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


                                      - 3 -

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


                                      - 4 -

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.


                                      - 5 -

HIGH-SPECIFICATION  FLOATERS  (32)

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



                                                 YEAR        WATER    DRILLING
                                                ENTERED      DEPTH      DEPTH
                                               SERVICE/    CAPACITY   CAPACITY                                       ESTIMATED
NAME                                   TYPE   UPGRADED(a)  (IN FEET)  (IN FEET)      LOCATION        CUSTOMER     EXPIRATION (b)
-------------------------------------  -----  -----------  ---------  ---------  ----------------  -------------  ---------------
                                                                                             
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


                                      - 6 -

                                                 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:



                                YEAR        WATER    DRILLING
                               ENTERED      DEPTH      DEPTH
                              SERVICE/    CAPACITY   CAPACITY                                        ESTIMATED
NAME                   TYPE  UPGRADED(a)  (IN FEET)  (IN FEET)      LOCATION         CUSTOMER     EXPIRATION (b)
---------------------  ----  -----------  ---------  ---------  -----------------  -------------  ---------------
                                                                             
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


                                      - 7 -

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.

(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.


     JACKUP  RIGS  (26)

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



                                     WATER    DRILLING
                    YEAR ENTERED     DEPTH      DEPTH
                      SERVICE/     CAPACITY   CAPACITY                                           ESTIMATED
NAME                 UPGRADED(a)   (IN FEET)  (IN FEET)        LOCATION          CUSTOMER     EXPIRATION (b)
------------------  -------------  ---------  ---------  --------------------  -------------  ---------------
                                                                            
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.

     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.

     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.

     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.

     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

(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.


     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.

     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,
                                                                    ----------------------------
                                                                        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.

     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.

     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  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 ($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


                                     - 38 -

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,


                                     - 39 -

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.


                                     - 40 -

     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").


                                     - 41 -



                                                                                                                   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


                                     - 43 -

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


                                     - 44 -

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


                                     - 45 -

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.


                                     - 60 -

                        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


                                     - 61 -

                        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.


                                     - 67 -

                        TRANSOCEAN INC. AND SUBSIDIARIES
             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,


                                     - 68 -

                        TRANSOCEAN INC. AND SUBSIDIARIES
             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


                                     - 69 -

                        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.


                                     - 70 -

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

NOTE  8-DEBT

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



                                                                                  DECEMBER 31,
                                                                                ------------------
                                                                                  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
                                    =============


                                     - 71 -

                        TRANSOCEAN INC. AND SUBSIDIARIES
             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


                                     - 72 -

                        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.


                                     - 73 -

                        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.


                                     - 75 -

                        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.


                                     - 76 -

                        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
                                                                        =======  ========  =======




                                     - 77 -

                        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.

     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, its underwriters and insurance
broker  in  the  16th Judicial District Court of St. Mary Parish, Louisiana. The
plaintiffs  alleged  damages amounting to in excess of $50 million in connection
with  the drilling of a turnkey well in 1995 and 1996. The case was tried before
a  jury  in  January  and  February  2000,  and  the  jury returned a verdict of
approximately  $30  million  in  favor  of  the  plaintiffs  for excess drilling


                                     - 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:



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

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.


                                     - 83 -

                        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 -