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, 2003
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
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Ordinary Shares, par value $0.01 per share New York Stock Exchange, Inc.

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 30, 2003, 319,853,774 ordinary shares were outstanding and the
aggregate market value of such shares held by non-affiliates was approximately
$7.0 billion (based on the reported closing market price of the ordinary shares
on such date of $21.97 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 27, 2004, 320,711,252 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, 2003, 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, 2003

ITEM PAGE
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PART I
ITEM 1. Business . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3
Background of Transocean . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3
Drilling Fleet . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4
Markets. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9
Management Services. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10
Drilling Contracts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10
Significant Clients. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10
Regulation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11
Employees. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11
Available Information. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12
ITEM 2. Properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12
ITEM 3. Legal Proceedings. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12
ITEM 4. Submission of Matters to a Vote of Security Holders. . . . . . . . . . . . . . . . . . . 14
Executive Officers of the Registrant . . . . . . . . . . . . . . . . . . . . . . . . . . 14
PART II
ITEM 5. Market for Registrant's Common Equity and Related Shareholder Matters . . . . . . . . . 16
ITEM 6. Selected Consolidated Financial Data. . . . . . . . . . . . . . . . . . . . . . . . . . 18
ITEM 7. Management's Discussion and Analysis of Financial Condition and Results of Operations . 20
ITEM 7A. Quantitative and Qualitative Disclosures About Market Risk. . . . . . . . . . . . . . . 52
ITEM 8. Financial Statements and Supplementary Data . . . . . . . . . . . . . . . . . . . . . . 53
ITEM 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure. . 97
ITEM 9A Controls and Procedures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 97
PART III
ITEM 10. Directors and Executive Officers of the Registrant. . . . . . . . . . . . . . . . . . . 97
ITEM 11. Executive Compensation. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 97
ITEM 12. Security Ownership of Certain Beneficial Owners and Management and Related
Shareholder Matters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 97
ITEM 13. Certain Relationships and Related Transactions. . . . . . . . . . . . . . . . . . . . . 97
ITEM 14. Principal Accounting Fees and Services. . . . . . . . . . . . . . . . . . . . . . . . . 97

PART IV
ITEM 15. Exhibits, Financial Statement Schedules and Reports on Form 8-K . . . . . . . . . . . . 97

PART I

ITEM 1. BUSINESS

Transocean 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 contract drilling
services for oil and gas wells. As of March 1, 2004, we owned, had partial
ownership interests in or operated 96 mobile offshore drilling units, excluding
the fleet of TODCO (together with its subsidiaries and predecessors, unless the
context requires otherwise, "TODCO"), a publicly traded drilling company in
which we own a majority interest. As of this date, our fleet consisted of 32
High-Specification semisubmersibles and drillships ("floaters"), 26 Other
Floaters, 26 Jackup Rigs and 12 Other Rigs. As of March 1, 2004, TODCO's fleet
consisted of 24 jackup rigs, 30 drilling barges, nine land rigs, three
submersible drilling rigs and four other drilling rigs.

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.

In December 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." On January 31, 2001, we completed our merger
transaction (the "R&B Falcon merger") with R&B Falcon Corporation ("R&B
Falcon"). We accounted for the R&B Falcon merger using the purchase method of
accounting with the Company treated as the accounting acquiror. At the time of
the merger, R&B Falcon operated a diverse global drilling rig fleet, consisting
of drillships, semisubmersibles, jackup rigs and other units in addition to the
Gulf of Mexico Shallow and Inland Water segment fleet. In May 2002, we changed
our name to "Transocean Inc."

In July 2002, we announced plans to pursue a divestiture of our Gulf of
Mexico Shallow and Inland Water business, which was a part of R&B Falcon. R&B
Falcon's overall business was considerably broader than the Gulf of Mexico
Shallow and Inland Water business. In preparation for this divestiture, we began
the transfer of all assets and businesses out of R&B Falcon that were unrelated
to the Gulf of Mexico Shallow and Inland Water business. In December 2002, R&B
Falcon changed its name to TODCO and, in January 2004, the Gulf of Mexico
Shallow and Inland Water business segment became known as the TODCO segment.

In February 2004, we completed an initial public offering of TODCO, in
which we sold 13.8 million shares of TODCO's class A common stock representing
23 percent of TODCO's outstanding common stock. Before the closing of the
offering, TODCO completed the transfer to us of all unrelated assets and
businesses. At March 1, 2004, we held approximately 77 percent of the
outstanding common stock of TODCO, represented by 46.2 million shares of class B
common stock, and consolidate TODCO in our financial statements. TODCO's class A
common stock has one vote per share, and its class B common stock has five votes
per share. Our current long-term intent is to dispose of our remaining interest
in TODCO, which could be achieved through a number of possible transactions
including additional public offerings, open market sales, sales to one or more
third parties, a spin-off to our shareholders, split-off offerings to our
shareholders that would allow for the opportunity to exchange our shares for
shares of TODCO class A common stock or a combination of these transactions.

We provide contract drilling services in several market sectors and
aggregate these operations into two business segments. Our Transocean Drilling
segment (formerly called the "International and U.S. Floater Contract Drilling
Services" business segment) is comprised of drillships, semisubmersibles,
jackups and other drilling rigs. Our TODCO segment (formerly called the "Gulf of
Mexico Shallow and Inland Water" business segment) consists of our interest in
TODCO, which conducts jackup, drilling barge, land rig, submersible and other
rig operations in the U.S. Gulf of Mexico and inland waters, Mexico, Trinidad
and Venezuela. Our operations are aggregated into these two business segments
based on the similarity of economic characteristics among the market sectors in
which each operates. These characteristics include the

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services provided and the types of customers for which we provide these
services. Although each of our business segments consists of various rig
categories, the type of rig used to perform our drilling operations is dependent
upon the needs and demands of our clients. As a result, operating decisions and
allocation of assets and resources are determined by our customers.

For information about the revenues, operating income, assets and other
information relating to our business segments and the geographic areas in which
we operate, see "Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations" and Note 19 to our consolidated financial
statements included in Item 8 of this report. For information about the risks
and uncertainties relating to our business, see "Item 7. Management's Discussion
and Analysis of Financial Condition and Results of Operations-Risk Factors."

DRILLING FLEET

We principally use three types of drilling rigs:
- drillships;
- semisubmersibles; and
- jackups.

Also included in our fleet are barge drilling rigs, tenders, a mobile
offshore production unit, a platform drilling rig and a land rig. TODCO's fleet
consists of jackups, barge drilling rigs, submersibles, land drilling rigs, a
platform rig and lake barges.

Most of our drilling equipment is suitable for both exploration and
development drilling, and we normally engage 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. 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.

TRANSOCEAN DRILLING FLEET

As of March 1, 2004, our Transocean Drilling segment fleet of 96 rigs
included:
- 32 High-Specification Floaters, which are comprised of:
- 13 Fifth-Generation Deepwater Floaters;
- 15 Other Deepwater Floaters; and
- four Other High-Specification Floaters;
- 26 Other Floaters;
- 26 Jackups; and
- 12 Other Rigs, which are comprised of:
- four barge drilling rigs;
- four tenders;
- one platform drilling rig;
- one mobile offshore production unit;
- one land rig; and
- one coring drillship.

As of February 27, 2004, this segment's fleet was located in the U.S. Gulf
of Mexico (14 units), Canada (one unit), Brazil (10 units), North Europe (17
units), the Mediterranean and Middle East (nine units), the Caspian Sea (one
unit), Africa (18 units), India (10 units) and Asia and Australia (16 units).

We periodically review the use of the term "deepwater" in connection with
our fleet. The term as used in the drilling industry to denote a particular
segment of the market varies somewhat and continues to evolve with technological
improvements. We generally view the deepwater market sector as that which begins
in water depths of approximately 4,500 feet.

In the first quarter of 2004, we changed the categories we use to describe
this segment's fleet into a "High-Specification Floaters" category, consisting
of our "Fifth-Generation Deepwater Floaters," "Other Deepwater Floaters" and
Other "High-Specification Floaters," an "Other Floaters" category, a "Jackups"
category and an "Other Rigs" category. Within our High-Specification Floaters
category, we consider our Fifth-Generation Deepwater Floaters to be those set
forth in the fleet table listed below, which were built in the last construction
cycle (approximately 1996-2001) and have high-pressure mud pumps and a water
depth capability of 7,500 feet or greater. The Other Deepwater Floaters are
generally those other

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semisubmersible rigs and drillships that have a water depth capacity of at least
4,500 feet and the Other High-Specification Floaters are harsh environment
floaters that were built as fourth-generation rigs in the mid- to late-1980's
and have greater displacement than previously constructed rigs resulting in
larger variable load capacity, more usable deck space and better motion
characteristics. Our Other Floaters category is generally comprised of those
non-high-specification floaters with a water depth capacity of less than 4,500
feet. The Jackups category consists of this segment's jackup fleet, and the
Other Rigs category consists of other rigs which are of a different type or use.
We have changed these categories to better reflect how we view, and how we
believe our investors and the industry view, our fleet in an effort to better
reflect our strategic focus on the ownership and operation of premium
high-specification floating rigs.

Drillships are generally self-propelled, shaped like conventional ships and
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. Our
three Enterprise-class drillships are equipped for dual-activity drilling, which
is a well-construction technology we developed and patented 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.

Semisubmersibles are floating vessels that can be submerged by means of a
water ballast system such that the lower hulls are 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. Our three Express-class semisubmersibles equipped with the unique
tri-act derrick were designed to reduce overall well construction costs and
effectively integrate new technology and working relationships.

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.

Rigs described in the following tables as "operating" are under contract,
including rigs being mobilized under contract. Rigs described as "warm stacked"
are not under contract and may require the hiring of additional crew, but are
generally ready for service with little or no capital expenditures and are being
actively marketed. Rigs described as "cold stacked" are not being actively
marketed on short or near term contracts, generally cannot be reactivated upon
short notice and normally require the hiring of most of the crew, a maintenance
review and possibly significant refurbishment before they can be reactivated.
Our cold stacked rigs and some of our warm stacked 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. For some of these rigs, the cost
could be significant. We would take these factors into consideration together
with market conditions, length of contract and dayrate and other contract terms
in deciding whether to return a particular idle rig to service. We may consider
marketing some of our cold stacked rigs for alternative uses, including as
accommodation units, from time to time until drilling activity increases and we
obtain drilling contracts for these units.

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HIGH-SPECIFICATION FLOATERS (32)

The following tables provide certain information regarding our
High-Specification fleet in this segment as of February 27, 2004:

FIFTH-GENERATION DEEPWATER FLOATERS (13)
Deepwater Discovery (c) . . . . . . . HSD 2000 10,000 30,000 Nigeria ExxonMobil March 2004
Nigeria ExxonMobil May 2004
Deepwater Expedition (c). . . . . . . HSD 1999 10,000 30,000 Brazil Petrobras September 2005
Deepwater Frontier (c). . . . . . . . HSD 1999 10,000 30,000 Brazil Petrobras March 2004
Deepwater Millennium (c). . . . . . . HSD 1999 10,000 30,000 U.S. Gulf Anadarko March 2004
U.S. Gulf Anadarko April 2004
U.S. Gulf Dominion May 2004
U.S. Gulf Dominion June 2004
U.S. Gulf Burlington November 2004
Deepwater Pathfinder (c). . . . . . . HSD 1998 10,000 30,000 U.S. Gulf ChevronTexaco April 2004
Discoverer Deep Seas (c) (f). . . . . HSD 2001 10,000 35,000 U.S. Gulf ChevronTexaco January 2006
Discoverer Enterprise (c) (f) . . . . HSD 1999 10,000 35,000 U.S. Gulf BP December 2004
Discoverer Spirit (c) (f) . . . . . . HSD 2000 10,000 35,000 U.S. Gulf Unocal September 2005
Deepwater Horizon (c) . . . . . . . . HSS 2001 10,000 30,000 U.S. Gulf BP September 2004
Cajun Express (c) (g) . . . . . . . . HSS 2001 8,500 35,000 U.S. Gulf Dominion May 2004
U.S. Gulf ChevronTexaco August 2004
Deepwater Nautilus (d). . . . . . . . HSS 2000 8,000 30,000 U.S. Gulf Shell June 2005
Sedco Energy (c) (g). . . . . . . . . HSS 2001 7,500 25,000 Nigeria ChevronTexaco October 2004
Sedco Express (c) (g) . . . . . . . . HSS 2001 7,500 25,000 Brazil Petrobras August 2004

OTHER DEEPWATER FLOATERS (15)
Deepwater Navigator (c) . . . . . . . HSD 2000 7,200 25,000 Brazil Petrobras July 2004
Peregrine I (c) . . . . . . . . . . . HSD 1982/1996 7,200 25,000 Brazil Petrobras March 2004
Discoverer 534 (c). . . . . . . . . . HSD 1975/1991 7,000 25,000 India Reliance May 2004
Discoverer Seven Seas (c) . . . . . . HSD 1976/1997 7,000 25,000 India ONGC February 2007
Transocean Marianas . . . . . . . . . HSS 1979/1998 7,000 25,000 U.S. Gulf Dominion March 2004
Sedco 707 (c) . . . . . . . . . . . . HSS 1976/1997 6,500 25,000 Brazil Petrobras December 2005
Jack Bates. . . . . . . . . . . . . . HSS 1986/1997 5,400 30,000 U.K. North Sea Warm stacked April 2004
U.K. North Sea TotalFinaElf June 2004
Sedco 709 (c) . . . . . . . . . . . . HSS 1977/1999 5,000 25,000 Nigeria Shell May 2004
M. G. Hulme, Jr. (e). . . . . . . . . HSS 1983/1996 5,000 25,000 Nigeria TotalFinaElf March 2004
Nigeria TotalFinaElf June 2004
Transocean Richardson . . . . . . . . HSS 1988 5,000 25,000 Ivory Coast CNR October 2005
Jim Cunningham. . . . . . . . . . . . HSS 1982/1995 4,600 25,000 Egypt GUPCO July 2004
Transocean Leader . . . . . . . . . . HSS 1987/1997 4,500 25,000 U.K. North Sea Warm stacked May 2004
Norwegian N. Sea Statoil August 2005
Transocean Rather . . . . . . . . . . HSS 1988 4,500 25,000 Angola ExxonMobil April 2004
Sovereign Explorer. . . . . . . . . . HSS 1984 4,500 25,000 Las Palmas Cold stacked -
Sedco 710 (c) . . . . . . . . . . . . HSS 1983/1997 4,500 25,000 Brazil Petrobras October 2006

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YEAR WATER DRILLING
ENTERED DEPTH DEPTH
SERVICE/ CAPACITY CAPACITY ESTIMATED
NAME TYPE UPGRADED(a) (IN FEET) (IN FEET) LOCATION CUSTOMER EXPIRATION (b)
------------------------------------- ----- ----------- --------- --------- ---------------- ------------- ---------------
OTHER HIGH-SPECIFICATION FLOATERS (4)
Henry Goodrich. . . . . . . . . . . . HSS 1985 2,000 30,000 Canada Terra Nova February 2005
Paul B. Loyd, Jr. . . . . . . . . . . HSS 1990 2,000 25,000 U.K. North Sea BP March 2004
U.K. North Sea BP March 2005
Transocean Arctic . . . . . . . . . . HSS 1986 1,650 25,000 Norwegian N. Sea Cold stacked -
Polar Pioneer . . . . . . . . . . . . HSS 1985 1,500 25,000 Norwegian N. Sea Norsk Hydro October 2004
Norwegian N. Sea Statoil June 2006

_______________________________________
"HSD" means high-specification drillship.
"HSS" means high-specification semisubmersible.

(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 last expected termination date. 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 leased from its owner, an unrelated third party, under an operating lease as a result of a
sale/leaseback transaction in November 1995.
(f) Enterprise-class rig.
(g) Express-class rig.

OTHER FLOATERS (26)

The following table provides certain information regarding our Other
Floater drilling rigs in this segment as of February 27, 2004:

Peregrine III (c) . . OD 1976 4,200 25,000 U.S. Gulf Cold stacked -
Sedco 700 . . . . . . OS 1973/1997 3,600 25,000 Equatorial Guinea Amerada Hess July 2004
Transocean Amirante . OS 1978/1997 3,500 25,000 U.S. Gulf Cold stacked -
Transocean Legend . . OS 1983 3,500 25,000 Brazil Petrobras May 2004
C. Kirk Rhein, Jr.. . OS 1976/1997 3,300 25,000 U.S. Gulf Cold stacked -
Transocean Driller. . OS 1991 3,000 25,000 Brazil Warm stacked -
Falcon 100. . . . . . OS 1974/1999 2,400 25,000 U.S. Gulf Cold stacked -
Sedco 703 . . . . . . OS 1973/1995 2,000 25,000 Australia BHPB March 2004
Australia Apache April 2004
Australia BHPB May 2004
Australia Apache June 2004
Australia ENI July 2004
Australia ChevronTexaco August 2004
Sedco 711 . . . . . . OS 1982 1,800 25,000 U.K. North Sea Shell March 2004
U.K. North Sea Shell December 2004
Transocean John Shaw. OS 1982 1,800 25,000 U.K. North Sea Warm stacked -
Sedco 714 . . . . . . OS 1983/1997 1,600 25,000 U.K. North Sea EnCana April 2004
Sedco 712 . . . . . . OS 1983 1,600 25,000 U.K. North Sea Cold stacked -
Actinia . . . . . . . OS 1982 1,500 25,000 Egypt IEOC June 2004
Sedco 600 . . . . . . OS 1983/1994 1,500 25,000 Singapore Warm stacked -
Sedco 601 . . . . . . OS 1983 1,500 25,000 Indonesia Schlumberger May 2004
Sedco 602 . . . . . . OS 1983 1,500 25,000 Singapore Cold stacked -
Sedco 702 . . . . . . OS 1973/1992 1,500 25,000 Australia Cold stacked -
Sedneth 701 . . . . . OS 1972/1993 1,500 25,000 Angola ChevronTexaco September 2004

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Transocean Prospect . OS 1983/1992 1,500 25,000 U.K. North Sea Cold stacked -
Transocean Searcher . OS 1983/1988 1,500 25,000 Norwegian N. Sea Statoil June 2004
Norwegian N. Sea Statoil May 2005
Transocean Winner . . OS 1983 1,500 25,000 Norwegian N. Sea Cold stacked -
Transocean Wildcat. . OS 1977/1985 1,300 25,000 U.K. North Sea Cold stacked -
Transocean Explorer . OS 1976 1,250 25,000 U.K. North Sea Cold stacked -
J. W. McLean. . . . . OS 1974/1996 1,250 25,000 U.K. North Sea Oilexco March 2004
Sedco 704 . . . . . . OS 1974/1993 1,000 25,000 U.K. North Sea ChevronTexaco March 2004
U.K. North Sea ADTI May 2004
Sedco 706 . . . . . . OS 1976/1994 1,000 25,000 U.K. North Sea Cold stacked -

_______________________________________
"OD" means other drillship.
"OS" means other semisubmersible.

JACKUP RIGS (26)

The following table provides certain information regarding our Jackup Rig
fleet in this segment as of February 27, 2004:

Trident IX . . . . 1982 400 21,000 Vietnam JVPC August 2004
Vietnam JVPC August 2005
Trident 17 . . . . 1983 355 25,000 Vietnam Carigali June 2004
Harvey H. Ward . . 1981 300 25,000 Malaysia Talisman July 2004
J. T. Angel. . . . 1982 300 25,000 India ONGC May 2004
Roger W. Mowell. . 1982 300 25,000 Malaysia Talisman November 2004
Ron Tappmeyer. . . 1978 300 25,000 India ONGC November 2006
D. R. Stewart. . . 1980 300 25,000 Italy ENI March 2005
Randolph Yost. . . 1979 300 25,000 India ONGC November 2006
C. E. Thornton . . 1974 300 25,000 India ONGC June 2004
F. G. McClintock . 1975 300 25,000 India ONGC October 2004
Shelf Explorer . . 1982 300 25,000 Equatorial Guinea Marathon March 2004
Transocean III . . 1978/1993 300 20,000 Egypt Devon September 2004
Transocean Nordic. 1984 300 25,000 India Reliance March 2004
Trident II . . . . 1977/1985 300 25,000 India ONGC May 2006
Trident IV-A . . . 1980/1999 300 25,000 Angola ChevronTexaco April 2004
Trident VI . . . . 1981 300 21,000 Nigeria Warm stacked -
Trident VIII . . . 1981 300 21,000 Nigeria ChevronTexaco May 2004
Trident XII. . . . 1982/1992 300 25,000 India ONGC November 2006
Trident XIV. . . . 1982/1994 300 20,000 Angola Warm stacked -
Trident 15 . . . . 1982 300 25,000 Thailand Unocal February 2005
Trident 16 . . . . 1982 300 25,000 Thailand PTTEP May 2004
Trident 20 . . . . 2000 350 25,000 Caspian Sea Warm stacked April 2004
Caspian Sea Petronas December 2004

- 8 -

WATER DRILLING
YEAR ENTERED DEPTH DEPTH
SERVICE/ CAPACITY CAPACITY ESTIMATED
NAME UPGRADED(a) (IN FEET) (IN FEET) LOCATION CUSTOMER EXPIRATION (b)
------------------ ------------- --------- --------- -------------------- ------------- ---------------
George H. Galloway. 1984 300 25,000 Italy ENI July 2004
Transocean Comet. . 1980 250 20,000 Egypt GUPCO October 2005
Transocean Mercury. 1969/1998 250 20,000 Egypt GUPCO June 2004
Transocean Jupiter. 1981/1997 170 16,000 United Arab Emirates Cold stacked -

____________________________
(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 last
expected termination date. Some contracts may permit the client to extend the contract.

OTHER RIGS

In addition to our floaters and jackups, we also own or operate several
other types of rigs in this segment. These rigs include four drilling barges,
four tenders, a platform drilling rig, a mobile offshore production unit and a
land rig, as well as a coring drillship.

TODCO FLEET

As of March 1, 2004, the TODCO segment fleet consisted of 24 jackups, 30
drilling barges, three submersible rigs and a platform drilling rig, as well as
nine land rigs and three lake barges. As of March 1, 2004, TODCO's fleet was
located in the U.S. (52 units), Mexico (three units), Venezuela (13 units) and
Trinidad (two units). The following table contains information relating to
TODCO's fleet as of such date:

NO. OF TOTAL NO.
LOCATION OPERATING RIGS OF RIGS
------------------- -------------- ---------

U.S. Gulf of Mexico
- Jackups 9 19
- Submersibles - 3
U.S. Inland Waters
- Drilling Barges 12 30
Mexico
- Jackups 2 2
Venezuela
- Jackups 1 1
- Land Rigs 1 9
- Lake Barges - 3
Trinidad
- Jackups 1 2
- Platform Rig - 1

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. Consequently, we operate in a single, global offshore
drilling market. 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. For this reason, water-depth capability is a key component in
determining rig suitability for a particular drilling project. Another
distinguishing feature in some drilling market segments is a rig's ability to
operate in harsh environments, including extreme marine and climatic conditions
and temperatures.

- 9 -

The deepwater and mid-water market sectors 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
4,500 feet and extends to the maximum water depths in which rigs are capable of
drilling, which is currently approximately 10,000 feet. We view the mid-water
market sector as that which covers water depths of about 300 feet to
approximately 4,500 feet.

The global shallow water market segment begins at the outer limit of the
transition zone and extends to water depths of about 300 feet. We service this
segment with our jackups and drilling tenders, which are located outside of the
U.S. TODCO also operates in this market segment with jackups and submersibles.
This segment has been developed to a significantly greater degree than the
deepwater market segment because the shallower water depths have made it much
more accessible than the deeper water market segments.

The "transition zone" market segment is characterized by marshes, rivers,
lakes, shallow bay and coastal water areas. We operate in this segment using our
drilling barges located in West Africa and Southeast Asia. TODCO operates in
this market segment along the U.S. Gulf of Mexico coastline, which has been the
world's largest market segment for barge rigs.

TODCO also conducts 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 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, 2004,
we were performing such services in the North Sea, India and Malaysia. These
management service revenues did not represent a material portion of our revenues
during 2003.

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 the reduction in or loss of
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), as well as for
many government-controlled and independent oil companies. Major clients included
BP, Shell, Petrobras and Statoil. Our largest unaffiliated clients in 2003 were
Petrobras, BP and Shell accounting for 11.8 percent, 11.1 percent and 10.7
percent, respectively, of our 2003 operating revenues. No other unaffiliated
client accounted for 10 percent or more of our 2003 operating revenues. 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.

- 10 -

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 and
requiring the 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.

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. Included among these are regulations
that require the preparation of spill contingency plans and establish air
quality standards for certain pollutants, including particulate matter, volatile
organic compounds, sulfur dioxide, carbon monoxide and nitrogen oxides. 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 U.S. 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 U.S. 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 TODCO's inland 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

We require highly skilled personnel to operate our drilling units. As a
result, we conduct extensive personnel recruiting, training and safety programs.
At January 31, 2004, excluding TODCO employees, we had approximately 10,100
employees, of which approximately 1,900 persons were contracted through contract
labor providers. As of such date, approximately 24 percent of these employees
worldwide worked under collective bargaining agreements, most of whom worked in
Brazil, Norway, U.K. and Nigeria. Of these represented employees, substantially
all are working under agreements that are subject to salary negotiation in 2004.
These negotiations could result in higher personnel expenses, other increased
costs or increased operating restrictions.

- 11 -

At January 31, 2004, TODCO had approximately 1,800 employees, of which
approximately six percent worked under collective bargaining agreements in
Trinidad and Venezuela.

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.

You may also find information related to our corporate governance, board
committees and company code of ethics at our website. Among the information you
can find there is the following:

- Corporate Governance Guidelines;
- Audit Committee Charter;
- Corporate Governance Committee Charter;
- Executive Compensation Committee Charter;
- Finance and Benefits Committee Charter; and
- Code of Ethics.

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, France and Indonesia. Our remaining offices and
bases are located in various countries in North America, South America, the
Caribbean, Europe, Africa, the Middle East, India and Asia. We lease most of
these facilities.

TODCO maintains principal executive offices in Houston, Texas and has
operational offices in the U.S., Mexico, Trinidad and Venezuela.

ITEM 3. LEGAL PROCEEDINGS

In 1990 and 1991, two of our subsidiaries were served with various
assessments collectively valued at approximately $5.8 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. In October
2001, the Brazil Supreme Court rejected our appeal of an adverse lower court's
ruling with respect to a June 1991 assessment, which is valued at approximately
$5 million. We are continuing to challenge the assessment and have an action to
suspend a related tax foreclosure proceeding. We have received a favorable
ruling in connection with a disputed August 1990 assessment but the government
has appealed that ruling. 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

- 12 -

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 are now
awaiting a hearing date. 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 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 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 TODCO, 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. The matter has
now been fully resolved with all the plaintiffs. We believe that most, if not
all, of the settlement amounts are covered by relevant primary and excess
liability insurance policies. However, the insurers and underwriters denied
coverage and one has filed a counterclaim. TODCO has instituted litigation
against those insurers and underwriters to enforce its rights under the relevant
policies. TODCO has settled with some of the insurers but is continuing the
litigation against the remaining insurers. Pursuant to the master separation
agreement with TODCO, we are responsible and will indemnify TODCO for any losses
TODCO incurs from these actions and we will benefit from any recovery. 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, TODCO was notified by the U.S. Environmental Protection
Agency ("EPA") that the EPA had identified a subsidiary 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 a review of TODCO's internal records to date, TODCO
disputes its designation as a potentially responsible party. Pursuant to the
master separation agreement with TODCO, we are responsible and will indemnify
TODCO for any losses TODCO incurs in connection with this action. 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 August 2003, a judgment of approximately $9.5 million was entered by the
Labor Division of the Provincial Court of Luanda, Angola, against us and one of
our labor contractors, Hull Blyth, in favor of certain former workers on several
of our drilling rigs. The workers were employed by Hull Blyth to work on several
drilling rigs while the rigs were located in Angola. When the drilling contracts
concluded and the rigs left Angola, the workers' employment ended. The workers
brought suit claiming that they were not properly compensated when their
employment ended. In addition to the monetary judgment, the Labor Division
ordered the workers to be hired by us. We believe that this judgment is without
sufficient legal foundation and have appealed the matter to the Angola Supreme
Court. We further believe that Hull Blyth has an obligation to protect us from
any judgment. We do not believe that the ultimate outcome of this matter 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.

- 13 -

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 2003.

EXECUTIVE OFFICERS OF THE REGISTRANT

AGE AS OF
OFFICER OFFICE MARCH1, 2004
----------------------- -------------------------------------------------------------- ------------

J. Michael Talbert. . . Chairman of the Board 57
Robert L. Long. . . . . President and Chief Executive Officer 58
Jean P. Cahuzac . . . . Executive Vice President and Chief Operating Officer 50
Eric B. Brown . . . . . Senior Vice President, General Counsel and Corporate Secretary 52
Gregory L. Cauthen. . . Senior Vice President and Chief Financial Officer 46
Barbara S. Koucouthakis Vice President and Chief Information Officer 45
Tim L. Juran. . . . . . Vice President, Human Resources 45
Jan Rask. . . . . . . . President and Chief Executive Officer of TODCO 48

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.

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 and Chief Financial Officer of
the Company. He was also Treasurer of the Company until July 2003. Mr. Cauthen
served as Vice President, Chief Financial Officer and Treasurer from December
2001 until he was elected in July 2002 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.

- 14 -

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.

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.

Jan Rask is President and Chief Executive Officer of TODCO, a publicly
traded drilling company in which the Company owns a majority interest. 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 TODCO in his current capacity. 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. Mr.
Rask has been a director of Veritas DGC, Inc., an integrated geophysical service
company since 1998.

Brenda S. Masters, previously the Company's Vice President and Controller,
left the Company in December 2003. Mr. Cauthen now serves as the Company's
Principal Accounting Officer.

- 15 -

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

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 . . . . . . . . . . . $24.36 $19.87
Second Quarter. . . . . . . . . . . 25.90 18.40
Third Quarter . . . . . . . . . . . 22.43 18.50
Fourth Quarter. . . . . . . . . . . 24.85 18.49

2004 First Quarter (through February 27) $30.06 $23.10

On February 27, 2004, the last reported sales price of our ordinary shares
on the NYSE Composite Tape was $29.48 per share. On such date, there were 17,564
holders of record of the Company's ordinary shares and 320,711,252 ordinary
shares outstanding.

We discontinued the payment of a quarterly cash dividend, and the last
dividend 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. However, under current Cayman Islands law, there is no
withholding tax on dividends.

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, of 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 27, 2004, 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 of

- 16 -

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.

- 17 -

ITEM 6. SELECTED CONSOLIDATED FINANCIAL DATA

The selected consolidated financial data as of December 31, 2003 and 2002
and for each of the three years in the period ended December 31, 2003 has been
derived from the audited consolidated financial statements included elsewhere
herein. The selected consolidated financial data as of December 31, 2001, 2000
and 1999, and for the years ended December 31, 2000 and 1999 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.
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 the merged company.

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 beginning as of
December 31, 1999 and the statement of operations and other financial data
beginning the year ended December 31, 2000 represent the consolidated financial
position, cash flows and results of operations of the merged company. The
statement of operations and other financial data for the year ended December 31,
1999, 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,
-------------------------------------------------------------
2003 2002 2001 2000 1999
-------- -------- -------- ------- -------
(IN MILLIONS, EXCEPT PER SHARE DATA)

STATEMENT OF OPERATIONS
Operating revenues . . . . . . . . . . . . . . . . $ 2,434 $ 2,674 $ 2,820 $1,230 $ 648
Operating income (loss). . . . . . . . . . . . . . 240 (2,310) 550 133 49
Income (loss) before cumulative effect of changes
in accounting principles . . . . . . . . . . . . 18 (2,368) 253 (b) 109 (b) 58
Income (loss) before cumulative effect of changes
in accounting principles per share
Basic. . . . . . . . . . . . . . . . . . . . . . $ 0.06 $ (7.42) $ 0.82 (b) $ 0.52 (b) $ 0.53 (a)
Diluted. . . . . . . . . . . . . . . . . . . . . $ 0.06 $ (7.42) $ 0.80 (b) $ 0.51 (b) $ 0.53 (a)

BALANCE SHEET DATA (AT END OF PERIOD)
Total assets . . . . . . . . . . . . . . . . . . . $11,663 $12,665 $17,048 $6,359 $6,140
Total debt . . . . . . . . . . . . . . . . . . . . 3,658 4,678 5,024 1,453 1,266
Total equity . . . . . . . . . . . . . . . . . . . 7,193 7,141 10,910 4,004 3,910
Dividends per share. . . . . . . . . . . . . . . . $ - $ 0.06 $ 0.12 $ 0.12 -

OTHER FINANCIAL DATA
Cash provided by operating activities. . . . . . . $ 526 $ 937 $ 560 $ 196 $ 241
Cash used in investing activities. . . . . . . . . (448) (45) (26) (493) (90)
Cash provided by (used in) financing activities. . (818) (531) 285 166 (159)
Capital expenditures . . . . . . . . . . . . . . . 496 141 506 575 537
Operating margin . . . . . . . . . . . . . . . . . 10% N/M 20% 11% 8%

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

(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) Income (loss) before cumulative effect of changes in accounting principles and the related basic and
diluted per share amounts reflect a reclassification of loss on retirement of debt previously reported as an
extraordinary item.

- 18 -

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

YEARS ENDED DECEMBER 31,
-------------------------------
2003 2002 2001
--------- --------- ---------

OPERATING REVENUES
United States . . . . . . $ 753 $ 753 $ 980
Brazil. . . . . . . . . . 317 283 356
United Kingdom. . . . . . 212 346 355
Rest of the World (a) . . 1,152 1,292 1,129
--------- --------- ---------
Total Operating Revenues $ 2,434 $ 2,674 $ 2,820
========= ========= =========

AS OF DECEMBER 31,
--------------------
2003 2002
--------- ---------
LONG-LIVED ASSETS
United States . . . . . . $ 3,320 $ 3,905
Goodwill (b). . . . . . . 2,231 2,218
Brazil. . . . . . . . . . 1,283 1,239
Rest of the World (a) . . 3,650 3,391
--------- ---------
Total Long-Lived Assets $ 10,484 $ 10,753
========= =========

______________________
(a) Rest of the World represents countries in which we operate that
individually had operating revenues or long-lived assets representing less
than 10 percent of total operating revenues earned or total long-lived
assets.
(b) Goodwill resulting from the Sedco Forex and R&B Falcon mergers has not been
allocated to individual countries.

- 19 -

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. (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 contract drilling
services for oil and gas wells. As of March 1, 2004, we owned, had partial
ownership interests in or operated 96 mobile offshore and barge drilling units,
excluding the fleet of TODCO (together with its subsidiaries and predecessors,
unless the context requires otherwise, "TODCO"), a publicly traded company in
which we own a majority interest. As of this date, our fleet included 32
High-Specification semisubmersibles and drillships ("floaters"), 26 Other
Floaters, 26 Jackup Rigs and 12 Other Rigs. As of March 1, 2004, TODCO's fleet
consisted of 24 jackup rigs, 30 drilling barges, nine land rigs, three
submersible drilling rigs and four other drilling rigs.

Key measures of our total company results of operations and financial
condition are as follows:

YEARS ENDED DECEMBER 31,
--------------------------------
2003 2002 CHANGE
--------------- --------------- ---------------

(IN MILLIONS, EXCEPT DAYRATES AND PERCENTAGES)
Average dayrate (a). . . . . . . . . . . . . . $ 67,200 $ 74,800 $ (7,600)
Utilization (b). . . . . . . . . . . . . . . . 57% 59% N/A
STATEMENT OF OPERATIONS
Operating revenue. . . . . . . . . . . . . . . $ 2,434.3 $ 2,673.9 $ (239.6)
Operating and maintenance expense. . . . . . . 1,610.4 1,494.2 116.2
Operating income (loss). . . . . . . . . . . . 239.7 (2,309.9) 2,549.6
Net income (loss). . . . . . . . . . . . . . . 19.2 (3,731.9) 3,751.1
BALANCE SHEET DATA (AT END OF PERIOD)
Cash . . . . . . . . . . . . . . . . . . . . . 474.0 1,214.2 (740.2)
Total Assets . . . . . . . . . . . . . . . . . 11,662.6 12,665.1 (1,002.5)
Debt . . . . . . . . . . . . . . . . . . . . . 3,658.1 4,678.0 (1,019.9)

______________________
"N/A" means not applicable.

(a) Average dayrate is defined as contract drilling revenue earned per revenue earning day.
(b) Utilization is the total actual number of revenue earning days as a percentage of the
total number of calendar days in the period.

The decreases in our average dayrates and utilization were mainly
attributable to the decline in overall market conditions primarily within our
Other Floaters fleet category. The increase in our operating and maintenance
expenses was primarily due to a change in accounting for client reimbursable
expenses. In addition, our revenues, utilization and operating and maintenance
expense were negatively impacted by a riser separation incident on the drillship
Discoverer Enterprise, a well control incident on inland barge Rig 62, an
electrical fire on the Peregrine I, a fire on inland barge Rig 20 and a labor
strike and a restructuring of a benefit plan in Nigeria (see "-Significant
Events"). With the overall market decline we have responded rapidly to reduce
costs when rigs were idled. We also reduced costs by implementing standardized
purchasing through negotiated agreements, nationalization of our labor force
where appropriate and headcount reductions in support groups. Our 2003 financial
results included the recognition of a number of non-cash charges pertaining to
asset impairments and loss on debt retirements. Debt and cash decreased during
2003 primarily as a result of repayments on debt instruments as we continue to
maintain our focus on debt reduction. We also increased our investment in the
Fifth-Generation fleet category by purchasing the portions of the Deepwater
Drilling L.L.C. ("DD LLC") and Deepwater Drilling II L.L.C. ("DDII LLC")

- 20 -

joint ventures that had previously been held by ConocoPhillips and paying off
the synthetic lease financing arrangements associated with the Deepwater
Pathfinder and Deepwater Frontier. See "-Acquisitions and Dispositions."

As a result of the implementation of Emerging Issues Task Force ("EITF")
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 are
being recognized as operating and maintenance expense beginning in 2003. In
addition, the amounts billed to our customers associated with these reimbursable
costs are being recognized as operating revenue. The increase in operating
revenues and operating and maintenance expense resulting from this
implementation was approximately $100.5 million for the year ended December 31,
2003. This change in the accounting treatment for client reimbursables had 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 have not been
reclassified, as the amounts were not material.

In the first quarter of 2004, we changed the categories we use to describe
our Transocean Drilling segment fleet into a "High-Specification Floaters"
category, consisting of our "Fifth-Generation Deepwater Floaters," "Other
Deepwater Floaters" and "Other High-Specification Floaters," an "Other Floaters"
category, a "Jackups" category and an "Other Rigs" category. Within our
High-Specification Floaters category, we consider our Fifth-Generation Deepwater
Floaters to be the semisubmersibles Deepwater Horizon, Cajun Express, Deepwater
Nautilus, Sedco Energy and Sedco Express and the drillships Deepwater Discovery,
Deepwater Expedition, Deepwater Frontier, Deepwater Millennium, Deepwater
Pathfinder, Discoverer Deep Seas, Discoverer Enterprise, and Discoverer Spirit.
These rigs were built in the last construction cycle and have high-pressure mud
pumps and a water depth capability of 7,500 feet or greater. The Other Deepwater
Floaters are generally those other semisubmersible rigs and drillships that have
a water depth capacity of at least 4,500 feet. The Other High-Specification
Floaters are those rigs capable of drilling in harsh environments that were
built as fourth-generation rigs in the mid- to late-1980's and have greater
displacement than previously constructed rigs resulting in larger variable load
capacity, more useable deck space and better motion characteristics. The Other
Floaters category is generally comprised of those non-high-specification
floaters with a water depth capacity of less than 4,500 feet. The Jackups
category consists of this segment's jackup fleet, and the Other Rigs category
consists of other rigs that are of a different type or use. We changed these
categories to better reflect how we view, and how we believe our investors and
the industry view, our fleet in an effort to better reflect our strategic focus
on the ownership and operation of premium high-specification floating rigs.

Our operations are aggregated into two reportable segments: (i) Transocean
Drilling (formerly called "International and U.S. Floater Contract Drilling
Services") and (ii) TODCO (formerly called "Gulf of Mexico Shallow and Inland
Water"). The Transocean Drilling segment consists of floaters, jackups and other
rigs used in support of offshore drilling activities and offshore support
services. The TODCO segment consists of our interest in TODCO, which conducts
jackup, drilling barge, land rig, submersible and other rig operations in the
U.S. Gulf of Mexico and inland waters, Mexico, Trinidad and Venezuela. We
provide services with different types of drilling equipment in several
geographic regions. The location of our rigs and the allocation of resources to
build or upgrade rigs is determined by the activities and needs of our
customers.

SIGNIFICANT EVENTS

Transocean Drilling Segment

DD LLC and DDII LLC Joint Ventures-In May 2003, we purchased
ConocoPhillips' 40 percent interest in DDII LLC. DDII LLC was the lessee in a
synthetic lease financing facility with a special purpose entity entered into in
connection with the construction of the Deepwater Frontier. As a result of this
purchase, we consolidated DDII LLC in our financial statements late in the
second quarter of 2003. In December 2003, DDII LLC paid $197.5 million for the
purchase of the rig through the payoff of the synthetic lease financing
arrangement. In conjunction with the payoff of the synthetic lease financing
arrangements, our relationship with the special purpose entity was terminated.
See "-Special Purpose Entities."

In December 2003, we purchased ConocoPhillips' 50 percent interest in DD
LLC. DD LLC was the lessee in a synthetic lease financing facility with a
special purpose entity entered into in connection with the construction of the
Deepwater Pathfinder. As a result of this purchase, we consolidated DD LLC in
our financial statements late in the fourth quarter of 2003. In December 2003,
DD LLC paid $185.3 million for the purchase of the rig through the payoff of the
synthetic lease financing arrangement. In conjunction with the payoff of the
synthetic lease financing arrangement, our relationship with the special purpose
entity was terminated. See "-Special Purpose Entities."

Operational Incidents-In April 2003, our deepwater drillship Peregrine I
temporarily suspended drilling operations as a result of an electrical fire
requiring repairs at a shipyard. The rig resumed operations in early July 2003.
Operating income was negatively impacted by approximately $9.5 million due to
the loss of dayrate and related expenses. See "-Historical 2003 compared to
2002."

- 21 -

In April 2003, we announced that drilling operations had ceased on four of
our mobile offshore drilling units located offshore Nigeria due to a strike by
local members of the labor unions in Nigeria on the semisubmersible rigs M.G.
Hulme, Jr. and Sedco 709 and the jackup rigs Trident VI and Trident VIII. All of
these rigs returned to operations in May and June 2003. Labor issues in Nigeria
were resolved and settled in the fourth quarter of 2003. Operating income was
negatively impacted by approximately $26.6 million due to loss of dayrate and
the restructuring of the Nigeria defined benefit plan (see "-Defined Benefit
Pension Plans").

In May 2003, we announced that a drilling riser had separated on our
deepwater drillship Discoverer Enterprise and that the rig had temporarily
suspended drilling operations for our customer. The rig resumed operations in
July 2003. Operating income for the year ended December 31, 2003 was negatively
impacted by approximately $46.4 million due to expenses incurred on the
Discoverer Enterprise as well as several other of our Fifth-Generation Deepwater
Floaters related to the drilling riser separation and a related disagreement
with our customer that was resolved in the first quarter of 2004. See
"-Historical 2003 compared to 2002." We are currently in discussions with our
insurers relating to an insurance claim for a portion of our losses stemming
from this incident.

TODCO Segment

IPO-In February 2004, we completed the initial public offering ("IPO") of
TODCO, in which we sold 13.8 million shares of TODCO's class A common stock,
representing approximately 23 percent of TODCO's total outstanding shares, at
$12.00 per share. We received net proceeds of $155.7 million from the IPO and
expect to recognize a gain of approximately $43 million in the first quarter of
2004, which represents the excess of net proceeds received over the net book
value of the shares of TODCO sold in the IPO. Additionally, as a result of the
deconsolidation of TODCO from our other U.S. subsidiaries for U.S. federal
income tax purposes in conjunction with the IPO, we expect to establish a
valuation allowance against the deferred tax assets of TODCO in excess of its
deferred tax liabilities. The amount of such valuation allowance will depend
upon many factors, including the ultimate allocation of tax benefits between
TODCO and other Transocean subsidiaries under applicable law and taxable income
for calendar year 2004. The amount of the valuation allowance could be as much
as or more than the gain on the sale of the TODCO shares in the IPO.

As of March 1, 2004, we held an approximate 77 percent interest in TODCO,
represented by 46.2 million shares of class B common stock, and we have
approximately 94 percent of the outstanding voting interest in TODCO. Each share
of our class B common stock has five votes per share compared to one vote per
share of the class A common stock. We consolidate TODCO in our financial
statements and expect to continue to consolidate TODCO in our financial
statements until we no longer own a majority voting interest. Because the IPO
had not been completed by the end of the third quarter of 2003, we recognized
$8.8 million of costs relating to the IPO in general and administrative expense
for the year ended December 31, 2003, of which $3.1 million was incurred and
deferred during 2002. TODCO was formerly known as R&B Falcon Corporation ("R&B
Falcon"). Before the closing of the IPO, TODCO transferred to us all assets and
businesses unrelated to TODCO's business. R&B Falcon's business was previously
considerably broader than TODCO's ongoing business.

Operational Incidents-In June 2003, TODCO incurred a loss as a result of a
well blowout and fire aboard inland barge Rig 62. During the year ended December
31, 2003, TODCO incurred a $7.6 million loss relating to this incident. While
the loss did not exceed our insurance deductible for this incident, we do not
expect any additional amounts that may be incurred related to this incident to
have a material adverse affect on our consolidated financial statements or
results of operations. See "-Historical 2003 compared to 2002."

In September 2003, TODCO recorded a loss of approximately $3.5 million on
inland barge Rig 20 as a result of a fire. While the loss did not exceed our
insurance deductible for this incident, we do not expect any additional amounts
that may be incurred related to this incident to have a material adverse affect
on our consolidated financial statements or results of operations. See
"-Historical 2003 compared to 2002."

OUTLOOK

Drilling Market-Commodity prices were at historically strong levels during
2003, and we believe commodity price indicators point towards continued
near-term strength in oil and gas prices. While future commodity price
expectations have historically been a key driver for offshore drilling demand,
the availability of quality drilling prospects, relative production costs, the
stage of reservoir development and political and regulatory environments all
affect our customers' drilling programs. Strong commodity prices did not result
in significant increased offshore drilling activity in the fourth quarter or in
2003 generally.

Prospects for our High-Specification Floaters appear relatively stable over
the next six months, with expected improvement in the latter half of the year
and in 2005. A number of our Fifth-Generation Deepwater Floaters will conclude
longer term contracts in 2004 and will be pursuing future work, so intermittent
idle time is possible for these units. However, we have recently been successful
in securing work for five of our High-Specification Floaters that ended term
contracts in late 2003 and early 2004, with three of these units obtaining
long-term contracts and the other two obtaining shorter-term

- 22 -

exploratory work. We continue to believe that over the long term, deepwater
exploration and development drilling opportunities in the Gulf of Mexico, West
Africa and other market sectors represent a significant source of future
deepwater rig demand. We have also seen an unexpected increase in bid activity
in Norway, which presents opportunities for our Other High-Specification
Floaters.

The level of activity for the non-U.S. jackup market sector is expected to
increase in 2004. There is currently a modest overcapacity in the West Africa
jackup market sector, but it is expected to dissipate by mid-2004. The Middle
East and India are both expected to see increases in jackup demand in 2004. As a
result of the anticipated increased activity, we believe jackup dayrates will
generally meet or exceed levels achieved in each non-U.S. geographic market
sector in 2003.

The outlook for our Other Floaters that operate in the mid-water market
sector remains weak as this sector continues to be significantly oversupplied
globally. We expect overall North Sea industry fleet utilization to remain at
current levels until the expected normal seasonal increase in demand in the
summer months. We expect the Norwegian sector to improve over the remainder of
the year. Demand in the U.S. Gulf of Mexico market sector continues to be
dampened by increased competition from deepwater rigs operating below their full
water depth capability.

The TODCO segment continues to benefit from a declining base of jackup rig
supply in the Gulf of Mexico, which has helped to lift utilization and dayrates
in an otherwise flat rig demand environment. With a potential increase in
international jackup activity causing a further reduction in supply, dayrates
are expected to generally remain stable. Demand in the inland waters of
Louisiana and Texas for drilling barges has remained flat over the past quarter.
We believe there are signs of increased drilling of deep wells greater than
18,000 feet in these inland areas in 2004, which could increase the utilization
and dayrates in this segment.

The offshore contract drilling market remains highly competitive and
cyclical, and it has been historically difficult to forecast future market
conditions. Extraneous risks include declines in oil and/or gas prices that
reduce rig demand and adversely affect utilization and dayrates. Major operator
and national oil company capital budgets are key drivers of the overall business
climate, and these may change within a fiscal year depending on exploration
results and other factors. Additionally, increased competition for our
customers' drilling budgets could come from, among other areas, land-based
energy markets in Russia, other former Soviet Union states and the Middle East.

As of February 27, 2004, approximately 45 percent of our Transocean
Drilling segment fleet days were committed for the remainder of 2004 and
approximately 18 percent for the year 2005. For our TODCO segment, which has
traditionally operated under short-term contracts, committed fleet days were
approximately seven percent for the remainder of 2004 and three percent are
currently committed for the year 2005.

Tax Matters-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.

Our income tax returns are subject to review and examination in the various
jurisdictions in which we operate. The U.S. Internal Revenue Service is
currently auditing our tax returns for calendar years 1999, the year we became a
Cayman Islands company, and 2000. In addition, other tax authorities have
examined the amounts of income and expense subject to tax in their jurisdiction
for prior periods. We are currently contesting various non-U.S. assessments that
have been asserted and would expect to contest any future U.S. or non-U.S.
assessments. While we cannot predict or provide assurance as to the final
outcome of existing or future assessments, we do not believe that the ultimate
resolution of these asserted income tax liabilities will have a material adverse
effect on our business or consolidated financial position.

As a result of the deconsolidation of TODCO from our other U.S.
subsidiaries for U.S. federal income tax purposes in conjunction with the IPO,
we expect to establish a valuation allowance against the deferred tax assets of
TODCO in excess of its deferred tax liabilities. The amount of such valuation
allowance will depend upon many factors, including the ultimate allocation of
tax benefits between TODCO and our other subsidiaries under applicable law and
taxable income for calendar

- 23 -

year 2004. The amount of the valuation allowance could be as much as or more
than the gain on the sale of the TODCO shares in the IPO (see "-Significant
Events").

Insurance-In January 2003, we renewed our principal insurance coverages for
property damage, liability, and occupational injury and illness. Premiums for
such coverages would have increased substantially were it not for us taking
significantly higher deductibles. The increased premiums were a result of
increased rates demanded by the insurance markets for most insurance coverages
as a result of losses the insurance industry has sustained in the past several
years and perceived increased risks following the terrorist attacks on September
11, 2001. The renewal of these coverages was for the period January 1, 2003
through March 1, 2004.

We renewed these insurance coverages as of March 1, 2004 for a 14-month
period ending May 1, 2005. Although premiums for these coverages were somewhat
lower, we again chose to increase deductibles to reduce premiums further, given
our continued improvement in our loss history. If our property and occupational
illness claim experience in 2004 is comparable to 2003, we would expect a small
decrease in our insurance expenses related to property damage, liabilities, and
occupational injury and illness coverages. Because of the increase in our
deductible exposure for 2004, an increase in our loss experience could result in
higher insurance related expense for the period.

During the second quarter of 2003, we renewed our directors' and officers'
liability insurance. Insurance markets have demanded significant premium
increases for this type of insurance. As a result, we chose to increase our
deductible substantially and agreed to co-insure losses with the underwriters in
order to mitigate increased premiums. We expect to renew our directors' and
officers' insurance in 2004 with substantially the same structure. At this time,
we expect the cost of such insurance to rise slightly.

Stock-Based Compensation Expense-As a result of the adoption of Statement
of Financial Accounting Standards ("SFAS") 123, Accounting for Stock-Based
Compensation, our stock-based compensation expense is expected to increase in
2004. The increase will result from the impact of a full year of expense related
to our 2003 awards, compared to six months of expense in 2003, and expense
related to our 2004 awards, expected to occur in July 2004. Future periods will
continue to have increases in stock-based compensation expense until the impact
of the layering effect of future awards is normalized. In conjunction with the
TODCO IPO, TODCO granted stock option and nonvested restricted share awards to
certain key employees. Due to accelerated vesting provisions outlined in certain
key executives employment agreements, TODCO expects to record a charge of
approximately $5.6 million during the first quarter of 2004, and a total of
$10.8 million during 2004 related to its stock-based compensation awards.
Additionally, TODCO expects to recognize approximately $1.5 million of expense
during the first quarter of 2004 related to a modification of our options issued
in prior periods to TODCO employees for which vesting was accelerated and all
unvested options became fully vested, and the exercise term extended through the
life of the option, under the employee matters agreement executed in connection
with the TODCO IPO.

Debt Retirement-In February 2004, we announced the redemption of our 9.5%
Senior Notes due December 2008 at the make-whole premium price provided in the
indenture. The redemption is expected to be completed by March 30, 2004. The
face value of the bonds to be redeemed is $289.8 million. Based on interest
rates at March 1, 2004, the cost to redeem these bonds is expected to be
approximately $366.3 million, and we expect to recognize a loss on retirement of
debt of approximately $24.1 million, which reflects adjustments for fair value
of the debt at the merger transaction ("R&B Falcon merger") with R&B Falcon in
January 2001 and the premium on the termination of the related interest rate
swap. These amounts could vary depending upon actual interest rates. We expect
to utilize existing cash balances, which includes proceeds from the TODCO IPO,
to fund this redemption. The redemption does not affect the 9.5% Senior Notes
due December 2008 of TODCO.

- 24 -

PERFORMANCE AND OTHER KEY INDICATORS

Fleet Utilization and Dayrates-The following table shows our average
dayrate and utilization for the quarterly periods ending on or prior to December
31, 2003. Average dayrate is defined as contract drilling revenue earned per
revenue earning day in the period. Utilization in the table below is defined as
the total actual number of revenue earning days in the period as a percentage of
the total number of calendar days in the period for all drilling rigs in our
fleet.

Three Months Ended
-----------------------------------------------
December 31, September 30, December 31,
2003 2003 2002
-------------- --------------- --------------

Average Dayrates (a)(b)

Transocean Drilling Segment:
High-Specification Floaters
Fifth-Generation Deepwater Floaters . $ 186,500 $ 176,600 $ 188,700
Other Deepwater Floaters . . . . . . $ 101,400 $ 112,500 $ 120,400
Other High-Specification Floaters. . $ 117,900 $ 117,200 $ 121,600
Total High-Specification Floaters. . . $ 141,800 $ 142,200 $ 146,300
Other Floaters . . . . . . . . . . . $ 60,600 $ 60,600 $ 76,800
Jackups. . . . . . . . . . . . . . . $ 53,700 $ 54,400 $ 57,700
Other Rigs . . . . . . . . . . . . . $ 45,200 $ 48,800 $ 36,200
-------------- --------------- --------------
Segment Total . . . . . . . . . . . . . . $ 87,900 $ 89,000 $ 96,100
-------------- --------------- --------------

TODCO Segment:
Jackups and Submersibles . . . . . . . $ 25,800 $ 20,800 $ 21,700
Inland Barges. . . . . . . . . . . . . $ 17,200 $ 16,900 $ 19,600
Other Rigs . . . . . . . . . . . . . . $ 20,700 $ 20,500 $ 19,400
-------------- --------------- --------------
Segment Total . . . . . . . . . . . . . . $ 21,500 $ 19,300 $ 20,300
-------------- --------------- --------------

Total Drilling Fleet. . . . . . . . . . . $ 67,400 $ 67,000 $ 74,300
============== =============== ==============

Utilization (a)(b)

Transocean Drilling Segment:
High-Specification Floaters
Fifth-Generation Deepwater Floaters. 91% 97% 96%
Other Deepwater Floaters . . . . . . 69% 73% 96%
Other High-Specification Floaters. . 74% 74% 75%
Total High-Specification Floaters. . . 78% 82% 93%
Other Floaters . . . . . . . . . . . 47% 51% 55%
Jackups. . . . . . . . . . . . . . . 81% 85% 83%
Other Rigs . . . . . . . . . . . . . 53% 49% 48%
-------------- --------------- --------------
Segment Total . . . . . . . . . . . . . . 68% 71% 74%
-------------- --------------- --------------

TODCO Segment:
Jackups and Submersibles . . . . . . . 52% 54% 33%
Inland Barges . . . . . . . . . . . . . 40% 38% 44%
Other Rigs . . . . . . . . . . . . . . 24% 38% 27%
-------------- --------------- --------------
Segment Total . . . . . . . . . . . . . . 40% 44% 37%
-------------- --------------- --------------

Total Drilling Fleet. . . . . . . . . . . 56% 59% 58%
============== =============== ==============

_________________
(a) Applicable to all rigs.
(b) Effective January 1, 2003, the calculation of average dayrates and utilization was
changed to include all rigs based on contract drilling revenues. Prior periods have
been restated to reflect the change.

Contract Drilling Revenue-Our contract drilling revenues are based
primarily on dayrates received for our drilling services and the number of
operating days during the relevant periods. The level of our contract drilling
revenue depends on dayrates, which in turn are primarily a function of industry
supply and demand for drilling units in the markets in which we

- 25 -

operate. During periods of high demand, our rigs typically achieve higher
utilization and dayrates than during periods of low demand. Some of our drilling
contracts also enable us to earn mobilization, contract preparation, capital
upgrade, and bonus and demobilization revenue. Mobilization, contract
preparation and capital upgrade revenue earned on a lump sum basis is recognized
over the original contract term. Bonus and demobilization revenue is recognized
when earned.

Operating and Maintenance Costs-Our operating and maintenance costs
represent all direct and indirect costs associated with the operation and
maintenance of our drilling rigs. The principal elements of these costs are
direct and indirect labor and benefits, repair and maintenance, insurance, boat
and helicopter rentals, professional and technical fees, freight costs,
communications, customs duties, tool rentals and services, fuel and water,
general taxes and licenses. Labor, repair and maintenance and insurance costs
represent the most significant components of our operating and maintenance
costs.

We do not expect operating and maintenance expenses to necessarily
fluctuate in proportion to changes in operating revenues. Operating revenues may
fluctuate as a function of changes in dayrate; however, costs for operating a
rig are generally fixed or only semi-variable regardless of the dayrate being
earned. In addition, should our rigs incur idle time between contracts, we
typically do not de-man those rigs because we will use the crew to prepare the
rig for its next contract. During times of reduced activity, reductions in costs
may not be immediate as portions of the crew may be required to prepare our rigs
for stacking, after which time the crew members are assigned to active rigs or
dismissed. In general, labor costs increase primarily due to higher salary
levels and inflation. Equipment maintenance expenses fluctuate depending upon
the type of activity the unit is performing and the age and condition of the
equipment. In addition, due to unfavorable insurance market conditions and the
resulting increase in premiums, our insurance deductibles increased effective
December 2002. Our deductible level for the year 2003 under our hull and
machinery and our protection and indemnity policies was $10.0 million per
occurrence. While our deductible per occurrence will remain unchanged in 2004,
our overall aggregate insurance deductible has increased for the upcoming policy
year.

Depreciation Expense-Our depreciation expense is based on estimates,
assumptions and judgments relative to capitalized costs, useful lives and
salvage values of our assets. We generally compute depreciation using the
straight-line method after allowing for salvage values.

General and Administrative Expense-General and administrative expense
includes all costs related to our corporate executives, directors, investor
relations, corporate accounting and reporting, information technology, internal
audit, legal, tax, treasury, risk management and human resource functions.

Interest Expense-Interest expense consists of financing cost amortization
and interest associated with our senior notes and other debt. Interest expense
is partially offset by the amortization of gains on interest rate swaps
terminated during 2003. We expect the amortization of these gains to continue
over the life of the related debt instruments (see "-Derivative Instruments").

Income Taxes-Provisions for income taxes are based on expected taxable
income, statutory rates and tax planning opportunities available to us in the
various jurisdictions in which we operate. Taxable income may differ from
pre-tax income for financial accounting purposes, particularly in countries with
revenue-based taxes. There is no expected relationship between the provision for
income taxes and income before income taxes because the countries in which we
operate have different taxation regimes. We provide a valuation allowance for
deferred tax assets when it is more likely than not that some or all of the
benefit from the deferred tax asset will not be realized. See "-Critical
Accounting Policies."

FINANCIAL CONDITION

DECEMBER 31, 2003 COMPARED TO DECEMBER 31, 2002

DECEMBER 31,
--------------------
2003 2002 CHANGE % CHANGE
--------- --------- ---------- ---------

(IN MILLIONS, EXCEPT % CHANGE)
TOTAL ASSETS
Transocean Drilling . . . . . $10,874.0 $11,804.1 $ (930.1) (8)%
TODCO . . . . . . . . . . . . 788.6 861.0 (72.4) (8)%
--------- --------- ---------- ---------
$11,662.6 $12,665.1 $(1,002.5) (8)%
========= ========= ========== =========

The decrease in the Transocean Drilling segment assets was mainly due to a
decrease in cash and cash equivalents ($551.4 million) that resulted primarily
from the repayment of debt during 2003 and depreciation ($416.0 million). The
decrease in TODCO segment assets was primarily due to depreciation ($92.2
million) and asset impairments ($11.3 million),

- 26 -

partially offset by an increase in total assets due to the consolidation of
Delta Towing Holdings, LLC ("Delta Towing") ($6.7 million) as a result of the
early adoption of Financial Accounting Standards Board's ("FASB") Interpretation
("FIN") 46, Consolidation of Variable Interest Entities (as revised December
2003) (see "-New Accounting Pronouncements").

LIQUIDITY AND CAPITAL RESOURCES

SOURCES AND USES OF CASH

YEARS ENDED DECEMBER 31,
----------------------------
2003 2002 CHANGE
------------- ------------- ----------

(In millions)
NET CASH PROVIDED BY OPERATING ACTIVITIES
Net income (loss). . . . . . . . . . . . $ 19.2 $ (3,731.9) $ 3,751.1
Depreciation . . . . . . . . . . . . . . 508.2 500.3 7.9
Other non-cash items . . . . . . . . . . (63.2) 4,047.2 (4,110.4)
Working capital. . . . . . . . . . . . . 61.6 121.0 (59.4)
------------- ------------- ----------
$ 525.8 $ 936.6 $ (410.8)
============= ============= ==========

Net cash provided by operating activities decreased due to a combination of
poor operating results after adjusting for non-cash items and a decrease in cash
provided from working capital changes in 2003 compared to 2002.

YEARS ENDED DECEMBER 31,
----------------------------
2003 2002 CHANGE
------------- ------------- --------

(In millions)
NET CASH USED IN INVESTING ACTIVITIES
Capital expenditures. . . . . . . . . . . . $ (495.9) $ (141.0) $(354.9)
Proceeds from disposal of assets. . . . . . 8.4 88.3 (79.9)
DDII LLC's cash acquired, net of cash paid. 18.1 - 18.1
DD LLC's cash acquired. . . . . . . . . . . 18.6 - 18.6
Other, net. . . . . . . . . . . . . . . . . 3.3 7.4 (4.1)
------------- ------------- --------
$ (447.5) $ (45.3) $(402.2)
============= ============= ========

Net cash used in investing activities increased for the year ended December
31, 2003 as compared to the prior year due to an increase in capital
expenditures resulting primarily from the acquisition of the Deepwater Frontier
and Deepwater Pathfinder totaling $382.8 million (see "Capital Expenditures")
and lower proceeds from disposal of assets, partially offset by $36.7 million of
cash acquired upon acquisition of ConocoPhillips' interests in DD LLC and DDII
LLC.

YEARS ENDED DECEMBER 31,
----------------------------
2003 2002 CHANGE
------------- ------------- ----------

(In millions)
NET CASH USED IN FINANCING ACTIVITIES
Net repayments under commercial paper program . . . . . $ - $ (326.4) $ 326.4
Borrowings from issuance of debt. . . . . . . . . . . . 2.1 - 2.1
Borrowings under credit facility agreement. . . . . . . 250.0 - 250.0
Cash received from termination of interest rate swaps . 173.5 - 173.5
Repayments on other debt instruments. . . . . . . . . . (1,252.7) (189.3) (1,063.4)
Other, net. . . . . . . . . . . . . . . . . . . . . . . 8.6 (14.8) 23.4
------------- ------------- ----------
$ (818.5) $ (530.5) $ (288.0)
============= ============= ==========

Net cash used in financing activities increased in 2003 compared to 2002
primarily due to higher debt repayments, which included the repurchase of debt
put to us during the year and early debt retirements. Partially offsetting the
cash paid for debt retirements were cash received from the termination of
interest rate swaps (see "-Derivative Instruments") and borrowings under our
revolving credit facility to partially fund the payoff of synthetic lease
financing facilities (see "-Acquisitions and Dispositions"). Also in 2002 we
discontinued the payment of quarterly dividends after the second quarter
dividend payment.

- 27 -

CAPITAL EXPENDITURES

Capital expenditures totaled $495.9 million during the year ended December
31, 2003 and included our acquisition of two fifth-generation deepwater rigs,
the Deepwater Pathfinder and Deepwater Frontier, through the payoff of synthetic
lease financing arrangements totaling $382.8 million (see "-Acquisitions and
Dispositions"). The remaining $113.1 million related to capital expenditures for
existing fleet and corporate infrastructure. A substantial majority of our
capital expenditures in 2003 related to the Transocean Drilling segment.

During 2004, we expect to spend less than $100 million on our existing
fleet, corporate infrastructure and major upgrades, excluding those upgrades
required and funded by our drilling contracts, although this amount is dependent
upon the actual level of operational and contracting activity. A substantial
majority of our expected capital expenditures in 2004 relates to our Transocean
Drilling 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 (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.

Acquisitions-As a result of the R&B Falcon merger, we had ownership
interests in two unconsolidated joint ventures, 50 percent in DD LLC, and 60
percent in DDII LLC. Subsidiaries of ConocoPhillips owned the remaining
interests in these joint ventures. Each of the joint ventures was 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 were owned by special purpose entities and leased to the joint
ventures.

In May 2003, WestLB AG, one of the lenders in the Deepwater Frontier
synthetic lease financing facility, assigned its $46.1 million remaining
promissory note receivable to us in exchange for cash of $46.1 million. Also in
May 2003, but subsequent to the WestLB AG assignment, we purchased
ConocoPhillips' 40 percent interest in DDII LLC for approximately $5.0 million.
As a result of this purchase, we consolidated DDII LLC late in the second
quarter of 2003. In addition, we acquired certain drilling and other contracts
from ConocoPhillips for approximately $9.0 million in cash. In December 2003,
DDII LLC prepaid the remaining $197.5 million debt and equity principal amounts
owed, plus accrued and unpaid interest, to us and other lenders under the
synthetic lease financing facility. As a result of this prepayment, DDII LLC
became the legal owner of the Deepwater Frontier.

In November 2003, we purchased the remaining 25 percent minority interest
in the Caspian Sea Ventures International Limited ("CSVI") joint venture. CSVI
owns the jackup rig Trident 20 and is now a wholly owned subsidiary.

In December 2003, we purchased ConocoPhillips' 50 percent interest in DD
LLC in connection with the payoff of the Deepwater Pathfinder synthetic lease
financing facility. As a result of this purchase, we consolidated DD LLC late in
the fourth quarter of 2003. Concurrent with the purchase of this ownership
interest, DD LLC prepaid the remaining $185.3 million debt and equity principal
amounts owed, plus accrued and unpaid interest, to the lenders under the
synthetic lease financing facility. As a result of this prepayment, DD LLC
became the legal owner of the Deepwater Pathfinder.

Dispositions-In January 2003, we completed the sale of the RBF 160 to a
third party for net proceeds of $13.1 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 flows,
respectively.

In February 2004, we completed the IPO of TODCO. See "-Significant Events."

SOURCES OF LIQUIDITY

Our primary sources of liquidity in 2003 were our cash flows from
operations, existing cash balances, borrowings on our $800 million, five-year
revolving credit agreement and proceeds from the termination of our interest
rate swaps. The

- 28 -

primary uses of cash were debt repayment and capital expenditures. At December
31, 2003, we had $474.0 million in cash and cash equivalents.

We expect to rely primarily upon existing cash balances and internally
generated cash flows to maintain liquidity in 2004, as cash flows from
operations are expected to be positive and, together with existing cash
balances, adequate to fulfill anticipated obligations such as scheduled debt
maturities, capital expenditures and working capital needs. From time to time,
we may also use bank lines of credit to maintain liquidity for short-term cash
needs.

Excluding the acquisition of the Deepwater Pathfinder and Deepwater
Frontier (see "-Capital Expenditures"), we have significantly reduced our
capital expenditures compared to prior years due to the completion of our
newbuild program in 2001 and ongoing efforts to contain capital expenditures. We
expect capital expenditures for the fleet to be less than $100 million in 2004.

When cash on hand, cash flows from operations, proceeds from asset sales,
including the TODCO IPO, and committed bank facility availability exceed our
expected liquidity needs, we may use a portion of such cash to reduce debt prior
to scheduled maturity through repurchases, redemptions or tender offers, or make
repayments on bank borrowings.

In February 2004, we announced the redemption of the 9.5% Senior Notes due
December 2008 at the make-whole premium price provided in the indenture, which
does not effect the 9.5% Senior Notes due December 2008 of TODCO (see
"-Outlook"). We expect to utilize existing cash balances, which includes
proceeds from the TODCO IPO, to fund this redemption.

At December 31, 2003 and 2002, our total debt was $3,658.1 million and
$4,678.0 million, respectively. During the year ended December 31, 2003, we
reduced net debt, a non-GAAP financial measure defined as total debt less swap
receivables and cash and cash equivalents, by $98.4 million. The components of
net debt at carrying value were as follows (in millions):

DECEMBER 31,
---------------------
2003 2002
--------- ----------

Total Debt. . . . . . . . . . . $3,658.1 $ 4,678.0
Less: Cash and cash equivalents (474.0) (1,214.2)
Swap receivables. . . . . . - (181.3)

We believe net debt provides useful information regarding the level of our
indebtedness by reflecting the amount of indebtedness assuming cash and
investments are used to repay debt. Net debt has been reduced each year since
2001 due to the fact that cash flows, primarily from operations and asset sales,
have been greater than that needed for capital expenditures.

Our internally generated cash flow is directly related to our business and
the market sectors in which we operate. Should the drilling market deteriorate,
or should we experience poor results in our operations, cash flow from
operations may be reduced. However, we have continued to generate positive cash
flow from operating activities over recent years.

We have access to a bank line of credit under an $800 million five-year
revolving credit agreement expiring in December 2008. As of March 1, 2004,
$600.0 million remained available under this credit line. Because our current
cash balances and this revolving credit agreement provide us with adequate
liquidity, we terminated our commercial paper program during the first quarter
of 2004.

The bank credit line requires compliance with various covenants and
provisions customary for agreements of this nature, including earnings before
interest, taxes, depreciation and amortization ("EBITDA") to interest coverage
ratio and debt to tangible capital ratio, both as defined by the credit
agreement, of not less than three to one and not greater than 50 percent,
respectively. Other provisions of the credit agreement includes 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 this
facility. 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 line and cause us to lose access to this facility.

In April 2001, the Securities and Exchange Commission ("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

- 29 -

other securities. At February 28, 2004, $1.6 billion in gross proceeds of
securities remained unissued under the shelf registration statement.

Our access to 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,
industry conditions, general economic conditions, market conditions and market
perceptions of us and our industry.

Our contractual obligations included in the table below are at face value
(in millions).

FOR THE YEARS ENDING DECEMBER 31,
----------------------------------------------------
TOTAL 2004 2005-2006 2007-2008 THEREAFTER
-------- ----- ---------- ---------- -----------

CONTRACTUAL OBLIGATIONS
Debt. . . . . . . . . . $3,485.1 $45.8 $ 770.3 $ 919.0 $ 1,750.0
Operating Leases. . . . 83.6 27.0 28.9 14.2 13.5
-------- ----- ---------- ---------- -----------
Total Obligations . . . $3,568.7 $72.8 $ 799.2 $ 933.2 $ 1,763.5
======== ===== ========== ========== ===========

Bondholders may, at their option, require us to repurchase the 1.5%
Convertible Debentures due 2021, the 7.45% Notes due 2027 and the Zero Coupon
Convertible Debentures due 2020 in May 2006, April 2007 and May 2008,
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 are also required to repurchase the convertible
debentures at the option of the holders at other later dates.

See "-Defined Benefit Pension Plans" for discussion of pension funding
requirements.

At December 31, 2003, we had other commitments that we are contractually
obligated to fulfill with cash should the obligations be called. These
obligations include 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. 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 and Brazil. These letters of credit and surety bond obligations are not
normally called as we typically comply with the underlying performance
requirement. The table below provides a list of these obligations in U.S. dollar
equivalents and their time to expiration.

FOR THE YEARS ENDING DECEMBER 31,
---------------------------------------------------
TOTAL 2004 2005-2006 2007-2008 THEREAFTER
------ ------ ---------- ---------- -----------

(IN MILLIONS)
OTHER COMMERCIAL COMMITMENTS
Standby Letters of Credit . $186.2 $166.7 $ 10.3 $ 9.2 $ -
Surety Bonds. . . . . . . . 169.5 66.2 103.2 0.1 -
------ ------ ---------- ---------- -----------
Total . . . . . . . . . . . $355.7 $232.9 $ 113.5 $ 9.3 $ -
====== ====== ========== ========== ===========

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, 2003, 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

- 30 -

be received or paid under the swaps is recognized over the lives of the swaps as
an adjustment to interest expense. If an interest rate swap is terminated, the
gain or loss is amortized over the life of the underlying debt.

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. 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.

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 received cash
proceeds, net of accrued interest, of approximately $173.5 million that was
recognized as a fair value adjustment to long-term debt in our consolidated
balance sheet and is being amortized as a reduction to interest expense over the
life of the underlying debt. Such reduction amounted to approximately $23.1
million in 2003 and is expected to be approximately $27.2 million in 2004.

HISTORICAL 2003 COMPARED TO 2002

Following is an analysis of our Transocean Drilling segment and TODCO
segment operating results, as well as an analysis of income and expense
categories that we have not allocated to our two segments.

Transocean Drilling Segment

YEARS ENDED
DECEMBER 31,
----------------------------
2003 2002 CHANGE % CHANGE
------------- ------------- ------------- ------------
(IN MILLIONS, EXCEPT DAY AMOUNTS AND PERCENTAGES)

Operating days (a) . . . . . . . . . . . . . . . . . . . . 23,712 26,315 (2,603) (10)%
Utilization (a) (b) (d). . . . . . . . . . . . . . . . . . 69% 78% N/A (12)%
Average dayrate (a) (c) (d). . . . . . . . . . . . . . . . $ 89,400 $ 93,500 $ (4,100) (4)%
Contract drilling revenues . . . . . . . . . . . . . . . . $ 2,124.0 $ 2,486.1 $ (362.1) (15)%
Client reimbursable revenues . . . . . . . . . . . . . . . 82.7 - 82.7 N/M
------------- ------------- ------------- ------------
2,206.7 2,486.1 (279.4) (11)%
Operating and maintenance expense. . . . . . . . . . . . . 1,367.9 1,291.3 76.6 6%
Depreciation . . . . . . . . . . . . . . . . . . . . . . . 416.0 408.4 7.6 2%
Impairment loss on long-lived assets and goodwill. . . . . 5.2 2,528.1 (2,522.9) N/M
Gain from sale of assets, net. . . . . . . . . . . . . . . (4.9) (2.7) (2.2) 81%
------------- ------------- ------------- ------------
Operating income (loss) before general and administrative
expense. . . . . . . . . . . . . . . . . . . . . . . . . $ 422.5 $ (1,739.0) $ 2,161.5 124%
============= ============= ============= ============

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

(a) Applicable to all rigs.
(b) Utilization is defined as the total actual number of revenue earning days as a percentage of total number
of calendar days in the period.
(c) Average dayrate is defined as contract drilling revenue earned per revenue earning day.
(d) Effective January 1, 2003, the calculation of average dayrates and utilization was changed to include all
rigs based on contract drilling revenues. Prior periods have been restated to reflect the change.

Due to a general deterioration in market conditions, average dayrates and
utilization declined resulting in a decrease in this segment's contract drilling
revenues of approximately $339.0 million, excluding the impact of the items
discussed separately below. Contract drilling revenues were also adversely
impacted by approximately $37.0 million due to the labor strike in Nigeria, the
riser separation incident on the Discoverer Enterprise and the electrical fire
on the Peregrine I. Additional decreases of $29.1 million resulted from rigs
sold, returned to owner and transferred from this segment to the

- 31 -

TODCO segment and the favorable settlement of a contract dispute during 2002.
These decreases were partially offset by increases in contract drilling revenue
of $45.2 million from a rig transferred into this segment from the TODCO segment
during the second quarter of 2002 and from the Deepwater Frontier as a result of
the consolidation of DDII LLC late in the second quarter of 2003. See
"-Significant Events."

Operating revenues for 2003 included $82.7 million related to costs
incurred and billed to customers on a reimbursable basis. See "-Overview."

The increase in this segment's operating and maintenance expense was
primarily due to the recognition of approximately $83.0 million in client
reimbursable costs as operating and maintenance expense as a result of
implementing EITF 99-19 in 2003 (see "-Overview"). In addition, expenses
increased approximately $89.9 million due to costs associated with the riser
separation incident on the Discoverer Enterprise, the consolidation of DDII LLC,
which leased the Deepwater Frontier, the restructuring of the Nigeria defined
benefit plan, costs related to the electrical fire on the Peregrine I and the
transfer of a jackup rig into this segment from the TODCO segment during the
second quarter of 2002 (see "-Significant Events"). Partially offsetting these
increases were decreased operating and maintenance expenses of approximately
$51.0 million resulting from lower activity, implementation of standardized
purchasing through negotiated agreements, nationalization of our labor force in
certain operating locations and headcount reductions in support groups.
Operating and maintenance expenses were further reduced by $44.0 million
relating to rigs sold, returned to owner or removed from drilling service during
and subsequent to 2002, the settlements of a dispute and an insurance claim as
well as a reduction in our insurance program expense during 2003 and costs
incurred in 2002 associated with restructuring charges and a litigation
provision with no comparable activity in 2003.

The increase in this segment's depreciation expense resulted primarily from
$9.1 million of additional depreciation on capital upgrades, the transfer of a
rig from the TODCO segment into this segment and depreciation expense related to
assets reclassified from held for sale to our active fleet during 2002 because
they no longer met the criteria for assets held for sale under SFAS 144. These
increases were partially offset by lower depreciation expense of $2.8 million
following the sale of rigs classified as held and used during and subsequent to
2002.

The decrease in impairment loss in this segment is primarily due to the
recognition of a $2,494.1 million goodwill impairment charge that resulted from
our annual impairment test of goodwill conducted as of October 1, 2002 with no
comparable charge in 2003. The impairment charge recorded in 2003 resulted from
the removal of two drilling units from our active fleet. In 2002, we also
recorded $28.5 million of non-cash impairment charges in this segment 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.

During 2003, this segment recognized net pre-tax gains of $4.9 million
related to the sale of the RBF 160, the Searex 15, the settlement of an
insurance claim and the sale of other assets. During 2002, this segment
recognized net pre-tax gains of $5.5 million related to the sale of the
Transocean 96, Transocean 97 and a mobile offshore production unit, the partial
settlement of an insurance claim and the sale of other assets, which were
partially offset by net pre-tax losses of $2.8 million from the sale of the RBF
209 and an office building.

TODCO Segment
YEARS ENDED
DECEMBER 31,
----------------------------
2003 2002 CHANGE % CHANGE
------------- ------------- ------------- ------------

(IN MILLIONS, EXCEPT DAY AMOUNTS AND PERCENTAGES)

Operating days (a). . . . . . . . . . . . . . . . . . . . 10,953 9,101 1,852 20%
Utilization (a) (b) (d) . . . . . . . . . . . . . . . . . 41% 34% N/A 21%
Average dayrate (a) (c) (d) . . . . . . . . . . . . . . . $ 19,200 $ 20,600 $ (1,400) (7)%

Contract drilling revenues. . . . . . . . . . . . . . . . $ 209.8 $ 187.8 $ 22.0 12%
Client reimbursable revenues. . . . . . . . . . . . . . . 17.8 - 17.8 N/M
------------- ------------- ------------- ------------
227.6 187.8 39.8 21%
Operating and maintenance expense . . . . . . . . . . . . 242.5 202.9 39.6 20%
Depreciation. . . . . . . . . . . . . . . . . . . . . . . 92.2 91.9 0.3 N/M
Impairment loss on long-lived assets and goodwill . . . . 11.3 399.3 (388.0) N/M
Gain from sale of assets, net . . . . . . . . . . . . . . (0.9) (1.0) 0.1 (10)%
------------- ------------- ------------- ------------
Operating loss before general and administrative expense. $ (117.5) $ (505.3) $ 387.8 77%
============= ============= ============= ============

- 32 -

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

Higher utilization in 2003 resulted in an increase in this segment's
contract drilling revenue of $42.9 million, partially offset by a decrease of
$21.7 million due to lower average dayrates.

Operating revenues for 2003 included $17.8 million related to costs
incurred and billed to customers on a reimbursable basis. See "-Overview."

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 increase in this segment's operating and maintenance expense was due
primarily to approximately $18.0 million in client reimbursable costs as
operating and maintenance expense as a result of implementing EITF 99-19 during
2003 (see "-Overview"). In addition, expenses increased due to an increase in
activity of approximately $14.0 million in 2003, costs of approximately $11.0
million associated with the well control incident on inland barge Rig 62 and the
fire incident on inland barge Rig 20 (see " Significant Events"), as well as
approximately $7.4 million related to a write-down of other receivables, an
insurance claim provision and the consolidation of a joint venture that owns two
land rigs during the third quarter of 2002. These increases were partially
offset by approximately $10.9 million of reduced expense relating to our
insurance program in 2003 compared to the same period in 2002, the release of a
provision for doubtful accounts receivable during 2003 upon collection of
amounts previously reserved, lower expenses resulting from the transfer of a
jackup rig from this segment into the Transocean Drilling segment during the
second quarter of 2002 and severance-related costs, other restructuring charges
and compensation-related expenses incurred in 2002 with no comparable activity
in 2003.

The decrease in impairment loss in this segment is primarily due to the
recognition of a $381.9 million non-cash goodwill impairment charge that
resulted from our annual impairment test of goodwill conducted as of October 1,
2002 with no comparable charge in 2003. Our 2003 impairment charges resulted
primarily from our decision to take five jackup rigs out of drilling service and
market the rigs for alternative uses. In 2002, we recorded non-cash impairment
charges in this segment of $17.4 million 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.

Total Company Results of Operations

YEARS ENDED
DECEMBER 31,
------------------
2003 2002 CHANGE % CHANGE
------- --------- ---------- ---------

(IN MILLIONS, EXCEPT % CHANGE)

General and Administrative Expense . . . . . . . . . . $ 65.3 $ 65.6 $ (0.3) N/M
Other (Income) Expense, net
Equity in earnings of joint ventures . . . . . . . . (5.1) (7.8) 2.7 (35)%
Interest income. . . . . . . . . . . . . . . . . . . (18.8) (25.6) 6.8 (26)%
Interest expense, net of amounts capitalized . . . . 202.0 212.0 (10.0) (5)%
Loss on retirement of debt . . . . . . . . . . . . . 15.7 - 15.7 N/M
Impairment loss on note receivable from related party 21.3 - 21.3 N/M
Other, net . . . . . . . . . . . . . . . . . . . . . 3.0 0.3 2.7 N/M
Income Tax Expense (Benefit) . . . . . . . . . . . . . 3.0 (123.0) 126.0 N/M
Cumulative Effect of Changes in Accounting Principles. (0.8) 1,363.7 (1,364.5) N/M

_________________________
"N/M" means not meaningful

- 33 -

The decrease in general and administrative expense was primarily
attributable to $9.0 million of costs related to the exchange of our newly
issued notes for TODCO's notes in March 2002 as more fully described in Note 8
to our consolidated financial statements and reduced expense related to employee
benefits for 2003. Offsetting these decreases was $8.8 million in expenses
relating to the IPO of TODCO in 2003, of which $3.1 million was incurred and
deferred in 2002.

Equity in earnings of joint ventures decreased approximately $3.8 million
primarily related to TODCO's 25 percent share of losses from Delta Towing, which
included TODCO's share of non-cash impairment charges on the carrying value of
Delta Towing's fleet and a decrease in our 50 percent share of earnings from
Overseas Drilling Limited ("ODL"), which owns the drillship Joides Resolution,
as the rig came off contract in the third quarter of 2003. Offsetting these
decreases was an increase in equity in earnings of $1.6 million related to our
50 percent share of earnings of DD LLC, which leased the Deepwater Pathfinder,
as a result of the rig's increased utilization and average dayrates in 2003
compared to the same period in 2002.

The decrease in interest income was primarily due to a decrease of $3.2
million in interest earned on the notes receivable from Delta Towing due largely
to the establishment of a reserve in the third quarter of 2003 resulting from
Delta Towing's failure to make scheduled quarterly interest payments (see
"-Related Party Transactions"). Also contributing to the decrease was lower
average cash balances for 2003 compared to 2002 primarily due to the utilization
of cash for debt reduction and capital expenditures.

The decrease in interest expense was attributable to reductions in interest
expense of $29.7 million associated with debt that was refinanced, repaid or
retired during and subsequent to 2002. We also received a refund of interest in
2003 from a taxing authority compared to an interest payment in 2002 resulting
in a reduction in interest expense of $2.1 million. Partially offsetting these
decreases was the termination of our fixed to floating interest rate swaps in
the first quarter of 2003, which resulted in a net increase in interest expense
of $22.2 million (see "-Derivative Instruments").

During 2003, we recognized a $15.7 million loss on early retirements of
$888.6 million face value debt.

During 2003, we recognized a $21.3 million impairment loss on our note
receivable from Delta Towing (see " Related Party Transactions").

We recognized a $3.5 million loss in other, net relating to the effect of
foreign currency exchange rate changes on our monetary assets and liabilities
primarily those denominated in Venezuelan bolivars (see "-Item 7A. Quantitative
and Qualitative Disclosures about Market Risk-Foreign Exchange Risk"), partially
offset by the favorable effect of foreign currency exchange rate changes on a
U.K. pound denominated escrow deposit.

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. The year ended December 31, 2003 included a tax benefit of $14.6
million attributable to the favorable resolution of a non-U.S. income tax
liability, partially offset by an increase in our estimated annual effective tax
rate to approximately 30 percent on earnings before non-cash note receivable and
other asset impairments, loss on debt retirements, IPO-related costs and Nigeria
benefit plan restructuring costs compared to our effective tax rate of
approximately 14 percent for 2002. 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 2003, we recognized a $0.8 million gain as a cumulative effect of a
change in accounting principle related to TODCO's consolidation of Delta Towing
at December 31, 2003 as a result of the early adoption of the FIN 46 (see "-New
Accounting Pronouncements"). During 2002, we recognized a $1,363.7 million
goodwill impairment charge in our TODCO reporting unit as a cumulative effect of
a change in accounting principle related to the implementation of SFAS 142.

HISTORICAL 2002 COMPARED TO 2001

On January 31, 2001, we completed the R&B Falcon merger with R&B Falcon
Corporation. 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 statements of operations and cash flows for the year ended December
31, 2001 include eleven months of operating results and cash flows for the
merged company.

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

- 34 -

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 $60,600 in 2001 to $74,800 in 2002, the
resulting increase in revenues was more than offset by a substantial decrease in
utilization, which was 74% in 2001 compared to 59% in 2002. Our 2002 financial
results included the recognition of a number of non-cash charges pertaining
substantially to goodwill impairments.

Transocean Drilling Segment

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

Operating days (a) . . . . . . . . . . . . . . . . . . . . . . . . 26,315 28,294 (1,979) (7)%
Utilization (a) (b) (d). . . . . . . . . . . . . . . . . . . . . . 78% 81% N/A (4)%
Average dayrate (a) (c) (d). . . . . . . . . . . . . . . . . . . . $ 93,500 $ 81,900 $ 11,600 14%

Contract drilling revenues . . . . . . . . . . . . . . . . . . . . $ 2,486.1 $ 2,385.2 $ 100.9 4%
Operating and maintenance expense. . . . . . . . . . . . . . . . . 1,291.3 1,326.7 (35.4) (3)%
Depreciation . . . . . . . . . . . . . . . . . . . . . . . . . . . 408.4 373.5 34.9 9%
Goodwill amortization. . . . . . . . . . . . . . . . . . . . . . . - 114.2 (114.2) N/M
Impairment loss on long-lived assets and goodwill. . . . . . . . . 2,528.1 39.4 2,488.7 N/M
Gain from sale of assets, net. . . . . . . . . . . . . . . . . . . (2.7) (50.7) 48.0 (95)%
------------- ------------- ------------- ------------
Operating income (loss) before general and administrative expense $ (1,739.0) $ 582.1 $ (2,321.1) (399)%
============= ============= ============= ============

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

(a) Applicable all rigs.
(b) Utilization is defined as the total actual number of revenue earning days as a percentage of the total number
of calendar days in the period.
(c) Average dayrate is defined as contract drilling revenue earned per revenue earning day.
(d) Effective January 1, 2003, the calculation of average dayrates and utilization was changed to include all rigs
based on contract drilling revenues. Prior periods have been restated to reflect the change.

The increase in this segment's operating revenues resulted from a $97.6
million increase from 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 TODCO segment late in 2001 and mid-2002. In addition, operating
revenues relating to historical Transocean assets totaled $1.5 billion for 2002,
representing a $32.9 million, or two percent, increase over 2001. 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 also decreased by approximately $29.5 million for
2002 compared to 2001, as a result of the sale of RBF FPSO L.P., which owned the
Seillean. 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 favorable
settlement of a contract dispute in 2002.

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

- 35 -

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 assets acquired in the 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 TODCO 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 TODCO 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 of approximately $16.7
million following the suspension of depreciation on certain rigs transferred to
assets held for sale, the sale of various rigs classified as assets held and
used during 2001 and an asset classified as held for sale in 2002 that was
subsequently transferred to the TODCO segment.

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.

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.

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.

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

(IN MILLIONS, EXCEPT DAY AMOUNTS AND PERCENTAGES)

Operating days (a) . . . . . . . . . . . . . . . . . . . . 9,101 16,375 (7,274) (44)%
Utilization (a) (b) (d). . . . . . . . . . . . . . . . . . 34% 63% N/A (47)%
Average dayrate (a) (c) (d). . . . . . . . . . . . . . . . $ 20,600 $ 26,900 $ (6,300) (23)%

Contract drilling revenues . . . . . . . . . . . . . . . . $ 187.8 $ 434.9 $ (247.1) (57)%
Operating and maintenance expense. . . . . . . . . . . . . 202.9 276.6 (73.7) (27)%
Depreciation . . . . . . . . . . . . . . . . . . . . . . . 91.9 96.6 (4.7) (5)%
Goodwill amortization. . . . . . . . . . . . . . . . . . . - 40.7 (40.7) N/M
Impairment loss on long-lived assets and goodwill. . . . . 399.3 1.0 398.3 N/M
Gain from sale of assets, net. . . . . . . . . . . . . . . (1.0) (5.8) 4.8 (83)%
------------- ------------- ------------- ------------
Operating income (loss) before general and administrative
expense. . . . . . . . . . . . . . . . . . . . . . . . . $ (505.3) $ 25.8 $ (531.1) (2,059)%
============= ============= ============= ============

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

(a) Applicable to all rigs.
(b) Utilization is defined as the total actual number of revenue earning days as a percentage of the total number

- 36 -

of calendar days in the period.
(c) Average dayrate is defined as contract drilling revenue earned per revenue earning day.
(d) Effective January 1, 2003, the calculation of average dayrates and utilization was changed to include all
rigs based on contract drilling revenues. Prior periods have been restated to reflect the change.

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 Transocean Drilling
segment resulted in a $23.7 million decrease. Excluding these three jackup rigs,
decreased utilization and average dayrates resulted in a decrease in this
segment's contract drilling revenues of $223.4 million.

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 Transocean Drilling 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 Transocean
Drilling 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.

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.

- 37 -

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%
Other (Income) Expense, net
Equity in earnings of joint ventures . . . . . . . . (7.8) (16.5) 8.7 (53)%
Interest income. . . . . . . . . . . . . . . . . . . (25.6) (18.7) (6.9) 37%
Interest expense, net of amounts capitalized . . . . 212.0 223.9 (11.9) (5)%
Loss on retirement of debt . . . . . . . . . . . . . - 28.8 (28.8) N/M
Other, net . . . . . . . . . . . . . . . . . . . . . 0.3 0.8 (0.5) (63)%
Income Tax Expense (Benefit) . . . . . . . . . . . . . (123.0) 76.2 (199.2) 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 newly
issued 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 TODCO's 25 percent share of losses from Delta Towing ($4.1 million) and to
the reduced earnings attributable to our 60 percent share of the earnings of
DDII LLC, which owns the Deepwater Frontier ($4.5 million), and our 50 percent
share of 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)
with no corresponding activity in 2002. 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
interest rates 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.

During 2001, we recognized a $28.8 million loss related to the early
retirement of $1,233.4 million face value debt.

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 14 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 2002, we recognized a $1,363.7 million goodwill impairment charge as
a cumulative effect of a change in accounting principle in our TODCO reporting
unit related to the implementation of SFAS 142.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

Our discussion and analysis of our financial condition and results of
operations are based upon our consolidated financial statements. This discussion
should be read in conjunction with disclosures included in the notes to our
consolidated financial statements related to estimates, contingencies and new
accounting pronouncements. Significant accounting policies

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are discussed in Note 2 to our consolidated financial statements. The
preparation of these financial statements requires us to make estimates and
judgments that affect the reported amounts of assets, liabilities, revenues,
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 postretirement 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. Management has discussed each of these
critical accounting policies and estimates with the Audit Committee of the Board
of Directors.

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 client receivables. If the financial condition of our
clients 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.

Provision for income taxes-Our tax provision is based on expected taxable
income, statutory rates and tax planning opportunities available to us in the
various jurisdictions in which we operate. Determination of taxable income in
any jurisdiction requires the interpretation of the related tax laws. Our
effective tax rate is expected to fluctuate from year to year as our operations
are conducted in different taxing jurisdictions and the amount of pre-tax income
fluctuates. Currently payable income tax expense represents either nonresident
withholding taxes or the liabilities expected to be reflected on our income tax
returns for the current year while the net deferred tax expense or benefit
represents the change in the balance of deferred tax assets or liabilities as
reported on the balance sheet.

We establish valuation allowances to reduce deferred tax assets when it is
more likely than not that some portion or all of the deferred tax assets will
not be realized in the future. While we have considered estimated future taxable
income and ongoing prudent and feasible tax planning strategies in assessing the
need for the valuation allowances, changes in these estimates and assumptions,
as well as changes in tax laws could require us to adjust the valuation
allowances for our deferred tax assets. These adjustments to the valuation
allowance would impact our income tax provision in the period in which such
adjustments are identified and recorded. See "-Historical 2003 compared to
2002."

Goodwill impairment-We perform a test for impairment of our goodwill
annually as of October 1 as prescribed by SFAS 142, Goodwill and Other
Intangible Assets. Because our business is cyclical in nature, goodwill could be
significantly impaired depending on when the assessment is performed in the
business cycle. The 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 65
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 or asset groups 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, 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,

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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. See "-Defined Benefit
Pension Plans."

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. Our contingent liability reserves relate primarily to
litigation, personal injury claims and potential tax assessments. Revisions to
contingent liability reserves 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.

RESTRUCTURING CHARGES

In September 2002, we committed to restructuring plans in France, Norway
and in our TODCO segment. We established a liability of approximately $5.2
million for the estimated severance-related costs associated with the
involuntary termination of 81 employees pursuant to these plans. The charge was
reported as operating and maintenance expense in our consolidated statements of
operations of which approximately $4.0 million and $1.2 million related to the
Transocean Drilling segment and TODCO segment, respectively. Through December
31, 2003, approximately $4.6 million had been paid to 74 employees representing
full or partial payments. In June 2003, we released the expected surplus
liability of $0.3 million to operating and maintenance expense in the Transocean
Drilling segment. Substantially all of the remaining liability is expected to be
paid by the end of the first quarter in 2005.

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, two funded and one unfunded (the "Frozen Plans"), that were
frozen prior to the merger for which benefits no longer accrue 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.

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In addition, we provide several defined benefit plans, primarily group
pension schemes with life insurance companies covering our Norway operations and
two unfunded plans covering certain of our employees and former employees (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 are comprised of the
U.S. Plans, the Norway Plans and the Nigeria Plan (collectively the "Transocean
Plans").

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TOTAL
RETIREMENT SUPPLEMENTAL FROZEN SUBTOTAL- NORWAY NIGERIA TRANSOCEAN
PLAN BENEFIT PLAN PLANS U.S. PLANS PLANS PLAN PLANS
------------ -------------- -------- ------------ -------- --------- ------------

(in millions)
ACCUMULATED BENEFIT OBLIGATION
At December 31, 2003 $ 101.4 $ 7.7 $ 102.2 $ 211.3 $ 30.2 $ - $ 241.5
At December 31, 2002 86.6 5.0 95.6 187.2 37.1 3.4 227.7

PROJECTED BENEFIT OBLIGATION
At December 31, 2003 $ 138.1 $ 10.9 $ 102.2 $ 251.2 $ 44.2 $ 0.1 $ 295.5
At December 31, 2002 131.2 7.6 95.8 234.6 50.4 10.6 295.6

FAIR VALUE OF PLAN ASSETS
At December 31, 2003 $ 95.0 $ - $ 91.3 $ 186.3 $ 28.1 $ - $ 214.4
At December 31, 2002 80.9 - 79.6 160.5 28.0 - 188.5

FUNDED STATUS
At December 31, 2003 $ (43.1) $ (10.9) $ (10.9) $ (64.9) $ (16.1) $ (0.1) $ (81.1)
At December 31, 2002 (50.3) (7.6) (16.2) (74.1) (22.4) (10.6) (107.1)

NET PERIODIC BENEFIT COST (INCOME)
Year Ending December 31, 2003 $ 10.7 $ 1.6 $ (1.7) $ 10.6 $ (1.8) $ 13.0 $ 21.8 (a)
Year Ending December 31, 2002 11.6 2.6 (3.7) 10.5 3.4 3.2 17.1 (a)

CHANGE IN ACCUMULATED OTHER COMPREHENSIVE INCOME
Year Ending December 31, 2003 $ (8.2) $ 1.3 $ (3.1) $ (10.0) $ - $ - $ (10.0)
Year Ending December 31, 2002 8.2 - 37.5 45.7 - - 45.7

EMPLOYER CONTRIBUTIONS
Year Ending December 31, 2003 $ - $ 0.7 $ 0.4 $ 1.1 $ 3.8 $ 18.4 $ 23.3
Year Ending December 31, 2002 - 2.4 0.3 2.7 3.0 0.9 6.6

WEIGHTED-AVERAGE ASSUMPTIONS - BENEFIT OBLIGATIONS
DISCOUNT RATE
At December 31, 2003 6.00% 6.00% 6.00% 6.00% 20.00% 6.25% (b)
At December 31, 2002 6.50% 6.50% 6.50% 6.00% 20.00% 6.90% (b)
RATE OF COMPENSATION INCREASE
At December 31, 2003 5.45% 5.45% - 3.50% 15.00% 5.24% (b)
At December 31, 2002 5.50% 5.50% - 3.50% 15.00% 5.53% (b)

WEIGHTED-AVERAGE ASSUMPTIONS - NET PERIODIC BENEFIT COST
DISCOUNT RATE
At December 31, 2003 6.50% 6.50% 6.50% 6.00% 20.00% 6.65% (b)
At December 31, 2002 7.00% 7.00% 7.00% 6.00% 20.00% 7.31% (b)
EXPECTED LONG-TERM RATE OF RETURN ON PLAN ASSETS
At December 31, 2003 9.00% - 9.00% 7.00% - 8.73% (c)
At December 31, 2002 9.00% - 9.00% 7.00% - 8.73% (c)
RATE OF COMPENSATION INCREASE
At December 31, 2003 5.45% 5.45% - 3.50% 15.00% 5.24% (b)
At December 31, 2002 5.50% 5.50% - 3.50% 15.00% 5.53% (b)

(a) Pension costs were reduced by expected returns on plan assets of $19.7 million and
$20.7 million for the years ended December 31, 2003 and 2002, respectively.
(b) Weighted-average based on relative average projected benefit obligation for the year.
(c) Weighted-average based on relative average fair value of plan assets for the year.

For the funded U.S. Plans, our funding policy consists of reviewing the
funded status of these plans annually and contributing an amount at least equal
to the minimum contribution required under the Employee Retirement Income
Security

- 42 -

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 2003 or 2002.
Contributions to the unfunded U.S. Plans in 2003 and 2002 were to fund benefit
payments.

Plan assets of the funded Transocean Plans have been favorably impacted by
a substantial rise in world equity markets during 2003 and an allocation of
approximately 60 percent of plan assets to equity securities. Debt securities
and other investments also experienced increased values, but to a lesser extent.
During 2003, the market value of the investments in the Transocean Plans
increased by $25.9 million, or 13.7 percent. The increase is due to net
investment gains of $33.8 million, primarily in the funded U.S. Plans, resulting
from the favorable performance of equity markets in 2003, partially offset by
benefit plan payments of $7.8 million from these plans. We expect to contribute
$10.0 million to the Transocean Plans in 2004, comprised of $5.4 million to the
funded U.S. Plans, an estimated $2.0 million to fund expected benefit payments
for the unfunded U.S. Plans and Nigeria Plan, and an estimated $2.6 million for
the Norway Plans to fund expected benefit payments. We expect the required
contributions will be funded from cash flow from operations. We have generated
unrecognized net actuarial losses due to the effect of the unfavorable
performance in previous years of the plan assets of the funded Transocean Plans.
As of December 31, 2003 we had cumulative losses of approximately $11.7 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
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 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. During 2002, we recorded a non-cash minimum
pension liability adjustment related to the U.S. Plans that resulted in a charge
to other comprehensive income of $32.5 million, net of tax of $13.2 million.
This charge was attributable primarily to the decline in the market value of the
funded U.S. Plans' assets and increased benefit obligations associated with a
reduction in the discount rate that resulted in the value of the funded U.S.
Plans' assets being less than the accumulated benefit obligation. Increases in
the fair value of plan assets in 2003 have resulted in a reduction in the
minimum pension liability of $9.3 million, net of tax of $0.7 million. At
December 31, 2003, the minimum pension liability included in other comprehensive
income was $23.2 million, net of tax of $12.5 million. The minimum pension
liability adjustments did not impact our results of operations during 2002 or
2003, nor did these adjustments affect our ability to meet any financial
covenants related to our debt facilities.

Our expected long-term rate of return on plan assets for the funded U.S.
Plans was 9.0 percent as of December 31, 2003 and 2002. The expected long-term
rate of return on plan assets was developed by reviewing each plan's targeted
asset allocation and asset class long-term rate of return expectations. We
regularly review our actual asset allocation and periodically rebalance plan
assets as appropriate. For the funded U.S. Plans, we discounted our future
pension obligations using a rate of 6.0 percent at December 31, 2003, 6.5
percent at December 31, 2002 and 7.0 percent at December 31, 2001. We expect
pension expense related to the Transocean Plans for 2004 to decrease by
approximately $2.5 million based on the reduction in costs attributable to the
Nigeria Plan resulting from the restructuring of this plan, partially offset by
the change in the discount rate assumptions for the U.S. Plans.

For each percentage point the expected long-term rate of return assumption
is lowered, pension expense would increase approximately $1.9 million. For each
one-half percentage point the discount rate is lowered, pension expense would
increase by approximately $3.3 million.

During 2003, we terminated all Nigerian employees, which resulted in the
payment of all accrued benefits under the Nigeria Plan. Approximately 80 of
these employees were made redundant during 2003, while the remaining employees
not considered redundant were rehired under a new plan. In accordance with the
provisions of SFAS 88, Employers' Accounting for Settlements and Curtailments of
Defined Benefit Pension Plans and Termination Benefits, this resulted in a
partial plan curtailment and a plan settlement. We paid approximately $17.0
million in severance benefits under the Nigeria Plan during 2003 as a result of
these events. In accordance with SFAS 88, we have accounted for these events as
a plan restructuring and recorded a net settlement expense of $10.4 million, as
well as a $4.6 million liability. This liability will reduce future pension

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expense related to the Nigeria Plan as it will be recognized over the expected
service term of the related employees. Pension expense for the Nigeria Plan is
estimated to be $0.1 million in 2004 and represents a 94.6% decrease as compared
to the 2003 plan expenses (excluding the settlement related expenses discussed
above).

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

OFF-BALANCE SHEET ARRANGEMENTS

Special Purpose Entities-DD LLC and DDII LLC were previously unconsolidated
joint ventures in which we owned a 50 percent and 60 percent interest,
respectively, and each was party to a synthetic lease financing facility. See
"-Acquisitions and Dispositions."

DD LLC's annual rent payments for the Deepwater Pathfinder, totaling
approximately $28.2 million in 2003, were substantially fixed through October
2003 due to the interest rate swap (see "-Derivative Instruments"). Subsequent
to the scheduled expiration of the interest rate swap, rent payments were
subject to changes in market interest rates. DDII LLC's annual rent payments for
the Deepwater Frontier were subject to changes in market interest rates and
totaled approximately $23.8 million in 2003.

With the payoff of the synthetic lease financing arrangements in December
2003, our relationships with the special purpose entities were terminated.

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 November 2005. At the termination of the lease, we may purchase the rig
for a maximum amount of approximately $35.7 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 in
exchange for a 25 percent equity interest, 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"). For the year ended
December 31, 2003, TODCO recognized interest income of $3.1 million on the
outstanding notes receivable and $0.3 million on the outstanding balance of the
Delta Towing Revolver.

Delta Towing defaulted on the notes in January 2003 by failing to make its
scheduled quarterly interest payment and remains in default as a result of its
continued failure to make its quarterly interest payments. As a result of our
continued evaluation of the collectibility of the notes, TODCO recorded a $21.3
million impairment of the notes in June 2003 based on Delta Towing's discounted
cash flows over the terms of the notes, which deteriorated in the second quarter
of 2003 as a result of the continued decline in Delta Towing's business outlook.
As permitted in the notes in the event of default, TODCO began offsetting a
portion of the amount owed to Delta Towing against the interest due under the
notes. Additionally, TODCO established a reserve of $1.6 million for interest
income earned during the year ended December 31, 2003 on the notes receivable.
TODCO consolidated Delta Towing effective December 31, 2003 (see "- New
Accounting Pronouncements").

As part of the formation of the joint venture on January 31, 2001, TODCO
entered into a charter arrangement with Delta Towing under which TODCO 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 TODCO agreed to treat Delta Towing as a preferred supplier
for the provision of marine support services.

In 2003, TODCO incurred charges totaling $11.7 million from Delta Towing
for services rendered, which were reflected in operating and maintenance
expense.

DD LLC and DDII LLC-Prior to our purchase of ConocoPhillips' interest in DD
LLC and DDII LLC (see "-Acquisitions and Dispositions"), we were a party to
drilling services agreements with DD LLC and DDII LLC for the

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operation of the Deepwater Pathfinder and Deepwater Frontier, respectively. In
2003, we earned $1.6 million and $1.3 million for such drilling services from DD
LLC and DDII LLC, respectively.

ODL-We own a 50 percent interest in an unconsolidated joint venture
company, ODL. ODL owns the Joides Resolution, for which we provide certain
operational and management services. In 2003, we earned $1.2 million for those
services.

SEPARATION OF TODCO

Master Separation Agreement with TODCO-We entered into a master separation
agreement with TODCO that provides for the completion of the separation of
TODCO's business from ours. It also governs aspects of the relationship between
us and TODCO following the IPO. The master separation agreement provides for
cross-indemnities that generally place financial responsibility on TODCO and its
subsidiaries for all liabilities associated with the businesses and operations
falling within the definition of TODCO's business, and that generally place
financial responsibility for liabilities associated with all of our businesses
and operations with us, regardless of the time those liabilities arise.

Under the master separation agreement we also agreed to generally release
TODCO, and TODCO agreed to generally release us, from any liabilities that arose
prior to the closing of the IPO, including acts or events that occurred in
connection with the separation or the IPO; provided, that specified ongoing
obligations and arrangements between TODCO and our company are excluded from the
mutual release.

The master separation agreement defines the TODCO business to generally
mean contract drilling and similar services for oil and gas wells using jackup,
submersible, barge and platform drilling rigs in the U.S. Gulf of Mexico and
U.S. inland waters; contract drilling and similar services for oil and gas wells
in and offshore Mexico, Trinidad, Colombia and Venezuela; and TODCO's joint
venture interest in Delta Towing. Our business is generally defined to include
all of the businesses and activities not defined as the TODCO business and
specifically includes contract drilling and similar services for oil and gas
wells using semisubmersibles and drillships in the U.S. Gulf of Mexico; contract
drilling and similar services for oil and gas wells in geographic regions
outside of the U.S. Gulf of Mexico, U.S. inland waters, Mexico, Colombia,
Trinidad and Venezuela; oil and gas exploration and production activities; coal
production activities; and the turnkey drilling business that TODCO formerly
operated in the U.S. Gulf of Mexico and offshore Mexico.

The master separation agreement also contains several provisions regarding
TODCO's corporate governance and accounting practices that apply as long as we
own specified percentages of TODCO's common stock. As long as we own shares
representing a majority of the voting power of TODCO's outstanding voting stock,
we will have the right to nominate for designation by TODCO's board of
directors, or a nominating committee of the board, a majority of the members of
the board, as well as the chairman of the board, and designate at least a
majority of the members of any committee of TODCO's board of directors.

If our beneficial ownership of TODCO's common stock is reduced to a level
of at least 10 percent but less than a majority of the voting power of TODCO's
outstanding voting stock, we will have the right to designate for nomination a
number of directors proportionate to our voting power and designate one member
of any committee of TODCO's board of directors.

Tax Sharing Agreement with TODCO-Our wholly owned subsidiary, Transocean
Holdings Inc. ("Transocean Holdings"), has entered into a tax sharing agreement
with TODCO in connection with the IPO. The tax sharing agreement governs
Transocean Holdings' and TODCO's respective rights, responsibilities and
obligations with respect to taxes and tax benefits, the filing of tax returns,
the control of audits and other tax matters. Under this agreement, all U.S.
federal, state, local and foreign income taxes and income tax benefits
(including income taxes and income tax benefits attributable to the TODCO
business) that accrued on or before the closing of the IPO generally will be for
the account of Transocean Holdings. Accordingly, Transocean Holdings generally
will be liable for any income taxes that accrued on or before the closing of the
IPO, but TODCO generally must pay Transocean Holdings for the amount of any
income tax benefits created on or before the closing of the IPO ("pre-closing
tax benefits") that it uses or absorbs on a return with respect to a period
after the closing of the IPO. As of December 31, 2003, TODCO is estimated to
have approximately $450 million of pre-closing tax benefits subject to its
obligation to reimburse Transocean Holdings, after elimination of those benefits
TODCO expects to use in connection with its separation from Transocean Holdings.
The ultimate amount will depend on many factors, including the ultimate
allocation of tax benefits between TODCO and our other subsidiaries under
applicable law and taxable income for calendar year 2004. This amount includes
approximately $200 million of tax benefits reflected in Transocean's December
31, 2003 historical financial statements and additional tax benefits expected to
result from the closing of the offering, specified ownership changes, statutory
allocations of tax benefits among Transocean Holdings consolidated group members
and other events. The estimated tax benefits on these historical financial
statements are before any reductions from a valuation allowance expected to be
recorded during the first quarter of 2004 or any transactions that could occur
after the IPO. Income

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taxes and income tax benefits accruing after the closing of the IPO, to the
extent attributable to Transocean Holdings or its affiliates (other than TODCO
or its subsidiaries), generally will be for the account of Transocean Holdings
and, to the extent attributable to TODCO or its subsidiaries, generally will be
for the account of TODCO. However, TODCO will be responsible for all taxes,
other than income taxes, attributable to the TODCO business, whether accruing
before, on or after the closing of the IPO.

Exceptions to the general allocation rules discussed above may apply with
respect to specific tax items or under special circumstances, including in
circumstances where TODCO's use or absorption of any pre-closing tax benefit
defers or precludes its use or absorption of any income tax benefit created
after the closing of the IPO or arises out of or relates to the alternative
minimum tax provisions of the U.S. Internal Revenue Code. In addition, TODCO
generally must pay Transocean Holdings for any tax benefits otherwise
attributable to TODCO that result from the delivery by Transocean or its
subsidiaries, after the closing of the IPO, of stock of Transocean to an
employee of TODCO in connection with the exercise of an employee stock option.
If any person other than Transocean or its subsidiaries becomes the beneficial
owner of greater than 50 percent of the aggregate voting power of TODCO's
outstanding voting stock, TODCO will be deemed to have used or absorbed all
pre-closing tax benefits and generally will be required to pay Transocean
Holdings a specified amount for these pre-closing tax benefits at the time the
requisite voting power is attained. Moreover, if any of TODCO's subsidiaries
that join with TODCO in the filing of consolidated returns ceases to join in the
filing of such returns, TODCO will be deemed to have used that portion of the
pre-closing tax benefits attributable to that subsidiary following the
cessation, and TODCO generally will be required to pay Transocean Holdings a
specified amount for this deemed tax benefit at the time such subsidiary ceases
to join in the filing of such returns.

Other Agreements with TODCO-In addition to the agreements described above,
we also entered into the following agreements with TODCO: (1) a transition
services agreement under which we will provide specified administrative support
during the transitional period following the closing of the IPO, (2) an employee
matters agreement that allocates specified assets, liabilities and
responsibilities relating to TODCO's current and former employees and their
participation in our benefit plans under which we have generally agreed to
indemnify TODCO for employment liabilities arising from any acts of our
employees or from claims by our employees against TODCO and for liabilities
relating to benefits for our employees (and TODCO has generally agreed to
similarly indemnify us) and (3) a registration rights agreement under which
TODCO has agreed to register the sale of shares of TODCO's common stock held by
us under the Securities Act of 1933, as amended, and granted us "piggy-back"
registration rights.

NEW ACCOUNTING PRONOUNCEMENTS

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
Accounting Principles Board Opinion ("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. As a result of our adoption of this
statement, our results of operations for the year ended December 31, 2001
included $28.8 million related to the loss on early retirement of debt
previously classified as an extraordinary item.

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, 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.
Compensation expense in 2003 increased approximately $4.3 million, net of tax of
$1.8 million, as of result of the adoption. See Note 2 to our consolidated
financial statements.

- 46 -

In January 2003, the FASB issued FIN 46. FIN 46 requires the consolidation
of variable interest entities in which an enterprise absorbs a majority of the
entity's expected losses, receives a majority of the entity's expected residual
returns, or both, as a result of ownership, contractual or other financial
interests in the entity. The provisions of FIN 46 are effective immediately for
those variable interest entities created after January 31, 2003. The provisions
of FIN 46, as amended December 2003, are effective for the first interim or
annual period ending after December 15, 2003 for those variable interest
entities held prior to February 1, 2003 that are considered to be special
purpose entities. The provisions, as amended, are to be applied no later than
the end of the first reporting period that ends after March 15, 2004 for all
other variable interest entities held prior to February 1, 2003. We have adopted
and applied the provisions of FIN 46, as revised December 2003, effective
December 31, 2003 for all variable interest entities.

At December 31, 2003, through our then wholly owned subsidiary, TODCO, we
had a 25 percent ownership interest in Delta Towing, a joint venture established
for the purpose of owning and operating inland and shallow water marine support
vessel equipment. At the time Delta Towing was formed, it issued $144.0 million
in notes to TODCO. Prior to the R&B Falcon merger, $64.0 million of the notes
were fully reserved leaving an $80.0 million balance at January 31, 2001. This
note agreement was subsequently amended to provide for a $4.0 million,
three-year revolving credit facility. Delta Towing's property and equipment with
a net book value at December 31, 2003 of $50.6 million serve as collateral for
TODCO's notes receivable. The carrying value of the notes receivable, net of
allowance for credit losses and equity losses in the joint venture, was $49.0
million at December 31, 2003. Delta Towing also issued a $3.0 million note to
the 75 percent joint venture partner. Delta Towing is considered a variable
interest entity as its equity is not sufficient to absorb its expected losses.
Because TODCO has the largest percentage of investment at risk through the notes
receivable, TODCO would absorb the majority of the joint venture's expected
losses; therefore, TODCO is deemed to be the primary beneficiary of Delta Towing
for accounting purposes. As such, TODCO consolidated Delta Towing effective
December 31, 2003 and the consolidation resulted in an increase in net assets
and a corresponding gain as a cumulative effect of a change in accounting
principle of approximately $0.8 million.

We are party to a sale/leaseback agreement for the semisubmersible drilling
rig M.G. Hulme, Jr. with an unrelated third party leasing company (see
"Off-Balance Sheet Arrangements-Sale/Leaseback"). Under the sale/leaseback
agreement, we have the option to purchase the semisubmersible drilling rig at
the end of the lease for a maximum amount of approximately $35.7 million.
Because the sale/leaseback agreement is with an entity in which we have no
direct investment, we are not entitled to receive the financial statements of
the leasing entity and the equity holders of the leasing company will not
release the financial statements or other financial information to us in order
for us to make the determination of whether we have a variable interest in the
entity. In addition, without the financial statements, we are unable to
determine if we are the primary beneficiary of the entity and, if so, what we
would consolidate. We have no exposure to loss as a result of the sale/leaseback
agreement. We incurred rig rental expense related to the sale/leaseback
agreement of $12.5 million, $12.6 million and $11.9 million during each of the
years ended December 31, 2003, 2002 and 2001, respectively. We currently account
for the lease of this semisubmersible drilling rig as an operating lease.

RISK FACTORS

OUR BUSINESS DEPENDS ON THE LEVEL OF ACTIVITY IN THE OIL AND GAS INDUSTRY,
WHICH IS SIGNIFICANTLY AFFECTED BY VOLATILE OIL AND GAS PRICES.

Our business depends on the level of activity in 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' expectations of future commodity prices typically drive
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,

- 47 -

- 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 IS HIGHLY COMPETITIVE AND CYCLICAL, WITH INTENSE PRICE
COMPETITION.

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.

OUR DRILLING CONTRACTS MAY BE TERMINATED DUE TO A NUMBER OF EVENTS.

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 remaining long-term
contracts associated with 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 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.

OUR BUSINESS INVOLVES NUMEROUS OPERATING HAZARDS.

Our operations are subject to the usual hazards inherent in the drilling of
oil and gas wells, such as blowouts, reservoir damage, and 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.

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. Also,
we may be effectively prevented from enforcing these indemnities because of the
nature of our relationship with some of our larger clients.

- 48 -

We maintain broad insurance coverages, including coverages for property
damage, occupational injury and illness, and general and marine third-party
liabilities. Property damage insurance covers against marine and other perils,
including losses due to capsizing, grounding, collision, fire, lightning,
hurricanes, wind, storms, and action of waves, punch-throughs, cratering,
blowouts, explosions, and war risks. We insure all of our offshore drilling
equipment for general and third party liabilities, occupational and illness
risks, and property damage. We generally insure all of our offshore drilling
rigs against property damage for their approximate fair market value.

In accordance with industry practices, we believe we are adequately insured
for 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
generally to insure all of our rigs for their approximate fair market value, our
insurance would not completely cover the costs that would be required to replace
certain of our units, including certain High-Specification Floaters. We have
also increased our deductibles such that certain claims may not be reimbursed by
insurance carriers. Such lack of reimbursement may cause the company to incur
substantial costs.

OUR NON-U.S. OPERATIONS INVOLVE ADDITIONAL RISKS NOT ASSOCIATED WITH OUR
U.S. OPERATIONS.

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 March 1, 2004, all areas in which we were operating
were covered by existing insurance policies.

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.

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. In January 2003,
Venezuela implemented foreign exchange controls that limit TODCO's ability to
convert local currency into U.S. dollars and transfer excess funds out of
Venezuela. The exchange controls could also result in an artificially high value
being placed on the local Venezuela currency. In the third quarter of 2003, to
limit our local currency exposure, we entered into an interim arrangement with
one of our customers in which we are to receive 55 percent of the billed
receivables in U.S. dollars with the remainder paid in local currency. Until new
contracts have been negotiated, the interim arrangement will remain in place.
See "-Item 7A. Quantitative and Qualitative Disclosures About Market
Risk-Foreign Exchange Risk."

- 49 -

A CHANGE IN TAX LAWS OF ANY COUNTRY IN WHICH WE OPERATE COULD RESULT IN A
HIGHER TAX RATE ON OUR WORLDWIDE EARNINGS, AND THE TRANSFER OF ASSETS BY TODCO
OR ONE OF ITS SUBSIDIARIES TO TRANSOCEAN OR ONE OF ITS OTHER SUBSIDIARIES COULD
RESULT IN THE IMPOSITION OF TAXES.

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. In addition,
our income tax returns are subject to review and examination in various
jurisdictions in which we operate. See "-Outlook."

We completed our restructuring of the ownership of a portion of the assets
held by TODCO and its subsidiaries in connection with TODCO's initial public
offering. These transfers 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.

FAILURE TO RETAIN KEY PERSONNEL COULD HURT OUR OPERATIONS.

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.

On January 31, 2004, excluding TODCO employees, approximately 24 percent of
our employees worldwide worked under collective bargaining agreements, most of
whom worked in Brazil, Norway, U.K. and Nigeria. Of these represented employees,
substantially all are working under agreements that are subject to salary
negotiation in 2004. These negotiations could result in higher personnel
expenses, other increased costs or increased operating restrictions.

TODCO also has employees working under collective bargaining agreements,
most of whom were working in Venezuela and Trinidad. At January 31, 2004,
approximately six percent of TODCO employees worked under collective bargaining
agreements in Trinidad and Venezuela.

OUR EXECUTIVE OFFICERS AND NONEMPLOYEE DIRECTORS WHO ALSO SERVE AS
DIRECTORS OF TODCO MAY HAVE POTENTIAL CONFLICTS OF INTEREST AS TO MATTERS
RELATING TO TODCO AND TRANSOCEAN.

Three of our executive officers are directors of TODCO, and one of our
nonemployee directors is also a director of TODCO. As a result of their
positions, these directors may have potential conflicts of interest as to
matters relating to TODCO and Transocean. In connection with any transaction or
other relationship involving the two companies, these directors may need to
recuse themselves and not participate in any board action relating to these
transactions or relationships. In addition, our interests may conflict with
those of TODCO in a number of areas relating to our past and ongoing
relationships. We may not be able to resolve any potential conflicts with TODCO
and, even if we do, the resolution may be less favorable than if we were dealing
with an unaffiliated third party.

COMPLIANCE WITH OR BREACH OF ENVIRONMENTAL LAWS CAN BE COSTLY AND COULD
LIMIT OUR OPERATIONS.

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. Also, we
may be effectively prevented from enforcing these indemnities because of the
nature of our relationship with some of our larger clients.

- 50 -

WORLD POLITICAL EVENTS COULD AFFECT THE MARKETS FOR DRILLING SERVICES.

On September 11, 2001, the U.S. was the target of terrorist attacks of
unprecedented scope. In the past several years, world political events have
resulted in military action in Afghanistan and Iraq. 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. 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.

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.

INFLATION

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.

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, commodity prices,
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 relocation of rigs to the Middle East and India, the U.S. gas
drilling market, rig classes and business segments, plans to dispose of our
remaining interest in TODCO, the expected completion date, cost and loss on
retirement and funding of the redemption of our 9.5% notes, the valuation
allowance for deferred net tax assets of TODCO, the expected gain in connection
with the TODCO IPO, intended reduction of debt, planned asset sales, timing of
asset sales, proceeds from asset sales, reactivation of stacked units, future
labor costs, signs and effects of increased drilling of deep wells in the inland
waters of Louisiana and Texas, 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, renewal and structure of directors' and
officers' insurance, increase in overall insurance deductible, 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 2004 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, those described under "-Risk
Factors" above, 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. All subsequent written
and oral forward-looking statements attributable to the Company or to persons
acting on our behalf are expressly qualified in their entirety by reference to
these risks and uncertainties. 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.

- 51 -

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. The table below presents scheduled debt
and related weighted-average interest rates for each of the years ended December
31 relating to debt as of December 31, 2003. Weighted-average variable rates are
based on London Interbank Offered Rate in effect at December 31, 2003, plus
applicable margins.

At December 31, 2003 (in millions, except interest rate percentages):

SCHEDULED MATURITY DATE (a) (b) FAIR VALUE
------------------------------------------------------------------- ---------
2004 2005 2006 2007 2008 THEREAFTER TOTAL 12/31/03
------ ------- ------- ------- ------- ------------ --------- ---------

Total debt
Fixed rate. . . . . . . . . . $45.8 $370.3 $400.0 $100.0 $569.0 $ 1,750.0 $3,235.1 $ 3,599.8
Average interest rate. . . 7.4% 6.8% 1.5% 7.5% 8.2% 7.2% 6.6%
Variable rate . . . . . . . . - - - - $250.0 - $ 250.0 $ 250.0
Average interest rate. . . - - - - 1.7% - 1.7%

__________________________
(a) Maturity dates of the face value of our debt assumes the put options on the 1.5% Convertible Debentures,
7.45% Notes and Zero Coupon Convertible Debentures will be exercised in May 2006, April 2007 and May 2008,
respectively.
(b) Expected maturity amounts are based on the face value of debt.

At December 31, 2003, we had approximately $250.0 million of variable rate
debt at face value (7.2 percent of total debt at face value). This variable rate
debt represented revolving credit bank debt. Given outstanding amounts as of
that date, a one percent rise in interest rates would result in an additional
$1.9 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, 2003 cash investment levels, a one percent increase in interest
rates would result in approximately $4.7 million of additional interest income
per year.

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, which is our functional
currency, 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 typically have minimal impact on overall results. In
situations where payments of local currency do not equal local currency
requirements, 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, 2003, we had
no material open foreign exchange contracts.

In January 2003, Venezuela implemented foreign exchange controls that limit
our ability to convert local currency into U.S. dollars and transfer excess
funds out of Venezuela. The exchange controls could also result in an
artificially high value being placed on the local currency. As a result, we
recognized a loss of $1.5 million, net of tax of $0.8 million, on the
revaluation of the local currency into functional U.S dollars during the second
quarter of 2003. In the third quarter of 2003, to limit our local currency
exposure, we entered into an interim arrangement with one of our customers in
which we are to receive 55 percent of the billed receivables in U.S. dollars
with the remainder paid in local currency. Until new contracts have been
negotiated, the interim arrangement will remain in place.

- 52 -

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

REPORT OF INDEPENDENT AUDITORS

To the Shareholders and Board of Directors of
Transocean Inc.

We have audited the accompanying consolidated balance sheets of Transocean
Inc. and Subsidiaries (the "Company") as of December 31, 2003 and 2002, 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, 2003. Our audits also included the financial statement schedule listed in
Item 15(a) of this Form 10-K. 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, 2003 and 2002, and the consolidated results of
their operations and their cash flows for each of the three years in the period
ended December 31, 2003, 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 Statements of Financial Accounting Standards Nos. 123 and 142,
effective January 1, 2003 and January 1, 2002, respectively.

/s/ Ernst & Young LLP

Houston, Texas
January 29, 2004

- 53 -

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

YEARS ENDED DECEMBER 31,
--------------------------------
2003 2002 2001
--------- ---------- ---------

OPERATING REVENUES. . . . . . . . . . . . . . . . . . . . . . . . . . . . . $2,333.8 $ 2,673.9 $2,820.1
Contract drilling revenues . . . . . . . . . . . . . . . . . . . . . . . 100.5 - -
--------- ---------- ---------
Client reimbursable revenues . . . . . . . . . . . . . . . . . . . . . . 2,434.3 2,673.9 2,820.1

COSTS AND EXPENSES
Operating and maintenance. . . . . . . . . . . . . . . . . . . . . . . . 1,610.4 1,494.2 1,603.3
Depreciation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 508.2 500.3 470.1
Goodwill amortization. . . . . . . . . . . . . . . . . . . . . . . . . . - - 154.9
General and administrative . . . . . . . . . . . . . . . . . . . . . . . 65.3 65.6 57.9
Impairment loss on long-lived assets and goodwill. . . . . . . . . . . . 16.5 2,927.4 40.4
Gain from sale of assets, net. . . . . . . . . . . . . . . . . . . . . . (5.8) (3.7) (56.5)
--------- ---------- ---------
2,194.6 4,983.8 2,270.1
--------- ---------- ---------
OPERATING INCOME (LOSS) . . . . . . . . . . . . . . . . . . . . . . . . . . 239.7 (2,309.9) 550.0
--------- ---------- ---------

OTHER INCOME (EXPENSE), NET
Equity in earnings of joint ventures . . . . . . . . . . . . . . . . . . 5.1 7.8 16.5
Interest income. . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18.8 25.6 18.7
Interest expense, net of amounts capitalized . . . . . . . . . . . . . . (202.0) (212.0) (223.9)
Loss on retirement of debt . . . . . . . . . . . . . . . . . . . . . . . (15.7) - (28.8)
Impairment loss on note receivable from related party. . . . . . . . . . (21.3) - -
Other, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (3.0) (0.3) (0.8)
--------- ---------- ---------
(218.1) (178.9) (218.3)
--------- ---------- ---------
INCOME (LOSS) BEFORE INCOME TAXES, MINORITY INTEREST AND
CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES . . . . . . . . . 21.6 (2,488.8) 331.7
Income Tax Expense (Benefit). . . . . . . . . . . . . . . . . . . . . . . . 3.0 (123.0) 76.2
Minority Interest . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0.2 2.4 2.9
--------- ---------- ---------
INCOME (LOSS) BEFORE CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES. 18.4 (2,368.2) 252.6
Cumulative Effect of Changes in Accounting Principles . . . . . . . . . . . 0.8 (1,363.7) -
--------- ---------- ---------
NET INCOME (LOSS) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 19.2 $(3,731.9) $ 252.6
========= ========== =========

BASIC EARNINGS (LOSS) PER SHARE
Income (Loss) Before Cumulative Effect of Changes in Accounting Principles $ 0.06 $ (7.42) $ 0.82
Cumulative Effect of Changes in Accounting Principles . . . . . . . . . . - (4.27) -
--------- ---------- ---------
Net Income (Loss). . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 0.06 $ (11.69) $ 0.82
========= ========== =========

DILUTED EARNINGS (LOSS) PER SHARE
Income (Loss) Before Cumulative Effect of Changes in Accounting Principles $ 0.06 $ (7.42) $ 0.80
Cumulative Effect of Changes in Accounting Principles. . . . . . . . . . - (4.27) -
--------- ---------- ---------
Net Income (Loss). . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 0.06 $ (11.69) $ 0.80
========= ========== =========

WEIGHTED AVERAGE SHARES OUTSTANDING
Basic. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 319.8 319.1 309.2
--------- ---------- ---------
Diluted. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 321.4 319.1 314.8
--------- ---------- ---------

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

See accompanying notes.

- 54 -

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

YEARS ENDED DECEMBER 31,
---------------------------
2003 2002 2001
------ ---------- -------

Net Income (Loss). . . . . . . . . . . . . . . . . . . . . . . . $19.2 $(3,731.9) $252.6
------ ---------- -------
Other Comprehensive Income (Loss), net of tax
Gain on terminated interest rate swaps . . . . . . . . . . . . - - 4.1
Amortization of gain on terminated interest rate swaps . . . . (0.2) (0.3) (0.2)
Change in unrealized loss on securities available for sale . . 0.2 - (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 (net of tax expense (benefit)
of $1.1 and $(1.1) for each of the years ended December 31,
2003 and 2002, respectively) . . . . . . . . . . . . . . . . 2.0 3.6 -
Change in minimum pension liability (net of tax expense
(benefit) of $0.7 and $(13.2) for the years ended
December 31, 2003 and 2002, respectively). . . . . . . . . . 9.3 (32.5) -
------ ---------- -------
Other Comprehensive Income (Loss). . . . . . . . . . . . . . . . 11.3 (29.2) (2.3)
------ ---------- -------
Total Comprehensive Income (Loss). . . . . . . . . . . . . . . . $30.5 $(3,761.1) $250.3
====== ========== =======

See accompanying notes.

- 55 -

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

DECEMBER 31,
----------------------
2003 2002
---------- ----------

ASSETS
Cash and Cash Equivalents . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 474.0 $ 1,214.2
Accounts Receivable, net
Trade . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 435.3 437.6
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 45.0 61.7
Materials and Supplies, net . . . . . . . . . . . . . . . . . . . . . . . . . . . 152.0 155.8
Deferred Income Taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41.0 21.9
Other Current Assets. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31.6 20.5
---------- ----------
Total Current Assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,178.9 1,911.7
---------- ----------

Property and Equipment. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10,673.0 10,198.0
Less Accumulated Depreciation . . . . . . . . . . . . . . . . . . . . . . . . . . 2,663.4 2,168.2
---------- ----------
Property and Equipment, net . . . . . . . . . . . . . . . . . . . . . . . . . . 8,009.6 8,029.8
---------- ----------
Goodwill. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,230.8 2,218.2
Investments in and Advances to Joint Ventures . . . . . . . . . . . . . . . . . . 5.5 108.5
Deferred Income Taxes, net. . . . . . . . . . . . . . . . . . . . . . . . . . . . 28.2 26.2
Other Assets. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 209.6 370.7
---------- ----------
Total Assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $11,662.6 $12,665.1
========== ==========

LIABILITIES AND SHAREHOLDERS' EQUITY

Accounts Payable. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 146.1 $ 134.1
Accrued Income Taxes. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 57.2 59.5
Debt Due Within One Year. . . . . . . . . . . . . . . . . . . . . . . . . . . . . 45.8 1,048.1
Other Current Liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . 262.0 262.2
---------- ----------
Total Current Liabilities. . . . . . . . . . . . . . . . . . . . . . . . . . 511.1 1,503.9
---------- ----------

Long-Term Debt. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3,612.3 3,629.9
Deferred Income Taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 42.8 107.2
Other Long-Term Liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . 303.8 282.7
---------- ----------
Total Long-Term Liabilities. . . . . . . . . . . . . . . . . . . . . . . . . 3,958.9 4,019.8
---------- ----------

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, 319,926,500 and
319,219,072 shares issued and outstanding at December 31, 2003 and 2002,
respectively. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.2 3.2
Additional Paid-in Capital. . . . . . . . . . . . . . . . . . . . . . . . . . . . 10,643.8 10,623.1
Accumulated Other Comprehensive Loss. . . . . . . . . . . . . . . . . . . . . . . (20.2) (31.5)
Retained Deficit. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (3,434.2) (3,453.4)
---------- ----------
Total Shareholders' Equity . . . . . . . . . . . . . . . . . . . . . . . . . 7,192.6 7,141.4
---------- ----------
Total Liabilities and Shareholders' Equity . . . . . . . . . . . . . . . . . $11,662.6 $12,665.1
========== ==========

See accompanying notes.

- 56 -

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, 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
Net income. . . . . . . . . . . . . . . - - - - 19.2 19.2
Issuance of ordinary shares under
stock-based compensation plans. . . . 0.7 - 14.0 - - 14.0
Gain on terminated interest rate swaps. - - - (0.2) - (0.2)
Fair value adjustment on marketable
securities held for sale. . . . . . . . 0.2 0.2
Other comprehensive income
related to joint venture. . . . . . . - - - - 2.0 - 2.0
Minimum pension liability . . . . . . . - - - 9.3 - 9.3
Other . . . . . . . . . . . . . . . . . - - 6.7 - - 6.7
------- ------- ------------ --------------- ---------- ----------

Balance at December 31, 2003. . . . . . . 319.9 $ 3.2 $ 10,643.8 $ (20.2) $(3,434.2) $ 7,192.6
======= ======= ============ =============== ========== ==========

See accompanying notes.

- 57 -

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

YEARS ENDED DECEMBER 31,
-------------------------------
2003 2002 2001
--------- ---------- --------

CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 19.2 $(3,731.9) $ 252.6
Adjustments to reconcile net income (loss) to net cash provided by
operating activities
Depreciation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 508.2 500.3 470.1
Goodwill amortization. . . . . . . . . . . . . . . . . . . . . . . . . . . . - - 154.9
Impairment loss on goodwill. . . . . . . . . . . . . . . . . . . . . . . . . - 4,239.7 -
Deferred income taxes. . . . . . . . . . . . . . . . . . . . . . . . . . . . (98.5) (224.4) (107.7)
Equity in earnings of joint ventures . . . . . . . . . . . . . . . . . . . . (5.1) (7.8) (16.5)
Net (gain) loss from disposal of assets. . . . . . . . . . . . . . . . . . . 13.4 3.9 (52.5)
Loss on retirement of debt . . . . . . . . . . . . . . . . . . . . . . . . . 15.7 - 28.8
Impairment loss on long-lived assets . . . . . . . . . . . . . . . . . . . . 16.5 51.4 40.4
Impairment loss on note receivable from related party. . . . . . . . . . . . 21.3 - -
Amortization of debt-related discounts/premiums, fair value
adjustments and issue costs, net . . . . . . . . . . . . . . . . . . . . . (24.3) 6.2 (4.0)
Deferred income, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.4 (5.5) (46.7)
Deferred expenses, net . . . . . . . . . . . . . . . . . . . . . . . . . . . (33.2) (20.0) (53.8)
Other long-term liabilities. . . . . . . . . . . . . . . . . . . . . . . . . 10.8 17.1 (2.1)
Other, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15.8 (13.4) 5.1
Changes in operating assets and liabilities, net of effects from the R&B Falcon
merger
Accounts receivable. . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19.8 179.4 (55.2)
Accounts payable and other current liabilities . . . . . . . . . . . . . . . 6.5 (78.8) (95.9)
Income taxes receivable/payable, net . . . . . . . . . . . . . . . . . . . . 27.8 8.9 48.2
Other current assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7.5 11.5 (5.3)
--------- ---------- --------
Net Cash Provided by Operating Activities. . . . . . . . . . . . . . . . . . . . . 525.8 936.6 560.4
--------- ---------- --------

CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (495.9) (141.0) (506.2)
Note issued to related party . . . . . . . . . . . . . . . . . . . . . . . . . . (46.1) - -
Payments received from note issued to related party. . . . . . . . . . . . . . . 46.1 - -
Deepwater Drilling II L.L.C.'s cash acquired, net of cash paid . . . . . . . . . 18.1 - -
Deepwater Drilling L.L.C.'s cash acquired. . . . . . . . . . . . . . . . . . . . 18.6 - -
Proceeds from sale of securities . . . . . . . . . . . . . . . . . . . . . . . . - - 17.2
Proceeds from sale of subsidiary . . . . . . . . . . . . . . . . . . . . . . . . - - 85.6
Proceeds from disposal of assets, net. . . . . . . . . . . . . . . . . . . . . . 8.4 88.3 116.1
Merger costs paid. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . - - (24.4)
Cash acquired in merger, net of cash paid. . . . . . . . . . . . . . . . . . . . - - 264.7
Joint ventures and other investments, net. . . . . . . . . . . . . . . . . . . . 3.3 7.4 20.6
--------- ---------- --------
Net Cash Used in Investing Activities. . . . . . . . . . . . . . . . . . . . . . . (447.5) (45.3) (26.4)
--------- ---------- --------

See accompanying notes.

- 58 -

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

YEARS ENDED DECEMBER 31,
---------------------------------
2003 2002 2001
---------- --------- ----------

CASH FLOWS FROM FINANCING ACTIVITIES
Net borrowings (repayments) under commercial paper program - (326.4) 326.4
Net borrowings from issuance of debt. . . . . . . . . . . . . . . . 2.1 - 1,693.5
Net borrowings (repayments) on revolving credit agreements. . . . . 250.0 - (180.1)
Repayments on other debt instruments. . . . . . . . . . . . . . . . (1,252.7) (189.3) (1,551.0)
Cash from termination of interest rate swaps. . . . . . . . . . . . 173.5 - -
Net proceeds from issuance of ordinary shares under stock-based
compensation plans. . . . . . . . . . . . . . . . . . . . . . . . 12.8 10.2 29.6
Proceeds from issuance of ordinary shares upon exercise of warrants - - 10.6
Dividends paid - (19.1) (38.2)
Financing costs . . . . . . . . . . . . . . . . . . . . . . . . . . (4.9) (8.5) (15.2)
Other, net. . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0.7 2.6 9.3
---------- --------- ----------
Net Cash Provided by (Used in) Financing Activities . . . . . . . . . (818.5) (530.5) 284.9
---------- --------- ----------

Net Increase (Decrease) in Cash and Cash Equivalents. . . . . . . . . (740.2) 360.8 818.9
---------- --------- ----------
Cash and Cash Equivalents at Beginning of Period. . . . . . . . . . . 1,214.2 853.4 34.5
---------- --------- ----------
Cash and Cash Equivalents at End of Period. . . . . . . . . . . . . . $ 474.0 $1,214.2 $ 853.4
========== ========= ==========

See accompanying notes.

- 59 -

TRANSOCEAN INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1-NATURE OF BUSINESS AND PRINCIPLES OF CONSOLIDATION

Transocean Inc. (together with its subsidiaries and predecessors, unless
the context requires otherwise, the "Company") is a leading international
provider of offshore 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, 2003, the
Company owned, had partial ownership interests in or operated 96 mobile offshore
and barge drilling units, excluding the fleet of TODCO (together with its
subsidiaries and predecessors, unless the context requires otherwise, "TODCO"),
a publicly traded company as of February 2004 in which the Company owns a
majority interest. As of this date, the Company's assets consisted of 32
High-Specification semisubmersibles and drillships ("floaters"), 26 Other
Floaters, 26 Jackup Rigs and 12 Other Rigs. As of December 31, 2003, TODCO's
fleet consisted of 24 jackups, 30 drilling barges, nine land rigs, three
submersible drilling rigs and four other drilling rigs. The Company contracts
its drilling rigs, related equipment and work crews primarily on a dayrate basis
to drill oil and gas wells. The Company also provides additional services,
including management of third party well service activities.

On January 31, 2001, the Company 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 consisting of
drillships, semisubmersibles, jackup rigs and other units in addition to the
Gulf of Mexico Shallow and Inland Water segment fleet. As a result of the
merger, R&B Falcon 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 statements of operations and cash flows for the year
ended December 31, 2001 include 11 months of operating results and cash flows
for the merged company.

In July 2002, the Company announced plans to pursue a divestiture of its
Gulf of Mexico Shallow and Inland Water business, which was a part of R&B
Falcon. R&B Falcon's overall business was considerably broader than the Gulf of
Mexico Shallow and Inland Water business. In preparation for this divestiture,
the Company began the transfer of all assets and businesses out of R&B Falcon
that were unrelated to the Gulf of Mexico Shallow and Inland Water business. In
December 2002, R&B Falcon changed its name to TODCO and, in January 2004, the
Gulf of Mexico Shallow and Inland Water business segment became known as the
TODCO segment. In February 2004, TODCO completed an initial public offering
("IPO") (see Note 25). Before the closing of the IPO, TODCO completed the
transfer to the Company of all unrelated assets and businesses.

For investments in joint ventures that do not meet the criteria of a
variable interest entity and where the Company is not deemed to be the primary
beneficiary for accounting purposes of those entities that meet the variable
interest entity criteria, 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 significant influence over 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 significant influence over the joint venture. For investments in joint
ventures that meet the criteria of a variable interest entity and where the
Company is deemed to be the primary beneficiary for accounting purposes, such
entities are consolidated (see Note 2). Intercompany transactions and accounts
are eliminated.

NOTE 2-SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Accounting Estimates-The preparation of financial statements in conformity
with accounting principles generally accepted in the 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 postretirement benefits, other employment benefits and contingent
liabilities. The Company bases its estimates on historical experience and on
various other assumptions it believes are 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) Transocean Drilling (formerly "International and U.S.
Floater Contract Drilling Services") and (ii) TODCO (formerly "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 are determined by the activities and needs of customers. See Note
19.

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.

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

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 $12.0 million and $13.2 million at December 31,
2003 and 2002, respectively.

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
receivable 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. With the consolidation of Delta Towing
Holdings, LLC ("Delta Towing"), TODCO's notes receivable have been eliminated
from the Company's consolidated balance sheet at December 31, 2003 (see "-New
Accounting Pronouncements").

Allowance for Doubtful Accounts-The Company establishes an allowance for
doubtful accounts on a case-by-case basis when it believes the required payment
of specific amounts owed is unlikely to occur. This allowance was approximately
$29 million and $21 million at December 31, 2003 and 2002, 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. During the
year ended December 31, 2003, TODCO recorded an allowance for loan loss of $21.3
million (see Note 20). As a result of the consolidation of Delta Towing, the
allowance, together with the note receivable balance, was eliminated from the
Company's consolidated balance sheet (see "-New Accounting Pronouncements").
There was no allowance for loan loss at December 31, 2003 and 2002.

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 $17 million and $19 million at December 31, 2003 and 2002,
respectively.

Property and Equipment-Property and equipment, consisting primarily of
offshore drilling rigs and related equipment, represented more than 65 percent
of the Company's total assets at December 31, 2003. 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. The Company had no assets
classified as held for sale at December 31, 2003 and 2002.

Goodwill-Prior to the adoption of SFAS 142, Goodwill and Other Intangible
Assets, 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 no longer amortized and is now tested for impairment 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 reviewed by

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

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 resulting from the R&B
Falcon merger was allocated to the Company's two reporting units, Transocean
Drilling and TODCO, 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.
Goodwill resulting from previous mergers was allocated entirely to the
Transocean Drilling reporting unit.

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
Transocean Drilling reporting unit. However, because of deterioration in market
conditions that affected the TODCO reporting unit 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 Transocean Drilling and TODCO reporting units, respectively.

During the fourth quarter of 2003, the Company performed its annual test of
goodwill impairment as of October 1 with no impairment indicated for the year
ended December 31, 2003.

The Company's goodwill balance and changes in the carrying amount of
goodwill are as follows (in millions):

BALANCE AT BALANCE AT
JANUARY 1, DECEMBER 31,
2003 OTHER (a) 2003
----------- ---------- -------------

Transocean Drilling . . . . . . . $ 2,218.2 $ 12.6 $ 2,230.8

______________________
(a) Primarily represents net unfavorable adjustments during 2003 of income
tax-related pre-acquisition contingencies related to the R&B Falcon merger.

- 62 -

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

Net income (loss) and earnings (loss) per share for the years ended
December 31, 2003, 2002 and 2001 adjusted for goodwill amortization are as
follows (in millions, except per share data):

YEARS ENDED DECEMBER 31,
-------------------------
2003 2002 2001
----- ---------- ------

Reported income (loss) before cumulative effect of changes
in accounting principles. . . . . . . . . . . . . . . . . $18.4 $(2,368.2) $252.6
Add back: Goodwill amortization . . . . . . . . . . . . . . - - 154.9
----- ---------- ------
Adjusted reported income (loss) before cumulative effect
of changes in accounting principles . . . . . . . . . . . 18.4 (2,368.2) 407.5
Cumulative effect of changes in accounting principles . . . 0.8 (1,363.7) -
----- ---------- ------
Adjusted net income (loss). . . . . . . . . . . . . . . . . $19.2 $(3,731.9) $407.5
===== ========== ======

Basic earnings (loss) per share:
Reported income (loss) before cumulative effect of changes
in accounting principles. . . . . . . . . . . . . . . . . $0.06 $ (7.42) $ 0.82
Goodwill amortization . . . . . . . . . . . . . . . . . . . - - 0.50
----- ---------- ------
Adjusted reported income (loss) before cumulative effect
of changes in accounting principles . . . . . . . . . . . 0.06 (7.42) 1.32
Cumulative effect of changes in accounting principles . . . - (4.27) -
----- ---------- ------
Adjusted net income (loss). . . . . . . . . . . . . . . . . $0.06 $ (11.69) $ 1.32
===== ========== ======

Diluted earnings (loss) per share:
Reported income (loss) before cumulative effect of changes
in accounting principles. . . . . . . . . . . . . . . . . $0.06 $ (7.42) $ 0.80
Goodwill amortization . . . . . . . . . . . . . . . . . . . - - 0.49
----- ---------- ------
Adjusted reported income (loss) before cumulative effect
of changes in accounting principles . . . . . . . . . . . 0.06 (7.42) 1.29
Cumulative effect of changes in accounting principles . . . - (4.27) -
----- ---------- ------
Adjusted net income (loss). . . . . . . . . . . . . . . . . $0.06 $ (11.69) $ 1.29
===== ========== ======

Impairment of Long-Lived Assets-The carrying value of long-lived assets,
principally 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.

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 were considered refinements of the estimation process of
the prior year and were 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 new drilling contracts,
revenues earned and incremental costs incurred directly related to preparation
and mobilization 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 reported 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.

- 63 -

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

Capitalized Interest-Interest costs for the construction and upgrade of
qualifying assets are capitalized. The Company incurred total interest expense
of $202.0 million, $212.0 million and $258.8 million for the years ended
December 31, 2003, 2002 and 2001, respectively. The Company capitalized interest
costs on construction work in progress of $34.9 million for the year ended
December 31, 2001. No interest cost was capitalized during the years ended
December 31, 2003 and 2002.

Derivative Instruments and Hedging Activities-The Company accounts for its
derivative instruments and hedging activities in accordance with SFAS 133,
Accounting for Derivative Instruments and Hedging Activities. See Notes 9 and
10.

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 $(3.5) million, $(0.5) million, and $1.1 million for the years
ended December 31, 2003, 2002 and 2001, 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,
particularly in countries with revenue-based taxes. There is no expected
relationship between the provision for income taxes and income before income
taxes because the countries in which the Company operates 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 14.

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" and Note 16). 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.

Effective January 1, 2003, the Company adopted the fair value recognition
provisions of SFAS 123 using the prospective method. Under the prospective
method and in accordance with the provisions of SFAS 148, Accounting for
Stock-Based Compensation - Transition and Disclosure, the recognition provisions
are applied to all employee awards granted, modified, or settled after January
1, 2003. As a result of the adoption of SFAS 123, the Company recorded higher
compensation expense of $4.3 million ($0.01 per diluted share), net of tax of
$1.8 million, related to its stock-based compensation awards and modifications,
and its Employee Stock Purchase Plan ("ESPP") during 2003.

- 64 -

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

The expense related to stock-based employee compensation included in the
determination of net income for the years ended December 31, 2003, 2002 and 2001
would be less than that which would have been recognized if the fair value
method had been applied to all awards granted after the original effective date
of SFAS 123. If the Company had elected to adopt the fair value recognition
provisions of SFAS 123 as of its original effective date, pro forma net income
and diluted net income per share would have been as follows:

YEARS ENDED DECEMBER 31,
----------------------------
2003 2002 2001
------- ---------- -------

Net Income (Loss) as Reported . . . . . . . . . . . . . . . . . . . $ 19.2 $(3,731.9) $252.6
Add back: Stock-based compensation expense included in reported
net income (loss), net of related tax effects . . . . . . . . . 4.6 2.8 0.1
Deduct: Total stock-based compensation expense determined under
fair value based method for all awards, net of related tax effects
Long-Term Incentive Plan. . . . . . . . . . . . . . . . . . . (17.6) (23.5) (11.2)
ESPP. . . . . . . . . . . . . . . . . . . . . . . . . . . . . (2.5) (2.2) (1.7)

------- ---------- -------
Pro Forma net income (loss) . . . . . . . . . . . . . . . . . . . $ 3.7 $(3,754.8) $239.8
======= ========== =======

Basic Earnings (Loss) Per Share
As Reported . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 0.06 $ (11.69) $ 0.82
Pro Forma . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0.01 (11.77) 0.78

Diluted Earnings (Loss) Per Share
As Reported . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 0.06 $ (11.69) $ 0.80
Pro Forma . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0.01 (11.77) 0.76

The above pro forma amounts are not indicative of future pro forma results.
The fair value of each option grant under the Long-Term 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,
----------------------------------------
2003 2002 2001
------------ ------------ ------------

Dividend yield. . . . . . . . . . . . . . . . . - - 0.30%
Expected price volatility range . . . . . . . . 39%-45% 49%-51% 50%-51%
Risk-free interest rate range . . . . . . . . . 1.94%-3.16% 2.79%-4.11% 4.13%-5.25%
Expected life of options (in years) . . . . . . 4.21 3.84 4.00
Weighted-average fair value of options granted. $ 7.13 $ 12.25 $ 16.26

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

YEARS ENDED DECEMBER 31,
-------------------------------------------------
2003 2002 2001
--------------- --------------- ---------------

Dividend yield . . . . . . . . . . . . . . . . - - 0.30%
Expected price volatility. . . . . . . . . . . 41% 45% 51%
Risk-free interest rate. . . . . . . . . . . . 1.09% 2.14% 1.71%
Expected life of options . . . . . . . . . . . Less than one Less than one Less than one
year year year
Weighted-average fair value of options granted $ 4.69 $ 4.76 $ 7.22

New Accounting Pronouncements-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

- 65 -

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

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 adopted
SFAS 145 effective January 1, 2003. As a result of the adoption of this
statement, the Company's results of operations for the year ended December 31,
2001 included $28.8 million ($0.09 per diluted share) related to the loss on
early retirement of debt previously classified as an extraordinary item.

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 of the disclosure requirements 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 under SFAS 123 effective January 1, 2003.
Compensation expense in 2003 increased approximately $4.3 million ($0.01 per
diluted share), net of tax of $1.8 million, as of result of adoption. See
"-Stock-Based Compensation."

In January 2003, the FASB issued Interpretation ("FIN") 46, Consolidation
of Variable Interest Entities. FIN 46 requires the consolidation of variable
interest entities in which an enterprise absorbs a majority of the entity's
expected losses, receives a majority of the entity's expected residual returns,
or both, as a result of ownership, contractual or other financial interests in
the entity. The provisions of FIN 46 were effective immediately for those
variable interest entities created after January 31, 2003. The provisions, as
amended December 2003, are effective for the first interim or annual period
ending after December 15, 2003 for those variable interest entities held prior
to February 1, 2003 that are considered to be special purpose entities. The
provisions, as amended, are to be applied no later than the end of the first
reporting period that ends after March 15, 2004 for all other variable interest
entities held prior to February 1, 2003. The Company adopted and applied the
provisions of FIN 46, as revised December 31, 2003, effective December 31, 2003
for all variable interest entities.

At December 31, 2003, through TODCO, the Company had a 25 percent ownership
interest in Delta Towing, a joint venture established for the purpose of owning
and operating inland and shallow water marine support vessel equipment. See Note
20. Delta Towing is considered a variable interest entity as its equity is not
sufficient to absorb its expected losses. Because TODCO has the largest
percentage of investment at risk through the notes receivable, TODCO would
absorb the majority of the joint venture's expected losses; therefore, TODCO is
deemed to be the primary beneficiary of Delta Towing for accounting purposes. As
such, TODCO consolidated Delta Towing effective December 31, 2003 and the
consolidation resulted in an increase in net assets and a corresponding gain as
a cumulative effect of a change in accounting principle of approximately $0.8
million.

The Company is party to a sale/leaseback agreement for the semisubmersible
drilling rig M.G. Hulme, Jr. with an unrelated third party leasing company (see
Note 15). Under the sale/leaseback agreement, the Company has the option to
purchase the semisubmersible drilling rig at the end of the lease for a maximum
amount of approximately $35.7 million. Because the sale/leaseback agreement is
with an entity in which the Company has no direct investment, the Company is not
entitled to receive the financial statements of the leasing entity and the
equity holders of the leasing company will not release the financial statements
or other financial information in order for the Company to make the
determination of whether the entity is a variable interest entity. In addition,
without the financial statements, the Company is unable to determine if it is
the primary beneficiary of the entity and, if so, what it would consolidate. The
Company has no exposure to loss as a result of the sale/leaseback agreement. The
Company has incurred rig rental expense related to the sale/leaseback agreement
of $12.5 million, $12.6 million and $11.9 million during each of the years ended
December 31, 2003, 2002 and 2001, respectively. The Company currently accounts
for the lease of this semisubmersible drilling rig as an operating lease.

Effective January 2003, the Company implemented Emerging Issues Task Force
("EITF") Issue No. 99-19, Reporting Revenues Gross as a Principal versus Net as
an Agent. As a result of the implementation of the EITF, the costs incurred and
charged to the Company's customers on a reimbursable basis are recognized as
operating and maintenance expense. In addition,

- 66 -

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

the amounts billed to the Company's customers associated with these reimbursable
costs are being recognized as client reimbursable revenue. The increase in
client reimbursable revenues and operating and maintenance expense was $100.5
million in 2003 as a result of the implementation of EITF 99-19. The change in
accounting principle had no effect on the Company's results of operations or
consolidated financial position. Prior period amounts have not been
reclassified, as these amounts were not material.

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, 2003 and 2002, net of tax, 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)
Other comprehensive income (loss) (0.2) 0.2 2.0 9.3 11.3
------------ --------------- ----------------- ----------- ---------------
Balance at December 31, 2003 . . . $ 3.4 $ (0.4) $ - $ (23.2) $ (20.2)
============ =============== ================= =========== ===============

Deepwater Drilling L.L.C. ("DD LLC"), a previously unconsolidated
subsidiary in which the Company had a 50 percent ownership interest, entered
into interest rate swaps with aggregate market values netting to a $6.7 million
liability at December 31, 2002 (see Note 18). The Company's interest in these
swaps was recorded as other comprehensive loss related to unconsolidated joint
venture. These swaps expired in October 2003 (see Note 10).

NOTE 4-BUSINESS COMBINATION

On January 31, 2001, the Company completed a merger transaction with R&B
Falcon, 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.

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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED

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 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 R&B
Falcon assuming the R&B Falcon merger was completed as of January 1, 2001 for
the year ended December 31, 2001 are as follows (in millions, except per share
data):

Operating revenues. . . . . . . . $2,946.0
Operating income. . . . . . . . . 553.9
Income from continuing operations 260.2
Earnings per share:
Basic . . . . . . . . . . . . . . $ 0.82
Diluted . . . . . . . . . . . . . $ 0.80

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 AND OTHER ASSET ACQUISITIONS

Capital expenditures totaled $495.9 million during the year ended December
31, 2003 and included the Company's acquisition of two Fifth-Generation
Deepwater Floaters, the Deepwater Pathfinder and Deepwater Frontier, through the
payoff of synthetic lease financing arrangements totaling $382.8 million. The
remaining $113.1 million related to capital expenditures for existing fleet and
corporate infrastructure. A substantial majority of the capital expenditures in
2003 related to the Transocean Drilling segment.

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 the capital expenditures in 2002
related to the Transocean Drilling segment.

Capital expenditures, including capitalized interest, totaled $506.2
million during the year ended December 31, 2001 and included approximately
$175.0 million, $42.0 million, $41.0 million and $24.0 million spent on the
construction of the Deepwater Horizon, Sedco Energy, Sedco Express and Cajun
Express, respectively. A substantial majority of the capital expenditures in
2001 related to the Transocean Drilling segment. The Company's construction
program was completed as of December 31, 2001.

As a result of the R&B Falcon merger, the Company acquired ownership
interests in two unconsolidated joint ventures, 50 percent in DD LLC and 60
percent in Deepwater Drilling II L.L.C. ("DDII LLC"). Subsidiaries of
ConocoPhillips owned the remaining interests in these joint ventures. Each of
the joint ventures was 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 were owned by special purpose entities and leased
to the joint ventures.

In May 2003, WestLB AG, one of the lenders in the Deepwater Frontier
synthetic lease financing facility, assigned its $46.1 million remaining
promissory note receivable to the Company in exchange for cash of $46.1 million.
Also in May 2003, but subsequent to the WestLB AG assignment, the Company
purchased ConocoPhillips' 40 percent interest in DDII LLC for approximately $5.0
million. As a result of this purchase, the Company consolidated DDII LLC late in
the second quarter of 2003. In addition, the Company acquired certain drilling
and other contracts from ConocoPhillips for approximately $9.0 million in cash.
In December 2003, DDII LLC prepaid the remaining $197.5 million debt and equity
principal amounts owed,

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED

plus accrued and unpaid interest, to the Company and other lenders under the
synthetic lease financing facility. As a result of this prepayment, DDII LLC
became the legal owner of the Deepwater Frontier.

In November 2003, the Company purchased the remaining 25 percent minority
interest in the Caspian Sea Ventures International Limited ("CSVI") joint
venture. CSVI owns the jackup rig Trident 20 and is now a wholly owned
subsidiary of the Company.

In December 2003, the Company purchased ConocoPhillips' 50 percent interest
in DD LLC in connection with the payoff of the Deepwater Pathfinder synthetic
lease financing facility. As a result of this purchase, the Company consolidated
DD LLC late in the fourth quarter of 2003. Concurrent with the purchase of this
ownership interest, DD LLC prepaid the remaining $185.3 million debt and equity
principal amounts owed, plus accrued and unpaid interest, to the lenders under
the synthetic lease financing facility. As a result of this prepayment, DD LLC
became the legal owner of the Deepwater Pathfinder.

NOTE 6-ASSET DISPOSITIONS

In January 2003, in the Transocean Drilling segment, the Company completed
the sale of a jackup rig, the RBF 160, for net proceeds of $13.1 million and
recognized a gain of $0.2 million, net of tax of $0.1 million. The proceeds were
received in December 2002.

During the year ended December 31, 2003, the Company settled an insurance
claim and sold certain other assets for net proceeds of approximately $8.4
million and recorded net gains of $4.0 million ($0.01 per diluted share), net of
tax of $0.6 million, in the Transocean Drilling segment and $0.6 million, net of
tax of $0.3 million, in its TODCO segment.

During the year ended December 31, 2002, in the Transocean Drilling
segment, the Company sold the jackup rig RBF 209 and two semisubmersible rigs,
the Transocean 96 and Transocean 97, for net proceeds of $49.4 million and
recognized net losses of $0.3 million, net of tax of $0.1 million.

During the year ended December 31, 2002, the Company settled an insurance
claim and sold certain other assets for net proceeds of approximately $38.9
million and recorded net gains of $2.8 million ($0.01 per diluted share), net of
tax of $0.3 million, and $0.6 million, net of tax of $0.4 million, in the
Transocean Drilling and TODCO segments, respectively.

In December 2001, in the Transocean Drilling 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 gain of
$17.1 million ($0.05 per diluted share), net of tax of $9.2 million, for the
year ended December 31, 2001.

In February 2001, in the Transocean Drilling segment, Sea Wolf Drilling
Limited ("Sea Wolf"), a joint venture in which the Company held 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 after-tax 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 after-tax 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 gains of $5.1 million ($0.02 per diluted share), net of tax of $0.8 million,
and $3.8 million ($0.01 million per diluted share), net of tax of $2.0 million,
in the Transocean Drilling and TODCO segments, respectively.

NOTE 7-IMPAIRMENT LOSS ON LONG-LIVED ASSETS

During the year ended December 31, 2003, the Company recorded non-cash
impairment charges of $6.9 million ($0.02 per diluted share), net of tax of $3.7
million, in the TODCO segment as a result of the Company's decision to take five
jackup rigs out of drilling service and market the rigs for alternative uses.
The Company does not anticipate returning these rigs to drilling service as it
is believed to be cost prohibitive. In accordance with SFAS 144, the carrying
value of these assets was adjusted to fair market value. The fair market values
of these units as non-drilling rigs were based on third party valuations. The

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

Company also recorded a non-cash impairment charge in this segment of $0.5
million, net of tax of $0.2 million, related to its approximate 12 percent
investment in Energy Virtual Partners, LP and Energy Virtual Partners Inc. The
impairment resulted from the Company's determination that the fair value of the
assets of those entities did not support its carrying value, which is included
in investments in and advances to joint ventures in the Company's consolidated
balance sheets. The impairment was determined and measured based on the
remaining book value of the Company's investment, management's assessment of the
fair value of that investment at the time the decision was made and the amount
received upon liquidation of the assets of the investment.

During the year ended December 31, 2003, the Company recorded an after-tax,
non-cash impairment charge of $4.2 million ($0.01 per diluted share) related to
assets held and used in the Transocean Drilling segment as a result of the
Company's decision to remove one mid-water semisubmersible rig and one
self-erecting tender rig from drilling service. The impairment was determined
and measured based on an estimate of fair value derived from an offer from a
potential buyer. The Company also recorded an after-tax, non-cash impairment
charge of $1.0 million in this segment as a result of the Company's decision to
discontinue its leases on its oil and gas properties. The impairment was
determined and measured based on the remaining book value of the assets and
management's assessment of the fair value at the time the decision was made.

In 2002, the Company recorded non-cash impairment charges of $18.6 million
($0.06 per diluted share), net of tax of $9.9 million, and $10.6 million ($0.03
per diluted share), net of tax of $5.7 million, in its Transocean Drilling and
TODCO 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 Transocean Drilling and TODCO segments, respectively. See
Note 2.

In 2002, the Company recorded non-cash impairment charges in its Transocean
Drilling and TODCO segments of $3.6 million ($0.01 per diluted share), net of
tax of $1.9 million, and $0.7 million, net of tax of $0.4 million, respectively,
related 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 non-cash impairment
charges in its Transocean Drilling and TODCO segments of $30.4 million ($0.10
per diluted share), net of tax of $9.0 million, and $0.7 million, net of tax of
$0.3 million, respectively. In the Transocean Drilling segment, the impairment
related to assets held for sale and certain assets held and used of $18.6
million, net of tax of $9.0 million, and $11.8 million, respectively. In the
TODCO segment, the impairment related to certain assets held and used. 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 assets held and used and offers from potential buyers
for assets held for sale.

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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,
------------------
2003 2002
-------- --------

6.5% Senior Notes, due April 2003. . . . . . . . . . . . . . . . . . . . . . . $ - $ 239.7
9.125% Senior Notes, due December 2003 . . . . . . . . . . . . . . . . . . . . - 89.5
Amortizing Term Loan Agreement - final maturity December 2004. . . . . . . . . - 300.0
6.75% Senior Notes, due April 2005 (a) . . . . . . . . . . . . . . . . . . . . 361.2 371.8
7.31% Nautilus Class A1 Amortizing Notes - final maturity May 2005 . . . . . . 63.6 104.7
9.41% Nautilus Class A2 Notes, due May 2005. . . . . . . . . . . . . . . . . . - 51.7
6.95% Senior Notes, due April 2008 (a) . . . . . . . . . . . . . . . . . . . . 269.5 277.2
9.5% Senior Notes, due December 2008 (a) . . . . . . . . . . . . . . . . . . . 357.3 371.8
800 Million Revolving Credit Agreement - final maturity December 2008. . . . . 250.0 -
6.625% Notes, due April 2011 (b) . . . . . . . . . . . . . . . . . . . . . . . 797.3 803.7
7.375% Senior Notes, due April 2018. . . . . . . . . . . . . . . . . . . . . . 250.4 250.5
Zero Coupon Convertible Debentures, due May 2020 (put options exercisable
May 2008 and May 2013) (c) . . . . . . . . . . . . . . . . . . . . . . . . . 16.5 527.2
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. . . . . . . . . . . . . . . . . . . . . . . . . 198.1 198.0
7.45% Notes, due April 2027 (put options exercisable April 2007) . . . . . . . 94.8 94.6
7.5% Notes, due April 2031 . . . . . . . . . . . . . . . . . . . . . . . . . . 597.5 597.4
Other. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.9 0.2
-------- --------
Total Debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3,658.1 4,678.0
Less Debt Due Within One Year (c). . . . . . . . . . . . . . . . . . . . . . . 45.8 1,048.1
-------- --------
Total Long-Term Debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $3,612.3 $3,629.9
======== ========

(a) At December 31, 2002, the Company was a party to interest rate swap
agreements with respect to these debt instruments. These interest rate swap
agreements were terminated in January 2003. See Note 10.
(b) At December 31, 2002, the Company was a party to interest rate swap
agreements with respect to these debt instruments. These interest rate swap
agreements were terminated in March 2003. See Note 10.
(c) At December 31, 2002, the Zero Coupon Convertible Debentures were
classified as debt due within one year since the put options were
exercisable in May 2003. At December 31, 2003, the remaining balance of the
debentures not put back to the Company in May 2003 was classified as
long-term debt.

The scheduled maturity of the Company's debt, at face value, assumes the
bondholders exercise their options to require the Company to repurchase the 1.5%
Convertible Debentures, 7.45% Notes and Zero Coupon Convertible Debentures in
May 2006, April 2007 and May 2008, respectively, and is as follows (in
millions):

YEARS ENDING
DECEMBER 31,
-------------
2004 . . . $ 45.8
2005 . . . 370.3
2006 . . . 400.0
2007 . . . 100.0
2008 . . . 819.0
Thereafter 1,750.0
-------------
Total. . . $ 3,485.1
=============

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED

Commercial Paper Program-The Company has a revolving credit agreement,
described below, which, together with previous revolving credit agreements,
provided liquidity through commercial paper borrowings during 2002 and 2003. At
December 31, 2003, no amounts were outstanding under the Commercial Paper
Program.

Revolving Credit Agreements-The Company is party to an $800.0 million
five-year revolving credit agreement (the "Revolving Credit Agreement") dated
December 16, 2003. This revolving credit agreement replaced the previously
existing $550.0 million five-year revolving credit agreement dated December 29,
2000 and the $250.0 million 364-day revolving credit agreement dated December
26, 2002, which were both terminated effective December 16, 2003. The Revolving
Credit Agreement bears interest, at the Company's option, at a base rate or
London Interbank Offered Rate ("LIBOR") plus a margin that can vary from 0.350
percent to 0.950 percent depending on the Company's non-credit enhanced senior
unsecured public debt rating. At December 31, 2003, the applicable margin was
0.500 percent. A facility fee varying from 0.075 percent to 0.225 percent
depending on the Company's non-credit enhanced senior unsecured public debt
rating, is incurred on the daily amount of the underlying commitment, whether
used or unused, throughout the term of the facility. At December 31, 2003, the
applicable facility fee was 0.125 percent. A utilization fee of 0.125 percent is
payable if amounts outstanding under the Revolving Credit Agreement are greater
than $264.0 million. At December 31, 2003, $250.0 million was outstanding under
the Revolving Credit Agreement.

The Revolving Credit Agreement requires compliance with various covenants
and provisions customary for agreements of this nature, including earnings
before interest, taxes, depreciation and amortization ("EBITDA") to interest
coverage ratio, as defined by the credit agreement, of not less than three to
one, a debt to total tangible capital ratio, as defined by the credit agreement,
of not greater than 50 percent, and limitations on creating liens, incurring
debt, transactions with affiliates, sale/leaseback transactions and mergers and
sale of substantially all assets.

6.5%, 6.75%, 6.95%, 7.375%, 9.125% and 9.5% Senior Notes and Exchange
Offer-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. 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 (see "-Retired and Repurchased Debt"). 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 and such amortization was approximately $1.3 million in
each of the years ended December 31, 2003 and 2002. The 6.75%, 6.95%, 7.375% and
9.5% Senior Notes are redeemable at the Company's option at a make-whole premium
(see Note 25).

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, 2003, $400.0 million principal amount of
these notes was outstanding.

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

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

anniversary of issuance at the issuance price plus accrued original issue
discount to the date of repurchase (see "-Retired and Repurchased Debt"). 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, 2003, $26.4 million face value of these notes was
outstanding with a discounted value of $16.8 million. Should all of the
debentures be put to the Company in May 2008, the debentures will have a
discounted value of $19.0 million.

Retired and Repurchased Debt-In December 2003, the Company repaid all of
the $87.1 million principal amount outstanding 9.125% Senior Notes, of which
$10.2 million principal amount outstanding was the obligation of TODCO, plus
accrued and unpaid interest, in accordance with their scheduled maturity. The
Company funded the repayment from existing cash balances.

In December 2003, the Company repaid the remaining $187.5 million principal
amount outstanding under the Term Loan Agreement, plus accrued and unpaid
interest, of which $150.0 million related to the early retirement of this debt.
The Term Loan Agreement was terminated in conjunction with this repayment. The
Company funded the repayment from existing cash balances.

In May 2003, the Company repurchased and retired all of the $50.0 million
principal amount outstanding 9.41% Nautilus Class A2 Notes due May 2005 and
funded the repurchase from existing cash balances. The Company recognized a loss
on the early retirement of debt of approximately $3.6 million ($0.01 per diluted
share), net of tax of $1.9 million, in the second quarter of 2003.

In May 2003, holders of the Company's Zero Coupon Convertible Debentures
due May 24, 2020 had the option to require the Company to repurchase their
debentures. Holders of $838.6 million aggregate principal amount, or
approximately 97 percent, of these debentures exercised this option and the
Company repurchased their debentures at a repurchase price of $628.57 per $1,000
principal amount. Under the terms of the debentures, the Company had the option
to pay for the debentures with cash, the Company's ordinary shares, or a
combination of cash and shares, and elected to pay the $527.2 million repurchase
price from existing cash balances. The Company recognized additional expense of
approximately $10.2 million ($0.03 per diluted share) as an after-tax loss on
retirement of debt in the second quarter of 2003 to fully amortize the remaining
debt issue costs related to the repurchased debentures.

In April 2003, the Company repaid the entire $239.5 million principal
amount outstanding 6.5% Senior Notes, of which $5.0 million principal amount
outstanding was the obligation of TODCO, plus accrued and unpaid interest, in
accordance with their scheduled maturity. The Company funded the repayment from
existing cash balances.

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.

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 typically have minimal impact on overall results. In
situations where payments of local currency do not equal local currency
requirements, 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.

The Company does not enter into derivative transactions for speculative
purposes. At December 31, 2003, the Company had no material open foreign
exchange contracts.

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

In January 2003, Venezuela 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. As a result, the
Company recognized a loss of $1.5 million, net of tax of $0.8 million, on the
revaluation of the local currency into functional U.S. dollars during the second
quarter of 2003. In the third quarter of 2003, to limit its exposure, the
Company entered into an interim arrangement with one of its customers in which
the Company is to receive 55 percent of the billed receivables in U.S. dollars
with the remainder paid in local currency.

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, 2003 and 2002, 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
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.
These interest rate swap transactions, however, have all been terminated as of
December 31, 2003. 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 that potentially subject the Company to
concentrations of credit risk are primarily cash and cash equivalents, trade
receivables, swap receivables and, prior to December 31, 2003, notes receivable
from Delta Towing (see Notes 2 and 10). 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

- 74 -

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

locations, local 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 dispersed in various countries. See Note 19. The
Company maintains an allowance for doubtful 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, excluding TODCO employees,
approximately 24 percent of the Company's employees worked under collective
bargaining agreements at December 31, 2003, most of whom worked in Brazil,
Norway, U.K. and Nigeria. Of these represented employees, substantially all are
working under agreements that are subject to salary negotiation in 2004.

At December 31, 2003, approximately five percent of TODCO employees worked
under collective bargaining agreements in Trinidad and Venezuela.

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. The objective of each transaction was to
protect the debt against changes in fair value due to changes in the benchmark
interest rate. Under each interest rate swap, the Company received the fixed
rate equal to the coupon of the hedged item and paid LIBOR plus a margin of 50
basis points, 246 basis points, 171 basis points and 413 basis points,
respectively, which were designated as the respective benchmark interest rates,
on each of the interest payment dates until maturity of the respective notes.
The hedges were 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 applied and there was no requirement to periodically
reassess the effectiveness of the hedges during the term of the swaps.

In January 2003, the Company terminated the swaps with respect to its
6.75%, 6.95% and 9.5% Senior Notes. In March 2003, the Company terminated the
swaps with respect to its 6.625% Notes. As a result of these terminations, the
Company received cash proceeds, net of accrued interest, of approximately $173.5
million that was recognized as a fair value adjustment to long-term debt in the
Company's consolidated balance sheet and is being amortized as a reduction to
interest expense over the life of the underlying debt. Such reduction amounted
to approximately $23.1 million ($0.07 per diluted share) in 2003 and is expected
to be approximately $27.2 million ($0.08 per diluted share) in 2004.

At December 31, 2003, the Company had no outstanding interest rate swaps.
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 as follows at December 31, 2002 (in millions):

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
------
$181.3
======

DD LLC, a previously unconsolidated joint venture in which the Company had
a 50 percent ownership interest, entered into interest rate swaps in August 1998
that expired in October 2003 (see Note 6). The Company's interest in these swaps
was included in accumulated other comprehensive income, net of tax, with
corresponding reductions to deferred income taxes and investments in and
advances to joint ventures.

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

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 are adjusted to
estimated market value based on current and forward LIBOR rates. The Company had
no outstanding swap receivables at December 31, 2003 (see Note 10).

Notes receivable from related party-The fair value of notes receivable from
related party with a carrying amount of $82.8 million at December 31, 2002 could
not be determined because there is no available market price for such notes. Due
to the adoption of FIN 46 and the consolidation of the related party, the notes
receivable have been eliminated in consolidation. See Notes 2 and 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, 2003 DECEMBER 31, 2002
---------------------- ----------------------
CARRYING CARRYING
AMOUNT FAIR VALUE AMOUNT FAIR VALUE
--------- ----------- --------- -----------

Cash and cash equivalents $ 474.0 $ 474.0 $ 1,214.2 $ 1,214.2
Trade receivables . . . . 435.3 435.3 437.6 437.6
Swap receivables. . . . . - - 181.3 181.3
Debt. . . . . . . . . . . 3,658.1 3,849.8 4,678.0 4,848.5

NOTE 12-OTHER CURRENT LIABILITIES

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

DECEMBER 31,
--------------
2003 2002
------ ------

Accrued Payroll and Employee Benefits $133.0 $143.6
Accrued Interest. . . . . . . . . . . 39.2 32.2
Deferred Income . . . . . . . . . . . 35.7 31.1
Reserves for Contingent Liabilities . 17.5 22.9
Accrued Taxes, Other than Income. . . 12.7 19.3
Other . . . . . . . . . . . . . . . . 23.9 13.1
------ ------
Total Other Current Liabilities . . $262.0 $262.2
====== ======

NOTE 13-SUPPLEMENTARY CASH FLOW INFORMATION

Non-cash investing activities for the years ended December 31, 2003, 2002
and 2001 included $8.9 million, $7.9 million and $11.8 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.

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

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 $219.0 million, $210.5 million and $190.6
million for the years ended December 31, 2003, 2002 and 2001, respectively. Cash
payments for income taxes, net, were $73.4 million, $91.1 million and $122.5
million for the years ended December 31, 2003, 2002 and 2001, respectively.

NOTE 14-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.

In June 2003, the Company recorded a $14.6 million ($0.04 per diluted
share) foreign tax benefit attributable to the favorable resolution of a
non-U.S. income tax liability.

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 noncurrent
deferred taxes payable.

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

YEARS ENDED DECEMBER 31,
--------------------------
2003 2002 2001
------- -------- -------

Current Provision. . . . . . . . . . . . . . . . . . . . . . . . . . . $101.5 $ 101.4 $174.4
Deferred (Benefit) . . . . . . . . . . . . . . . . . . . . . . . . . . (98.5) (224.4) (98.2)
------- -------- -------
Income Tax Provision (Benefit) before Cumulative Effect of Changes in
Accounting Principles. . . . . . . . . . . . . . . . . . . . . . . . $ 3.0 $(123.0) $ 76.2
======= ======== =======

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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,
------------------
2003 2002
-------- --------

DEFERRED TAX ASSETS-CURRENT
Accrued personnel taxes. . . . . . . . . . . . . . . . . $ 1.1 $ 1.7
Accrued workers' compensation insurance. . . . . . . . . 6.8 4.6
Other accruals . . . . . . . . . . . . . . . . . . . . . 4.1 9.1
Insurance accruals . . . . . . . . . . . . . . . . . . . 14.3 5.7
Other. . . . . . . . . . . . . . . . . . . . . . . . . . 18.2 5.4
-------- --------
Total Current Deferred Tax Assets. . . . . . . . . . . 44.5 26.5
-------- --------

DEFERRED TAX LIABILITIES-CURRENT
Deferred drydock . . . . . . . . . . . . . . . . . . . . (3.5) (4.6)
-------- --------
Total Current Deferred Tax Liabilities . . . . . . . . (3.5) (4.6)
-------- --------
Net Current Deferred Tax Assets. . . . . . . . . . . . $ 41.0 $ 21.9
======== ========

DEFERRED TAX ASSETS-NONCURRENT-NON-U.S.
Net operating loss carryforwards-non-U.S.. . . . . . . . $ 28.2 $ 26.2
-------- --------
Net Noncurrent Deferred Tax Assets-non-U.S . . . . . . $ 28.2 $ 26.2
======== ========

DEFERRED TAX ASSETS-NONCURRENT
Net operating loss and other miscellaneous carryforwards $ 619.1 $ 380.3
Foreign tax credit carryforwards . . . . . . . . . . . . 259.2 216.9
Retirement and benefit plan accruals . . . . . . . . . . 3.8 7.9
Other accruals . . . . . . . . . . . . . . . . . . . . . 35.6 11.5
Deferred income and other. . . . . . . . . . . . . . . . 0.7 29.5
Valuation allowance for noncurrent deferred tax assets . (154.9) (112.3)
-------- --------
Total Noncurrent Deferred Tax Assets . . . . . . . . . 763.5 533.8
-------- --------

DEFERRED TAX LIABILITIES-NONCURRENT
Depreciation and amortization. . . . . . . . . . . . . . (689.0) (558.9)
Investment in subsidiaries . . . . . . . . . . . . . . . (109.3) (67.7)
Other. . . . . . . . . . . . . . . . . . . . . . . . . . (8.0) (14.4)
-------- --------
Total Noncurrent Deferred Tax Liabilities. . . . . . . (806.3) (641.0)
-------- --------
Net Noncurrent Deferred Tax Liabilities. . . . . . . . $ (42.8) $(107.2)
======== ========

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. At
December 31, 2001, the Company's valuation allowance was $90.7 million. The
valuation allowance for non-current deferred tax assets increased $42.6 million
and $21.6 million during the years ended December 31, 2003 and 2002,
respectively.

The Company's U.S. net operating loss carryforwards expire between 2004 and
2023. The tax effect of the U.S. net operating loss carryforwards was $580.9
million at December 31, 2003. The Company's U.K. net operating loss

- 78 -

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

carryforwards do not expire. The tax effect of the U.K. net operating loss
carryforwards was $28.2 million at December 31, 2003, which the Company intends
to utilize through future earnings. The Company's fully benefited U.S. foreign
tax credit carryforwards will expire between 2004 and 2008.

Transocean Inc., a Cayman Islands company, is not subject to income taxes
in the Cayman Islands. For the three years ended December 31, 2003, 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. While the Company cannot predict or provide assurance as to
the final outcome of existing or future assessments, it believes 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 Limited ("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 15-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, 2003, future minimum rental payments related to
noncancellable operating leases are as follows (in millions):

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

2004 . . . $ 27.0
2005 . . . 21.2
2006 . . . 7.7
2007 . . . 7.0
2008 . . . 7.2
Thereafter 13.5
-------------
Total. . $ 83.6
=============

- 79 -

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 a maximum amount of approximately $35.7
million at the end of the lease term of November 29, 2005. At December 31, 2003,
the future minimum lease payments, excluding the purchase option, was $24.9
million and was included in the table above.

Rental expense for all operating leases, including leases with terms of
less than one year, was approximately $51 million, $52 million and $96 million
for the years ended December 31, 2003, 2002 and 2001, respectively.

Legal Proceedings-In 1990 and 1991, two of the Company's subsidiaries were
served with various assessments collectively valued at approximately $5.8
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. In October 2001, the Brazil Supreme Court rejected the Company's
appeal of an adverse lower court's ruling with respect to a June 1991
assessment, which is valued at approximately $5 million. The Company is
continuing to challenge the assessment and has an action to suspend a related
tax foreclosure proceeding, which is currently at the trial court level. The
Company received a favorable ruling in connection with a disputed August 1990
assessment but the government has appealed that ruling. 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 is now awaiting a hearing date. 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 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.

- 80 -

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

costs, loss of insurance proceeds, loss of hydrocarbons and interest. The
Company believes that most, if not all, of the settlement amounts are covered by
relevant primary and excess liability insurance policies. However, the insurers
and underwriters denied coverage and one has filed a counterclaim. TODCO has
instituted litigation against those insurers and underwriters to enforce its
rights under the relevant policies. TODCO has settled with some of the insurers
but is continuing the litigation against the remaining insurers. The Company is
responsible for any losses TODCO incurs from these actions under the master
separation agreement with TODCO and the Company will benefit from any recovery.
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, TODCO was notified by the U.S. Environmental Protection
Agency ("EPA") that the EPA had identified a subsidiary of TODCO 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 review of TODCO's internal records to date, TODCO
disputes its designation as a potentially responsible party. Pursuant to the
master separation agreement with TODCO, the Company is responsible and will
indemnify TODCO for any losses TODCO incurs in connection with this action. The
Company does not expect that the ultimate outcome of this case will have a
material adverse effect on the Company's business or consolidated financial
position.

In August 2003, a judgment of approximately $9.5 million was entered by the
Labor Division of the Provincial Court of Luanda, Angola, against the Company
and a labor contractor for the Company, Hull Blyth, in favor of certain former
workers on several of the Company's drilling rigs. The workers were employed by
Hull Blyth to work on several drilling rigs while the rigs were located in
Angola. When the drilling contracts concluded and the rigs left Angola, the
workers' employment ended. The workers brought suit claiming that they were not
properly compensated when their employment ended. In addition to the monetary
judgment, the Labor Division ordered the workers to be hired by the Company. The
Company believes that this judgment is without sufficient legal foundation and
has appealed the matter to the Angola Supreme Court. The Company further
believes that Hull Blyth has an obligation to protect the Company from any
judgment. The Company does not believe that the ultimate outcome of this matter
will have a material adverse effect on the Company's 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
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, 2003 totaling $186.2 million. These letters of
credit guarantee various contract bidding and insurance activities under various
lines provided by several banks.

As is customary in the contract drilling business, the Company also has
various surety bonds totaling $169.5 million in place that secure customs
obligations relating to the importation of its rigs and certain performance and
other obligations.

NOTE 16-STOCK-BASED COMPENSATION PLANS

Long-Term Incentive Plan-The Company has an incentive plan for key
employees and outside directors (the "Incentive Plan"). Prior to 2003, the
Company accounted for its Incentive Plan under APB 25 and related
interpretations. Effective January 1, 2003, the Company adopted the fair value
recognition provisions of SFAS 123 using the prospective method. Under the
prospective method and in accordance with the provisions of SFAS 148 (see Note
2), the recognition provisions are applied to all employee awards granted,
modified, or settled after January 1, 2003.

Under the Incentive Plan, awards can be granted in the form of stock
options, nonvested restricted stock, stock appreciation rights ("SARs") and cash
performance awards. Such awards include traditional time-vesting awards
("time-based vesting awards"), and awards that are earned based on the
achievement of certain performance criteria ("performance-based awards").
Options issued under the Incentive Plan have a 10-year term. Time-based vesting
awards vest in three equal annual installments after the date of grant.
Performance-based awards have a two year performance cycle with the number of
options or shares earned being determined following the completion of the
performance cycle (the "determination date") at which time

- 81 -

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

one-third of the options or shares granted vest. Additional vesting occurs
January 1 of the two subsequent years following the determination date.

As of December 31, 2003, 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. On December 31, 1999, all unvested stock options and SARs
and all nonvested restricted shares granted after April 1996 became fully vested
as a result of the Sedco Forex merger. At December 31, 2003, there were
approximately 6.2 million total shares available for future grants under the
Incentive Plan, assuming that the 1.5 million performance-based awards in 2003
are ultimately issued at the maximum amount.

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 Schlumberger options held by
Sedco Forex employees at the date of the spin-off will lapse in accordance with
their provisions. Non-vested Schlumberger 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 R&B Falcon and its subsidiaries were granted stock options under
various plans. As a result of the R&B Falcon merger, the Company assumed all
outstanding R&B Falcon stock options and converted them into options to purchase
ordinary shares of the Company.

Time-Based Vesting Awards

The following table summarizes time-based vesting stock option activity:

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

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

Granted. . . . . . . . . . . . . . . . . 314,860 20.95
Exercised. . . . . . . . . . . . . . . . (149,361) 10.97
Forfeited. . . . . . . . . . . . . . . . (267,684) 35.47
----------------- -----------------
Outstanding at December 31, 2003 . . . . 15,275,401 $ 27.92
================= =================

Exercisable at December 31, 2001 . . . . 9,977,963 $ 24.29
Exercisable at December 31, 2002 . . . . 11,332,039 $ 26.14
Exercisable at December 31, 2003 . . . . 13,091,737 $ 27.53

- 82 -

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

The following table summarizes information about time-based vesting stock
options outstanding at December 31, 2003:

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

$ 8.38 - $19.86 4.75 years 3,980,811 $ 15.16 3,876,143 $ 15.05
$20.12 - $33.69 5.99 years 6,212,583 $ 25.96 4,773,521 $ 25.54
$34.63 - $81.78 6.44 years 5,082,007 $ 40.30 4,442,073 $ 40.56

At December 31, 2003, there were 41,360 time-based vesting nonvested
restricted ordinary shares and 135,418 SARs outstanding under the Incentive
Plan.

Performance-Based Awards

There was no performance-based award activity prior to 2003. The following
table summarizes performance-based stock option activity during 2003:

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

Granted. . . . . . . . . . . . . 725,350 $ 21.20
Forfeited. . . . . . . . . . . . (39,019) 21.20
----------------- -----------------
Outstanding at December 31, 2003 686,331 $ 21.20
================= =================

At December 31, 2003, none of the performance-based stock options were
exercisable.

The following table summarizes information about performance-based stock
options outstanding at December 31, 2003:

21.20 9.52 years 686,331 $ 21.20 - $ -

During 2003, the Company granted performance-based nonvested restricted
ordinary share awards that are earnable based on the achievement of certain
performance targets. The number of shares to be issued will be quantified upon
completion of the performance period at the determination date. At December 31,
2003, the maximum number of nonvested restricted ordinary shares that could be
issued at the determination date was 829,065.

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,
2003, 777,930 ordinary shares were available for issuance pursuant to the Stock
Purchase Plan.

NOTE 17-RETIREMENT PLANS, OTHER POSTEMPLOYMENT BENEFITS AND OTHER BENEFIT PLANS

Defined Benefit Pension Plans-The Company maintains 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, the Company acquired two funded and one unfunded defined benefit pension
plans (the "Frozen Plans") that were frozen prior to the merger for which
benefits no longer accrue, but the pension obligations have not been fully paid
out. The Company refers to the Retirement Plan, the Supplemental Benefit Plan
and the Frozen Plans collectively as the U.S. Plans.

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

In addition, the Company provides several defined benefit plans, primarily
group pension schemes with life insurance companies covering our Norway
operations and two unfunded plans covering certain of the Company's employees
and former employees (the "Norway Plans"). Certain of the Norway plans are
funded in part by employee contributions. Company 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. The Company also has an unfunded defined
benefit plan (the "Nigeria Plan") that provides retirement and severance
benefits for certain Nigerian employees. The defined benefit pension benefits
provided by the Company are comprised of the U.S. Plans, the Norway Plans and
the Nigeria Plan (collectively the "Transocean Plans"). The Company uses a
January 1 measurement date for all of its plans.

The change in projected benefit obligation, change in plan assets and
funded status is shown in the table below (in millions):

DECEMBER 31,
-----------------
2003 2002
------- --------

CHANGE IN PROJECTED BENEFIT OBLIGATION
Projected benefit obligation at beginning of year. . . . . . . . . $295.6 $ 242.7
Service cost . . . . . . . . . . . . . . . . . . . . . . . . . . . 16.6 16.8
Interest cost. . . . . . . . . . . . . . . . . . . . . . . . . . . 18.2 19.0
Actuarial losses (gains) . . . . . . . . . . . . . . . . . . . . . (7.6) 27.0
Settlements / curtailments . . . . . . . . . . . . . . . . . . . . (7.5) -
Special termination benefits . . . . . . . . . . . . . . . . . . . - 1.1
Plan amendments. . . . . . . . . . . . . . . . . . . . . . . . . . (6.4) 3.1
Benefits paid. . . . . . . . . . . . . . . . . . . . . . . . . . . (13.4) (14.1)
------- --------
Projected benefit obligation at end of year. . . . . . . . . . . 295.5 295.6
======= ========

CHANGE IN PLAN ASSETS
Fair value of plan assets at beginning of year . . . . . . . . . . 188.5 210.4
Actual return on plan assets . . . . . . . . . . . . . . . . . . . 33.8 (14.4)
Employer contributions . . . . . . . . . . . . . . . . . . . . . . 23.3 6.6
Settlements / curtailments . . . . . . . . . . . . . . . . . . . . (17.8) -
Benefits paid. . . . . . . . . . . . . . . . . . . . . . . . . . . (13.4) (14.1)
------- --------
Fair value of plan assets at end of year . . . . . . . . . . . . 214.4 188.5
======= ========

FUNDED STATUS. . . . . . . . . . . . . . . . . . . . . . . . . . . (81.1) (107.1)
Unrecognized transition obligation . . . . . . . . . . . . . . . . 2.0 2.9
Unrecognized net actuarial loss. . . . . . . . . . . . . . . . . . 71.7 86.4
Unrecognized prior service cost. . . . . . . . . . . . . . . . . . 2.3 11.3
------- --------
Accrued pension liability. . . . . . . . . . . . . . . . . . . . $ (5.1) $ (6.5)
======= ========

AMOUNTS RECOGNIZED IN THE CONSOLIDATED BALANCE SHEETS CONSIST OF:
Prepaid benefit cost . . . . . . . . . . . . . . . . . . . . . . . $ 3.4 $ 1.6
Accrued benefit liability. . . . . . . . . . . . . . . . . . . . . (44.3) (54.5)
Intangible asset . . . . . . . . . . . . . . . . . . . . . . . . . 0.1 0.7
Accumulated other comprehensive income . . . . . . . . . . . . . . 35.7 45.7
------- --------
Net amount recognized. . . . . . . . . . . . . . . . . . . . . . $ (5.1) $ (6.5)
======= ========

The accumulated benefit obligation for all defined benefit pension plans
was $241.5 million and $227.7 million at December 31, 2003 and 2002,
respectively.

- 84 -

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

The aggregate projected benefit obligation and fair value of plan assets
for plans with a projected benefit obligation in excess of plan assets are as
follows (in millions):

DECEMBER 31,
--------------
2003 2002
------ ------

Projected benefit obligation $286.1 $291.3
Fair value of plan assets. . 204.7 182.9

The aggregate accumulated benefit obligation and fair value of plan assets
for plans with an accumulated benefit obligation in excess of plan assets are as
follows (in millions):

DECEMBER 31,
--------------
2003 2002
------ ------

Accumulated benefit obligation $228.5 $216.0
Fair value of plan assets. . . 195.2 174.3

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

YEARS ENDED DECEMBER 31,
-------------------------
2003 2002 2001
------- ------- -------

COMPONENTS OF NET PERIODIC BENEFIT COST (a)
Service cost. . . . . . . . . . . . . . . . . . . . . . . . . $ 16.6 $ 16.8 $ 12.0
Interest cost . . . . . . . . . . . . . . . . . . . . . . . . 18.2 19.0 15.9
Expected return on plan assets. . . . . . . . . . . . . . . . (19.7) (20.7) (7.5)
Amortization of transition obligation . . . . . . . . . . . . 0.3 0.3 0.3
Amortization of prior service cost. . . . . . . . . . . . . . 1.3 1.4 0.4
Recognized net actuarial (gains) losses . . . . . . . . . . . 0.4 (0.5) (11.3)
Special termination benefits (b). . . . . . . . . . . . . . . - 1.1 -
SFAS 88 settlements/curtailments. . . . . . . . . . . . . . . 4.7 (0.3) -
------- ------- -------
Benefit cost. . . . . . . . . . . . . . . . . . . . . . . . $ 21.8 $ 17.1 $ 9.8
======= ======= =======

Increase (decrease) in minimum pension liability included in
other comprehensive income (in millions). . . . . . . . . . $(10.0) $ 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.

Weighted-average assumptions used to determine benefit obligations:

DECEMBER 31,
------------
2003 2002
----- -----

Discount rate . . . . . . . . 6.25% 6.90%
Rate of compensation increase 5.24% 5.53%

Weighted-average assumptions used to determine net periodic benefit cost:

DECEMBER 31,
-------------------
2003 2002 2001
----- ----- -----

Discount rate. . . . . . . . . . . . . . . . . . 6.65% 7.31% 7.75%
Expected long-term rate of return in plan assets 8.73% 8.73% 9.24%
Rate of compensation increase. . . . . . . . . . 5.24% 5.53% 5.71%

- 85 -

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

The defined benefit pension obligations and the related benefit costs are
accounted for in accordance with SFAS 87, Employers' Accounting for Pensions.
Pension obligations are actuarially determined and are affected by assumptions
including expected return on plan assets, discount rates, compensation
increases, and employee turnover rates. The Company evaluates its assumptions
periodically and makes 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. The Company evaluates
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 a third party investment advisor utilizing the asset
allocation classes held by the plan's portfolios. The Company utilizes the
Moody's Aa long-term corporate bond yield as a basis for determining the
discount rate for a majority of its plans. Changes in these and other
assumptions used in the actuarial computations could impact the plans projected
benefit obligations, pension liabilities, pension expense and other
comprehensive income. The determination of pension expense is based 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.

The Company's pension plan weighted-average asset allocations for funded
Transocean Plans by asset category are as follows:

DECEMBER 31,
--------------
2003 2002
------ ------

Equity securities 59.7% 53.0%
Debt securities . 30.1% 36.2%
Other . . . . . . 10.2% 10.8%
------ ------
Total . . . . . 100.0% 100.0%
====== ======

The Company has determined the asset allocation of the plans that it
believes is best able to produce maximum long-term gains without taking on undue
risk. After modeling many different asset allocation scenarios, the Company has
determined that an asset allocation mix of approximately 60 percent equity
securities, 30 percent debt securities, and 10 percent other investments is most
appropriate. Other investments are generally a diversified mix of funds that
specialize in various equity and debt strategies that are expected to provide
positive returns each year relative to U.S. Treasury Bills. These strategies may
include, among others, arbitrage, short-selling, and merger and acquisition
investment opportunities. The Company reviews asset allocations and results
quarterly to ensure that managers are meeting specified objectives and policies
as written and agreed to by each manager and the Company. These objectives and
policies are reviewed each year.

The plan's investment managers have discretion in the securities in which
they may invest within their asset category. Given this discretion, the managers
may, from time-to-time, invest in the Company's stock or debt. This could
include taking either long or short positions in such securities. As these
managers are required to maintain well diversified portfolios, the actual
investment in the Company's common stock would be immaterial relative to asset
categories and the overall plan.

The Company expects to contribute $10.0 million to the Transocean Plans in
2004, comprised of $5.4 million to the funded U.S. Plans, an estimated $2.0
million to fund expected benefit payments for the unfunded U.S. Plans and
Nigeria Plan, and an estimated $2.6 million for the Norway Plans to fund
expected benefit payments.

Nigeria Plan-During 2003, the Company terminated all Nigerian employees,
which resulted in the payment of all accrued benefits under the Nigeria Plan.
Approximately 80 of these employees were made redundant during 2003, while the
remaining employees not considered redundant were rehired under a new plan. In
accordance with the provisions of SFAS 88, Employers' Accounting for Settlements
and Curtailments of Defined Benefit Pension Plans and Termination Benefits, this
resulted in a partial plan curtailment and a plan settlement. The Company paid
approximately $17.0 million in severance benefits under the Nigeria Plan during
2003 as a result of these events. In accordance with SFAS 88, the Company has
accounted for these events as a plan restructuring and recorded a net settlement
expense of $10.4 million, as well as a $4.6 million liability. This liability
will reduce future pension expense related to the Nigeria Plan as it will be
recognized over the expected service term of the related employees. Pension
expense for the Nigeria Plan is estimated to be $0.1 million in 2004 and
represents a 94.6% decrease as compared to the 2003 plan expenses (excluding the
settlement related expenses discussed above).

- 86 -

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

Postretirement Benefits Other Than Pensions-The Company has several
unfunded contributory and noncontributory postretirement benefit plans covering
substantially all of its Transocean Drilling segment U.S. employees. The
postretirement health care plans include a limit on the Company's share of costs
for recent and future retirees. The Company uses a January 1 measurement date
for all of its plans.

The change in benefit obligation, change in plan assets and funded status
are shown in the table below (in millions):

DECEMBER 31,
----------------
2003 2002
------- -------

CHANGE IN BENEFIT OBLIGATION
Benefit obligation at beginning of year. . . . $ 41.2 $ 29.2
Service cost . . . . . . . . . . . . . . . . . 1.9 1.0
Interest cost. . . . . . . . . . . . . . . . . 3.4 2.5
Actuarial losses . . . . . . . . . . . . . . . 20.1 6.7
Participants' contributions. . . . . . . . . . 0.3 0.2
Plan amendments. . . . . . . . . . . . . . . . - 3.5
Settlements / curtailments . . . . . . . . . . (2.9) -
Benefits paid. . . . . . . . . . . . . . . . . (2.0) (1.9)
------- -------
Benefit obligation at end of year. . . . . . 62.0 41.2
------- -------

CHANGE IN PLAN ASSETS
Fair value of plan assets at beginning of year 0.2 0.5
Actual return on plan assets . . . . . . . . . (0.2) (0.3)
Company contributions. . . . . . . . . . . . . 1.7 1.7
Participants' contributions. . . . . . . . . . 0.3 0.2
Benefits paid. . . . . . . . . . . . . . . . . (2.0) (1.9)
------- -------
Fair value of plan assets at end of year . . - 0.2
------- -------

FUNDED STATUS. . . . . . . . . . . . . . . . . (62.0) (41.0)
Unrecognized net actuarial gain. . . . . . . . 26.0 7.6
Unrecognized prior service cost. . . . . . . . 1.2 3.3
------- -------
Postretirement benefit liability . . . . . . $(34.8) $(30.1)
======= =======

Amounts recognized in the consolidated balance sheets for the years ended
December 31, 2003 and 2002 consisted of accrued benefit costs totaling $34.8
million and $30.1 million, respectively. There were no prepaid benefit costs
recognized for the years ended December 31, 2003 and 2002.

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

YEARS ENDED DECEMBER 31,
-----------------------
2003 2002 2001
------ ----- ------

COMPONENTS OF NET PERIODIC BENEFIT COST
Service cost . . . . . . . . . . . . . . $ 2.0 $ 1.0 $ 0.4
Interest cost. . . . . . . . . . . . . . 3.4 2.5 1.9
Amortization of prior service cost . . . 0.3 0.5 -
Settlements/curtailments . . . . . . . . (0.6) - -
Recognized net actuarial loss (gain) . . 1.3 0.3 (0.1)
------ ----- ------
Benefit Cost . . . . . . . . . . . . . $ 6.4 $ 4.3 $ 2.2
====== ===== ======

One of the Company's postretirement benefit plans is a retiree life
insurance plan. Effective January 1, 2003, the plan was amended such that
participants who retire after December 31, 2002 no longer receive postretirement
benefits provided under this plan. As such, the Company recorded a curtailment
gain of $0.6 million related to this amendment.

Weighted-average discount rates used to determine benefit obligations were
6.00% and 6.50% for the years ended December 31, 2003 and 2002, respectively.

- 87 -

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

Weighted-average assumptions used to determine net periodic benefit cost
were as follows:

DECEMBER 31,
-------------------
2003 2002 2001
----- ----- -----

Discount rate. . . . . . . . . . . . . . . . . . 6.50% 6.50% 7.00%
Expected long-term rate of return in plan assets - - 7.00%
Rate of compensation increase. . . . . . . . . . 5.50% 5.50% 5.50%

Assumed health care cost trend rates were as follows:

DECEMBER 31,
------------
2003 2002
----- -----

Health care cost trend rate assumed for next year. . . . 11% 12%
Rate to which the cost trend rate is assumed to decline
(the ultimate trend rate). . . . . . . . . . . . . . . 5% 5%
Year that the rate reaches the ultimate trend rate . . . 2009 2009

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 2003 . . . . $ 0.8 $ (0.6)
Effect on postretirement benefit obligations as of December 31, 2003 $ 7.3 $ (5.8)

The Company's other postretirement benefit (retiree life insurance and
medical benefits) obligations and the related benefit costs are accounted for in
accordance with SFAS 106, Employers' Accounting for Postretirement Benefits
Other than Pensions. Postretirement costs and obligations are actuarially
determined and are affected by assumptions including expected discount rates,
compensation increases, employee turnover rates and health care cost trend
rates. The Company evaluates its assumptions periodically and makes adjustments
to these assumptions and the recorded liabilities as necessary.

Two of the most critical assumptions for postretirement benefit plans are
the assumed discount rate and the expected health care cost trend rates. The
Company utilizes the Moody's Aa long-term corporate bond yield as a basis for
determining the discount rate. The accumulated postretirement benefit obligation
and service cost were developed using a health care trend rate of 11.0 percent
for 2003 reducing 1.0 percent per year to an ultimate trend rate of 5.0 percent
per year for 2009 and later. The initial trend rate was selected with reference
to recent Transocean experience and broader national statistics. The ultimate
trend rate is a long term assumption and was selected to reflect the
anticipation that the portion of gross domestic product devoted to health care
becomes constant. Changes in these and other assumptions used in the actuarial
computations could impact the Company's projected benefit obligations, pension
liabilities and pension expense.

The Company expects to contribute $1.8 million to its other postretirement
benefit plans in 2004 to fund expected benefit payments.

On December 8, 2003, the Medicare Prescription Drug, Improvement and
Modernization Act of 2003 (the "Act") was signed into law. The Act introduced a
prescription drug benefit under Medicare as well as a federal subsidy to
sponsors of retiree health care benefit plans that currently provide a
prescription drug benefit that is equivalent to the expanded Medicare benefit.
Employers have the option to either receive the subsidy or to supplement the
Medicare paid prescription drug benefit on a secondary payor basis. In
accordance with SFAS 106, employers are required to consider presently enacted
changes in relevant laws in current period measurements of postretirement
benefit costs and the accumulated postretirement benefit obligation. As a
result, the accumulated postretirement benefit obligation and net periodic
postretirement benefit costs for future periods should reflect the effects of
the Act.

- 88 -

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

In January 2004, the FASB staff issued FASB Staff Position ("FSP") 106-1,
Accounting and Disclosure Requirements Related to the Medicare Prescription
Drug, Improvement and Modernization Act of 2003. FSP 106-1 permits a sponsor of
a postretirement health care plan that provides a prescription drug benefit to
make a one-time election to defer accounting for the effects of the Act. The
deferral will continue to apply until authoritative guidance on the accounting
for the federal subsidy is issued or a significant event occurs that would
ordinarily call for remeasurement of a plan's assets and obligations. The
Company elected to defer accounting for the Act and will continue to assess the
effects the Act will have on its postretirement benefit plan costs. As a result
of the deferral election, the disclosures above relating to the net periodic
postretirement benefit costs do not reflect the effects of the Act on the
Company's postretirement benefit plans. The finalization of pending
authoritative guidance could require restatement of previously reported
information.

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 that
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 $21.8 million, $21.3 million and $21.6
million of expense related to its defined contribution plans for the years ended
December 31, 2003, 2002 and 2001, 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, 2003, 2002 or 2001.

NOTE 18-INVESTMENTS IN AND ADVANCES TO JOINT VENTURES

The Company had 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 approximately $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 and was dissolved in 2003.

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 20.

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 of $3.2
million was finalized in January 2003.

As a result of the R&B Falcon merger, the Company had ownership interests
in two unconsolidated joint ventures, 50 percent in DD LLC and 60 percent in
DDII LLC. Subsidiaries of ConocoPhillips owned the remaining interests in these
joint ventures. The Company purchased ConocoPhillips' interests in DDII LLC and
DD LLC in late May 2003 and late December 2003, respectively, at which time both
DDII LLC and DD LLC became wholly owned subsidiaries. See Note 5.

As a result of the R&B Falcon merger, TODCO has a 25 percent ownership
interest in Delta Towing. See Note 20. As result of the Company's adoption of
FIN 46 effective December 31, 2003, Delta Towing was consolidated at December
31, 2003. See Note 2.

- 89 -

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

NOTE 19-SEGMENTS, GEOGRAPHICAL ANALYSIS AND MAJOR CUSTOMERS

The Company's operations are aggregated into two reportable segments: (i)
Transocean Drilling and (ii) TODCO. The Transocean Drilling segment consists of
floaters, jackups and other rigs used in support of offshore drilling activities
and offshore support services. The TODCO segment consists of our interest in
TODCO, which conducts jackups, barge drilling rigs, land rigs, submersibles and
other rig operations located in the U.S. Gulf of Mexico and inland waters,
Mexico, Trinidad and 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.

Operating revenues and income (loss) before income taxes, minority interest
and cumulative effect of changes in accounting principles by segment were as
follows (in millions):

YEARS ENDED DECEMBER 31,
---------------------------------
2003 2002 2001
---------- ---------- ---------

Operating Revenues
Transocean Drilling . . . . . . . . . . . . . . . . . . . . . . $ 2,206.7 $ 2,486.1 $2,385.2
TODCO . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 227.6 187.8 441.1
Elimination of intersegment revenues. . . . . . . . . . . . . . - - (6.2)
---------- ---------- ---------
Total Operating Revenues. . . . . . . . . . . . . . . . . . . $ 2,434.3 $ 2,673.9 $2,820.1
========== ========== =========

Operating Income (Loss) Before General and Administrative Expense
Transocean Drilling . . . . . . . . . . . . . . . . . . . . . . $ 422.5 $(1,739.0) $ 582.1
TODCO . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (117.5) (505.3) 25.8
---------- ---------- ---------
305.0 (2,244.3) 607.9
Unallocated general and administrative expense. . . . . . . . . (65.3) (65.6) (57.9)
Unallocated other expense, net. . . . . . . . . . . . . . . . . (218.1) (178.9) (218.3)
---------- ---------- ---------
Income (Loss) Before Income Taxes, Minority Interest and
Cumulative Effect of Changes in Accounting Principles . . . . $ 21.6 $(2,488.8) $ 331.7
========== ========== =========

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

YEARS ENDED DECEMBER 31,
---------------------------------
2003 2002 2001
---------- ---------- ---------

Transocean Drilling . . . . . . . . . . . . . . . . . . . . . . $ 416.0 $ 408.4 $ 373.5
TODCO . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 92.2 91.9 96.6
---------- ---------- ---------
Total Depreciation Expense. . . . . . . . . . . . . . . . . . $ 508.2 $ 500.3 $ 470.1
========== ========== =========

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

DECEMBER 31,
---------------------
2003 2002
---------- ---------

Transocean Drilling . . . . . . . . . . . . . . . . . . . . . . $ 10,874.0 $11,804.1
TODCO . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 788.6 861.0
---------- ---------
Total Assets. . . . . . . . . . . . . . . . . . . . . . . . . $ 11,662.6 $12,665.1
========== =========

- 90 -

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

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

YEARS ENDED DECEMBER 31,
----------------------------
2003 2002 2001
-------- -------- --------

OPERATING REVENUES
United States. . . . . . . $ 752.8 $ 752.5 $ 979.5
Brazil . . . . . . . . . . 316.7 283.0 355.8
United Kingdom . . . . . . 211.6 345.7 354.6
Rest of the World (a). . . 1,153.2 1,292.7 1,130.2
-------- -------- --------
Total Operating Revenues $2,434.3 $2,673.9 $2,820.1
======== ======== ========

AS OF DECEMBER 31,
--------------------
2003 2002
--------- ---------

LONG-LIVED ASSETS
United States. . . . . . . $ 3,319.7 $ 3,905.0
Goodwill (b) . . . . . . . 2,230.8 2,218.2
Brazil . . . . . . . . . . 1,282.9 1,239.5
Rest of the World (a). . . 3,650.3 3,390.7
--------- ---------
Total Long-Lived Assets $10,483.7 $10,753.4
========= =========

__________________
(a) Rest of the World represents countries in which the Company operates that
individually had operating revenues or long-lived assets representing less
than 10 percent of total operating revenues earned or total long-lived
assets.
(b) 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, 2003, Petrobras, BP and Shell accounted for
approximately 11.8 percent, 11.1 percent and 10.7 percent, respectively, of the
Company's operating revenues, of which the majority was reported in the
Transocean Drilling segment. 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
Transocean Drilling 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 Transocean Drilling segment. The loss of these or other
significant customers could have a material adverse effect on the Company's
results of operations.

NOTE 20-RELATED PARTY TRANSACTIONS

DD LLC and DDII LLC-Prior to the Company's purchase of ConocoPhillips'
interest in DD LLC and DDII LLC (see Note 5), the Company was party to drilling
services agreements with DD LLC and DDII LLC for the operations of the Deepwater
Pathfinder and Deepwater Frontier, respectively. For the year ended December 31,
2003, the Company earned $1.6 million and $1.3 million for such services to DD
LLC and DDII LLC, 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 were 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 were included in accounts receivable - other.

From time to time, the Company contracted the Deepwater Frontier from DDII
LLC. During that time, DDII LLC billed the Company for the full operating
dayrate and issued a non-cash credit for downtime hours in excess of 24 hours in
any calendar month. The Company recorded a dayrate rebate receivable for all
such non-cash credits and was responsible for payment of 100 percent of all
drilling contract invoices received. At December 31, 2002, the cumulative
dayrate rebate receivable from DDII LLC totaled $15.1 million and was recorded
as investment in and advances to joint ventures in the

- 91 -

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

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 was included in operating and maintenance expense in the Company's
consolidated statement of operations. The Company incurred no expense for the
years ended December 31, 2003 or 2002 due to the expiration of its lease late in
2001. At December 31, 2002, the Company had amounts payable to DDII LLC of $0.3
million, which was included in accounts payable in the consolidated balance
sheet.

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 in exchange for a 25 percent equity interest, 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 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 December 31, 2002, $78.9 million was outstanding
under the Company's Tier 1 Note. For the years ended December 31, 2003, 2002 and
2001, the Company earned interest income on the outstanding balance at each
period of $3.1 million, $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 accrued interest at
eight percent per annum, with interest payable quarterly. For each of the years
ended December 31, 2003 and 2002, TODCO recognized $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, 2002, the Company
had interest receivable from Delta Towing of $1.7 million.

Delta Towing defaulted on the notes in January 2003 by failing to make its
scheduled quarterly interest payment and remains in default as a result of its
continued failure to make its quarterly interest payments. As a result of
TODCO's continued evaluation of the collectibility of the notes, TODCO recorded
a $21.3 million impairment of the notes in June 2003 based on Delta Towing's
discounted cash flows over the terms of the notes, which deteriorated in the
second quarter of 2003 as a result of the continued decline in Delta Towing's
business outlook. As permitted in the notes in the event of default, TODCO began
offsetting a portion of the amount owed to Delta Towing against the interest due
under the notes. Additionally, in 2003, TODCO established a reserve of $1.6
million for interest income earned during the year ended December 31, 2003 on
the notes receivable.

As a result of the adoption of FIN 46 and a determination that TODCO was
the primary beneficiary for accounting purposes of Delta Towing, TODCO
consolidated Delta Towing effective December 31, 2003 and intercompany
transactions and accounts have been eliminated. Consolidation of Delta Towing
resulted in an increase in net assets and a corresponding gain as a cumulative
effect of a change in accounting principle of approximately $0.8 million. See
Note 2.

As part of the formation of the joint venture on January 31, 2001, TODCO
entered into an agreement with Delta Towing under which TODCO 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, 2003, TODCO incurred
charges of $11.7 million, which was reflected in operating and maintenance
expense. During the year ended December 31, 2002, TODCO incurred charges
totaling $10.7 million from Delta Towing for services rendered, of which $1.6
million was rebilled to

- 92 -

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

TODCO's customers and $9.1 million was reflected in operating and maintenance
expense. During the year ended December 31, 2001, TODCO incurred charges
totaling $15.6 million from Delta Towing for services rendered, of which $6.5
million was rebilled to TODCO'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 for the each of the
years ended December 31, 2003, 2002 and 2001. Such amounts are included in
operating revenues in the Company's consolidated statements of operations. At
December 31, 2003 and 2002, the Company had receivables from ODL of $3.1 million
and $1.2 million, respectively, which were recorded as accounts receivable -
other in the consolidated balance sheets.

NOTE 21-RESTRUCTURING CHARGES

In September 2002, the Company committed to restructuring plans in France,
Norway and in its TODCO segment. The Company established a liability of
approximately $5.2 million for the estimated severance-related costs associated
with the involuntary termination of 81 employees pursuant to these plans. The
charge was reported as operating and maintenance expense in the Company's
consolidated statements of operations of which approximately $4.0 million and
$1.2 million related to the Transocean Drilling segment and TODCO segment,
respectively. Through December 31, 2003, approximately $4.6 million had been
paid to 74 employees representing full or partial payments. In June 2003, the
Company released the expected surplus liability of $0.3 million to operating and
maintenance expense in the Transocean Drilling segment. Substantially all of the
remaining liability is expected to be paid by the end of the first quarter in
2005.

- 93 -

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

NOTE 22-EARNINGS PER SHARE

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

YEARS ENDED DECEMBER 31,
--------------------------
2003 2002 2001
------ ---------- ------

NUMERATOR FOR BASIC AND DILUTED EARNINGS (LOSS) PER SHARE
Income (Loss) Before Cumulative Effect of Changes in Accounting
Principles. . . . . . . . . . . . . . . . . . . . . . . . . . . $ 18.4 $(2,368.2) $252.6
Cumulative Effect of Changes in Accounting Principles . . . . . . 0.8 (1,363.7) -
------ ---------- ------
Net Income (Loss) . . . . . . . . . . . . . . . . . . . . . . . . $ 19.2 $(3,731.9) $252.6
====== ========== ======
DENOMINATOR FOR DILUTED EARNINGS (LOSS) PER SHARE
Weighted-average shares outstanding for basic earnings per share. 319.8 319.1 309.2
Effect of dilutive securities:
Employee stock options and unvested stock grants. . . . . . . . 1.1 - 3.4
Warrants to purchase ordinary shares. . . . . . . . . . . . . . 0.5 - 2.2
------ ---------- ------
Adjusted weighted-average shares and assumed
conversions for diluted earnings (loss) per share . . . . . . . 321.4 319.1 314.8
====== ========== ======

BASIC EARNINGS (LOSS) PER SHARE
Income (Loss) Before Cumulative Effect of Changes in Accounting
Principles. . . . . . . . . . . . . . . . . . . . . . . . . . . $ 0.06 $ (7.42) $ 0.82
Cumulative Effect of Changes in Accounting Principles. . . . . . - (4.27) -
------ ---------- ------
Net Income (Loss). . . . . . . . . . . . . . . . . . . . . . . . $ 0.06 $ (11.69) $ 0.82
====== ========== ======

DILUTED EARNINGS (LOSS) PER SHARE
Income (Loss) Before Cumulative Effect of Changes in Accounting
Principles. . . . . . . . . . . . . . . . . . . . . . . . . . . $ 0.06 $ (7.42) $ 0.80
Cumulative Effect of Changes in Accounting Principles. . . . . . - (4.27) -
------ ---------- ------
Net Income (Loss). . . . . . . . . . . . . . . . . . . . . . . . $ 0.06 $ (11.69) $ 0.80
====== ========== ======

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 23-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 of the Company 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, 2003 there were 261,000 warrants outstanding to
purchase 4,567,500 ordinary shares.

- 94 -

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

NOTE 24-QUARTERLY RESULTS (UNAUDITED)

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

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

2003
Operating Revenues. . . . . . . . . . . . . . . . . $ 616.0 $ 603.9 $622.9 $ 591.5
Operating Income (a) . . . . . . . . . . . . . . . 101.6 19.8 72.8 45.5
Income (Loss) Before Cumulative Effect of a Change
in Accounting Principle. . . . . . . . . . . . . . 47.2 (44.5) 11.0 4.7
Net Income (Loss) (b) . . . . . . . . . . . . . . . $ 47.2 $ (44.5) $ 11.0 $ 5.5
Basic Earnings (Loss) Per Share
Income (Loss) Before Cumulative Effect of a
Change in Accounting Principle. . . . . . . . . $ 0.15 $ (0.14) $ 0.03 $ 0.02
Diluted Earnings (Loss) Per Share
Income (Loss) Before Cumulative Effect of a
Change in Accounting Principle. . . . . . . . . $ 0.15 $ (0.14) $ 0.03 $ 0.02
Weighted Average Shares Outstanding
Shares for basic earnings per share . . . . . . . 319.7 319.8 319.9 319.9
Shares for diluted earnings per share . . . . . . 321.6 319.8 321.1 321.3

2002
Operating Revenues. . . . . . . . . . . . . . . . . $ 667.9 $ 646.2 $695.2 $ 664.6
Operating Income (Loss) (c) . . . . . . . . . . . . 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) (d) . . . . . . . . . . . . . . . $(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

___________________________
(a) Second quarter 2003 included loss on impairments of $15.8 million (see Note 7). Third Quarter
2003 included costs related to the TODCO IPO of $8.0 million (see Note 1). Fourth quarter 2003
included costs to restructure the Nigeria defined benefit plans of $16.9 million (see Note 17).
(b) Second quarter 2003 included loss on retirement of debt of $13.8 million (see Note 8),
impairment loss on note receivable from related party of $13.8 million (see Note 2) and a
favorable resolution of a non-U.S. income tax liability of $14.6 million (see Note 14).
(c) 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.
(d) 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 14).

- 95 -

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

NOTE 25-SUBSEQUENT EVENTS (UNAUDITED)

IPO-In February 2004, the Company completed the IPO of TODCO, in which the
Company sold 13.8 million shares of TODCO's class A common stock, representing
approximately 23 percent of TODCO's total outstanding shares, at $12.00 per
share. The Company received net proceeds of $155.7 million from the IPO and
expects to recognize a gain of approximately $43 million in the first quarter of
2004, which represents the excess of net proceeds received over the net book
value of the shares of TODCO sold in the IPO. The Company holds an approximate
77 percent interest in TODCO, represented by 46.2 million shares of class B
common stock, and consolidates TODCO in its financial statements as a business
segment.

The Company and TODCO entered into various agreements to set forth their
respective rights and obligations relating to their businesses and effect the
separation of the two companies. These agreements included a master separation
agreement, tax sharing agreement, employee matters agreement, transition
services agreement and registration rights agreement.

As a result of the deconsolidation of TODCO from the Company's other U.S.
subsidiaries for U.S. federal income tax purposes in conjunction with the IPO,
the Company expects to establish a valuation allowance against the deferred tax
assets of TODCO in excess of its deferred tax liabilities. The amount of such
valuation allowance will depend upon many factors, including the ultimate
allocation of tax benefits between TODCO and other subsidiaries of the Company
under applicable law and taxable income for calendar year 2004. The amount of
the valuation allowance could be as much as or more than the gain on the sale of
the TODCO shares in the IPO discussed above.

In conjunction with the closing of the TODCO IPO, TODCO granted nonvested
restricted stock and stock options to certain of its employees under its
long-term incentive plan and certain of these awards vested at the time of
grant. In accordance with the provisions of SFAS 123, TODCO expects to recognize
as compensation expense approximately $17.0 million over the vesting periods of
the awards. The Company expects TODCO will recognize approximately $6.0 million
in the first quarter of 2004 as a result of the immediate vesting of certain
awards. The Company also expects TODCO will amortize the remaining amount of
approximately $11.0 million to compensation expense over the next three years
with approximately $5.0 million over the remainder of 2004 and approximately
$5.0 million and $1.0 million in 2005 and 2006, respectively. In addition,
certain of TODCO's employees held options to acquire the Company's ordinary
shares that were granted prior to the IPO. In accordance with the employee
matters agreement, these options were modified, which resulted in the
accelerated vesting of the options and the extension of the term of the options
through the original contractual life. In connection with the modification of
these options, TODCO will recognize approximately $1.5 million additional
compensation in the first quarter of 2004.

9.5% Senior Note Redemption-In February 2004, the Company announced the
redemption of the 9.5% Senior Notes due December 2008 at the make-whole premium
price provided in the indenture. The redemption is expected to be completed by
March 30, 2004. The face value of the bonds to be redeemed is $289.8 million.
Based on interest rates at March 1, 2004, the cost to redeem these bonds is
expected to be approximately $366.3 million, and the Company expects to
recognize a loss on retirement of debt of approximately $24.1 million, which
reflects adjustments for fair value of the debt at the R&B Falcon merger and the
premium on the termination of the related interest rate swap. These amounts
could vary depending upon actual interest rates. The Company expects to utilize
existing cash balances, which includes proceeds from the TODCO IPO, to fund this
redemption. The redemption does not affect the 9.5% Senior Notes due December
2008 of TODCO.

- 96 -

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.

ITEM 9A. CONTROLS AND PROCEDURES

In accordance with Exchange Act Rules 13a-15 and 15d-15, we carried out an
evaluation, under the supervision and with the participation of management,
including our Chief Executive Officer and Chief Financial Officer, of the
effectiveness of our disclosure controls and procedures as of the end of the
period covered by this report. Based on that evaluation, our Chief Executive
Officer and Chief Financial Officer concluded that our disclosure controls and
procedures were effective as of December 31, 2003 to provide reasonable
assurance that information required to be disclosed in our reports filed or
submitted under the Exchange Act is recorded, processed, summarized and reported
within the time periods specified in the Securities and Exchange Commission's
rules and forms.

There has been no change in our internal controls over financial reporting
that occurred during the three months ended December 31, 2003 that has
materially affected, or is reasonably likely to materially affect, our internal
controls over financial reporting.

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

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

The information required by Items 10, 11, 12, 13 and 14 is incorporated
herein by reference to the Company's definitive proxy statement for its 2004
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, 2003. 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."

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 . . . . . . . . . . . . . . . . . 53
Consolidated Statements of Operations. . . . . . . . . . . . . . 54
Consolidated Statements of Comprehensive Income (Loss) . . . . . 55
Consolidated Balance Sheets. . . . . . . . . . . . . . . . . . . 56
Consolidated Statements of Equity. . . . . . . . . . . . . . . . 57
Consolidated Statements of Cash Flows. . . . . . . . . . . . . . 58
Notes to Consolidated Financial Statements . . . . . . . . . . . 60

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

(2) Financial Statement Schedules

- 97 -

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, 2001
Reserves and allowances deducted from asset
accounts:
Allowance for doubtful accounts
receivable. . . . . . . . . . . . . . . . $ 24.3 $ 12.0 $ 14.9(c) $ 27.0 (a) (e) $ 24.2

Allowance for obsolete materials and
supplies. . . . . . . . . . . . . . . . . 23.3 - 9.2(d) 8.4 (b) (f) 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(g) 6.5 (b) (h) (i) 18.6

Year Ended December 31, 2003
Reserves and allowances deducted from asset
accounts:
Allowance for doubtful accounts
receivable. . . . . . . . . . . . . . . . 20.8 24.4 - 16.1 (a) 29.1

Allowance for obsolete materials and
supplies. . . . . . . . . . . . . . . . . $ 18.6 $ 0.9 $ 0.2(l) $2.2 (b) (j) (k) $ 17.5

_____________________________
(a) Uncollectible accounts receivable written off, net of recoveries.
(b) Obsolete materials and supplies written off, net of scrap.
(c) Amount includes $15.0 relating to the allowance for doubtful accounts receivable assumed in the R&B
Falcon merger.
(d) Amount includes $8.7 relating to the obsolete materials and supplies inventory assumed in the R&B
Falcon merger.
(e) Amount includes $4.9 related to adjustments to the provision.
(f) Amount includes $2.7 related to sale of rigs.
(g) Amount includes $0.4 related to adjustments to the provision.
(h) Amount includes $0.8 related to sale of rigs/inventory.
(i) Amount includes $3.7 related to adjustments to the provision.
(j) Amount includes $0.8 related to sale of rigs/inventory.
(k) Amount includes $0.9 related to adjustments to the provision.
(l) Amount includes $0.2 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.

- 98 -

(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 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)

4.2 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)

4.3 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))

4.4 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)

- 99 -

4.5 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)

4.6 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)

4.7 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)

4.8 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)

4.9 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)

4.10 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)

4.11 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)

4.12 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)

4.13 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)

4.14 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)

4.15 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)

4.16 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)

4.17 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)

4.18 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)

4.19 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)

- 100 -

4.20 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)

4.21 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)

4.22 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)

4.23 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)

4.24 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)

+ 4.25 Revolving Credit Agreement dated December 16, 2003 among Transocean
Inc., the lenders party thereto, Suntrust Bank, as administrative
agent, Citibank, N.A. and Bank of America, N.A., as co-syndication
agents, The Royal Bank of Scotland plc and Bank One, NA, as
co-documentation agents, Wells Fargo Bank, N.A. and UBS Loan Finance
LLC, as managing agents, The Bank of New York, Den Norske Bank ASA and
HSBC Bank USA, as co-agents, and Citigroup Global Markets Inc. and
Suntrust Capital Markets, Inc., as co-lead arrangers

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)

*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 Amended and Restated Long-Term Incentive Plan of Transocean Inc.
(incorporated by reference to Exhibit 10.1 to the Company's Form 10-Q
for the quarter ended June 30,2003)

- 101 -

*10.7 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)

*10.8 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)

*10.9 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)

*10.10 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)

*10.11 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)

*10.12 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)

*10.13 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)

*10.14 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)

*10.15 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)

*10.16 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)

*10.17 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)

*10.18 Amendment No. 1 dated December 12, 2003 to the Employment Agreement
dated July 15, 2002 by and among Jan Rask, R&B Falcon Management
Services, Inc. and R&B Falcon Corporation (incorporated by reference
to Exhibit 10.8 to TODCO's Registration Statement No. 333-101921 on
Form S-1 dated February 3, 2004)

*10.19 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)

*10.20 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)

*10.21 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)

*10.22 1992 Long-Term Incentive Plan of Reading & Bates Corporation
(incorporated by reference to Exhibit B to Reading & Bates' Proxy
Statement dated April 27, 1992)

*10.23 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)

*10.24 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)

- 102 -

*10.25 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)

*10.26 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)

*10.27 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)

*10.28 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)

*10.29 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)

10.30 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)

10.31 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)

10.32 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)

10.33 Master Separation Agreement dated February 4, 2004 by and among
Transocean Inc., Transocean Holdings Inc. and TODCO (incorporated by
reference to Exhibit 99.2 to the Company's Current Report on Form 8-K
dated March 2, 2004)

10.34 Tax Sharing Agreement dated February 4, 2004 between Transocean
Holdings Inc. and TODCO (incorporated by reference to Exhibit 99.3 to
the Company's Current Report on Form 8-K dated March 2, 2004)

10.35 Transition Services Agreement dated February 4, 2004 between
Transocean Holdings Inc. and TODCO (incorporated by reference to
Exhibit 99.4 to the Company's Current Report on Form 8-K dated March
2, 2004)

10.36 Employee Matters Agreement dated February 4, 2004 by and among
Transocean Inc., Transocean Holdings Inc. and TODCO (incorporated by
reference to Exhibit 99.5 to the Company's Current Report on Form 8-K
dated March 2, 2004)

10.37 Registration Rights Agreement dated February 4, 2004 between
Transocean Inc. and TODCO (incorporated by reference to Exhibit 99.6
to the Company's Current Report on Form 8-K dated March 2, 2004)

+ 21 Subsidiaries of the Company

+ 23.1 Consent of Ernst & Young LLP

+ 24 Powers of Attorney

31.1 CEO Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of
2002

31.2 CFO Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of
2002

32.1 CEO Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of
2002

32.2 CFO Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of
2002

- 103 -

------------------------------
*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 28, 2003
(information furnished not filed) announcing the third quarter 2003 financial
results.

- 104 -

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 15, 2004.

TRANSOCEAN INC.
By: /s/ Gregory L. Cauthen
-----------------------------------
GREGORY L. CAUTHEN
SENIOR VICE PRESIDENT AND CHIEF FINANCIAL OFFICER

PURSUANT TO THE REQUIREMENTS OF THE SECURITIES EXCHANGE ACT OF 1934, THIS
REPORT HAS BEEN SIGNED BELOW BY THE FOLLOWING PERSONS ON BEHALF OF THE
REGISTRANT IN THE CAPACITIES INDICATED ON MARCH 15, 2004

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 and Chief Financial
---------------------------------- Officer (Principal Financial and
GREGORY L. CAUTHEN Accounting Officer)

* Director
----------------------------------
VICTOR E. GRIJALVA

* Director
----------------------------------
ARTHUR LINDENAUER

* Director
----------------------------------
PAUL B. LOYD, JR.

* Director
----------------------------------
MARTIN B. MCNAMARA

* Director
----------------------------------
ROBERTO MONTI

- 105 -

SIGNATURE TITLE
--------- -----

* Director
----------------------------------
RICHARD A. PATTAROZZI

* Director
----------------------------------
KRISTIAN SIEM

* Director
----------------------------------
IAN C. STRACHAN

By /s/ William E. Turcotte
--------------------------------
WILLIAM E. TURCOTTE
(ATTORNEY-IN-FACT)

- 106 -