 2001.

-57-

TRANSOCEAN INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED

Accounts and Notes Receivable-Accounts receivable trade are stated at the
historical carrying amount net of write-offs and allowance for doubtful accounts
receivable. Interest receivable on delinquent accounts receivable is included in
the accounts receivable trade balance and recognized as interest income when
chargeable and collectibility is reasonably assured. Notes receivable, included
in investments in and advances to joint ventures, are carried at the historical
carrying amount net of write-offs and allowance for loan loss. Interest income
on notes receivable, which is included in accounts receivable-other, is accrued
and recognized as interest income monthly on any unimpaired loan balance. The
Company's notes receivable do not have premiums or discounts associated with
their balances. Uncollectible notes and accounts receivable trade are written
off when a settlement is reached for an amount that is less than the outstanding
historical balance.

Allowance for Doubtful Accounts-The Company establishes an allowance for
doubtful accounts receivable on a case-by-case basis when it believes the
required payment of specific amounts owed is unlikely to occur. This allowance
was approximately $21 million and $24 million at December 31, 2002 and 2001,
respectively. An allowance for loan loss is established when events or
circumstances indicate that both the contractual interest and principal for a
note receivable are not fully collectible. A loan is considered delinquent when
principal and/or interest payments have not been made in accordance with the
payment terms of the loan. Collectibility is determined based on estimated
future cash flows discounted at the respective loan's effective interest rate
with the excess of the loan's total contractual interest and principal over the
estimated discounted future cash flows recorded as an allowance for loan loss.
There was no allowance for loan loss at December 31, 2002 and 2001.

Materials and Supplies-Materials and supplies are carried at the lower of
average cost or market less an allowance for obsolescence. Such allowance was
approximately $19 million and $24 million at December 31, 2002 and 2001,
respectively.

Property and Equipment-Property and equipment, consisting primarily of
offshore drilling rigs and related equipment, represented more than 60 percent
of the Company's total assets at December 31, 2002. The carrying values of
these assets are based on estimates, assumptions and judgments relative to
capitalized costs, useful lives and salvage values of the Company's rigs. These
estimates, assumptions and judgments reflect both historical experience and
expectations regarding future industry conditions and operations. Property and
equipment obtained in the R&B Falcon merger (see Note 4) were recorded at fair
value. The Company generally provides for depreciation using the straight-line
method after allowing for salvage values. Expenditures for renewals,
replacements and improvements are capitalized. Maintenance and repairs are
charged to operating expense as incurred. Upon sale or other disposition, the
applicable amounts of asset cost and accumulated depreciation are removed from
the accounts and the net amount, less proceeds from disposal, is charged or
credited to income.

As a result of the R&B Falcon merger, the Company conformed its policies
relating to estimated rig lives and salvage values. Estimated useful lives of
its drilling units now range from 18 to 35 years, reflecting maintenance history
and market demand for these drilling units, buildings and improvements from 10
to 30 years and machinery and equipment from four to 12 years. Depreciation
expense for the year ended December 31, 2001 was reduced by approximately $23
million ($0.07 per diluted share) as a result of conforming these policies.

Assets Held for Sale-Assets are classified as held for sale when the
Company has a plan for disposal of certain assets and those assets meet the held
for sale criteria of the Financial Accounting Standards Board's ("FASB")
Statement of Financial Accounting Standards ("SFAS") 144, Accounting for
Impairment or Disposal of Long-Lived Assets. Prior to the Company's adoption of
SFAS 144 (see "-New Accounting Pronouncements"), certain assets were classified
as held for sale under SFAS 121, Accounting for Impairment of Long-Lived Assets
and for Long-Lived Assets to be Disposed of. Effective with the R&B Falcon
merger, the Company established a plan to sell certain assets that were
considered non-core to the Company's business with the disposition of these
assets expected to complete by December 31, 2002. These assets included certain
drilling rigs, surplus equipment and an office building. At December 31, 2001,
the Company had assets held for sale in the amount of $148.4 million that were
included in other assets of which $105.3 million and $43.1 million related to
the International and U.S. Floater Contract Drilling Services and Gulf of Mexico
Shallow and Inland Water segments, respectively. At December 31, 2002, the
Company had either disposed of these non-core assets or reclassified them to
property and equipment in accordance with SFAS 144.

Goodwill-Prior to the adoption of SFAS 142, Goodwill and Other Intangible
Assets (see "-New Accounting Pronouncements"), the excess of the purchase price
over the estimated fair value of net assets acquired was accounted for as
goodwill and was amortized on a straight-line basis based on a 40-year life. The
amortization period was based on the nature of the offshore drilling industry,
long-lived drilling equipment and the long-standing relationships with core
customers. In accordance with SFAS 142, goodwill is tested at the reporting unit
level, which is defined as an operating segment or a component of an operating
segment that constitutes a business for which financial information is available
and is regularly

-58-

TRANSOCEAN INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED

reviewed by management. Management has determined that the Company's reporting
units are the same as its operating segments for the purpose of allocating
goodwill and the subsequent testing of goodwill for impairment. Goodwill was
allocated to the Company's two reporting units, International and U.S. Floater
Contract Drilling Services and Gulf of Mexico Shallow and Inland Water, at a
ratio of 68 percent and 32 percent, respectively. The allocation was determined
based on the percentage of each reporting unit's assets at fair value to the
total fair value of assets acquired in the R&B Falcon merger. The fair value was
determined from a third party valuation.

During the first quarter of 2002, the Company implemented SFAS 142 and
performed the initial test of impairment of goodwill on its two reporting units.
The test was applied utilizing the estimated fair value of the reporting units
as of January 1, 2002 determined based on a combination of each reporting unit's
discounted cash flows and publicly traded company multiples and acquisition
multiples of comparable businesses. There was no goodwill impairment for the
International and U.S. Floater Contract Drilling Services reporting unit.
However, because of deterioration in market conditions that affected the Gulf of
Mexico Shallow and Inland Water business segment since the completion of the R&B
Falcon merger, a $1,363.7 million ($4.27 per diluted share) impairment of
goodwill was recognized as a cumulative effect of a change in accounting
principle in the first quarter of 2002.

During the fourth quarter of 2002, the Company performed its annual test of
goodwill impairment as of October 1. Due to a general decline in market
conditions, the Company recorded a non-cash impairment charge of $2,876.0
million ($9.01 per diluted share) of which $2,494.1 million and $381.9 million
related to the International and U.S. Floater Contract Drilling Services and
Gulf of Mexico Shallow and Inland Water reporting units, respectively.

The Company's goodwill balance, after giving effect to the goodwill
write-downs, is $2.2 billion as of December 31, 2002. The changes in the
carrying amount of goodwill are as follows (in millions):

BALANCE AT BALANCE AT
JANUARY 1, LOSS ON DECEMBER 31,
2002 IMPAIRMENTS OTHER (a) 2002
----------- ------------- ---------- -------------

International and U.S. Floater Contract Drilling Services $ 4,721.1 $ (2,494.1) $ (8.8) $ 2,218.2
Gulf of Mexico Shallow and Inland Water . . . . . . . . . 1,745.6 (1,745.6) - -
----------- ------------- ---------- -------------
$ 6,466.7 $ (4,239.7) $ (8.8) $ 2,218.2
=========== ============= ========== =============

______________________
(a) Represents favorable settlements during 2002 of pre-acquisition contingencies related to the R&B Falcon
merger ($5.4 million) and the Sedco Forex merger ($3.4 million).

-59-

TRANSOCEAN INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED

Net income (loss) and earnings (loss) per share for the twelve months ended
December 31, 2002, 2001 and 2000 adjusted for goodwill amortization are as
follows (in millions, except per share data):

YEARS ENDED DECEMBER 31,
---------------------------
2002 2001 2000
---------- ------- ------

Reported net income (loss) before extraordinary items and cumulative
effect of a change in accounting principle. . . . . . . . . . . . . $(2,368.2) $271.9 $107.1
Add back: Goodwill amortization . . . . . . . . . . . . . . . . . . . - 154.9 26.7
---------- ------- ------
Adjusted reported net income (loss) before extraordinary items and
cumulative effect of a change in accounting principle . . . . . . . (2,368.2) 426.8 133.8
Gain (loss) on extraordinary items, net of tax. . . . . . . . . . . . - (19.3) 1.4
Cumulative effect of a change in accounting principle . . . . . . . . (1,363.7) - -
---------- ------- ------
Adjusted net income (loss). . . . . . . . . . . . . . . . . . . . . . $(3,731.9) $407.5 $135.2
========== ======= ======

Basic earnings (loss) per share:
Reported net income (loss) before extraordinary items and cumulative
effect of a change in accounting principle. . . . . . . . . . . . . $ (7.42) $ 0.88 $ 0.51
Goodwill amortization . . . . . . . . . . . . . . . . . . . . . . . . - 0.50 0.12
---------- ------- ------
Adjusted reported net income (loss) before extraordinary items and
cumulative effect of a change in accounting principle . . . . . . . (7.42) 1.38 0.63
Gain (loss) on extraordinary items, net of tax. . . . . . . . . . . . - (0.06) 0.01
Cumulative effect of a change in accounting principle . . . . . . . . (4.27) - -
---------- ------- ------
Adjusted net income (loss). . . . . . . . . . . . . . . . . . . . . . $ (11.69) $ 1.32 $ 0.64
========== ======= ======

Diluted earnings (loss) per share:
Reported net income (loss) before extraordinary items and cumulative
effect of a change in accounting principle. . . . . . . . . . . . . $ (7.42) $ 0.86 $ 0.50
Goodwill amortization . . . . . . . . . . . . . . . . . . . . . . . . - 0.49 0.13
---------- ------- ------
Adjusted reported net income (loss) before extraordinary items and
cumulative effect of a change in accounting principle . . . . . . . (7.42) 1.35 0.63
Gain (loss) on extraordinary items, net of tax. . . . . . . . . . . . - (0.06) 0.01
Cumulative effect of a change in accounting principle . . . . . . . . (4.27) - -
---------- ------- ------
Adjusted net income (loss). . . . . . . . . . . . . . . . . . . . . . $ (11.69) $ 1.29 $ 0.64
========== ======= ======

Impairment of Long-Lived Assets-The carrying value of long-lived assets,
principally goodwill and property and equipment, is reviewed for potential
impairment when events or changes in circumstances indicate that the carrying
amount of such assets may not be recoverable. For property and equipment held
for use, the determination of recoverability is made based upon the estimated
undiscounted future net cash flows of the related asset or group of assets being
evaluated. Property and equipment held for sale are recorded at the lower of
net book value or net realizable value. See Note 7. Prior to January 1, 2002,
recoverability of goodwill was determined based upon a comparison of the
Company's net book value to the value indicated by the market price of its
equity securities (see "-Goodwill" and "-New Accounting Pronouncements").

-60-

TRANSOCEAN INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED

Operating Revenues and Expenses-Operating revenues are recognized as
earned, based on contractual daily rates or on a fixed price basis. Although
the Company ceased providing turnkey drilling services in 2001, turnkey profits
were recognized on completion of the well and acceptance by the customer.
Events occurring after the date of the financial statements and before the
financial statements are issued that are within the normal exposure and risk
aspects of the turnkey contracts are considered refinements of the estimation
process of the prior year and are recorded as adjustments at the date of the
financial statements. Provisions for losses are made on contracts in progress
when losses are anticipated. In connection with drilling contracts, the Company
may receive revenues for preparation and mobilization of equipment and personnel
or for capital improvements to rigs. In connection with contracted
mobilizations, revenues earned and related costs incurred are deferred and
recognized over the primary contract term of the drilling project. Costs of
relocating drilling units without contracts to more promising market areas are
expensed as incurred. Upon completion of drilling contracts, any demobilization
fees received are reflected in income, as are any related expenses. Capital
upgrade revenues received are deferred and recognized over the primary contract
term of the drilling project. The actual cost incurred for the capital upgrade
is depreciated over the estimated useful life of the asset. The Company incurs
periodic survey and drydock costs in connection with obtaining regulatory
certification to operate its rigs on an ongoing basis. Costs associated with
these certifications are deferred and amortized over the period until the next
survey.

Capitalized Interest-Interest costs for the construction and upgrade of
qualifying assets are capitalized. The Company incurred total interest expense
of $212.0 million, $258.8 million and $89.6 million for the years ended December
31, 2002, 2001 and 2000, respectively. The Company capitalized interest costs on
construction work in progress of $34.9 million and $86.6 million for the years
ended December 31, 2001 and 2000, respectively. No interest cost was
capitalized during the year ended December 31, 2002.

Derivative Instruments and Hedging Activities-The Company adopted SFAS 133,
Accounting for Derivative Instruments and Hedging Activities as of January 1,
2001. Because of the Company's limited use of derivatives to manage its exposure
to fluctuations in foreign currency exchange rates and interest rates, the
adoption of the new statement had no effect on the Company's results of
operations or consolidated financial position. See Note 9.

Foreign Currency Translation-The Company accounts for translation of
foreign currency in accordance with SFAS 52, Foreign Currency Translation. The
majority of the Company's revenues and expenditures are denominated in U.S.
dollars to limit the Company's exposure to foreign currency fluctuations,
resulting in the use of the U.S. dollar as the functional currency for all of
the Company's operations. Foreign currency exchange gains and losses are
included in other income (expense) as incurred. Net foreign currency gains
(losses) were $(0.5) million, $1.1 million, and $(1.4) million for the years
ended December 31, 2002, 2001 and 2000, respectively.

Income Taxes-Income taxes have been provided based upon the tax laws and
rates in the countries in which operations are conducted and income is earned.
The income tax rates imposed by these taxing authorities vary substantially.
Taxable income may differ from pre-tax income for financial accounting purposes.
There is no expected relationship between the provision for income taxes and
income before income taxes because the countries have different taxation
regimes, which vary not only with respect to nominal rate but also in terms of
the availability of deductions, credits and other benefits. Variations also
arise because income earned and taxed in any particular country or countries may
fluctuate from period to period. Deferred tax assets and liabilities are
recognized for the anticipated future tax effects of temporary differences
between the financial statement basis and the tax basis of the Company's assets
and liabilities using the applicable tax rates in effect at year end. A
valuation allowance for deferred tax assets is recorded when it is more likely
than not that, some or all of the benefit from the deferred tax asset will not
be realized. See Note 15.

Stock-Based Compensation-In accordance with the provisions of SFAS 123,
Accounting for Stock-Based Compensation, the Company had elected to follow the
Accounting Principles Board Opinion ("APB") 25, Accounting for Stock Issued to
Employees, and related interpretations in accounting for its employee
stock-based compensation plans through December 31, 2002 (see "-New Accounting
Pronouncements"). Under the intrinsic value method of APB 25, if the exercise
price of employee stock options equals or exceeds the fair value of the
underlying stock on the date of grant, no compensation expense is recognized. If
an employee stock option is modified subsequent to the original grant date, and
the exercise price is less than the fair value of the underlying stock on the
date of the modification, compensation expense equal to the excess of the fair
value over the exercise price is recognized over the remaining vesting period.
Compensation expense for grants of restricted shares to employees is calculated
based on the fair value of the shares on the date of grant and is recognized
over the vesting period. Stock appreciation rights are considered variable
grants and are recorded at fair value, with the change in the recorded fair
value recognized as compensation expense. The Company did not record
compensation expense related to its employee Stock Purchase Plan. See Note 17.

-61-

TRANSOCEAN INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED

If compensation expense for grants to employees under the Incentive Plan
and the Stock Purchase Plan for the years ended December 31, 2002, 2001 and
2000, were recognized using the fair value method of accounting under SFAS 123
rather than the intrinsic value method under APB 25, net income (loss) and
earnings (loss) per share would have been reduced to the pro forma amounts
indicated below (in millions, except per share data):

YEARS ENDED DECEMBER 31,
----------------------------
2002 2001 2000
---------- ------- -------

Net Income (Loss) as Reported. . . . . . . . . . . . . . . . . . . . . $(3,731.9) $252.6 $108.5
Add back: Stock-based compensation expense included in reported
net income, net of related tax effects . . . . . . . . . . . . . . 2.8 0.1 1.1
Deduct: Total stock-based compensation expense determined under
fair value based method for all awards, net of related tax effects
Incentive Plan . . . . . . . . . . . . . . . . . . . . . . . . . (23.5) (11.2) (6.4)
Employee Stock Purchase Plan . . . . . . . . . . . . . . . . . . (2.2) (1.7) (1.7)
---------- ------- -------
Pro Forma net income (loss). . . . . . . . . . . . . . . . . . . . . $(3,754.8) $239.8 $101.5
========== ======= =======
Basic Earnings (Loss) Per Share
As Reported. . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ (11.69) $ 0.82 $ 0.52
Pro Forma. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (11.77) 0.78 0.48

Diluted Earnings (Loss) Per Share
As Reported. . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ (11.69) $ 0.80 $ 0.51
Pro Forma. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (11.77) 0.76 0.48

The above pro forma amounts are not indicative of future pro forma results.
The fair value of each option grant under the Incentive Plan was estimated on
the date of grant using the Black-Scholes option pricing model with the
following weighted-average assumptions used:

YEARS ENDED DECEMBER 31,
-------------------------------------
2002 2001 2000
----------- ----------- -----------

Dividend yield . . . . . . . . . . . . . . . . 0.00% 0.30% 0.25%
Expected price volatility range. . . . . . . . 49-51% 50-51% 46-47%
Risk-free interest rate range. . . . . . . . . 2.79-4.11% 4.13-5.25% 6.13-6.56%
Expected life of options (in years). . . . . . 3.84 4.00 4.00
Weighted-average fair value of options granted $ 12.25 $ 16.26 $ 15.21

The fair value of each option grant under the Stock Purchase Plan was
estimated using the following weighted-average assumptions:

YEARS ENDED DECEMBER 31,
----------------------------------------------------------------
2002 2001 2000
-------------------- -------------------- --------------------

Dividend yield . . . . . . . . . . . . . . . . 0.00% 0.30% 0.25%
Expected price volatility. . . . . . . . . . . 45% 51% 50%
Risk-free interest rate. . . . . . . . . . . . 2.14% 1.71% 5.64%
Expected life of options . . . . . . . . . . . Less than one year Less than one year Less than one year
Weighted-average fair value of options granted $ 4.76 $ 7.22 $ 7.67

-62-

TRANSOCEAN INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED

New Accounting Pronouncements-In July 2001, the FASB issued SFAS 142,
Goodwill and Other Intangible Assets, which is effective for fiscal years
beginning after December 12, 2001. Under SFAS 142, goodwill and intangible
assets with indefinite lives are no longer amortized but are reviewed at least
annually for impairment. The amortization provisions of SFAS 142 apply to
goodwill and intangible assets acquired after June 30, 2001. With respect to
goodwill and intangible assets acquired prior to July 1, 2001, the Company
adopted SFAS 142 effective January 1, 2002 and selected October 1 as its annual
test date for impairment of goodwill. In conjunction with the adoption of this
statement, the Company has discontinued the amortization of goodwill.
Application of the non-amortization provisions of SFAS 142 for goodwill resulted
in an increase in operating income of approximately $155 million ($0.49 per
diluted share) in 2002. During 2002, we recognized non-cash impairment charges
of $4.2 billion ($13.29 per diluted share) as a result of the adoption and
application of this statement. See "-Goodwill".

In August 2001, the FASB issued SFAS 144, Accounting for Impairment or
Disposal of Long-Lived Assets. SFAS 144 supersedes SFAS 121, Accounting for
Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed of, and
the accounting and reporting provisions of APB 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. SFAS
144 retains the accounting and reporting provisions of SFAS 121 for recognition
and measurement of long-lived asset impairment and for the measurement of
long-lived assets to be disposed of by sale and the accounting and reporting
provisions of APB 30. In addition to these fundamental provisions, SFAS 144
provides guidance for determining whether long-lived assets should be tested for
impairment and specific criteria for classifying assets to be disposed of as
held for sale. The statement is effective for fiscal years beginning after
December 15, 2001. The Company adopted the statement as of January 1, 2002. The
adoption of this statement had no material effect on the Company's consolidated
financial position or results of operations. See Note 7.

In April 2002, the FASB issued SFAS 145, Rescission of FASB Statements No.
4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections.
This statement eliminates the requirement under SFAS 4 to aggregate and classify
all gains and losses from extinguishment of debt as an extraordinary item, net
of related income tax effect. This statement also amends SFAS 13 to require
certain lease modifications with economic effects similar to sale-leaseback
transactions be accounted for in the same manner as sale-leaseback transactions.
In addition, SFAS 145 requires reclassification of gains and losses in all prior
periods presented in comparative financial statements related to debt
extinguishment that do not meet the criteria for extraordinary item in APB 30.
The statement is effective for fiscal years beginning after May 15, 2002 with
early adoption encouraged. The Company will adopt SFAS 145 effective January 1,
2003. Management does not expect adoption of this statement to have a material
effect on the Company's consolidated financial position or results of
operations.

In July 2002, the FASB issued SFAS 146, Obligations Associated with
Disposal Activities, which is effective for disposal activities initiated after
December 15, 2002, with early application encouraged. SFAS 146 addresses
financial accounting and reporting for costs associated with exit or disposal
activities and nullifies Emerging Issues Task Force Issue No. 94-3, Liability
Recognition for Certain Employee Termination Benefits and Other Costs to Exit an
Activity (including Certain Costs Incurred in a Restructuring). Under this
statement, a liability for a cost associated with an exit or disposal activity
would be measured and recognized at its fair value when it is incurred rather
than at the date of commitment to an exit plan. Also, severance pay would be
recognized over time rather than up front provided the benefit arrangement
requires employees to render future service beyond a minimum retention period,
which would be based on the legal notification period, or if there is no such
requirement, 60 days, thereby allowing a liability to be recorded over the
employees' future service period. The Company will adopt SFAS 146 effective
with disposal activities initiated after December 15, 2002. Management does not
expect adoption of this statement to have a material effect on the Company's
consolidated financial position or results of operations.

In December 2002, the FASB issued SFAS 148, Accounting for Stock-Based
Compensation - Transition and Disclosure, which is effective for fiscal years
ending after December 15, 2002. SFAS 148 amends SFAS 123 to permit two
additional transition methods for a voluntary change to the fair value based
method of accounting for stock-based employee compensation from the intrinsic
method under APB 25. The prospective method of transition under SFAS 123 is an
option for entities adopting the recognition provisions of SFAS 123 in a fiscal
year beginning before December 15, 2003. In addition, SFAS 148 amends the
disclosure requirements of SFAS 123 to require prominent disclosures in both
annual and interim financial statements concerning the method of accounting used
for stock-based employee compensation and the effects of that method on reported
results of operations. Under SFAS 148, pro forma disclosures are required in a
specific tabular format in the "Summary of Significant Accounting Policies". The
Company adopted the disclosure requirements of this statement as of December 31,
2002. The adoption had no effect on the Company's consolidated financial
position or results of operations. The Company adopted the fair value method of
accounting for stock-based compensation using the prospective method of
transition

-63-

TRANSOCEAN INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED

under SFAS 123 effective January 1, 2003. Management expects compensation
expense in 2003 will increase approximately $6 million as a result of adoption.
See "-Stock-Based Compensation".

In December 2002, the FASB issued Interpretation ("FIN") 45, Guarantor's
Accounting and Disclosure Requirements for Guarantees, Including Indirect
Guarantees of Indebtedness of Others. FIN 45 requires that at the time a company
issues a guarantee, the company must recognize an initial liability for the fair
value, or market value, of the obligations it assumes under that guarantee.
This interpretation is applicable on a prospective basis to guarantees issued or
modified after December 31, 2002. The Company does not anticipate adoption of
this interpretation will have a significant impact on its consolidated financial
position and results of operations.

In January 2003, the FASB issued FIN 46, Consolidation of Variable Interest
Entities. FIN 46 requires companies with a variable interest in a variable
interest entity to apply this guidance to that entity as of the beginning of the
first interim period beginning after June 15, 2003 for existing interests and
immediately for new interests. The application of the guidance could result in
the consolidation of a variable interest entity. The Company is evaluating the
impact of this interpretation on its consolidated financial position and results
of operations.

Reclassifications-Certain reclassifications have been made to prior period
amounts to conform with the current year presentation.

NOTE 3-ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

The components of accumulated other comprehensive income (loss) at December
31, 2002 and 2001 are as follows (in millions):

GAIN ON UNREALIZED OTHER TOTAL
TERMINATED GAINS COMPREHENSIVE OTHER
INTEREST ON AVAILABLE- LOSS RELATED TO MINIMUM COMPREHENSIVE
RATE FOR-SALE UNCONSOLIDATED PENSION INCOME
SWAPS SECURITIES JOINT VENTURE LIABILITY (LOSS)
------------ --------------- ----------------- ----------- ---------------

Balance at December 31, 2000. . . . $ - $ - $ - $ - $ -
Other comprehensive income (loss) 3.9 (0.6) (5.6) - (2.3)
------------ --------------- ----------------- ----------- ---------------
Balance at December 31, 2001. . . . 3.9 (0.6) (5.6) - (2.3)
Other comprehensive income (loss) (0.3) - 3.6 (32.5) (29.2)
------------ --------------- ----------------- ----------- ---------------
Balance at December 31, 2002. . . . $ 3.6 $ (0.6) $ (2.0) $ (32.5) $ (31.5)
============ =============== ================= =========== ===============

Deepwater Drilling L.L.C. ("DD LLC"), an unconsolidated subsidiary in which
the Company has a 50% ownership interest, has entered into interest rate swaps
with aggregate market values netting to a $6.7 million liability at December 31,
2002. The Company's interest in these swaps is recorded as other comprehensive
loss related to unconsolidated joint venture.

NOTE 4-BUSINESS COMBINATION

On January 31, 2001, the Company completed a merger transaction with R&B
Falcon, now known as "TODCO", in which an indirect wholly owned subsidiary of
the Company merged with and into R&B Falcon. As a result of the merger, R&B
Falcon common shareholders received 0.5 newly issued ordinary shares of the
Company for each R&B Falcon share. The Company issued approximately 106 million
ordinary shares in exchange for the issued and outstanding shares of R&B Falcon
and assumed warrants and options exercisable for approximately 13 million
ordinary shares. The ordinary shares issued in exchange for the issued and
outstanding shares of R&B Falcon constituted approximately 33 percent of the
Company's outstanding ordinary shares after the merger.

The Company accounted for the merger using the purchase method of
accounting with the Company treated as the accounting acquiror. The purchase
price of $6.7 billion was comprised of the calculated market capitalization of
the Company's ordinary shares issued at the time of merger with R&B Falcon of
$6.1 billion and the estimated fair value of R&B Falcon stock options and
warrants at the time of the merger of $0.6 billion. The market capitalization of
the Company's ordinary shares issued was calculated using the average closing
price of the Company's ordinary shares for a period immediately before and after
August 21, 2000, the date the merger was announced.

-64-

TRANSOCEAN INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED

The purchase price included, at estimated fair value at January 31, 2001,
current assets of $672 million, drilling and other property and equipment of
$4,010 million, other assets of $160 million and the assumption of current
liabilities of $338 million, other net long-term liabilities of $242 million and
long-term debt of $3,206 million. The excess of the purchase price over the
estimated fair value of net assets acquired was $5,630 million, which was
accounted for as goodwill and is reviewed for impairment annually in accordance
with SFAS 142. See Note 2.

In conjunction with the R&B Falcon merger, the Company established a
liability of $16.5 million for the estimated severance-related costs associated
with the involuntary termination of 569 R&B Falcon employees pursuant to
management's plan to consolidate operations and administrative functions
post-merger. Included in the 569 planned involuntary terminations were 387
employees engaged in the Company's land drilling business in Venezuela. The
Company has suspended active marketing efforts to divest this business and, as a
result, the estimated liability was reduced by $4.3 million in the third quarter
of 2001 with an offset to goodwill. Through December 31, 2002, all required
severance-related costs were paid to 182 employees whose positions were
eliminated as a result of this plan.

Unaudited pro forma combined operating results of the Company and TODCO
assuming the R&B Falcon merger was completed as of January 1, 2001 and 2000,
respectively, are as follows (in millions, except per share data):

YEARS ENDED
DECEMBER 31,
--------------------
2001 2000
-------- ---------

Operating revenues . . . . . . . . . . . $2,946.0 $2,292.4
Operating income . . . . . . . . . . . . 553.9 124.2
Income (Loss) from continuing operations 260.2 (292.9)
Earnings (Loss) per share:
Basic. . . . . . . . . . . . . . . . . $ 0.82 $ (0.93)
Diluted. . . . . . . . . . . . . . . . $ 0.80 $ (0.93)

The pro forma information includes adjustments for additional depreciation
based on the fair market value of the drilling and other property and equipment
acquired, amortization of goodwill arising from the transaction, increased
interest expense for debt assumed in the merger and related adjustments for
income taxes. The pro forma information is not necessarily indicative of the
results of operations had the transaction been effected on the assumed dates or
the results of operations for any future periods.

NOTE 5-CAPITAL EXPENDITURES

Capital expenditures totaled $141.0 million during the year ended December
31, 2002 and related to the Company's existing fleet and corporate
infrastructure. A substantial majority of our capital expenditures in 2002
related to the International and U.S. Floater Contract Drilling Services
segment.

Capital expenditures, including capitalized interest, totaled $506 million
during the year ended December 31, 2001 and included $175 million, $42 million,
$41 million and $24 million spent on the construction of the Deepwater Horizon,
Sedco Energy, Sedco Express and Cajun Express, respectively. A substantial
majority of the capital expenditures is related to the International and U.S.
Floater Contract Drilling Services segment. The Company's construction program
was completed as of December 31, 2001.

NOTE 6-ASSET DISPOSITIONS

In June 2002, in the International and U.S. Floater Contract Drilling
Services segment, the Company sold a jackup rig, the RBF 209, and recognized a
net after-tax loss of $1.5 million. In March 2002, in the International and U.S.
Floater Contract Drilling Services segment, the Company sold two semisubmersible
rigs, the Transocean 96 and Transocean 97, for net proceeds of $30.7 million and
recognized net after-tax gains of $1.3 million.

During the year ended December 31, 2002, the Company also settled an
insurance claim and sold certain other assets acquired in the R&B Falcon merger
and certain other assets held for sale for net proceeds of approximately $38.9
million and recorded net after-tax gains of $2.7 million ($0.01 per diluted
share) and $0.6 million in the Company's International and U.S. Floater Contract
Drilling Services and Gulf of Mexico Shallow and Inland Water segments,
respectively.

-65-

TRANSOCEAN INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED

In December 2001, in the International and U.S. Floater Contract Drilling
Services segment, the Company sold RBF FPSO L.P., which owned the Seillean, a
multi-purpose service vessel. The Company received net proceeds from the sale
of $85.6 million and recorded a net after-tax gain of $17.1 million ($0.05 per
diluted share) for the year ended December 31, 2001.

In February 2001, in the International and U.S. Floater Contract Drilling
Services segment, Sea Wolf Drilling Limited ("Sea Wolf"), a joint venture in
which the Company holds a 25 percent interest, sold two semisubmersible rigs,
the Drill Star and Sedco Explorer, to Pride International, Inc. In the first
quarter of 2001, the Company recognized accelerated amortization of the deferred
gain related to the Sedco Explorer of $18.5 million ($0.06 per diluted share),
which was included in gain from sale of assets. The Company's bareboat charter
with Sea Wolf on the Sedco Explorer was terminated effective June 2000. The
Company continued to operate the Drill Star, which was renamed the Pride North
Atlantic, under a bareboat charter agreement until October 2001, at which time
the rig was returned to its owner. The amortization of the Drill Star's
deferred gain was accelerated and produced incremental gains in 2001 of $36.3
million ($0.12 per diluted share), which was included as a reduction in
operating and maintenance expense.

During the year ended December 31, 2001, the Company sold certain other
assets acquired in the R&B Falcon merger and certain other assets held for sale.
The Company received net proceeds of approximately $116.1 million, and recorded
net after-tax gains of $5.1 million ($0.02 per diluted share) and $3.8 million
($0.01 million per diluted share) in its International and U.S. Floater Contract
Drilling Services and Gulf of Mexico Shallow and Inland Water segments,
respectively.

In July 2000, the Company sold a semisubmersible rig, the Transocean
Discoverer. Net proceeds from the sale of the rig totaled $42.7 million and
recognized a net after-tax gain of $9.4 million, or $0.04 per diluted share.

In February 2000, the Company sold its coiled tubing drilling services
business to Schlumberger Limited ("Schlumberger"). The net proceeds from the
sale were $24.9 million and no gain or loss was recognized on the sale. The
Company's interests in its Transocean-Nabors Drilling Technology LLC and
DeepVision LLC joint ventures were excluded from the sale.

NOTE 7-IMPAIRMENT LOSS ON LONG-LIVED ASSETS

In 2002, the Company recorded non-cash impairment charges of $28.5 million
($0.09 per diluted share) and $16.3 million ($0.05 per diluted share) in its
International and U.S. Floater Contract Drilling Services and Gulf of Mexico
Shallow and Inland Water segments, respectively, relating to the
reclassification of assets held for sale to assets held and used. The impairment
of these assets resulted from management's assessment that they no longer met
the held for sale criteria under SFAS 144. In accordance with SFAS 144, the
carrying value of these assets was adjusted to the lower of fair market value or
carrying value adjusted for depreciation from the date the assets were
classified as held for sale. The fair market values of these assets were based
on third party valuations.

During the fourth quarter of 2002, the Company performed its annual test of
goodwill impairment as of October 1, 2002. As a result of that test and a
general decline in market conditions, the Company recorded non-cash impairments
of $2,494.1 million ($7.82 per diluted share) and $381.9 million ($1.20 per
diluted share) in its International and U.S. Floater Contract Drilling Services
and Gulf of Mexico Shallow and Inland Water segments, respectively. See Note 2.

In 2002, the Company recorded non-cash impairment charges in its
International and U.S. Contract Drilling Services and Gulf of Mexico Shallow and
Inland Water segments of $5.5 million ($0.02 per diluted share) and $1.1 million
relating to assets held for sale, which resulted from deterioration in market
conditions. The impairments were determined and measured based on an estimate of
fair value derived from offers from potential buyers.

During the fourth quarter 2001, the Company recorded noncash impairment
charges in its International and U.S. Floater Contract Drilling Services and
Gulf of Mexico Shallow and Inland Water segments of $39.4 million ($0.13 per
diluted share) and $1.0 million, respectively. In the International and U.S.
Floater Contract Drilling Services segment, the impairment related to assets
held for sale and certain non-core assets held and used of $27.6 million and
$11.8 million, respectively. In the Gulf of Mexico Shallow and Inland Water
segment, the impairment related to certain non-core assets held and used of $1.0
million. The impairments resulted from deterioration in market conditions. The
methodology used in determining the fair market value included third-party
appraisals and industry experience for non-core assets held and used and offers
from potential buyers for assets held for sale.

-66-

TRANSOCEAN INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED

NOTE 8-DEBT

Debt, net of unamortized discounts, premiums and fair value adjustments, is
comprised of the following (in millions):

DECEMBER 31,
------------------
2002 2001
-------- --------

Commercial Paper. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ - $ 326.4
6.5% Senior Notes, due April 2003 . . . . . . . . . . . . . . . . . . . . . . 239.7 240.5
9.125% Senior Notes, due December 2003. . . . . . . . . . . . . . . . . . . . 89.5 92.0
Amortizing Term Loan Agreement - Final Maturity December 2004. . . . . . . . 300.0 400.0
6.75% Senior Notes, due April 2005 (a). . . . . . . . . . . . . . . . . . . . 371.8 354.6
7.31% Nautilus Class A1 Amortizing Notes - Final Maturity May 2005. . . . . . 104.7 142.9
9.41% Nautilus Class A2 Notes, due May 2005 . . . . . . . . . . . . . . . . . 51.7 52.4
Secured Rig Financing . . . . . . . . . . . . . . . . . . . . . . . . . . . . - 50.6
6.95% Senior Notes, due April 2008 (a). . . . . . . . . . . . . . . . . . . . 277.2 252.3
9.5% Senior Notes, due December 2008 (a). . . . . . . . . . . . . . . . . . . 371.8 348.1
6.625% Notes, due April 2011 (a). . . . . . . . . . . . . . . . . . . . . . . 803.7 711.7
7.375% Senior Notes, due April 2018 . . . . . . . . . . . . . . . . . . . . . 250.5 250.5
Zero Coupon Convertible Debentures, due May 2020 (put options exercisable
May 2003, May 2008 and May 2013) (b) . . . . . . . . . . . . . . . . . . . . 527.2 512.2
1.5% Convertible Debentures, due May 2021 (put options exercisable May 2006,
May 2011 and May 2016) . . . . . . . . . . . . . . . . . . . . . . . . . . . 400.0 400.0
8% Debentures, due April 2027 . . . . . . . . . . . . . . . . . . . . . . . . 198.0 197.9
7.45% Notes, due April 2027 (put options exercisable April 2007). . . . . . . 94.6 94.4
7.5% Notes, due April 2031. . . . . . . . . . . . . . . . . . . . . . . . . . 597.4 597.3
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0.2 -
-------- --------
Total Debt. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4,678.0 5,023.8
Less Debt Due Within One Year (b) . . . . . . . . . . . . . . . . . . . . . . 1,048.1 484.4
-------- --------
Total Long-Term Debt. . . . . . . . . . . . . . . . . . . . . . . . . . . . . $3,629.9 $4,539.4
======== ========

(a) At December 31, 2002, the Company was a party to interest rate swap
agreements with respect to these debt instruments. See Notes 10 and 26.
(b) The Zero Coupon Convertible Debentures are classified as debt due within
one year since the put option can be exercised in May 2003.

The scheduled maturity of the face value of the Company's debt assumes the
bondholders exercise their options to require the Company to repurchase the Zero
Coupon Convertible Debentures, 1.5% Convertible Debentures and 7.45% Notes in
May 2003, May 2006 and April 2007, respectively, and is as follows (in
millions):

YEARS ENDING
DECEMBER 31,
-------------

2003 . . . $ 1,062.0
2004 . . . 194.7
2005 . . . 419.6
2006 . . . 400.0
2007 . . . 100.0
Thereafter 2,300.0
-------------
Total. . . $ 4,476.3
=============

Commercial Paper Program-The Company has two revolving credit agreements,
described below, which provide liquidity for commercial paper borrowings. At
December 31, 2002, no amounts were outstanding under the Commercial Paper
Program.

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TRANSOCEAN INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED

Revolving Credit Agreements-The Company is a party to two revolving credit
agreements (together the "Revolving Credit Agreements"), a $550.0 million
five-year revolving credit agreement (the "Five-Year Revolver") dated December
29, 2000 and a $250.0 million 364-day revolving credit agreement (the "364-Day
Revolver") dated December 26, 2002. The Revolving Credit Agreements bear
interest, at the Company's option, at a base rate or London Interbank Offered
Rate ("LIBOR") plus a margin that can vary from 0.180 percent to 0.700 percent
under the Five-Year Revolver and from 0.190 percent to 0.725 percent under the
364-Day Revolver depending on the Company's non-credit enhanced senior unsecured
public debt rating. At December 31, 2002, the Five-Year Revolver and the
364-Day Revolver margins were 0.45 percent and 0.475 percent, respectively.
Facility fees varying from 0.070 percent to 0.200 percent under the Five-Year
Revolver and from 0.060 percent to 0.175 percent under the 364-Day Revolver,
depending on the Company's non-credit enhanced senior unsecured public debt
rating, are incurred on the daily amount of the underlying commitment, whether
used or unused, throughout the term of the facility. At December 31, 2002, the
facility fees on the Five-Year Revolver and 364-Day Revolver were 0.125 percent
and 0.100 percent, respectively. A utilization fee varying from 0.075 percent
to 0.150 percent, depending on the Company's non-credit enhanced senior
unsecured public debt rating, is payable if amounts outstanding under the
Five-Year Revolver or the 364-Day Revolver are greater than $181.5 million or
$82.5 million, respectively. The Revolving Credit Agreements contain covenants
similar to those contained in the Term Loan Agreement described below. There
were no amounts outstanding under the Revolving Credit Agreements at December
31, 2002.

Term Loan Agreement-The Company is a party to a $400.0 million amortizing
unsecured five-year term loan agreement dated as of December 16, 1999. Amounts
outstanding under the Term Loan Agreement bear interest, at the Company's
option, at a base rate or LIBOR plus a margin that can vary from 0.350 percent
to 1.475 percent depending on the Company's senior unsecured public debt rating.
At December 31, 2002, the margin was 0.70 percent per annum. The debt began to
amortize in March 2002, at a rate of $25.0 million per quarter in 2002. In 2003
and 2004, the debt amortizes at a rate of $37.5 million per quarter. As of
December 31, 2002, $300.0 million was outstanding under this agreement.

The Term Loan Agreement and the Revolving Credit Agreements require
compliance with various covenants and provisions customary for agreements of
this nature, including an interest coverage ratio, as defined by the credit
agreement, of not less than three to one, a debt to total capital ratio, as
defined by the credit agreement, of not greater than 40 percent, and limitations
on creating liens, incurring debt, transactions with affiliates, sale/leaseback
transactions and mergers and sale of substantially all assets. In calculating
the debt to total capital ratio, the credit agreements specifically exclude the
impact on total capital of all non-cash goodwill impairment charges recorded in
compliance with SFAS 142 (see Note 2).

6.5%, 6.75%, 6.95%, 7.375%, 9.125% and 9.5% Senior Notes and Exchange
Offer-In April 1998, TODCO issued 6.5%, 6.75%, 6.95% and 7.375% Senior Notes
with an aggregate principal amount of $1.1 billion. In December 1998, TODCO
issued 9.125% Senior Notes and 9.5% Senior Notes with an aggregate principal
amount of $400.0 million. Each of these notes was recorded at fair value on
January 31, 2001 as part of the R&B Falcon merger. The 6.75%, 6.95%, 7.375%,
9.125% and 9.5% Senior Notes are redeemable at the Company's option at a
make-whole premium. The 6.5% Senior Notes are not redeemable at the Company's
option.

In March 2002, the Company completed exchange offers and consent
solicitations for TODCO's 6.5%, 6.75%, 6.95%, 7.375%, 9.125% and 9.5% Senior
Notes (the "Exchange Offer"). As a result of the Exchange Offer, approximately
$234.5 million, $342.3 million, $247.8 million, $246.5 million, $76.9 million,
and $289.8 million principal amount of TODCO's outstanding 6.5%, 6.75%, 6.95%,
7.375%, 9.125% and 9.5% Senior Notes, respectively, were exchanged for the
Company's newly issued 6.5%, 6.75%, 6.95%, 7.375%, 9.125% and 9.5% Senior Notes
having the same principal amount, interest rate, redemption terms and payment
and maturity dates (and accruing interest from the last date for which interest
had been paid on the TODCO notes). Because the holders of a majority in
principal amount of each of these series of notes consented to the proposed
amendments to the applicable indenture pursuant to which the notes were issued,
some covenants, restrictions and events of default were eliminated from the
indentures with respect to these series of notes. After the Exchange Offer,
approximately $5.0 million, $7.7 million, $2.2 million, $3.5 million, $10.2
million and $10.2 million principal amount of the outstanding 6.5%, 6.75%,
6.95%, 7.375%, 9.125% and 9.5% Senior Notes, respectively, not exchanged remain
the obligation of TODCO. These notes are combined with the notes of the
corresponding series issued by the Company in the above table. In connection
with the Exchange Offer, TODCO paid $8.3 million in consent payments to holders
of TODCO's notes whose notes were exchanged. The consent payments are being
amortized as an increase to interest expense over the remaining term of the
respective notes. As a result of the amortization of the consent payments,
interest expense for 2002 increased by $1.3 million.

At December 31, 2002, approximately $239.5 million, $350.0 million, $250.0
million, $250.0 million, $87.1 million and $300.0 million principal amount of
both the Company's and TODCO's 6.5%, 6.75%, 6.95%, 7.375%, 9.125% and 9.5%
Senior Notes, respectively, were outstanding. The fair value of these Senior
Notes at December 31, 2002 was approximately

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TRANSOCEAN INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED

$242.3 million, $375.6 million, $283.8 million, $279.2 million, $92.5 million
and $383.2 million, respectively, based on the estimated yield to maturity as of
that date.

The Company entered into interest rate swaps relating to the 6.75%, 6.95%
and 9.5% Senior Notes. See Note 10.

1.5% Convertible Debentures-In May 2001, the Company issued $400.0 million
aggregate principal amount of 1.5% Convertible Debentures due May 2021. The
Company has the right to redeem the debentures after five years for a price
equal to 100 percent of the principal. Each holder has the right to require the
Company to repurchase the debentures after five, 10 and 15 years at 100 percent
of the principal amount. The Company may pay this repurchase price with either
cash or ordinary shares or a combination of cash and ordinary shares. The
debentures are convertible into ordinary shares of the Company at the option of
the holder at any time at a ratio of 13.8627 shares per $1,000 principal amount
debenture, subject to adjustments if certain events take place, if the closing
sale price per ordinary share exceeds 110 percent of the conversion price for at
least 20 trading days in a period of 30 consecutive trading days ending on the
trading day immediately prior to the conversion date or if other specified
conditions are met. At December 31, 2002, $400.0 million principal amount of
these notes was outstanding. The fair value of the 1.5% Convertible Debentures
at December 31, 2002 was approximately $367.0 million based on the estimated
yield to maturity as of that date.

6.625% Notes and 7.5% Notes-In April 2001, the Company issued $700.0
million aggregate principal amount of 6.625% Notes due April 15, 2011 and $600.0
million aggregate principal amount of 7.5% Notes due April 15, 2031. At December
31, 2002, $700.0 million and $600.0 million principal amount of these notes was
outstanding, respectively. The fair value of the 6.625% Notes and 7.5% Notes at
December 31, 2002 was approximately $766.4 million and $698.0 million,
respectively, based on the estimated yield to maturity as of that date.

The Company entered into interest rate swaps relating to the 6.625% Notes
and 7.5% Notes. See Note 10.

Zero Coupon Convertible Debentures-In May 2000, the Company issued Zero
Coupon Convertible Debentures due May 2020 with a face value at maturity of
$865.0 million. The debentures were issued to the public at a price of $579.12
per debenture and accrue original issue discount at a rate of 2.75 percent per
annum compounded semiannually to reach a face value at maturity of $1,000 per
debenture. The Company will pay no interest on the debentures prior to maturity
and has the right to redeem the debentures after three years for a price equal
to the issuance price plus accrued original issue discount to the date of
redemption. Each holder has the right to require the Company to repurchase the
debentures on the third, eighth and thirteenth anniversary of issuance at the
issuance price plus accrued original issue discount to the date of repurchase.
The Company may pay this repurchase price with either cash or ordinary shares or
a combination of cash and ordinary shares. The debentures are convertible into
ordinary shares of the Company at the option of the holder at any time at a
ratio of 8.1566 shares per debenture subject to adjustments if certain events
take place. At December 31, 2002, $865.0 million face value of these notes was
outstanding with a discounted value of $537.6 million. The fair value of the
Zero Coupon Convertible Debentures at December 31, 2002 was approximately $534.2
million based on the estimated yield to maturity as of that date. Should all of
the debentures be put to the Company in May 2003, the debentures will have a
discounted value of $543.7 million.

7.45% Notes and 8% Debentures-In April 1997, the Company issued $100.0
million aggregate principal amount of 7.45% Notes due April 15, 2027 and $200.0
million aggregate principal amount of 8% Debentures due April 15, 2027. Holders
of the 7.45% Notes may elect to have all or any portion of the 7.45% Notes
repaid on April 15, 2007 at 100 percent of the principal amount. The 7.45%
Notes, at any time after April 15, 2007, and the 8% Debentures, at any time, are
redeemable at the Company's option at a make-whole premium. At December 31,
2002, $100.0 million and $200.0 million principal amount of these notes was
outstanding, respectively. The fair value of the 7.45% Notes and 8% Debentures
at December 31, 2002 was approximately $115.0 million and $242.8 million,
respectively, based on the estimated yield to maturity as of that date.

All of the notes, debentures and bank agreements described above are senior
and unsecured.

Nautilus Class A1 and A2 Notes-In August 1999, one of the Company's
subsidiaries completed a $250.0 million project financing for the construction
of the Deepwater Nautilus that consisted of a $200.0 million, 7.31% Class A1
amortizing note with a final maturity in May 2005 and a $50.0 million, 9.41%
Class A2 note maturing in May 2005. Both notes are collateralized by the
Deepwater Nautilus, which had a carrying value of $303.6 million at December 31,
2002, and the rig's drilling contract revenues. These notes were recorded at
fair value on January 31, 2001 as part of the R&B Falcon merger. At December 31,
2002, approximately $105.8 million and $50.0 million principal amount,
respectively, of these notes were outstanding. The fair value of the Nautilus
Class A1 and A2 Notes at December 31, 2002 was approximately $111.9 million and
$56.4 million, respectively, based on the estimated yield to maturity as of that
date.

-69-

TRANSOCEAN INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED

Secured Rig Financing-At December 31, 2001, the Company had outstanding
$50.6 million of debt secured by the Trident IX and Trident 16. Payments under
these financing agreements included an interest component of 7.95 percent for
the Trident IX and 7.20 percent for the Trident 16. The financing arrangements
provided for a call right on the part of the Company to repay the financing
prior to expiration of their scheduled terms and in some circumstances a put
right on the part of the banks to require the Company to repay the financing.
Under either circumstance, the Company would retain ownership of the rigs.

In January 2002, the Company exercised its call option under the financing
arrangement to repay the financing on the Trident 16 prior to the expiration of
the scheduled term. The aggregate principal amount outstanding was $32.2
million. The premium paid as a result of the call option of approximately $2.0
million was recorded as an increase in the net book value of the Trident 16.

In March 2002, the Company also exercised its call option under the
financing arrangement to repay the financing on the Trident IX prior to the
expiration of the scheduled term. The aggregate principal amount outstanding was
$14.9 million. The premium paid as a result of the call option of approximately
$0.5 million was recorded as an increase in the net book value of the Trident
IX.

Redeemed and Repurchased Debt-In November and December of 2001, the
Company repurchased and retired approximately $11.3 million face value of the
9.125% Senior Notes due 2003 and $10.5 million face value of the 6.5% Senior
Notes due 2003. The Company funded the repurchases from cash on hand. The
Company recognized an extraordinary loss, net of tax, of approximately $0.6
million in the fourth quarter of 2001 relating to the early retirement of this
debt.

On November 30, 2001, the Company repaid all amounts outstanding related to
the 6.9% Notes using cash on hand. As a result, the Company recognized an
extraordinary loss, net of tax, of approximately $1.4 million in the fourth
quarter of 2001 relating to the early retirement of this debt.

On May 18, 2001, Cliffs Drilling Company ("Cliffs Drilling"), an indirect
wholly owned subsidiary of the Company, redeemed all of the approximately $200.0
million principal amount outstanding 10.25% Senior Notes due 2003, at 102.5
percent, or $1,025 per $1,000 principal amount, plus interest accrued to the
redemption date. The Company recognized an extraordinary gain, net of tax, of
approximately $1.6 million ($0.01 per diluted share) in the second quarter of
2001 relating to the early retirement of this debt.

On April 10, 2001, TODCO acquired, pursuant to a tender offer, all of the
approximately $400.0 million principal amount outstanding 11.375% Senior Secured
Notes due 2009 of its affiliate, RBF Finance Co., at 122.51 percent of principal
amount, or $1,225.10 per $1,000 principal amount, plus accrued and unpaid
interest.

On April 6, 2001, RBF Finance Co., an indirect wholly owned subsidiary of
the Company, redeemed all of the approximately $400.0 million principal amount
outstanding 11% Senior Secured Notes due 2006 at 125.282 percent, or $1,252.82
per $1,000 principal amount, plus accrued and unpaid interest, and TODCO
redeemed all of the approximately $200.0 million principal amount outstanding
12.25% Senior Notes due 2006 at 130.675 percent or $1,306.75 per $1,000
principal amount, plus accrued and unpaid interest. The Company funded the
redemption from the issuance of the 6.625% Notes and 7.5% Notes in April 2001.

On March 30, 2001, pursuant to an offer made in connection with the R&B
Falcon merger, Cliffs Drilling, a wholly owned subsidiary of TODCO, acquired
approximately $0.1 million of the 10.25% Senior Notes due 2003 at an amount
equal to 101 percent of the principal amount.

The Company recognized an extraordinary loss, net of tax, of approximately
$18.9 million ($0.06 per diluted share) in the second quarter of 2001 on the
early retirement of these debt instruments.

NOTE 9-FINANCIAL INSTRUMENTS AND RISK CONCENTRATION

Foreign Exchange Risk-The Company's international operations expose the
Company to foreign exchange risk. This risk is primarily associated with
compensation costs denominated in currencies other than the U.S. dollar and with
purchases from foreign suppliers. The Company uses a variety of techniques to
minimize exposure to foreign exchange risk, including customer contract payment
terms and foreign exchange derivative instruments.

-70-

TRANSOCEAN INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED

The Company's primary foreign exchange risk management strategy involves
structuring customer contracts to provide for payment in both U.S. dollars and
local currency. The payment portion denominated in local currency is based on
anticipated local currency requirements over the contract term. Due to various
factors, including local banking laws, other statutory requirements, local
currency convertibility and the impact of inflation on local costs, actual
foreign exchange needs may vary from those anticipated in the customer
contracts, resulting in partial exposure to foreign exchange risk. Fluctuations
in foreign currencies have minimal impact on overall results. In situations
where the primary strategy is not entirely attainable, foreign exchange
derivative instruments, specifically foreign exchange forward contracts, or spot
purchases may be used. A foreign exchange forward contract obligates the Company
to exchange predetermined amounts of specified foreign currencies at specified
exchange rates on specified dates or to make an equivalent U.S. dollar payment
equal to the value of such exchange.

Gains and losses on foreign exchange derivative instruments, which qualify
as accounting hedges, are deferred as other comprehensive income and recognized
when the underlying foreign exchange exposure is realized. Gains and losses on
foreign exchange derivative instruments, which do not qualify as hedges for
accounting purposes, are recognized currently based on the change in market
value of the derivative instruments. At December 31, 2002 and 2001, the Company
did not have any foreign exchange derivative instruments not qualifying as
accounting hedges.

Interest Rate Risk-The Company's use of debt directly exposes the Company
to interest rate risk. Floating rate debt, where the interest rate can be
changed every year or less over the life of the instrument, exposes the Company
to short-term changes in market interest rates. Fixed rate debt, where the
interest rate is fixed over the life of the instrument and the instrument's
maturity is greater than one year, exposes the Company to changes in market
interest rates should the Company refinance maturing debt with new debt.

In addition, the Company is exposed to interest rate risk in its cash
investments, as the interest rates on these investments change with market
interest rates.

The Company, from time to time, may use interest rate swap agreements to
manage the effect of interest rate changes on future income. These derivatives
are used as hedges and are not used for speculative or trading purposes.
Interest rate swaps are designated as a hedge of underlying future interest
payments. These agreements involve the exchange of amounts based on variable
interest rates and amounts based on a fixed interest rate over the life of the
agreement without an exchange of the notional amount upon which the payments are
based. The interest rate differential to be received or paid on the swaps is
recognized over the lives of the swaps as an adjustment to interest expense.
Gains and losses on terminations of interest rate swap agreements are deferred
and recognized as an adjustment to interest expense over the remaining life of
the underlying debt. In the event of the early retirement of a designated debt
obligation, any realized or unrealized gain or loss from the swap would be
recognized in income.

The major risks in using interest rate derivatives include changes in
interest rates affecting the value of such instruments, potential increases in
the interest expense of the Company due to market increases in floating interest
rates in the case of derivatives that exchange fixed interest rates for floating
interest rates and the credit worthiness of the counterparties in such
transactions.

The Company has entered into interest rate swap transactions hedging debt.
See Note 10. The Company has not hedged any of its other assets or liabilities
against interest rate movements.

The market value of the Company's swaps is carried on its consolidated
balance sheet as an asset or liability depending on the movement of interest
rates after the transaction is entered into and depending on the security being
hedged. Because the Company's swaps are considered to be perfectly effective,
the carrying value of the debt being hedged is adjusted for the market value of
the swaps.

Should a counterparty default at a time in which the market value of the
swap with that counterparty is classified as an asset in the Company's
consolidated balance sheet, the Company may be unable to collect on that asset.
To mitigate such risk of failure, the Company enters into swap transactions with
a diverse group of high-quality institutions.

Credit Risk-Financial instruments which potentially subject the Company to
concentrations of credit risk are primarily cash and cash equivalents, trade
receivables, swap receivables and notes receivable from Delta Towing LLC (see
Note 21). It is the Company's practice to place its cash and cash equivalents
in time deposits at commercial banks with high credit ratings or mutual funds,
which invest exclusively in high quality money market instruments. In foreign
locations, local

-71-

TRANSOCEAN INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED

financial institutions are generally utilized for local currency needs. The
Company limits the amount of exposure to any one institution and does not
believe it is exposed to any significant credit risk.

The Company derives the majority of its revenue from services to
international oil companies and government-owned and government-controlled oil
companies. Receivables are concentrated in various countries. See Note 20. The
Company maintains an allowance for uncollectible accounts receivable based upon
expected collectibility. The Company is not aware of any significant credit
risks relating to its customer base and does not generally require collateral or
other security to support customer receivables.

Labor Agreements-On a worldwide basis, the Company had approximately 10
percent of its employees working under collective bargaining agreements at
December 31, 2002, most of whom were working in Norway, U.K., Nigeria and
Trinidad. Of these represented employees, a majority are working under
agreements that are subject to salary negotiation in 2003.

NOTE 10-INTEREST RATE SWAPS

In June 2001, the Company entered into interest rate swap agreements in the
aggregate notional amount of $700.0 million with a group of banks relating to
the Company's $700.0 million aggregate principal amount of 6.625% Notes due
April 2011. In February 2002, the Company entered into interest rate swap
agreements with a group of banks in the aggregate notional amount of $900.0
million relating to the Company's $350.0 million aggregate principal amount of
6.75% Senior Notes due April 2005, $250.0 million aggregate principal amount of
6.95% Senior Notes due April 2008 and $300.0 million aggregate principal amount
of 9.5% Senior Notes due December 2008 (see Note 26). The objective of each
transaction is to protect the debt against changes in fair value due to changes
in the benchmark interest rate. Under each interest rate swap, the Company
receives the fixed rate equal to the coupon of the hedged item and pays the
floating rate (LIBOR) plus a margin of 50 basis points, 246 basis points, 171
basis points and 413 basis points, respectively, which are designated as the
respective benchmark interest rates, on each of the interest payment dates until
maturity of the respective notes. The hedges are considered perfectly effective
against changes in the fair value of the debt due to changes in the benchmark
interest rates over their term. As a result, the shortcut method applies and
there is no need to periodically reassess the effectiveness of the hedges during
the term of the swaps.

On March 13, 2001, the Company entered into interest rate swap agreements
relating to the anticipated private placement of $700.0 million aggregate
principal amount of 6.625% Notes due April 15, 2011 and $600.0 million aggregate
principal amount of 7.5% Notes due April 15, 2031 in the notional amounts of
$200.0 million and $400.0 million, respectively. The objective of each
transaction was to hedge a portion of the forecasted payments of interest
resulting from the anticipated issuance of fixed rate debt. Under each forward
interest rate swap, the Company paid a LIBOR swap rate and received the floating
rate of three-month LIBOR. Hedge effectiveness was assessed by the dollar-offset
method by comparing the changes in expected cash flows from the hedges with the
change in the LIBOR swap rates and the forward interest rate swaps were
determined to be highly effective. The hedge transactions were closed out on
March 30, 2001. The gain on these hedge transactions of $4.1 million is a
component of accumulated other comprehensive income in the consolidated balance
sheet. This gain is being recognized as a reduction of interest expense over the
life of the 7.5% Notes beginning in April 2001. For the years ended December 31,
2002 and 2001, the amount of net after-tax gain recognized was $0.3 million and
$0.2 million, respectively. At December 31, 2002 and 2001, the net after-tax
gain on these terminated interest rate swaps included in accumulated other
comprehensive income was $3.6 million and $3.9 million, respectively.

At December 31, 2002, the Company had outstanding interest rate swaps in
the aggregate notional amount of $1.6 billion. The market value of the
Company's outstanding interest rate swaps was included in other assets with
corresponding increases to long-term debt and was as follows (in millions):

DECEMBER 31,
-------------
2002 2001
------ -----

6.75% Senior Notes, due April 2005 . $ 18.7 $ -
6.95% Senior Notes, due April 2008 . 25.3 -
9.5% Senior Notes, due December 2008 30.6 -
6.625% Notes, due April 2011 . . . . 106.7 15.1
------ -----
$181.3 $15.1
====== =====

-72-

TRANSOCEAN INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED

DD LLC, an unconsolidated subsidiary in which the Company has a 50 percent
ownership interest, has entered into interest rate swaps with aggregate market
values netting to a liability of $6.7 million at December 31, 2002. The
Company's interest in these swaps has been included in accumulated other
comprehensive income, net of tax, with corresponding reductions to deferred
income taxes and investments in and advances to joint ventures.

NOTE 11-FAIR VALUE OF FINANCIAL INSTRUMENTS

The following methods and assumptions were used to estimate the fair value
of each class of financial instruments for which it is practicable to estimate
that value:

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

Swap receivables-The carrying value of swap receivables is adjusted to
estimated market value based on current and forward LIBOR rates.

Notes receivable from related party-The fair value of notes receivable from
related party with a carrying amount of $82.8 million and $78.9 million at
December 31, 2002 and 2001, respectively, could not be determined because there
is no available market price for such notes. See Note 21.

Debt-The fair value of the Company's fixed rate debt is calculated based on
the estimated yield to maturity. The carrying value of variable rate debt
approximates fair value.

DECEMBER 31, 2002 DECEMBER 31, 2001
---------------------- ---------------------
CARRYING CARRYING
AMOUNT FAIR VALUE AMOUNT FAIR VALUE
--------- ----------- --------- -----------

Cash and cash equivalents $ 1,214.2 $ 1,214.2 $ 853.4 $ 853.4
Trade receivables . . . . 437.6 437.6 602.9 602.9
Swap receivables . . . . 181.3 181.3 15.1 15.1
Debt. . . . . . . . . . . 4,678.0 4,848.5 5,023.8 5,001.8

NOTE 12-OTHER CURRENT LIABILITIES

Other current liabilities are comprised of the following (in millions):

DECEMBER 31,
--------------
2002 2001
------ ------

Accrued Payroll and Employee Benefits $143.6 $134.2
Accrued Interest. . . . . . . . . . . 32.2 38.8
Deferred Income . . . . . . . . . . . 31.1 18.2
Reserves for Contingent Liabilities . 22.9 47.5
Accrued Taxes, Other than Income. . . 19.3 26.6
Other . . . . . . . . . . . . . . . . 13.1 18.1
------ ------
Total Other Current Liabilities . . $262.2 $283.4
====== ======

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TRANSOCEAN INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED

NOTE 13-OTHER LONG-TERM LIABILITIES

Other long-term liabilities are comprised of the following (in millions):

DECEMBER 31,
--------------
2002 2001
------ ------

Reserves for Contingent Liabilities . . . . . . . . $137.6 $ 69.9
Accrued Pension and Early Retirement. . . . . . . . 56.0 22.8
Accrued Retiree Life Insurance and Medical Benefits 30.1 27.5
Minority Interest . . . . . . . . . . . . . . . . . 6.8 4.8
Long-Term Portion of Accrued Workers' Insurance . . 6.5 6.5
Deferred Income . . . . . . . . . . . . . . . . . . 6.4 11.6
Other . . . . . . . . . . . . . . . . . . . . . . . 39.3 35.4
------ ------
Total Other Long-Term Liabilities . . . . . . . . $282.7 $178.5
====== ======

NOTE 14-SUPPLEMENTARY CASH FLOW INFORMATION

Non-cash investing activities for the years ended December 31, 2002, 2001
and 2000 included $7.9 million, $11.8 million and $45.0 million, respectively,
related to accruals of capital expenditures. The accruals have been reflected in
the consolidated balance sheet as an increase in property and equipment, net and
accounts payable.

In 2002, the Company reclassified the remaining assets that had not been
disposed of from assets held for sale to property and equipment based on
management's assessment that these assets no longer met the held for sale
criteria under SFAS 144. As a result, $55.0 million was reflected as an increase
in property and equipment with a corresponding decrease in other assets.

Non-cash financing activities for the year ended December 31, 2001 included
$6.7 billion related to the Company's ordinary shares issued in connection with
the R&B Falcon merger. Non-cash investing activities for the year ended December
31, 2001 included $6.4 billion of net assets acquired in the R&B Falcon merger.

Concurrent with and subsequent to the R&B Falcon merger, the Company
removed certain non-strategic assets from the active rig fleet and categorized
them as assets held for sale. These reclassifications were reflected in the
December 31, 2001 consolidated balance sheet as a decrease in property and
equipment, net of $177.8 million, with a corresponding increase in other assets.

In February 2001, the Company received a distribution from a joint venture
in the form of marketable securities held for sale valued at $19.9 million. The
distribution was reflected in the consolidated balance sheet as an increase in
other current assets with a corresponding decrease in investments in and
advances to joint ventures.

Cash payments for interest were $210.5 million, $190.6 million and $81.3
million for the years ended December 31, 2002, 2001 and 2000, respectively. Cash
payments for income taxes, net, were $91.1 million, $122.5 million and $63.3
million for the years ended December 31, 2002, 2001 and 2000, respectively.

NOTE 15-INCOME TAXES

Income taxes have been provided based upon the tax laws and rates in the
countries in which operations are conducted and income is earned. There is no
expected relationship between the provision for or benefit from income taxes and
income or loss before income taxes because the countries have taxation regimes
that vary not only with respect to nominal rate, but also in terms of the
availability of deductions, credits and other benefits. Variations also arise
because income earned and taxed in any particular country or countries may
fluctuate from year to year. Transocean Inc., a Cayman Islands company, is not
subject to income tax in the Cayman Islands. The effective tax rate on
continuing operations for the years ended December 31, 2002, 2001 and 2000 was
4.9 percent, 23.8 percent and 25.4 percent, respectively.

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TRANSOCEAN INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED

During 2002, the Company recorded a $175.7 million ($0.55 per diluted
share) tax benefit attributable to the restructuring of certain non-U.S.
operations. As a result of the restructuring, previously unrecognized losses
were offset against deferred gains, resulting in a reduction of non-current
deferred taxes payable.

The components of the provision for income taxes are as follows (in
millions):

YEARS ENDED DECEMBER 31,
---------------------------
2002 2001 2000
-------- ------- -------

Current provision. . . . . . . . . . . . . . . . . . . . . . . . $ 101.4 $174.2 $ 66.5
Deferred benefit . . . . . . . . . . . . . . . . . . . . . . . . (224.4) (98.2) (30.1)
-------- ------- -------
Income tax expense (benefit) after extraordinary items and after
cumulative effect of a change in accounting principle. . . . . (123.0) 76.0 36.4
Tax effect of extraordinary items. . . . . . . . . . . . . . . . - 9.7 0.3
-------- ------- -------
Income Tax Expense (Benefit) before Extraordinary Items and
Cumulative Effect of a Change in Accounting Principle. . . . . $(123.0) $ 85.7 $ 36.7
======== ======= =======

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TRANSOCEAN INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED

Significant components of deferred tax assets and liabilities are as follows (in
millions):

DECEMBER 31,
------------------
2002 2001
-------- --------

DEFERRED TAX ASSETS-CURRENT
Accrued personnel taxes. . . . . . . . . . . . . . . . $ 1.7 $ 1.4
Accrued workers' compensation insurance. . . . . . . . 4.6 4.4
Other accruals . . . . . . . . . . . . . . . . . . . . 9.1 17.9
Insurance accruals . . . . . . . . . . . . . . . . . . 5.7 -
Other. . . . . . . . . . . . . . . . . . . . . . . . . 5.4 3.7
-------- --------
Total Current Deferred Tax Assets . . . . . . . . . . 26.5 27.4
-------- --------

DEFERRED TAX LIABILITIES-CURRENT
Deferred drydock . . . . . . . . . . . . . . . . . . . (4.6) (2.7)
Insurance accruals . . . . . . . . . . . . . . . . . . - (3.5)
Other accruals . . . . . . . . . . . . . . . . . . . . - (0.2)
-------- --------
Total Current Deferred Tax Liabilities. . . . . . . . (4.6) (6.4)
-------- --------
Net Current Deferred Tax Assets . . . . . . . . . . . $ 21.9 $ 21.0
======== ========

DEFERRED TAX ASSETS-NONCURRENT-NON-U.S.
Net operating loss carryforwards-non-U.S . . . . . . . $ 26.2 $ 28.0
-------- --------
Net Noncurrent Deferred Tax Assets-non-U.S.. . . . . $ 26.2 $ 28.0
======== ========

DEFERRED TAX ASSETS-NONCURRENT
Net operating loss carryforwards . . . . . . . . . . . $ 380.3 $ 354.3
Foreign tax credit carryforwards . . . . . . . . . . . 216.9 185.6
Retirement and benefit plan accruals . . . . . . . . . 7.9 0.8
Other accruals . . . . . . . . . . . . . . . . . . . . 11.5 7.9
Deferred income and other. . . . . . . . . . . . . . . 29.5 41.3
Valuation allowance for noncurrent deferred tax assets (112.3) (90.7)
-------- --------
Total Noncurrent Deferred Tax Assets. . . . . . . . . 533.8 499.2
-------- --------

DEFERRED TAX LIABILITIES-NONCURRENT
Depreciation and amortization. . . . . . . . . . . . . (558.9) (640.0)
Deferred gains . . . . . . . . . . . . . . . . . . . . - (123.2)
Investment in subsidiaries . . . . . . . . . . . . . . (67.7) (72.1)
Other. . . . . . . . . . . . . . . . . . . . . . . . . (14.4) (9.0)
-------- --------
Total Noncurrent Deferred Tax Liabilities . . . . . . (641.0) (844.3)
-------- --------
Net Noncurrent Deferred Tax Liabilities . . . . . . . $(107.2) $(345.1)
======== ========

Deferred tax assets and liabilities are recognized for the anticipated
future tax effects of temporary differences between the financial statement
basis and the tax basis of the Company's assets and liabilities using the
applicable tax rates in effect at year end. A valuation allowance for deferred
tax assets is recorded when it is more likely than not that some or all of the
benefit from the deferred tax asset will not be realized.

The Company provided a valuation allowance to offset deferred tax assets on
net operating losses incurred during the year in certain jurisdictions where, in
the opinion of management, it is more likely than not that the financial
statement benefit of these losses would not be realized. The Company has also
provided a valuation allowance for foreign tax credit carryforwards reflecting
the possible expiration of their benefits prior to their utilization. The
valuation allowance for non-current deferred tax assets increased $21.6 million
during the year ended December 31, 2002.

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TRANSOCEAN INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED

The Company's net U.S. operating loss carryforwards expire between 2003 and
2022. The tax effect of the U.S. net operating loss carryforwards was $380.3
million at December 31, 2002. The Company's U.K. net operating loss
carryforwards do not expire. The tax effect of the U.K. net operating loss
carryforwards was $26.2 million at December 31, 2002. The Company's fully
benefited U.S. foreign tax credit carryforwards will expire between 2004 and
2007.

Transocean Inc., a Cayman Islands company, is not subject to income taxes
in the Cayman Islands. For the three years ended December 31, 2002, there was no
Cayman Islands income or profits tax, withholding tax, capital gains tax,
capital transfer tax, estate duty or inheritance tax payable by a Cayman Islands
company or its shareholders. The Company has obtained an assurance from the
Cayman Islands government under the Tax Concessions Law (1995 Revision) that, in
the event that any legislation is enacted in the Cayman Islands imposing tax
computed on profits or income, or computed on any capital assets, gain or
appreciation, or any tax in the nature of estate duty or inheritance tax, such
tax shall not, until June 1, 2019, be applicable to the Company or to any of its
operations or to the shares, debentures or other obligations of the Company.
Therefore, under present law there will be no Cayman Islands tax consequences
affecting distributions.

The Company's income tax returns are subject to review and examination in
the various jurisdictions in which the Company operates. The U.S. Internal
Revenue Service is currently auditing the years 1999 and 2000. In addition,
other tax authorities have questioned the amounts of income and expense subject
to tax in their jurisdiction for prior periods. The Company is currently
contesting additional assessments which have been asserted and may contest any
future assessments. In the opinion of management, the ultimate resolution of
these asserted income tax liabilities will not have a material adverse effect on
the Company's business, consolidated financial position or results of
operations.

In connection with the distribution of Sedco Forex Holdings Limited ("Sedco
Forex") to the Schlumberger shareholders in December 1999, Sedco Forex and
Schlumberger entered into a Tax Separation Agreement. In accordance with the
terms of the Tax Separation Agreement, Schlumberger agreed to indemnify Sedco
Forex for any tax liabilities incurred directly in connection with the
preparation of Sedco Forex for this distribution. In addition, Schlumberger
agreed to indemnify Sedco Forex for tax liabilities associated with Sedco Forex
operations conducted through Schlumberger entities prior to the merger and any
tax liabilities associated with Sedco Forex assets retained by Schlumberger.

The Company was included in the consolidated federal income tax returns
filed by a former parent, Sonat Inc. ("Sonat") during all periods in which
Sonat's ownership was greater than or equal to 80 percent ("Affiliation Years").
The Company and Sonat entered into a Tax Sharing Agreement providing for the
manner of determining payments with respect to federal income tax liabilities
and benefits arising in the Affiliation Years. Under the Tax Sharing Agreement,
the Company will pay to Sonat an amount equal to the Company's share of the
Sonat consolidated federal income tax liability, generally determined on a
separate return basis. In addition, Sonat will pay the Company for Sonat's
utilization of deductions, losses and credits that are attributable to the
Company and in excess of that which would be utilized on a separate return
basis.

NOTE 16-COMMITMENTS AND CONTINGENCIES

Operating Leases-The Company has operating lease commitments expiring at
various dates, principally for real estate, office space, office equipment and
rig bareboat charters. In addition to rental payments, some leases provide that
the Company pay a pro rata share of operating costs applicable to the leased
property. As of December 31, 2002, future minimum rental payments related to
noncancellable operating leases are as follows (in millions):

YEARS ENDED
DECEMBER 31,
------------

2003 . . . $ 32.2
2004 . . . 25.8
2005 . . . 19.7
2006 . . . 6.9
2007 . . . 6.6
Thereafter 22.5
------------
Total . . $ 113.7
============

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TRANSOCEAN INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED

The Company is a party to an operating lease on the M. G. Hulme, Jr. The
drilling rig is leased from Deep Sea Investors, L.L.C., a special purpose entity
formed by several leasing companies to acquire the rig from one of the Company's
subsidiaries in November 1995 in a sale/leaseback transaction. Under this lease,
the Company may purchase the rig for approximately $35 million at the end of the
lease term of November 29, 2005. At December 31, 2002, the future minimum lease
payments, excluding the purchase option, was $37.9 million and was included in
the table above.

Rental expense for all operating leases, including leases with terms of
less than one year, was $52 million, $96 million and $50 million for the years
ended December 31, 2002, 2001 and 2000, respectively.

Legal Proceedings-In 1990 and 1991, two of the Company's subsidiaries were
served with various assessments collectively valued at approximately $7 million
from the municipality of Rio de Janeiro, Brazil to collect a municipal tax on
services. The Company believes that neither subsidiary is liable for the taxes
and has contested the assessments in the Brazilian administrative and court
systems. The Brazil Supreme Court rejected the Company's appeal of an adverse
lower court's ruling with respect to a June 1991 assessment, which was valued at
approximately $6 million. The Company plans to challenge the assessment in a
separate proceeding, which is currently at the trial court level. The Company
also is awaiting a ruling at various levels in connection with a disputed August
1990 assessment that is still pending before the Brazil Superior Court of
Justice. The Company also received an adverse ruling from the Taxpayer's Council
in connection with an October 1990 assessment and is appealing the ruling. If
the Company's defenses are ultimately unsuccessful, the Company believes that
the Brazilian government-controlled oil company, Petrobras, has a contractual
obligation to reimburse the Company for municipal tax payments required to be
paid by them. The Company does not expect the liability, if any, resulting from
these assessments to have a material adverse effect on its business or
consolidated financial position.

The Indian Customs Department, Mumbai, filed a "show cause notice" against
a subsidiary of the Company and various third parties in July 1999. The show
cause notice alleged that the initial entry into India in 1988 and other
subsequent movements of the Trident II jackup rig operated by the subsidiary
constituted imports and exports for which proper customs procedures were not
followed and sought payment of customs duties of approximately $31 million based
on an alleged 1998 rig value of $49 million, with interest and penalties, and
confiscation of the rig. In January 2000, the Customs Department issued its
order, which found that the Company had imported the rig improperly and
intentionally concealed the import from the authorities, and directed the
Company to pay a redemption fee of approximately $3 million for the rig in lieu
of confiscation and to pay penalties of approximately $1 million in addition to
the amount of customs duties owed. In February 2000, the Company filed an appeal
with the Customs, Excise and Gold (Control) Appellate Tribunal ("CEGAT")
together with an application to have the confiscation of the rig stayed pending
the outcome of the appeal. In March 2000, the CEGAT ruled on the stay
application, directing that the confiscation be stayed pending the appeal. The
CEGAT issued its opinion on the Company's appeal on February 2, 2001, and while
it found that the rig was imported in 1988 without proper documentation or
payment of duties, the redemption fee and penalties were reduced to less than
$0.1 million in view of the ambiguity surrounding the import practice at the
time and the lack of intentional concealment by the Company. The CEGAT further
sustained the Company's position regarding the value of the rig at the time of
import as $13 million and ruled that subsequent movements of the rig were not
liable to import documentation or duties in view of the prevailing practice of
the Customs Department, thus limiting the Company's exposure as to custom duties
to approximately $6 million. Following the CEGAT order, the Company tendered
payment of redemption, penalty and duty in the amount specified by the order by
offset against a $0.6 million deposit and $10.7 million guarantee previously
made by the Company. The Customs Department attempted to draw the entire
guarantee, alleging the actual duty payable is approximately $22 million based
on an interpretation of the CEGAT order that the Company believes is incorrect.
This action was stopped by an interim ruling of the High Court, Mumbai on writ
petition filed by the Company. Both the Customs Department and the Company filed
appeals with the Supreme Court of India against the order of the CEGAT, and both
appeals have been admitted. The Company applied for an expedited hearing, which
was denied. The Company and its customer agreed to pursue and obtained the
issuance of documentation from the Ministry of Petroleum that, if accepted by
the Customs Department, would reduce the duty to nil. The agreement with the
customer further provided that if this reduction was not obtained by the end of
2001, the customer would pay the duty up to a limit of $7.7 million. The Customs
Department did not accept the documentation or agree to refund the duties
already paid. The Company has requested the refund from the customer, who has
refused. The Company is pursuing its remedies against the Customs Department and
the customer. The Company does not expect, in any event, that the ultimate
liability, if any, resulting from the matter will have a material adverse effect
on its business or consolidated financial position.

In January 2000, a pipeline in the U.S. Gulf of Mexico was damaged by an
anchor from one of the Company's drilling rigs while the rig was under tow. The
incident resulted in damage to offshore facilities, including a crude oil
pipeline, the release of hydrocarbons from the damaged section of the pipeline
and the shutdown of the pipeline and allegedly affected production platforms.
All appropriate governmental authorities were notified, and the Company
cooperated fully with the

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TRANSOCEAN INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED

operator and relevant authorities in support of the remediation efforts. Certain
owners and operators of the pipeline (Poseidon Oil Pipeline Company LLC, Equilon
Enterprises LLC, Poseidon Pipeline Company, LLC and Marathon Oil Company) filed
suit in March 2000 in federal court, Eastern District of Louisiana, alleging
various damages in excess of $30 million. A second suit was filed by Walter Oil
& Gas Corporation and certain other plaintiffs in Harris County, Texas alleging
various damages in excess of $1.8 million, and the Company obtained a summary
judgment against Walter Oil & Gas Corporation and Amerada Hess. The Company
filed a limitation of liability proceeding in federal court, Eastern District of
Louisiana, claiming benefit of various statutes providing limitation of
liability for vessel owners, the result of which was to stay the first two suits
and to cause potential claimants (including the plaintiffs in the existing
suits) to file claims in this proceeding. El Paso Energy Corporation, the
owner/operator of the platform from which a riser was allegedly damaged, and
Texaco Exploration and Production Inc. have filed claims in the limitation of
liability proceeding as well. All claims arising out of the loss have been
settled and the terms of the settlement have been reflected in the Company's
results of operations for the year ended December 31, 2002. The settlement did
not have a material adverse effect on the Company's business or consolidated
financial position.

In November 1988, a lawsuit was filed in the U.S. District Court for the
Southern District of West Virginia against Reading & Bates Coal Co., a wholly
owned subsidiary of R&B Falcon, by SCW Associates, Inc. claiming breach of an
alleged agreement to purchase the stock of Belva Coal Company, a wholly owned
subsidiary of Reading & Bates Coal Co. with coal properties in West Virginia.
When those coal properties were sold in July 1989 as part of the disposition of
R&B Falcon's coal operations, the purchasing joint venture indemnified Reading &
Bates Coal Co. and R&B Falcon against any liability Reading & Bates Coal Co.
might incur as a result of this litigation. A judgment for the plaintiff of
$32,000 entered in February 1991 was satisfied and Reading & Bates Coal Co. was
indemnified by the purchasing joint venture. On October 31, 1990, SCW
Associates, Inc., the plaintiff in the above-referenced action, filed a separate
ancillary action in the Circuit Court, Kanawha County, West Virginia against R&B
Falcon, Caymen Coal, Inc. (the former owner of R&B Falcon's West Virginia coal
properties), as well as the joint venture, Mr. William B. Sturgill (the former
President of Reading & Bates Coal Co.) personally, three other companies in
which the Company believes Mr. Sturgill holds an equity interest, two employees
of the joint venture, First National Bank of Chicago and First Capital
Corporation. The lawsuit sought to recover compensatory damages of $50 million
and punitive damages of $50 million for alleged tortious interference with the
contractual rights of the plaintiff and to impose a constructive trust on the
proceeds of the use and/or sale of the assets of Caymen Coal, Inc. as they
existed on October 15, 1988. The lawsuit was settled in August 2002, and the
terms of the settlement have been reflected in the Company's results of
operations for the year ended December 31, 2002. The settlement did not have a
material adverse effect on the Company's business or consolidated financial
position.

In March 1997, an action was filed by Mobil Exploration and Producing U.S.
Inc. and affiliates, St. Mary Land & Exploration Company and affiliates and
Samuel Geary and Associates, Inc. against the Company, its underwriters and
insurance broker in the 16th Judicial District Court of St. Mary Parish,
Louisiana. The plaintiffs alleged damages amounting to in excess of $50 million
in connection with the drilling of a turnkey well in 1995 and 1996. The case was
tried before a jury in January and February 2000, and the jury returned a
verdict of approximately $30 million in favor of the plaintiffs for excess
drilling costs, loss of insurance proceeds, loss of hydrocarbons and interest.
The Company has appealed such judgment, and the Louisiana Court of Appeals has
reduced the amount for which the Company may be responsible to less than $10
million. The plaintiffs have requested that the Supreme Court of Louisiana
consider the matter and reinstate the original verdict. The Company believes
that all but potentially the portion of the verdict representing excess drilling
costs of approximately $4.7 million is covered by relevant primary and excess
liability insurance policies; however, the insurers and underwriters have denied
coverage. The Company has instituted litigation against those insurers and
underwriters to enforce its rights under the relevant policies. The Company does
not expect that the ultimate outcome of this case will have a material adverse
effect on its business or consolidated financial position.

In October 2001, the Company was notified by the U.S. Environmental
Protection Agency ("EPA") that the EPA had identified a subsidiary of the
Company as a potentially responsible party in connection with the Palmer Barge
Line superfund site located in Port Arthur, Jefferson County, Texas. Based upon
the information provided by the EPA and the Company's review of its internal
records to date, the Company disputes its designation as a potentially
responsible party and does not expect that the ultimate outcome of this case
will have a material adverse effect on its business or consolidated financial
position.

The Company and its subsidiaries are involved in a number of other
lawsuits, all of which have arisen in the ordinary course of the Company's
business. The Company does not believe that ultimate liability, if any,
resulting from any such other pending litigation will have a material adverse
effect on its business or consolidated financial position.

Self Insurance-The Company is self-insured for the deductible portion of
its insurance coverage. In the opinion of management, adequate accruals have
been made based on known and estimated exposures up to the deductible portion of

-79-

TRANSOCEAN INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED

the Company's insurance coverages. Management believes that claims and
liabilities in excess of the amounts accrued are adequately insured.

Letters of Credit and Surety Bonds-The Company had letters of credit
outstanding at December 31, 2002 totaling $54.0 million. These letters of credit
guarantee various contract bidding and insurance activities under various lines
provided by several banks. In January 2002, the Company terminated a $70.0
million letter of credit facility secured by mortgages on five drilling units,
the J.W. McLean, J.T. Angel, Randolph Yost, D.R. Stewart and George H. Galloway.

As is customary in the contract drilling business, the Company also has
various surety bonds totaling $215.8 million in place that secure customs
obligations relating to the importation of its rigs and certain performance and
other obligations.

NOTE 17-STOCK-BASED COMPENSATION PLANS

Long-Term Incentive Plan-The Company has an incentive plan for key
employees and outside directors (the "Incentive Plan"). Under the Incentive
Plan, awards can be granted in the form of stock options, restricted stock,
stock appreciation rights ("SARs") and cash performance awards. As of December
31, 2002, the Company was authorized to grant up to (i) 18.9 million ordinary
shares to employees; (ii) 600,000 ordinary shares to outside directors; and
(iii) 300,000 freestanding SARs to employees or directors under the Incentive
Plan. Options issued under the Incentive Plan have a 10-year term and become
exercisable in three equal annual installments after the date of grant. On
December 31, 1999, all unvested stock options and SARs and all unvested
restricted shares granted after April 1996 became fully vested as a result of
the Sedco Forex merger. At December 31, 2002, there were approximately 8.4
million total shares available for future grants under the Incentive Plan.

Prior to the Sedco Forex merger, key employees of Sedco Forex were granted
stock options at various dates under the Schlumberger stock option plans. For
all of the stock options granted under such plans, the exercise price of each
option equaled the market price of Schlumberger stock on the date of grant, each
option's maximum term was 10 years and the options generally vested in 20
percent increments over five years. Fully vested options held by Sedco Forex
employees at the date of the spin-off will lapse in accordance with their
provisions. Non-vested options were terminated and fully vested stock options
to purchase ordinary shares of the Company were granted under a new plan (the
"SF Plan").

Prior to the R&B Falcon merger (see Note 4), certain employees and outside
directors of TODCO and its subsidiaries were granted stock options under various
plans. As a result of the R&B Falcon merger, the Company assumed all outstanding
TODCO stock options and converted them into options to purchase ordinary shares
of the Company.

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TRANSOCEAN INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED

The following table summarizes option activities:

NUMBER OF SHARES WEIGHTED-AVERAGE
UNDER OPTION EXERCISE PRICE
----------------- -----------------

Outstanding at December 31, 1999 . . . . 3,259,418 $ 26.46
----------------- -----------------

Granted. . . . . . . . . . . . . . . . . 1,636,918 37.30
Exercised. . . . . . . . . . . . . . . . (499,428) 23.99
Forfeited. . . . . . . . . . . . . . . . (22,500) 37.00
----------------- -----------------
Outstanding at December 31, 2000 . . . . 4,374,408 30.74

Granted. . . . . . . . . . . . . . . . . 2,370,840 38.53
Options assumed in the R&B Falcon merger 8,094,010 22.25
Exercised. . . . . . . . . . . . . . . . (1,286,554) 20.91
Forfeited. . . . . . . . . . . . . . . . (92,025) 42.15
----------------- -----------------
Outstanding at December 31, 2001 . . . . 13,460,679 27.99

Granted. . . . . . . . . . . . . . . . . 2,160,963 28.63
Exercised. . . . . . . . . . . . . . . . (102,480) 18.12
Forfeited. . . . . . . . . . . . . . . . (141,576) 37.99
----------------- -----------------
Outstanding at December 31, 2002 . . . . 15,377,586 28.03
================= =================

Exercisable at December 31, 2000 . . . . 2,754,073 $ 26.91
Exercisable at December 31, 2001 . . . . 9,977,963 $ 24.29
Exercisable at December 31, 2002 . . . . 11,332,039 $ 26.14

The following table summarizes information about stock options outstanding
at December 31, 2002:

OPTIONS OUTSTANDING OPTIONS EXERCISABLE
WEIGHTED-AVERAGE ----------------------------- ------------------------------
RANGE OF REMAINING NUMBER WEIGHTED-AVERAGE NUMBER WEIGHTED-AVERAGE
EXERCISE PRICES CONTRACTUAL LIFE OUTSTANDING EXERCISE PRICE OUTSTANDING EXERCISE PRICE
---------------- ---------------- ----------- ---------------- ------------ ----------------

$ 7.58 - $19.50 5.59 years 4,084,172 $ 14.95 3,999,172 $ 14.87
$ 20.12 - $33.69 6.85 years 6,047,605 $ 26.21 4,046,705 $ 24.93
$ 34.63 - $81.78 7.45 years 5,245,809 $ 40.30 3,286,162 $ 41.36

At December 31, 2002, there were 35,341 restricted ordinary shares and
145,364 SARs outstanding under the Incentive Plan.

Employee Stock Purchase Plan-The Company provides a stock purchase plan
(the "Stock Purchase Plan") for certain full-time employees. Under the terms of
the Stock Purchase Plan, employees can choose each year to have between two and
20 percent of their annual base earnings withheld to purchase up to $25,000 of
the Company's ordinary shares. The purchase price of the stock is 85 percent of
the lower of its beginning-of-year or end-of-year market price. At December 31,
2002, 771,909 ordinary shares were available for issuance pursuant to the Stock
Purchase Plan.

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TRANSOCEAN INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED

NOTE 18-RETIREMENT PLANS AND OTHER POSTEMPLOYMENT BENEFITS

Defined Benefit Pension Plans-The change in benefit obligation, change in
plan assets and funded status for the years ended December 31, 2002 and 2001 is
shown in the table below (in millions):

DECEMBER 31,
-----------------
2002 2001
-------- -------

CHANGE IN BENEFIT OBLIGATION
Benefit obligation at beginning of year . . . . $ 242.7 $133.6
Merger with R&B Falcon. . . . . . . . . . . . . - 85.7
Service cost. . . . . . . . . . . . . . . . . . 16.8 12.0
Interest cost . . . . . . . . . . . . . . . . . 19.0 15.9
Actuarial losses. . . . . . . . . . . . . . . . 27.0 4.8
Special termination benefits. . . . . . . . . . 1.1 -
Plan amendments . . . . . . . . . . . . . . . . 3.1 0.8
Benefits paid . . . . . . . . . . . . . . . . . (14.1) (10.1)
-------- -------
Benefit obligation at end of year . . . . . . 295.6 242.7
======== =======

CHANGE IN PLAN ASSETS
Fair value of plan assets at beginning of year. 210.4 117.7
Merger with R&B Falcon. . . . . . . . . . . . . - 99.3
Actual return on plan assets. . . . . . . . . . (14.4) (1.3)
Company contributions . . . . . . . . . . . . . 6.6 4.8
Benefits paid . . . . . . . . . . . . . . . . . (14.1) (10.1)
-------- -------
Fair value of plan assets at end of year. . . 188.5 210.4
======== =======

FUNDED STATUS . . . . . . . . . . . . . . . . . (107.1) (32.3)
Unrecognized transition obligation. . . . . . . 2.9 3.5
Unrecognized net actuarial loss . . . . . . . . 86.4 32.4
Unrecognized prior service cost . . . . . . . . 11.3 0.1
-------- -------
Accrued pension asset (liability) . . . . . . $ (6.5) $ 3.7
======== =======

Comprised of:
Prepaid benefit cost. . . . . . . . . . . . . . $ 1.6 $ 34.2
Accrued benefit liability . . . . . . . . . . . (54.5) (30.5)
Intangible asset. . . . . . . . . . . . . . . . 0.7 -
Accumulated other comprehensive income. . . . . 45.7 -
-------- -------
Accrued pension asset (liability) . . . . . . $ (6.5) $ 3.7
======== =======

AS OF DECEMBER 31,
-----------------
2002 2001
-------- -------
WEIGHTED-AVERAGE ASSUMPTIONS
Discount rate . . . . . . . . . . . . . . . . . 6.90% 7.45%
Expected return on plan assets. . . . . . . . . 8.73% 9.24%
Rate of compensation increase . . . . . . . . . 5.53% 5.71%

The aggregate projected benefit obligation and fair value of plan assets
for plans with projected benefit obligations in excess of plan assets were
$291.3 million and $182.9 million, respectively, at December 31, 2002. The
aggregate projected benefit obligation and fair value of plan assets for plans
with projected benefit obligations in excess of plan assets were $153.3 million
and $112.5 million, respectively, at December 31, 2001.

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TRANSOCEAN INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED

The aggregate accumulated benefit obligation and fair value of plan assets
for plans with accumulated benefit obligations in excess of plan assets were
$216.0 million and $174.3 million, respectively, at December 31, 2002. The
aggregate accumulated benefit obligation and fair value of plan assets for plans
with accumulated benefit obligations in excess of plan assets were $23.9 million
and $7.0 million, respectively, at December 31, 2001.

Net periodic benefit cost included the following components (in millions):

YEARS ENDED DECEMBER 31,
------------------------
2002 2001 2000
------- ------- ------

COMPONENTS OF NET PERIODIC BENEFIT COST (a)
Service cost. . . . . . . . . . . . . . . . . . . $ 16.8 $ 12.0 $ 9.5
Interest cost . . . . . . . . . . . . . . . . . . 19.0 15.9 9.1
Expected return on plan assets. . . . . . . . . . (20.7) (7.5) (8.9)
Amortization of transition obligation . . . . . . 0.3 0.3 0.4
Amortization of prior service cost. . . . . . . . 1.4 0.4 -
Recognized net actuarial gains. . . . . . . . . . (0.5) (11.3) (1.4)
Special termination benefits (b). . . . . . . . . 1.1 - -
FAS 88 settlements/curtailments . . . . . . . . . (0.3) - -
------- ------- ------
Benefit cost. . . . . . . . . . . . . . . . . $ 17.1 $ 9.8 $ 8.7
======= ======= ======
Change in accumulated other comprehensive income. $ 45.7 $ - $ -
======= ======= ======

______________
(a) Amounts are before income tax effect.
(b) Special termination benefits paid to a former executive officer of the
Company from the Company's unfunded supplemental pension plan upon the
officer's retirement in June 2002.

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TRANSOCEAN INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED

Postretirement Benefits Other Than Pensions-The change in benefit
obligation, change in plan assets and funded status are shown in the table below
(in millions).

DECEMBER 31,
---------------
2002 2001
------- -------

CHANGE IN BENEFIT OBLIGATION
Benefit obligation at beginning of year . . . . $ 29.2 $ 12.0
Merger with R&B Falcon. . . . . . . . . . . . . - 16.1
Service cost. . . . . . . . . . . . . . . . . . 1.0 0.4
Interest cost . . . . . . . . . . . . . . . . . 2.5 1.9
Actuarial losses (gains). . . . . . . . . . . . 6.7 (0.2)
Participants' contributions . . . . . . . . . . 0.2 0.2
Plan amendments . . . . . . . . . . . . . . . . 3.5 -
Benefits paid . . . . . . . . . . . . . . . . . (1.9) (1.2)
------- -------
Benefit obligation at end of year . . . . . 41.2 29.2
------- -------

CHANGE IN PLAN ASSETS
Fair value of plan assets at beginning of year. 0.5 0.6
Actual return on plan assets. . . . . . . . . . (0.3) 0.1
Company contributions . . . . . . . . . . . . . 1.7 0.8
Participants' contributions . . . . . . . . . . 0.2 0.2
Benefits paid . . . . . . . . . . . . . . . . . (1.9) (1.2)
------- -------
Fair value of plan assets at end of year. . 0.2 0.5
------- -------

FUNDED STATUS . . . . . . . . . . . . . . . . . (41.0) (28.7)
Unrecognized net actuarial gain . . . . . . . . 7.6 0.9
Unrecognized prior service cost . . . . . . . . 3.3 0.3
------- -------
Postretirement benefit liability. . . . . . $ 30.1 $(27.5)
======= =======

AS OF DECEMBER 31,
-----------------
2002 2001
------- -------
WEIGHTED-AVERAGE ASSUMPTIONS
Discount rate . . . . . . . . . . . . . . . . . 6.50% 7.00%
Expected return on plan assets. . . . . . . . . - 7.00%
Rate of compensation increase . . . . . . . . . 5.50% 5.50%

Net periodic benefit cost included the following components (in millions):

YEARS ENDED
DECEMBER 31,
--------------------
2002 2001 2000
----- ------ -----

COMPONENTS OF NET PERIODIC BENEFIT COST
Service cost . . . . . . . . . . . . . . $ 1.0 $ 0.4 $ 0.2
Interest cost. . . . . . . . . . . . . . 2.5 1.9 0.8
Amortization of prior service cost . . . 0.5 - 0.1
Recognized net actuarial loss (gain) . . 0.3 (0.1) -
----- ------ -----
Benefit Cost . . . . . . . . . . . . $ 4.3 $ 2.2 $ 1.1
===== ====== =====

For measurement purposes, the rate of increase in the per capita costs of
covered health care benefits was assumed 12 percent in 2002, decreasing
gradually to five percent by the year 2009.

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TRANSOCEAN INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED

The assumed health care cost trend rate has significant impact on the
amounts reported for postretirement benefits other than pensions. A
one-percentage point change in the assumed health care trend rate would have the
following effects (in millions):

ONE- ONE-
PERCENTAGE PERCENTAGE
POINT POINT
INCREASE DECREASE
----------- ------------

Effect on total service and interest cost components in 2002 . . . . $ 0.4 $ (0.3)
Effect on postretirement benefit obligations as of December 31, 2002 $ 4.1 $ (3.3)

Defined Contribution Plans-The Company provides a defined contribution
pension and savings plan covering senior non-U.S. field employees working
outside the United States. Contributions and costs are determined as 4.5 percent
to 6.5 percent of each covered employee's salary, based on years of service. In
addition, the Company sponsors a U.S. defined contribution savings plan. It
covers certain employees and limits Company contributions to no more than 4.5
percent of each covered employee's salary, based on the employee's contribution.
The Company also sponsors various other defined contribution plans worldwide.
The Company recorded approximately $21.3 million, $21.6 million and $11.5
million of expense related to its defined contribution plans for the years ended
December 31, 2002, 2001 and 2000, respectively.

Deferred Compensation Plan-The Company provides a Deferred Compensation
Plan (the "Plan"). The Plan's primary purpose is to provide tax-advantageous
asset accumulation for a select group of management, highly compensated
employees and non-employee members of the Board of Directors of the Company.

Eligible employees who enroll in the Plan may elect to defer up to a
maximum of 90 percent of base salary, 100 percent of any future performance
awards, 100 percent of any special payments and 100 percent of directors'
meeting fees and annual retainers; however, the Administrative Committee (seven
individuals appointed by the Finance and Benefits Committee of the Board of
Directors) may, at its discretion, establish minimum amounts that must be
deferred by anyone electing to participate in the Plan. In addition, the
Executive Compensation Committee of the Board of Directors may authorize
employer contributions to participants and the Chief Executive Officer of the
Company (with Executive Compensation Committee approval) is authorized to cause
the Company to enter into "Deferred Compensation Award Agreements" with such
participants. There were no employer contributions to the Plan during the years
ending December 31, 2002, 2001 or 2000.

NOTE 19-INVESTMENTS IN AND ADVANCES TO JOINT VENTURES

The Company has a 25 percent interest in Sea Wolf. In September 1997,
Sedco Forex sold two semisubmersible rigs, the Drill Star and Sedco Explorer, to
Sea Wolf. The Company operated the rigs under bareboat charters. The sale
resulted in a deferred gain of $157 million, which was being amortized to
operating and maintenance expense over the six-year life of the bareboat
charters. See Note 6. As of December 31, 2001, Sea Wolf distributed
substantially all of its assets to its shareholders.

The Company has a 50 percent interest in Overseas Drilling Limited ("ODL"),
which owns the drillship, Joides Resolution. The drillship is contracted to
perform drilling and coring operations in deep waters worldwide for the purpose
of scientific research. The Company manages and operates the vessel on behalf
of ODL. See Note 21.

At December 31, 2000, the Company had a 24.9 percent interest in Arcade, a
Norwegian offshore drilling company. Arcade owns two high-specification
semisubmersible rigs, the Henry Goodrich and Paul B. Loyd, Jr. Because TODCO
owned 74.4 percent of Arcade, Arcade was consolidated in the Company's financial
statements effective with the R&B Falcon merger. In October 2001, the Company
purchased the remaining minority interest in Arcade. The purchase price was
finalized in January 2003 for $3.2 million.

As a result of the R&B Falcon merger, the Company has a 50 percent interest
in DD LLC. DD LLC leases and operates the Deepwater Pathfinder. The investment
in DD LLC was recorded at fair value as part of the R&B Falcon merger. See Note
21.

As a result of the R&B Falcon merger, the Company has a 60 percent interest
in Deepwater Drilling II L.L.C. ("DDII LLC"). DDII LLC leases and operates the
Deepwater Frontier. The investment in DDII LLC was recorded at fair value as
part of the R&B Falcon merger. Management of DDII LLC is governed by the Limited
Liability Company Agreement (the "LLCA")

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TRANSOCEAN INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED

between the Company and Conoco. In accordance with the LLCA, DDII LLC's
day-to-day operations and financial decisions are governed by the Members
Committee, which is comprised of six individuals of which the Company and Conoco
each appoint three individuals. Because the Company shares equal responsibility
and control with Conoco, DDII LLC's results of operations are not consolidated
with the Company's consolidated results of operations. See Note 21.

As a result of the R&B Falcon merger, the Company has a 25 percent interest
in Delta Towing Holdings LLC. See Note 21.

NOTE 20-SEGMENTS, GEOGRAPHICAL ANALYSIS AND MAJOR CUSTOMERS

The Company's operations are aggregated into two reportable segments: (i)
International and U.S. Floater Contract Drilling Services and (ii) Gulf of
Mexico Shallow and Inland Water. The International and U.S. Floater Contract
Drilling Services segment consists of high-specification floaters, other
floaters, non-U.S. jackups, other mobile offshore drilling units and other
assets used in support of offshore drilling activities and offshore support
services. The Gulf of Mexico Shallow and Inland Water segment consists of jackup
and submersible drilling rigs and inland drilling barges located in the U. S.
Gulf of Mexico and Trinidad, as well as land and lake barge drilling units
located in Venezuela. The Company provides services with different types of
drilling equipment in several geographic regions. The location of the Company's
rigs and the allocation of resources to build or upgrade rigs is determined by
the activities and needs of customers. Accounting policies of the segments are
the same as those described in the Summary of Significant Accounting Policies
(see Note 2). The Company accounts for intersegment revenue and expenses as if
the revenue or expenses were to third parties at current market prices.

Effective January 1, 2002, the Company changed the composition of its
reportable segments with the move of the responsibility for its Venezuela
operations to the Gulf of Mexico Shallow and Inland Water segment. Prior periods
have been restated to reflect the change.

Operating revenues and income before income taxes, minority interest,
extraordinary items and cumulative effect of a change in accounting principle by
segment were as follows (in millions):

YEARS ENDED DECEMBER 31,
-------------------------------
2002 2001 2000
---------- --------- --------

Operating Revenues
International and U.S. Floater Contract Drilling Services . . . . . . . $ 2,486.1 $2,385.2 $1,229.5
Gulf of Mexico Shallow and Inland Water . . . . . . . . . . . . . . . . 187.8 441.1 -
Elimination of intersegment revenues. . . . . . . . . . . . . . . . . . - (6.2) -
---------- --------- --------
Total Operating Revenues. . . . . . . . . . . . . . . . . . . . . . . . $ 2,673.9 $2,820.1 $1,229.5
========== ========= ========

Income (Loss) Before Income Taxes, Minority Interest, Extraordinary Items
and Cumulative Effect of a Change in Accounting Principle
International and U.S. Floater Contract Drilling Services . . . . . . $(1,739.0) $ 582.1 $ 144.4
Gulf of Mexico Shallow and Inland Water . . . . . . . . . . . . . . . (505.3) 25.8 -
---------- --------- --------
(2,244.3) 607.9 144.4
Unallocated general and administrative expense. . . . . . . . . . . . . . (65.6) (57.9) -
Unallocated other expense, net. . . . . . . . . . . . . . . . . . . . . . (178.9) (189.5) -
---------- --------- --------
Total Income (Loss) Before Income Taxes, Minority Interest,
Extraordinary Items and Cumulative Effect of a Change in Accounting
Principle . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $(2,488.8) $ 360.5 $ 144.4
========== ========= ========

Prior to the R&B Falcon merger on January 31, 2001, the Company operated in
one industry segment and, as such, there were no unallocated income items for
the year ended December 31, 2000.

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TRANSOCEAN INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED

Depreciation expense by segment was as follows (in millions):

YEARS ENDED DECEMBER 31,
------------------------
2002 2001 2000
------ ------ ------

International and U.S. Floater Contract Drilling Services $408.4 $373.5 $232.8
Gulf of Mexico Shallow and Inland Water . . . . . . . . . 91.9 96.6 -
------ ------ ------
Total Depreciation Expense. . . . . . . . . . . . . . $500.3 $470.1 $232.8
====== ====== ======

Total assets by segment were as follows (in millions):

DECEMBER 31,
--------------------
2002 2001
--------- ---------

International and U.S. Floater Contract Drilling Services $11,804.1 $14,247.3
Gulf of Mexico Shallow and Inland Water . . . . . . . . . 861.0 2,800.5
--------- ---------
Total Assets. . . . . . . . . . . . . . . . . . . . . $12,665.1 $17,047.8
========= =========

Operating revenues and long-lived assets by country were as follows (in
millions):

YEARS ENDED DECEMBER 31,
----------------------------
2002 2001 2000
-------- -------- --------

OPERATING REVENUES
United States. . . . . . . . $ 752.5 $ 979.5 $ 265.0
United Kingdom . . . . . . . 345.7 354.6 158.9
Brazil . . . . . . . . . . . 283.0 355.8 153.6
Norway . . . . . . . . . . . 145.2 227.8 248.5
Rest of the World. . . . . . 1,147.5 902.4 403.5
-------- -------- --------
Total Operating Revenues $2,673.9 $2,820.1 $1,229.5
======== ======== ========

AS OF DECEMBER 31,
--------------------
2002 2001
--------- ---------

LONG-LIVED ASSETS
United States. . . . . . . . $ 3,905.0 $ 3,881.5
Goodwill (a) . . . . . . . . 2,218.2 6,466.7
Rest of the World. . . . . . 4,630.2 4,962.8
--------- ---------
Total Long-Lived Assets. $10,753.4 $15,311.0
========= =========

______________________
(a) Goodwill has not been allocated to individual countries.

A substantial portion of the Company's assets are mobile. 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.

The Company's international operations are subject to certain political and
other uncertainties, including risks of war and civil disturbances (or other
events that disrupt markets), expropriation of equipment, repatriation of income
or capital, taxation policies, and the general hazards associated with certain
areas in which operations are conducted.

For the year ended December 31, 2002, BP and Shell accounted for
approximately 14.1 percent and 11.6 percent, respectively, of the Company's
operating revenues, of which the majority was reported in the International and
U.S. Floater Contract Drilling Services segment. For the year ended December 31,
2001, BP and Petrobras accounted for approximately 12.3 percent and 10.9
percent, respectively, of the Company's operating revenues, of which the
majority was reported in the International and U.S. Floater Contract Drilling
Services segment. For the year ended December 31, 2000, Statoil, BP and
Petrobras accounted for approximately 16.8 percent, 14.4 percent and 12.5
percent, respectively, of the Company's operating

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TRANSOCEAN INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED

revenues. The loss of these or other significant customers could have a material
adverse effect on the Company's results of operations.

NOTE 21-RELATED PARTY TRANSACTIONS

Schlumberger-The Company incurred expenses amounting to approximately $1.1
million, $3.5 million and $9.0 million for the years ended December 31, 2002,
2001 and 2000, respectively, for the transitional services provided by
Schlumberger in connection with the Sedco Forex merger.

DD LLC and DDII LLC-The Company is party to drilling services agreements
with DD LLC and DDII LLC for the operations of the Deepwater Pathfinder and
Deepwater Frontier, respectively. For the years ended December 31, 2002 and
2001, the Company earned $1.6 million and $1.4 million, respectively, for such
services to each of DD LLC and DDII LLC. Such revenue amounts are included in
operating revenues in the consolidated statement of operations. At December 31,
2002, the Company had receivables from DD LLC and DDII LLC of $2.6 million and
$3.9 million, respectively, which are included in accounts receivable - other.
At December 31, 2001, the Company had receivables from DD LLC and DDII LLC of
$2.6 million and $2.3 million, respectively, which are included in accounts
receivable - other.

From time to time, the Company contracts the Deepwater Frontier from DDII
LLC. During this time, DDII LLC bills the Company for the full operating
dayrate and issues a non-cash credit for downtime hours in excess of 24 hours in
any calendar month. The Company records a dayrate rebate receivable for all such
non-cash credits and is responsible for payment of 100 percent of all drilling
contract invoices received. At the end of the drilling contract, the Company
will receive in cash the credits issued for downtime hours plus an escalation
factor. At December 31, 2002 and 2001, the cumulative dayrate rebate receivable
from DDII LLC totaled $15.1 million and $13.7 million, respectively, and is
recorded as investment in and advances to joint ventures in the consolidated
balance sheet. For the year ended December 31, 2001, the Company incurred $54.4
million net expense from DDII LLC under the drilling contract. This amount is
included in operating and maintenance expense in the Company's consolidated
statement of operations. The Company incurred no expense for the year ended
December 31, 2002 due to the expiration of its lease late in 2001. At December
31, 2002 and 2001, the Company had amounts payable to DDII LLC of $0.3 million
and $2.1 million, respectively, which is included in accounts payable in the
consolidated balance sheet.

At the expiration of the leases, each joint venture may purchase the rig
for $185 million, in the case of the Deepwater Pathfinder, and $194 million, in
the case of the Deepwater Frontier, or return the rig to the respective special
purpose entity that owns the rig. The Company would be obligated to pay only
the portion of such price equal to its percentage ownership interest in the
applicable joint venture. The Company's proportionate share for such purchase
options is $93 million and $116 million, respectively. Under each joint venture
agreement, the consent of each joint venture partner is generally required to
approve actions of the joint venture, including the exercise of this purchase
option. The scheduled expiration of the lease is December 2003, in the case of
the Deepwater Pathfinder, and March 2004, in the case of the Deepwater Frontier.
Each of the leases is subject to certain extension options of DD LLC and DDII
LLC, respectively.

If a joint venture returns the rig at the end of the lease, the special
purpose entity may sell the rig. In connection with the return, DD LLC may be
required to pay an amount up to $138 million and DDII LLC may be required to pay
an amount up to $145 million, plus certain expenses in each case. These payments
may be reduced by a portion of the proceeds of the sale of the applicable rig.
If an event of default occurs under the applicable lease agreements, each joint
venture may be required to pay an amount equal to the amount of debt and equity
financing owed by the applicable special purpose entity plus certain expenses.
At December 31, 2002, the debt and equity financing outstanding applicable to
the owner of Deepwater Pathfinder and of Deepwater Frontier, was $203 million
and $217 million, respectively. At December 31, 2001, the debt and equity
financing outstanding applicable to the owner of Deepwater Pathfinder and of
Deepwater Frontier, was $219 million and $236 million, respectively. The Company
and Conoco have guaranteed their respective share of DD LLC's obligation to pay
the debt and equity financing outstanding. In December 2001, Transocean became a
guarantor of the DDII LLC debt and equity financing through a refinancing of the
lease. Transocean and Conoco have guaranteed their respective share of DDII
LLC's obligation to pay the debt and equity financing outstanding.

Delta Towing-Immediately prior to the closing of the R&B Falcon merger,
TODCO formed a joint venture to own and operate its U.S. inland marine support
vessel business (the "Marine Business"). In connection with the formation of the
joint venture, the Marine Business was transferred by a subsidiary of TODCO to
Delta Towing LLC ("Delta Towing") in exchange for a 25 percent equity interest
in Delta Towing Holdings, LLC, the parent of Delta Towing, and certain secured
notes payable from Delta Towing. The secured notes consisted of (i) an $80.0
million principal amount note bearing interest at eight percent per annum due
January 30, 2024 (the "Tier 1 Note"), (ii) a contingent $20.0 million principal
amount note bearing interest at

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TRANSOCEAN INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED

eight percent per annum with an expiration date of January 30, 2011 (the "Tier 2
Note") and (iii) a contingent $44.0 million principal amount note bearing
interest at eight percent per annum with an expiration date of January 30, 2011
(the "Tier 3 Note"). The 75 percent equity interest holder in the joint venture
also loaned Delta Towing $3.0 million in the form of a Tier 1 Note. Until
January 2011, Delta Towing must use 100 percent of its excess cash flow towards
the payment of principal and interest on the Tier 1 Notes. After January 2011,
50 percent of its excess cash flows are to be applied towards the payment of
principal and unpaid interest on the Tier 1 Notes. Interest is due and payable
quarterly without regard to excess cash flow.

Delta Towing must repay at least (i) $8.3 million of the aggregate
principal amount of the Tier 1 Note no later than January 2004, (ii) $24.9
million of the aggregate principal amount no later than January 2006 and (iii)
$62.3 million of the aggregate principal amount no later than January 2008.
After the Tier 1 Note has been repaid, Delta Towing must apply 75 percent of its
excess cash flow towards payment of the Tier 2 Note. Upon the repayment of the
Tier 2 Note, Delta Towing must apply 50 percent of its excess cash to repay
principal and interest on the Tier 3 Note. Any amounts not yet due under the
Tier 2 and Tier 3 Notes at the time of their expiration will be waived. The
Tier 1, 2 and 3 Notes are secured by mortgages and liens on the vessels and
other assets of Delta Towing.

TODCO valued its Tier 1, 2 and 3 Notes at $80 million immediately prior to
the closing of the R&B Falcon merger, the effect of which was to fully reserve
the Tier 2 and 3 Notes. At both December 31, 2002 and 2001, $78.9 million was
outstanding under the Company's Tier 1 Note. For the years ended December 31,
2002 and 2001, the Company earned interest income on the outstanding balance at
each period of $6.3 million and $5.8 million, respectively, on the Tier 1 Note.
In December 2001, the note agreement was amended to provide for a $4.0 million,
three-year revolving credit facility (the "Delta Towing Revolver") from the
Company. Amounts drawn under the Delta Towing Revolver accrue interest at eight
percent per annum, with interest payable quarterly. For the year ended December
31, 2002, the Company earned $0.3 million of interest income on the Delta Towing
Revolver. At December 31, 2002, $3.9 million was outstanding under the Delta
Towing Revolver. At December 31, 2001, no amounts were outstanding under the
Delta Towing Revolver. At December 31, 2002 and 2001, the Company had interest
receivable from Delta Towing of $1.7 million and $1.6 million, respectively.
See Note 26.

As part of the formation of the joint venture on January 31, 2001, the
Company entered into an agreement with Delta Towing under which the Company
committed to charter certain vessels for a period of one year ending January 31,
2002 and committed to charter for a period of 2.5 years from the date of
delivery 10 crewboats then under construction, all of which had been placed into
service as of December 31, 2002. During the year ended December 31, 2002, the
Company incurred charges totaling $10.7 million from Delta Towing for services
rendered, of which $1.6 million was rebilled to the Company's customers and $9.1
million was reflected in operating and maintenance expense. During the year
ended December 31, 2001, the Company incurred charges totaling $15.6 million
from Delta Towing for services rendered, of which $6.5 million was rebilled to
the Company's customers and $9.1 million was reflected in operating and
maintenance.

ODL-In conjunction with the management and operation of the Joides
Resolution on behalf of ODL, the Company earned $1.2 million, $1.2 million and
$1.1 million for the years ended December 31, 2002, 2001 and 2000, respectively.
Such amounts are included in operating revenues in the Company's consolidated
statements of operations. At December 31, 2002 and 2001, the Company had
receivables from ODL of $1.2 million and $2.6 million, respectively, which were
recorded as accounts receivable - other in the consolidated balance sheets.

NOTE 22-RESTRUCTURING CHARGES

In September 2002, the Company committed to a restructuring plan to close
its engineering office in Montrouge, France. The Company established a liability
of $2.8 million for the estimated severance-related costs associated with the
involuntary termination of 15 employees pursuant to this plan. The charge was
reported as operating and maintenance expense in the International and U.S.
Floater Contract Drilling Services segment in the Company's consolidated
statements of operations. Through December 31, 2002, $1.7 million had been paid
to employees whose positions were eliminated as a result of this plan. The
Company anticipates that substantially all amounts will be paid by the end of
the first quarter of 2003.

In September 2002, the Company committed to a restructuring plan for a
staff reduction in Norway as a result of a decline in activity in that region.
The Company established a liability of $1.2 million for the estimated
severance-related costs associated with the involuntary termination of eight
employees pursuant to this plan. The charge was reported as operating and
maintenance expense in the International and U.S. Floater Contract Drilling
Services segment in the Company's consolidated statements of operations. Through
December 31, 2002, $0.1 million had been paid to employees whose positions are
being eliminated as a result of this plan. The Company anticipates that
substantially all amounts will be paid by the end of the first quarter of 2004.

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TRANSOCEAN INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED

In September 2002, the Company committed to a restructuring plan to
consolidate certain functions and offices utilized in its Gulf of Mexico Shallow
and Inland Water segment. The plan resulted in the closure of an administrative
office and warehouse in Louisiana and relocation of most of the operations and
administrative functions previously conducted at that location. The Company
established a liability of $1.2 million for the estimated severance-related
costs associated with the involuntary termination of 57 employees pursuant to
this plan. The charge was reported as operating and maintenance expense in the
Company's consolidated statements of operations. Through December 31, 2002, no
amounts had been paid to employees whose employment is being terminated as a
result of this plan. The Company anticipates that substantially all amounts will
be paid by the end of the first quarter of 2003.

NOTE 23-EARNINGS PER SHARE

The reconciliation of the numerator and denominator used for the
computation of basic and diluted earnings per share is as follows (in millions,
except per share data):

YEARS ENDED DECEMBER 31,
---------------------------
2002 2001 2000
---------- ------- ------

NUMERATOR FOR BASIC AND DILUTED EARNINGS (LOSS) PER SHARE
Income (Loss) Before Extraordinary Items and Cumulative Effect of a
Change in Accounting Principle. . . . . . . . . . . . . . . . . . . $(2,368.2) $271.9 $107.1
Gain (Loss) on Extraordinary Items, net of tax. . . . . . . . . . . . - (19.3) 1.4
Cumulative Effect of a Change in Accounting Principle . . . . . . . . (1,363.7) - -
---------- ------- ------
Net Income (Loss) . . . . . . . . . . . . . . . . . . . . . . . . . . $(3,731.9) $252.6 $108.5
========== ======= ======
DENOMINATOR FOR DILUTED EARNINGS (LOSS) PER SHARE
Weighted-average shares outstanding for basic earnings per share. . . 319.1 309.2 210.4
Effect of dilutive securities:
Employee stock options and unvested stock grants. . . . . . . . . . - 3.4 1.3
Warrants to purchase ordinary shares. . . . . . . . . . . . . . . . - 2.2 -
---------- ------- ------
Adjusted weighted-average shares and assumed
conversions for diluted earnings per share . . . . . . . . . . . . 319.1 314.8 211.7
========== ======= ======

BASIC EARNINGS (LOSS) PER SHARE
Income (Loss) Before Extraordinary Items and Cumulative Effect of a
Change in Accounting Principle. . . . . . . . . . . . . . . . . . . $ (7.42) $ 0.88 $ 0.51
Gain (Loss) on Extraordinary Items, net of tax . . . . . . . . . . . - (0.06) 0.01
Cumulative Effect of a Change in Accounting Principle. . . . . . . . (4.27) - -
---------- ------- ------
Net Income (Loss). . . . . . . . . . . . . . . . . . . . . . . . . . $ (11.69) $ 0.82 $ 0.52
========== ======= ======

DILUTED EARNINGS (LOSS) PER SHARE
Income (Loss) Before Extraordinary Items and Cumulative Effect of a
Change in Accounting Principle. . . . . . . . . . . . . . . . . . . $ (7.42) $ 0.86 $ 0.50
Gain (Loss) on Extraordinary Items, net of tax . . . . . . . . . . . - (0.06) 0.01
Cumulative Effect of a Change in Accounting Principle. . . . . . . . (4.27) - -
---------- ------- ------
Net Income (Loss). . . . . . . . . . . . . . . . . . . . . . . . . . $ (11.69) $ 0.80 $ 0.51
========== ======= ======

-90-

TRANSOCEAN INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED

Ordinary shares subject to issuance pursuant to the conversion features of
the convertible debentures (see Note 8) are not included in the calculation of
adjusted weighted-average shares and assumed conversions for diluted earnings
per share because the effect of including those shares is anti-dilutive for all
periods presented. Incremental shares related to stock options, restricted stock
grants and warrants are not included in the calculation of adjusted
weighted-average shares and assumed conversions for diluted earnings per share
because the effect of including those shares is anti-dilutive for the year ended
December 31, 2002.

NOTE 24-STOCK WARRANTS

In connection with the R&B Falcon merger, the Company assumed the then
outstanding R&B Falcon stock warrants. Each warrant enables the holder to
purchase 17.5 ordinary shares at an exercise price of $19.00 per share. The
warrants expire on May 1, 2009. In 2001, the Company received $10.6 million and
issued 560,000 ordinary shares as a result of 32,000 warrants being exercised.
At December 31, 2002 there were 261,000 warrants outstanding to purchase
4,567,500 ordinary shares.

NOTE 25-QUARTERLY RESULTS (UNAUDITED)

Shown below are selected unaudited quarterly data (in millions, except per
share data):

QUARTER FIRST SECOND THIRD FOURTH
------- ---------- ------ -------- ----------

2002
Operating Revenues. . . . . . . . . . . . . . . . . $ 667.9 $646.2 $ 695.2 $ 664.6
Operating Income (Loss) (a) . . . . . . . . . . . . 142.3 139.0 136.1 (2,727.3)
Income (Loss) Before Cumulative Effect of a Change
in Accounting Principle . . . . . . . . . . . . . 77.3 80.0 255.2 (2,780.7)
Net Income (Loss) (b) . . . . . . . . . . . . . . . (1,286.4) 80.0 255.2 (2,780.7)
Basic Earnings (Loss) Per Share
Income (Loss) Before Cumulative Effect of a
Change in Accounting Principle. . . . . . . . $ 0.24 $ 0.25 $ 0.80 $ (8.71)
Diluted Earnings (Loss) Per Share
Income (Loss) Before Cumulative Effect of a
Change in Accounting Principle. . . . . . . . $ 0.24 $ 0.25 $ 0.79 $ (8.71)
Weighted Average Shares Outstanding
Shares for basic earnings per share . . . . . . . 319.1 319.1 319.2 319.2
Shares for diluted earnings per share . . . . . . 323.1 323.9 328.8 319.2

2001
Operating Revenues. . . . . . . . . . . . . . . . . $ 550.1 $752.2 $ 770.2 $ 747.6
Operating Income (c). . . . . . . . . . . . . . . . 74.5 178.2 179.8 117.5
Income Before Extraordinary Items . . . . . . . . . 30.5 85.8 97.6 58.0
Net Income (d). . . . . . . . . . . . . . . . . . . 30.5 68.5 97.6 56.0
Basic Earnings Per Share
Income Before Extraordinary Items . . . . . . . . $ 0.11 $ 0.27 $ 0.31 $ 0.19
Diluted Earnings Per Share
Income Before Extraordinary Items . . . . . . . . $ 0.11 $ 0.26 $ 0.30 $ 0.19
Weighted Average Shares Outstanding (e)
Shares for basic earnings per share . . . . . . . 280.6 318.2 318.7 318.7
Shares for diluted earnings per share . . . . . . 285.5 325.0 322.7 322.7

___________________________
(a) Third quarter 2002 included loss on impairments of $40.9 million. Fourth
quarter 2002 included loss on impairments of $2,885.4 million. See Note 7.

-91-

TRANSOCEAN INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED

(b) First quarter 2002 included a cumulative effect of a change in accounting
principle of $1,363.7 million relating to the impairment of goodwill (see
Note 2). Third quarter 2002 included a foreign tax benefit of $176.2
million (see Note 15).

(c) First quarter 2001 included two months of operating results for TODCO and
the second, third and fourth quarters of 2001 included three months of
operating results of TODCO, respectively. Fourth quarter 2001 included
impairment charges (see Note 7) and gain on sale of RBF FPSO L.P. (see Note
6).

(d) Second and fourth quarter 2001 included extraordinary losses of $17.3
million and $2.0 million, net of income taxes, respectively, relating to
the early retirement of debt.

(e) First quarter 2001 included the weighted-average effect of approximately
106 million ordinary shares issued on January 31, 2001 in the R&B Falcon
merger (see Note 4).

NOTE 26-SUBSEQUENT EVENTS (UNAUDITED)

Initial Public Offering-The Company is continuing with its previously
announced plans to divest its Gulf of Mexico Shallow and Inland Water business.
Under this plan, the Gulf of Mexico Shallow and Inland Water business would be
separated from the Company and established as a publicly traded company. The
Company currently anticipates that it will establish TODCO as the entity that
owns the business. The Company intends to transfer assets not used in this
business from TODCO to its other subsidiaries and these transfers will not
affect the consolidated financial statements of Transocean. The Company expects
to sell a portion of its interest in TODCO in an initial public offering when
market conditions warrant, subject to various factors. Given the current general
uncertainty in the equity and natural gas drilling markets, the Company is
unsure when the transaction could be completed on terms acceptable to it.

Asset Dispositions-In January 2003, the Company completed the sale of the
jackup rig, RBF 160, to a third party for net proceeds of $13.0 million and
recognized a net after-tax gain on sale of $0.2 million. The proceeds were
received in December 2002 and were reflected as deferred income and proceeds
from asset sales in the consolidated balance sheet and consolidated statement of
cash flow, respectively.

Delta Towing-In January 2003, Delta Towing failed to make its scheduled
quarterly interest payment of $1.7 million on the notes receivable. See Note
21. The Company has signed a 90-day waiver on the terms for payment of
interest.

Termination of Interest Rate Swaps-In January 2003, the Company terminated
the swaps with respect to its 6.75% Senior Notes due April 2005, 6.95% Senior
Notes due April 2008 and 9.5% Senior Notes due December 2008. In March 2003, the
Company terminated the swaps with respect to its 6.625% Notes due April 2011.
See Note 10. As a result of these terminations, the Company received cash
proceeds of $173.5 million, net of accrued interest, which will be recognized as
a fair value adjustment to long-term debt in the Company's consolidated balance
sheet and amortized as a reduction to interest expense over the life of the
underlying debt. For the year ended December 31, 2003, the amount to be
amortized as an adjustment to interest expense will be approximately $23.1
million.

Foreign Currency-Venezuela has recently implemented foreign exchange
controls that limit the Company's ability to convert local currency into U.S.
dollars and transfer excess funds out of Venezuela. The Company's drilling
contracts in Venezuela typically call for payments to be made in local currency,
even when the dayrate is denominated in U.S. dollars. The exchange controls
could also result in an artificially high value being placed on the local
currency.

-92-

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

The Company has not had a change in or disagreement with its accountants
within 24 months prior to the date of its most recent financial statements or in
any period subsequent to such date.

PART III

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 SHAREHOLDER MATTERS

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

The information required by Items 10, 11, 12 and 13 is incorporated herein
by reference to the Company's definitive proxy statement for its 2003 annual
general meeting of shareholders, which will be filed with the Securities and
Exchange Commission pursuant to Regulation 14A under the Securities Exchange Act
of 1934 within 120 days of December 31, 2002. Certain information with respect
to the executive officers of the Company is set forth in Item 4 of this annual
report under the caption "Executive Officers of the Registrant."

ITEM 14. CONTROLS AND PROCEDURES

Within the 90 days prior to the date of this report, the Company carried
out an evaluation, under the supervision and with the participation of the
Company's management, including the Chief Executive Officer and Chief Financial
Officer, of the effectiveness of the design and operation of the Company's
disclosure controls and procedures pursuant to Exchange Act Rule 13a-14. Based
on that evaluation, the Chief Executive Officer and the Chief Financial Officer
concluded that the Company's disclosure controls and procedures are effective in
timely alerting them to material information relating to the Company (including
its consolidated subsidiaries) required to be included in the Company's periodic
SEC filings. Subsequent to the date of their evaluation, there were no
significant changes in the Company's internal controls or in other factors that
could significantly affect the internal controls, including any corrective
actions with regard to significant deficiencies and material weaknesses.

PART IV

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

PAGE
----
Included in Part II of this report:
Report of Independent Auditors. . . . . . . . . . . . . . . . 50
Consolidated Statements of Operations . . . . . . . . . . . . 51
Consolidated Statements of Comprehensive Income (Loss). . . 52
Consolidated Balance Sheets. . . . . . . . . . . . . . . . . . 53
Consolidated Statements of Equity . . . . . . . . . . . . . . 54
Consolidated Statements of Cash Flows. . . . . . . . . . . . 55
Notes to Consolidated Financial Statements . . . . . . . . . 57

Financial statements of unconsolidated joint ventures are not presented
herein because such joint ventures do not meet the significance test.

(2) Financial Statement Schedules

-93-

TRANSOCEAN INC. AND SUBSIDIARIES
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
(IN MILLIONS)

ADDITIONS
---------------------
CHARGED CHARGED
BALANCE AT TO COSTS TO OTHER BALANCE AT
BEGINNING AND ACCOUNTS DEDUCTIONS END OF
OF PERIOD EXPENSES DESCRIBE DESCRIBE PERIOD
----------- --------- ---------- ---------- --------

Year Ended December 31, 2000
Reserves and allowances deducted from asset
Accounts:
Allowance for doubtful accounts
Receivable . . . . . . . . . . . . . . . $ 27.1 $ 20.0 $ 0.2 (a) $ 23.0 (a) $ 24.3

Allowance for obsolete materials and
Supplies . . . . . . . . . . . . . . . . 23.1 0.3 (0.2)(c) (0.1) (b)(d) 23.3

Year Ended December 31, 2001
Reserves and allowances deducted from asset
Accounts:
Allowance for doubtful accounts
Receivable . . . . . . . . . . . . . . . 24.3 12.0 14.9 (e) 27.0 (a)(g) 24.2

Allowance for obsolete materials and
Supplies . . . . . . . . . . . . . . . . 23.3 - 9.2 (f) 8.4 (b)(h) 24.1

Year Ended December 31, 2002
Reserves and allowances deducted from asset
Accounts:
Allowance for doubtful accounts
Receivable . . . . . . . . . . . . . . . 24.2 16.6 - 20.0 (a) 20.8

Allowance for obsolete materials and
Supplies . . . . . . . . . . . . . . . . $ 24.1 $ 0.3 $ 0.7 (i) $ 6.5 (b)(j)(k) $ 18.6

_____________________________
(a) Uncollectible accounts receivable written off, net of recoveries.
(b) Obsolete materials and supplies written off, net of scrap.
(c) Amount includes $0.4 related to a write-off to assets held for sale.
(d) Amount includes $0.7 related to reversals of prior year write-offs.
(e) Amount includes $15.0 relating to the allowance for doubtful accounts receivable assumed in the R&B Falcon merger.
(f) Amount includes $8.7 relating to the obsolete materials and supplies inventory assumed in the R&B Falcon merger.
(g) Amount includes $4.9 related to adjustments to the provision.
(h) Amount includes $2.7 related to sale of rigs.
(i) Amount includes $0.4 related to adjustments to the provision.
(j) Amount includes $0.8 related to sale of rigs/inventory.
(k) Amount includes $3.7 related to adjustments to the provision.

Other schedules are omitted either because they are not required or are not
applicable or because the required information is included in the financial
statements or notes thereto.

-94-

(3) Exhibits

The following exhibits are filed in connection with this Report:

NUMBER DESCRIPTION
---------------------

2.1 Agreement and Plan of Merger dated as of August 19, 2000 by and among
Transocean Inc., Transocean Holdings Inc., TSF Delaware Inc. and R&B
Falcon Corporation (incorporated by reference to Annex A to the Joint
Proxy Statement/Prospectus dated October 30, 2000 included in a
424(b)(3) prospectus filed by the Company on November 1, 2000)

2.2 Agreement and Plan of Merger dated as of July 12, 1999 among
Schlumberger Limited, Sedco Forex Holdings Limited, Transocean
Offshore Inc. and Transocean SF Limited (incorporated by reference to
Annex A to the Joint Proxy Statement/Prospectus dated October 27,
included in a 424(b)(3) prospectus filed by the Company on November 1,
2000)

2.3 Distribution Agreement dated as of July 12, 1999 between Schlumberger
Limited and Sedco Forex Holdings Limited (incorporated by reference to
Annex B to the Joint Proxy Statement/Prospectus dated October 27,
included in a 424(b)(3) prospectus filed by the Company on November 1,
2000)

2.4 Agreement and Plan of Merger and Conversion dated as of March 12, 1999
between Transocean Offshore Inc. and Transocean Offshore (Texas) Inc.
(incorporated by reference to Exhibit 2.1 to the Registration
Statement on Form S-4 of Transocean Offshore (Texas) Inc. filed on
April 8, 1999 (Registration No. 333-75899))

2.5 Agreement and Plan of Merger dated as of July 10, 1997 among R&B
Falcon, FDC Acquisition Corp., Reading & Bates Acquisition Corp.,
Falcon Drilling Company, Inc. and Reading & Bates Corporation
(incorporated by reference to Exhibit 2.1 to R&B Falcon's Registration
Statement on Form S-4 dated November 20, 1997)

2.6 Agreement and Plan of Merger dated as of August 21, 1998 by and among
Cliffs Drilling Company, R&B Falcon Corporation and RBF Cliffs
Drilling Acquisition Corp. (incorporated by reference to Exhibit 2 to
R&B Falcon's Registration Statement No. 333-63471 on Form S-4 dated
September 15, 1998)

3.1 Memorandum of Association of Transocean Sedco Forex Inc., as amended
(incorporated by reference to Annex E to the Joint Proxy
Statement/Prospectus dated October 30, 2000 included in a 424(b)(3)
prospectus filed by the Company on November 1, 2000)

3.2 Articles of Association of Transocean Sedco Forex Inc., as amended
(incorporated by reference to Annex F to the Joint Proxy
Statement/Prospectus dated October 30, 2000 included in a 424(b)(3)
prospectus filed by the Company on November 1, 2000)

3.3 Certificate of Incorporation on Change of Name to Transocean Inc.
(incorporated by reference to Exhibit 3.3 to the Company's Form 10-Q
for the quarter ended June 30, 2002)

4.1 Credit Agreement dated as of December 16, 1999 among Transocean
Offshore Inc., the Lenders party thereto, and SunTrust Bank, Atlanta,
as Agent (incorporated by reference to Exhibit 4.6 to the Company's
Form 10-K for the year ended December 31, 1997)

4.2 Indenture dated as of April 15, 1997 between the Company and Texas
Commerce Bank National Association, as trustee (incorporated by
reference to Exhibit 4.1 to the Company's Form 8-K dated April 29,
1997)

4.3 First Supplemental Indenture dated as of April 15, 1997 between the
Company and Texas Commerce Bank National Association, as trustee,
supplementing the Indenture dated as of April 15, 1997 (incorporated
by reference to Exhibit 4.2 to the Company's Form 8-K dated April 29,
1997)

4.4 Second Supplemental Indenture dated as of May 14, 1999 between the
Company and Chase Bank of Texas, National Association, as trustee
(incorporated by reference to Exhibit 4.5 to the Company's
Post-Effective Amendment No. 1 to Registration Statement on Form S-3
(Registration No. 333-59001-99))

-95-

4.5 Third Supplemental Indenture dated as of May 24, 2000 between the
Company and Chase Bank of Texas, National Association, as trustee
(incorporated by reference to Exhibit 4.1 to the Company's Current
Report on Form 8-K filed on May 24, 2000)

4.6 Fourth Supplemental Indenture dated as of May 11, 2001 between the
Company and The Chase Manhattan Bank (incorporated by reference to
Exhibit 4.3 to the Company's Quarterly Report on Form 10-Q for the
quarter ended March 31, 2001)

4.7 Form of 7.45% Notes due April 15, 2027 (incorporated by reference to
Exhibit 4.3 to the Company's Form 8-K dated April 29, 1997)

4.8 Form of 8.00% Debentures due April 15, 2027 (incorporated by reference
to Exhibit 4.4 to the Company's Form 8-K dated April 19, 1997)

4.9 Form of Zero Coupon Convertible Debenture due May 24, 2020 between the
Company and Chase Bank of Texas, National Association, as trustee
(incorporated by reference to Exhibit 4.1 to the Company's Current
Report on Form 8-K filed on May 24, 2000)

4.10 Form of 1.5% Convertible Debenture due May 15, 2021 (incorporated by
reference to Exhibit 4.2 to the Company's Current Report on Form 8-K
dated May 8, 2001)

4.11 Form of 6.625% Note due April 15, 2011 (incorporated by reference to
Exhibit 4.3 to the Company's Current Report on Form 8-K dated March
30, 2001)

4.12 Form of 7.5% Note due April 15, 2031 (incorporated by reference to
Exhibit 4.3 to the Company's Current Report on Form 8-K dated March
30, 2001)

4.13 Officers' Certificate establishing the terms of the 6.50% Notes due
2003, 6.75% Notes due 2005, 6.95% Notes due 2008, 7.375% Notes due
2018, 9.125% Notes due 2003 and 9.50% Notes due 2008 (incorporated by
reference to Exhibit 4.13 to the Company's Annual Report on Form 10-K
for the fiscal year ended December 31, 2001)

4.14 Officers' Certificate establishing the terms of the 7.375% Notes due
2018 (incorporated by reference to Exhibit 4.14 to the Company's
Annual Report on Form 10-K for the fiscal year ended December 31,
2001)

4.15 Indenture dated as of April 14, 1998, between R&B Falcon Corporation,
as issuer, and Chase Bank of Texas, National Association, as trustee,
with respect to Series A and Series B of each of $250,000,000 6 1/2%
Senior Notes due 2003, $350,000,000 6 3/4% Senior Notes due 2005,
$250,000,000 6.95% Senior Notes due 2008, and $250,000,000 7 3/8%
Senior Notes due 2018 (incorporated by reference to Exhibit 4.1 to R&B
Falcon's Registration Statement No. 333-56821 on Form S-4 dated June
15, 1998)

4.16 First Supplemental Indenture dated as of February 14, 2002 between R&B
Falcon Corporation and The Bank of New York (incorporated by reference
to Exhibit 4.16 to the Company's Annual Report on Form 10-K for the
fiscal year ended December 31, 2001)

4.17 Second Supplemental Indenture dated as of March 13, 2002 between R&B
Falcon Corporation and The Bank of New York (incorporated by reference
to Exhibit 4.17 to the Company's Annual Report on Form 10-K for the
fiscal year ended December 31, 2001)

4.18 Indenture dated as of December 22, 1998, between R&B Falcon
Corporation, as issuer, and Chase Bank of Texas, National Association,
as trustee, with respect to $400,000,000 Series A and Series B 9 1/8%
Senior Notes due 2003, and 9 1/2% Senior Notes due 2008 (incorporated
by reference to Exhibit 4.21 to R&B Falcon's Annual Report on Form
10-K for 1998)

4.19 First Supplemental Indenture dated as of February 14, 2002 between R&B
Falcon Corporation and The Bank of New York (incorporated by reference
to Exhibit 4.19 to the Company's Annual Report on Form 10-K for the
fiscal year ended December 31, 2001)

-96-

4.20 Warrant Agreement, including form of Warrant, dated April 22, 1999
between R&B Falcon and American Stock Transfer & Trust Company
(incorporated by reference to Exhibit 4.1 to R&B Falcon's Registration
Statement No. 333-81181 on Form S-3 dated June 21, 1999)

4.21 Supplement to Warrant Agreement dated January 31, 2001 among
Transocean Sedco Forex Inc., R&B Falcon Corporation and American Stock
Transfer & Trust Company (incorporated by reference to Exhibit 4.28 to
the Company's Annual Report on Form 10-K for the year ended December
31, 2000)

4.22 Registration Rights Agreement dated April 22, 1999 between R&B Falcon
and American Stock Transfer & Trust Company (incorporated by reference
to Exhibit 4.2 to R&B Falcon's Registration Statement No. 333-81181 on
Form S-3 dated June 21, 1999)

4.23 Supplement to Registration Rights Agreement dated January 31, 2001
between Transocean Sedco Forex Inc. and R&B Falcon Corporation
(incorporated by reference to Exhibit 4.30 to the Company's Annual
Report on Form 10-K for the year ended December 31, 2000)

4.24 Exchange and Registration Rights Agreement dated April 5, 2001 by and
between the Company and Goldman, Sachs & Co., as representatives of
the initial purchasers (incorporated by reference to the Company's
Current Report on Form 8-K dated March 30, 2001)

4.25 Credit Agreement dated as of December 29, 2000 among the Company, the
Lenders party thereto, Suntrust Bank, as Administrative Agent, ABN
AMRO Bank, N.V., as Syndication Agent, Bank of America, N.A., as
Documentation Agent, and Wells Fargo Bank Texas, National Association,
as Senior Managing Agent (incorporated by reference to Exhibit 4.32 to
the Company's Annual Report on Form 10-K for the year ended December
31, 2000)

4.26 364-Day Credit Agreement dated as of December 27, 2001 among the
Company, the Lenders party thereto, Suntrust Bank, as Administrative
Agent, ABN AMRO Bank, N.V., as Syndication Agent, Bank of America,
N.A., as Documentation Agent, and Wells Fargo Bank Texas, National
Association, as Senior Managing Agent (incorporated by reference to
Exhibit 4.26 to the Company's Annual Report on Form 10-K for the
fiscal year ended December 31, 2001)

4.27 Note Agreement dated as of January 30, 2001 among Delta Towing, LLC,
as Borrower, R&B Falcon Drilling USA, Inc., as RBF Noteholder and Beta
Marine Services, L.L.C., as Beta Noteholder (incorporated by reference
to Exhibit 4.35 to the Company's Annual Report on Form 10-K for the
year ended December 31, 2000)

4.28 Trust Indenture and Security Agreement dated as of August 12, 1999
between RBF Exploration Co., a Nevada corporation, and Chase Bank of
Texas, National Association, as trustee (incorporated by reference to
Exhibit 10.6 to R&B Falcon's Quarterly Report on Form 10-Q for the
quarter ended September 30, 1999)

4.29 Supplemental Indenture and Amendment dated as of February 1, 2000 to
the Trust Indenture and Security Agreement dated as of August 12, 1999
among RBF Exploration Co., BTM Capital Corporation and Chase Bank of
Texas, National Association, as trustee (incorporated by reference to
Exhibit 10.251 to R&B Falcon's Annual Report on Form 10-K for the year
ended December 31, 1999)

4.30 Second Supplemental Indenture and Amendment dated as of June 2, 2000
among RBF Exploration Co., BTM Capital Corporation, Nautilus
Exploration Limited, R&B Falcon Deepwater (UK) Limited and Chase Bank
of Texas, National Association, as trustee (incorporated by reference
to Exhibit 4.30 to the Company's Annual Report on Form 10-K for the
fiscal year ended December 31, 2001)

4.31 Third Supplemental Indenture and Amendment dated as of February 20,
2001 among RBF Exploration Co., BTM Capital Corporation, RBF Nautilus
Corporation, Nautilus Exploration Limited, R&B Falcon Deepwater (UK)
Limited and The Chase Manhattan Bank, as trustee (incorporated by
reference to Exhibit 4.31 to the Company's Annual Report on Form 10-K
for the fiscal year ended December 31, 2001)

10.1 Tax Sharing Agreement between Sonat Inc. and Sonat Offshore Drilling
Inc. dated June 3, 1993 (incorporated by reference to Exhibit 10-(3)
to the Company's Form 10-Q for the quarter ended June 30, 1993)

-97-

*10.2 Performance Award and Cash Bonus Plan of Sonat Offshore Drilling Inc.
(incorporated by reference to Exhibit 10-(5) to the Company's Form
10-Q for the quarter ended June 30, 1993)

*10.3 Form of Sonat Offshore Drilling Inc. Executive Life Insurance Program
Split Dollar Agreement and Collateral Assignment Agreement
(incorporated by reference to Exhibit 10-(9) to the Company's Form
10-K for the year ended December 31, 1993)

*10.4 Employee Stock Purchase Plan, as amended and restated effective
January 1, 2000 (incorporated by reference to Exhibit 4.4 to the
Company's Registration Statement on Form S-8 (Registration No.
333-94551) filed January 12, 2000)

*10.5 First Amendment to the Amended and Restated Employee Stock Purchase
Plan of Transocean Inc., effective as of January 31, 2001
(incorporated by reference to Exhibit 10.7 to the Company's Annual
Report on Form 10-K for the year ended December 31, 2000)

*10.6 Long-Term Incentive Plan of Transocean Inc., as amended and restated
effective January 1, 2000 (incorporated by reference to Annex B to the
Company's Proxy Statement dated April 3, 2001)

*10.7 First Amendment to the Amended and Restated Long-Term Incentive Plan
of Transocean Inc., effective as of January 31, 2001 (incorporated by
reference to Exhibit 10.9 to the Company's Annual Report on Form 10-K
for the year ended December 31, 2000)

*10.8 Second Amendment to the Amended and Restated Long-Term Incentive Plan
of Transocean Inc., effective May 11, 2001 (incorporated by reference
to Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q for the
quarter ended June 30, 2001)

*10.9 Form of Employment Agreement dated May 14, 1999 between J. Michael
Talbert, Robert L. Long, Donald R. Ray, Eric B. Brown and Barbara S.
Koucouthakis, individually, and the Company (incorporated by reference
to Exhibit 10.1 to the Company's Form 10-Q for the quarter ended June
30, 1999)

*10.10 Deferred Compensation Plan of Transocean Offshore Inc., as amended
and restated effective January 1, 2000 (incorporated by reference to
Exhibit 10.10 to the Company's Annual Report on Form 10-K for the year
ended December 31, 1999.)

*10.11 Employment Matters Agreement dated as of December 13, 1999 among
Schlumberger Limited, Sedco Forex Holdings Limited and Transocean
Offshore Inc. (incorporated by reference to Exhibit 4.3 to the
Company's Registration Statement on Form S-8 (Registration No.
333-94551) filed January 12, 2000)

*10.12 Sedco Forex Employees Option Plan of Transocean Sedco Forex Inc.
effective December 31, 1999 (incorporated by reference to Exhibit 4.5
to the Company's Registration Statement on Form S-8 (Registration No.
333-94569) filed January 12, 2000)

*10.13 Employment Agreement dated September 22, 2000 between J. Michael
Talbert and Transocean Offshore Deepwater Drilling Inc. (incorporated
by reference to Exhibit 10.1 to the Company's Form 10-Q for the
quarter ended September 30, 2000)

*10.14 Employment Agreement dated October 3, 2000 between Jon C. Cole and
Transocean Offshore Deepwater Drilling Inc. (incorporated by reference
to Exhibit 10.2 to the Company's Form 10-Q for the quarter ended
September 30, 2000)

*10.15 Agreement dated October 10, 2002 by and among Transocean Inc.,
Transocean Offshore Deepwater Drilling Inc. and J. Michael Talbert
(incorporated by reference to Exhibit 99.2 to the Company's Current
Report on Form 8-K dated October 10, 2002)

*10.16 Employment Agreement dated September 17, 2000 between Robert L. Long
and Transocean Offshore Deepwater Drilling Inc. (incorporated by
reference to Exhibit 10.3 to the Company's Form 10-Q for the quarter
ended September 30, 2000)

-98-

*10.17 Agreement dated May 9, 2002 by and among Transocean Offshore Deepwater
Drilling Inc. and Robert L. Long (incorporated by reference to Exhibit
99.4 to the Company's Current Report on Form 8-K dated October 10,
2002)

*10.18 Employment Agreement dated September 26, 2000 between Donald R. Ray
and Transocean Offshore Deepwater Drilling Inc. (incorporated by
reference to Exhibit 10.4 to the Company's Form 10-Q for the quarter
ended September 30, 2000)

*10.19 Employment Agreement dated October 8, 2000 between W. Dennis Heagney
and Transocean Offshore Deepwater Drilling Inc. (incorporated by
reference to Exhibit 10.5 to the Company's Form 10-Q for the quarter
ended September 30, 2000)

*10.20 Employment Agreement dated September 20, 2000 between Eric B. Brown
and Transocean Offshore Deepwater Drilling Inc. (incorporated by
reference to Exhibit 10.6 to the Company's Form 10-Q for the quarter
ended September 30, 2000)

*10.21 Employment Agreement dated October 4, 2000 between Barbara S.
Koucouthakis and Transocean Offshore Deepwater Drilling Inc.
(incorporated by reference to Exhibit 10.7 to the Company's Form 10-Q
for the quarter ended September 30, 2000)

*10.22 Employment Agreement dated July 15, 2002 by and among R&B Falcon
Corporation, R&B Falcon Management Services, Inc. and Jan Rask
(incorporated by reference to Exhibit 10.1 to the Company's Form 10-Q
for the quarter ended June 30, 2002)

*10.23 Consulting Agreement dated January 31, 2001 between Paul B. Loyd, Jr.
and R&B Falcon Corporation (incorporated by reference to Exhibit 10.21
to the Company's Annual Report on Form 10-K for the year ended
December 31, 2000)

*10.24 Consulting Agreement dated December 13, 1999 between Victor E.
Grijalva and Transocean Offshore Inc. (incorporated by reference to
Exhibit 10.21 to the Company's Annual Report on Form 10-K for the year
ended December 31, 2001)

*10.25 Amendment to Consulting Agreement between Transocean Offshore Inc.
(now known as Transocean Inc.) and Victor E. Grijalva dated October
10, 2002 (incorporated by reference to Exhibit 99.3 to the Company's
Current Report on Form 8-K dated October 10, 2002)

*10.26 1992 Long-Term Incentive Plan of Reading & Bates Corporation
(incorporated by reference to Exhibit B to Reading & Bates' Proxy
Statement dated April 27, 1992)

*10.27 1995 Long-Term Incentive Plan of Reading & Bates Corporation
(incorporated by reference to Exhibit 99.A to Reading & Bates' Proxy
Statement dated March 29, 1995)

*10.28 1995 Director Stock Option Plan of Reading & Bates Corporation
(incorporated by reference to Exhibit 99.B to Reading & Bates' Proxy
Statement dated March 29, 1995)

*10.29 1997 Long-Term Incentive Plan of Reading & Bates Corporation
(incorporated by reference to Exhibit 99.A to Reading & Bates' Proxy
Statement dated March 18, 1997)

*10.30 1998 Employee Long-Term Incentive Plan of R&B Falcon Corporation
(incorporated by reference to Exhibit 99.A to R&B Falcon's Proxy
Statement dated April 23,1998)

*10.31 1998 Director Long-Term Incentive Plan of R&B Falcon Corporation
(incorporated by reference to Exhibit 99.B to R&B Falcon's Proxy
Statement dated April 23,1998)

*10.32 1999 Employee Long-Term Incentive Plan of R&B Falcon Corporation
(incorporated by reference to Exhibit 99.A to R&B Falcon's Proxy
Statement dated April 13, 1999)

*10.33 1999 Director Long-Term Incentive Plan of R&B Falcon Corporation
(incorporated by reference to Exhibit 99.B to R&B Falcon's Proxy
Statement dated April 13, 1999)

-99-

10.34 Memorandum of Agreement dated November 28, 1995 between Reading and
Bates, Inc., a subsidiary of Reading & Bates Corporation, and Deep Sea
Investors, L.L.C. (incorporated by reference to Exhibit 10.110 to
Reading & Bates' Annual Report on Form 10-K for 1995)

10.35 Amended and Restated Bareboat Charter dated July 1, 1998 to Bareboat
Charter M. G. Hulme, Jr. dated November 28, 1995 between Deep Sea
Investors, L.L.C. and Reading & Bates Drilling Co., a subsidiary of
Reading & Bates Corporation (incorporated by reference to Exhibit
10.177 to R&B Falcon's Annual Report on Form 10-K for the year ended
December 31, 1998)

10.36 Limited Liability Company Agreement dated October 28, 1996 between
Conoco Development Company and RB Deepwater Exploration Inc.
(incorporated by reference to Exhibit 10.162 to Reading & Bates'
Annual Report on Form 10-K for the year ended December 31, 1996)

10.37 Amendment No. 1 dated February 7, 1997 to Limited Liability Company
Agreement dated October 28, 1996 between Conoco Development Company
and RB Deepwater Exploration Inc. (incorporated by reference to
Exhibit 10.183 to R&B Falcon's Annual Report on Form 10-K for the year
ended December 31, 1998)

10.38 Amendment No. 2 dated April 30, 1997 to Limited Liability Company
Agreement dated October 28, 1996 between Conoco Development Company
and RB Deepwater Exploration Inc. (incorporated by reference to
Exhibit 10.184 to R&B Falcon's Annual Report on Form 10-K for the year
ended December 31, 1998)

10.39 Amendment No. 3 dated April 24, 1998 to Limited Liability Company
Agreement dated October 28, 1996 between Conoco Development Company
and RB Deepwater Exploration Inc. (incorporated by reference to
Exhibit 10.185 to R&B Falcon's Annual Report on Form 10-K for the year
ended December 31, 1998)

10.40 Amendment No. 4 dated August 7, 1998 to Limited Liability Company
Agreement dated October 28, 1996 between Conoco Development Company
and RB Deepwater Exploration Inc. (incorporated by reference to
Exhibit 10.186 to R&B Falcon's Annual Report on Form 10-K for the year
ended December 31, 1998)

10.41 Participation Agreement dated as of July 30, 1998 among Deepwater
Drilling L.L.C., Deepwater Investment Trust 1998-A, Wilmington Trust
FSB and other Financial Institutions, as Certificate Purchasers, and
RBF Deepwater Exploration Inc. and Conoco Development Company solely
with respect to Sections 5.2 and 6.4 (incorporated by reference to
Exhibit 10.37 to the Company's Annual Report on Form 10-K for the
fiscal year ended December 31, 2001)

10.42 Limited Liability Company Agreement dated April 30, 1997 between
Conoco Development II Inc. and RB Deepwater Exploration II Inc.
(incorporated by reference to Exhibit 10.159 to R&B Falcon's Annual
Report on Form 10-K for the year ended December 31, 1997)

10.43 Amendment No. 1 dated April 24, 1998 to Limited Liability Company
Agreement dated April 30, 1997 between Conoco Development II Inc. and
RB Deepwater Exploration II Inc. (incorporated by reference to Exhibit
10.188 to R&B Falcon's Annual Report on Form 10-K for the year ended
December 31, 1998)

10.44 Guaranty, dated as of July 30, 1998, made by R&B Falcon in favor of
the Deepwater Investment Trust 1998-A, Wilmington Trust FSB, not in
its individual capacity, but solely as Investment Trustee, Wilmington
Trust Company, not in its individual capacity, except as specified
herein, but solely as Charter Trustee, BA Leasing & Capital
Corporation, as Documentation Agent, ABN Amro Bank N.V., as
Administrative Agent, The Bank of Nova Scotia, as Syndication Agent,
BA Leasing & Capital Corporation, ABN Amro Bank N.V., Bank Austria
Aktiengesellschaft New York Branch, The Bank of Nova Scotia,
Bayerische Vereinsbank AG New York Branch, Commerzbank
Aktiengesellschaft, Atlanta Agency, Credit Lyonnais New York Branch,
Great-West Life and Annuity Insurance Company, Mees Pierson Capital
Corporation, Westdeutsche Landesbank Girozentrale, New York Branch, as
Certificate Purchasers, and ABN Amro Bank, N.V., Bank of America
National Trust and Savings Association and The Bank of Nova Scotia,
New York Branch, as Swap Counterparties, and the other parties named
therein (incorporated by reference to Exhibit 10.1 to R&B Falcon's
Quarterly Report on Form 10-Q for the quarter ended September 30,
1998)

10.45 Letter agreement dated as of August 7, 1998 between RBF Deepwater
Exploration Inc., an indirect subsidiary of R&B Falcon, and Conoco
Development Company and Acknowledgment by Conoco Inc. and R&B Falcon

-100-

(incorporated by reference to Exhibit 10.2 to R&B Falcon's Quarterly
Report on Form 10-Q for the quarter ended September 30, 1998)

10.46 Letter agreement dated as of August 7, 1998 between RBF Deepwater
Exploration Inc., an indirect subsidiary of R&B Falcon, and Conoco
Development Company and Acknowledgment by Conoco Inc. and R&B Falcon
(incorporated by reference to Exhibit 10.3 to R&B Falcon's Quarterly
Report on Form 10-Q for the quarter ended September 30, 1998)

10.47 Amended and Restated Participation Agreement dated as of December 18,
2001 among Deepwater Drilling II L.L.C., Deepwater Investment Trust
1999-A, Wilmington Trust FSB, Wilmington Trust Company and other
Financial Institutions, as Certificate Purchasers, solely with respect
to Sections 2.15, 9.4, 12.13(b) and 12.13(d) Transocean Sedco Forex
Inc. and Conoco Inc., and solely with respect to Sections 5.2 and 6.4,
RBF Deepwater Exploration II Inc. and Conoco Development II Inc.
(incorporated by reference to Exhibit 10.43 to the Company's Annual
Report on Form 10-K for the fiscal year ended December 31, 2001)

10.48 Appendix 1 to Amended and Restated Participation Agreement dated as of
December 18, 2001 (incorporated by reference to Exhibit 10.44 to the
Company's Annual Report on Form 10-K for the fiscal year ended
December 31, 2001)

10.49 Agreement dated as of August 31, 1991 among Reading & Bates, Arcade
Shipping AS and Sonat Offshore Drilling, Inc. (incorporated by
reference to Exhibit 10.40 to Reading & Bates' Annual Report on Form
10-K for the year ended December 30, 1991)

*10.50 Separation Agreement dated as of December 21, 2001 by and between
Transocean Offshore Deepwater Drilling Inc. and W. Dennis Heagney
(incorporated by reference to Exhibit 10.46 to the Company's Annual
Report on Form 10-K for the fiscal year ended December 31, 2001)

*10.51 Separation Agreement dated as of July 23, 2002 by and between
Transocean Offshore Deepwater Drilling Inc. and Jon C. Cole
(incorporated by reference to Exhibit 10.2 to the Company's Form 10-Q
for the quarter ended June 30, 2002)

+21 Subsidiaries of the Company

+23.1 Consent of Ernst & Young LLP

+24 Powers of Attorney

______________________________
*Compensatory plan or arrangement.
+Filed herewith.

Exhibits listed above as previously having been filed with the Securities
and Exchange Commission are incorporated herein by reference pursuant to Rule
12b-32 under the Securities Exchange Act of 1934 and made a part hereof with the
same effect as if filed herewith.

Certain instruments relating to long-term debt of the Company and its
subsidiaries have not been filed as exhibits since the total amount of
securities authorized under any such instrument does not exceed 10 percent of
the total assets of the Company and its subsidiaries on a consolidated basis.
The Company agrees to furnish a copy of each such instrument to the Commission
upon request.

REPORTS ON FORM 8-K

The Company filed a Current Report on Form 8-K on October 10, 2002
announcing senior management appointments, a Current Report on Form 8-K on
October 29, 2002 (information furnished not filed) announcing that the updated
"Monthly Fleet Report" was available on the Company's website and a Current
Report on Form 8-K on November 26, 2002 (information furnished not filed)
announcing that the updated "Monthly Fleet Report" was available on the
Company's website.

-101-

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 25, 2003.

TRANSOCEAN INC.
By: /s/ Gregory L. Cauthen
----------------------------------
GREGORY L. CAUTHEN
SENIOR VICE PRESIDENT, CHIEF FINANCIAL OFFICER AND TREASURER

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 IN THE CAPACITIES INDICATED ON MARCH 25, 2003

SIGNATURE TITLE
--------- -----

/s/ J. Michael Talbert Chairman of the Board of Directors
----------------------------------
J. MICHAEL TALBERT

/s/ Robert L. Long President and Chief Executive Officer
---------------------------------- (Principal Executive Officer)
ROBERT L. LONG

/s/ Gregory L. Cauthen Senior Vice President, Chief
---------------------------------- Financial Officer and Treasurer
GREGORY L. CAUTHEN (Principal Financial Officer)

/s/ Ricardo H. Rosa Vice President and Controller
---------------------------------- (Principal Accounting Officer)
RICARDO H. ROSA

* Director
----------------------------------
VICTOR E. GRIJALVA

* Director
----------------------------------
RONALD L. KUEHN, JR.

* Director
----------------------------------
ARTHUR LINDENAUER

* Director
----------------------------------
PAUL B. LOYD, JR.

* Director
----------------------------------
MARTIN B. MCNAMARA

* Director
----------------------------------
ROBERTO MONTI

-102-

SIGNATURE TITLE
--------- -----

* Director
----------------------------------
RICHARD A. PATTAROZZI

* Director
----------------------------------
ALAIN ROGER

* Director
----------------------------------
KRISTIAN SIEM

* Director
----------------------------------
IAN C. STRACHAN

By /s/ William E. Turcotte
--------------------------------
WILLIAM E. TURCOTTE
(ATTORNEY-IN-FACT)

-103-

CERTIFICATIONS

Principal Executive Officer
---------------------------

I, Robert L. Long, certify that:

1. I have reviewed this annual report on Form 10-K of Transocean 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 we 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 registrant's board of directors (or persons performing the
equivalent function):

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 or not 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.

Date: March 25, 2003 /s/ Robert L. Long
-------------------------------------
Robert L. Long
President and Chief Executive Officer

-104-

Principal Financial Officer
---------------------------

I, Gregory L. Cauthen, certify that:

1. I have reviewed this annual report on Form 10-K of Transocean Inc.;

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;

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

Date: March 25, 2003 /s/ Gregory L. Cauthen
-------------------------------------
Gregory L. Cauthen
Senior Vice President, Chief Financial
Officer and Treasurer

-105-