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

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

                                    FORM 10-Q
(Mark  One)
[X]     QUARTERLY  REPORT  PURSUANT  TO  SECTION  13  OR 15(D) OF THE SECURITIES
        EXCHANGE  ACT  OF  1934

                FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 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
                    HOUSTON, TEXAS                       77046
      (Address of principal executive offices)         (Zip Code)

       Registrant's telephone number, including area code: (713) 232-7500
                             ______________________

     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 whether the registrant is an accelerated filer (as
defined  in  Rule  12b-2  of  the  Exchange  Act).  Yes   X   No
                                                        -----     -----

     As  of  October  31, 2003, 319,890,650 ordinary shares, par value $0.01 per
share,  were  outstanding.
================================================================================


<PAGE>
                                 TRANSOCEAN INC.

                               INDEX TO FORM 10-Q

                        QUARTER ENDED SEPTEMBER 30, 2003

                                                                            Page
                                                                            ----

PART  I  -  FINANCIAL  INFORMATION
----------------------------------

     ITEM  1.  Financial  Statements  (Unaudited)

          Condensed  Consolidated  Statements  of  Operations
             Three  and  Nine  Months  Ended  September 30, 2003 and 2002      2

          Condensed Consolidated Statements of Comprehensive Income (Loss)
             Three  and  Nine  Months  Ended  September 30, 2003 and 2002      3

          Condensed  Consolidated  Balance  Sheets
             September  30,  2003  and  December  31,  2002                    4

          Condensed  Consolidated  Statements  of  Cash  Flows
            Three  and  Nine  Months  Ended  September  30, 2003 and 2002      5

          Notes  to  Condensed  Consolidated  Financial  Statements            6

     ITEM  2.  Management's  Discussion  and  Analysis  of  Financial
          Condition  and  Results  of  Operations                             22

     ITEM  3.  Quantitative and Qualitative Disclosures about Market Risk     47

     ITEM  4.  Controls  and  Procedures                                      48

PART  II  -  OTHER  INFORMATION
-------------------------------

     ITEM  1.  Legal  Proceedings                                             49

     ITEM  6.  Exhibits  and  Reports  on  Form  8-K                          50


<PAGE>
                         PART I - FINANCIAL INFORMATION

ITEM  1.  FINANCIAL  STATEMENTS

     The  condensed consolidated financial statements of Transocean Inc. and its
consolidated  subsidiaries  (the  "Company") included herein have been prepared,
without  audit,  pursuant  to  the  rules  and regulations of the Securities and
Exchange  Commission.  Certain  information  and  notes  normally  included  in
financial statements prepared in accordance with accounting principles generally
accepted  in  the  United States have been condensed or omitted pursuant to such
rules  and regulations. These financial statements should be read in conjunction
with  the  audited  consolidated  financial  statements  and  the  notes thereto
included in the Company's Annual Report on Form 10-K for the year ended December
31,  2002.


                                        1
<PAGE>
<TABLE>
<CAPTION>
                        TRANSOCEAN INC. AND SUBSIDIARIES
                 CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
                      (In millions, except per share data)
                                   (Unaudited)

                                                               Three Months Ended     Nine Months Ended
                                                                 September 30,          September 30,
                                                               -------------------  --------------------
                                                                2003       2002       2003       2002
                                                               -------  ----------  ---------  ---------
<S>                                                            <C>      <C>         <C>        <C>
Operating Revenues
  Contract drilling revenues                                   $598.5   $   695.2   $1,764.7   $2,009.3
  Client reimbursable revenues                                   24.4           -       78.1          -
--------------------------------------------------------------------------------------------------------
                                                                622.9       695.2    1,842.8    2,009.3
--------------------------------------------------------------------------------------------------------
Costs and Expenses
  Operating and maintenance                                     403.0       381.1    1,203.6    1,127.7
  Depreciation                                                  126.8       124.2      381.1      374.1
  General and administrative                                     21.2        15.8       50.0       51.6
  Impairment loss on long-lived assets                              -        40.9       16.8       42.0
  Gain from sale of assets, net                                  (0.9)       (2.9)      (2.9)      (3.5)
--------------------------------------------------------------------------------------------------------
                                                                550.1       559.1    1,648.6    1,591.9
--------------------------------------------------------------------------------------------------------

Operating Income                                                 72.8       136.1      194.2      417.4

Other Income (Expense), net
  Equity in earnings of joint ventures                            1.9         0.4        7.3        4.8
  Interest income                                                 3.0         6.1       15.7       16.0
  Interest expense                                              (49.0)      (52.3)    (154.4)    (160.7)
  Loss on retirement of debt                                        -           -      (15.7)         -
  Impairment loss on note receivable from related party             -           -      (21.3)         -
  Other, net                                                     (0.2)        1.3       (3.5)       0.2
--------------------------------------------------------------------------------------------------------
                                                                (44.3)      (44.5)    (171.9)    (139.7)
--------------------------------------------------------------------------------------------------------
Income Before Income Taxes, Minority Interest and
  Cumulative Effect of a Change in Accounting Principle          28.5        91.6       22.3      277.7
Income Tax Expense (Benefit)                                     17.3      (164.8)       8.3     (137.1)
Minority Interest                                                 0.2         1.2        0.3        2.3
--------------------------------------------------------------------------------------------------------

Net Income Before Cumulative Effect of a Change in
   Accounting Principle                                          11.0       255.2       13.7      412.5
Cumulative Effect of a Change in Accounting Principle               -           -          -   (1,363.7)
--------------------------------------------------------------------------------------------------------

Net Income (Loss)                                              $ 11.0   $   255.2   $   13.7   $ (951.2)
========================================================================================================

Basic Earnings (Loss) Per Share
  Income Before Cumulative Effect of a Change in
    Accounting Principle                                       $ 0.03   $    0.80   $   0.04   $   1.29
  Loss on Cumulative Effect of a Change in Accounting
    Principle                                                       -           -          -      (4.27)
--------------------------------------------------------------------------------------------------------

  Net Income (Loss)                                            $ 0.03   $    0.80   $   0.04   $  (2.98)
========================================================================================================

Diluted Earnings (Loss) Per Share
  Income Before Cumulative Effect of a Change in Accounting
    Principle                                                  $ 0.03   $    0.79   $   0.04   $   1.28
  Loss on Cumulative Effect of a Change in Accounting
    Principle                                                       -           -          -      (4.22)
--------------------------------------------------------------------------------------------------------

  Net Income (Loss)                                            $ 0.03   $    0.79   $   0.04   $  (2.94)
========================================================================================================

Weighted Average Shares Outstanding
   Basic                                                        319.9       319.2      319.8      319.1
   Diluted                                                      321.1       328.8      321.4      323.0

Dividends Paid per Share                                       $    -   $       -   $      -   $   0.06
--------------------------------------------------------------------------------------------------------
</TABLE>

                             See accompanying notes.


                                        2
<PAGE>
<TABLE>
<CAPTION>
                        TRANSOCEAN INC. AND SUBSIDIARIES
        CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
                                  (In millions)
                                   (Unaudited)

                                                                  Three Months Ended  Nine Months Ended
                                                                    September  30,      September 30,
                                                                  ------------------  -----------------
                                                                    2003      2002     2003      2002
                                                                  --------  --------  -------  --------
<S>                                                               <C>       <C>       <C>      <C>
Net Income (Loss)                                                 $  11.0   $ 255.2   $ 13.7   $(951.2)
-------------------------------------------------------------------------------------------------------
Other comprehensive income (loss), net of tax
  Amortization of gain on terminated interest rate swaps             (0.1)     (0.1)    (0.2)     (0.2)
  Change in unrealized loss on securities available for sale         (0.1)     (0.2)     0.1      (0.1)
  Change in share of unrealized loss in unconsolidated
    joint venture's interest rate swaps (net of tax of $0.4
    and $1.0 for the three and nine months ended
    September 30, 2003, respectively)                                 0.7      (0.2)     1.8       1.9
  Minimum pension liability adjustments (net of tax of
    $0.4 for the nine months ended September 30, 2003)                  -         -      0.8         -
-------------------------------------------------------------------------------------------------------
Other comprehensive income (loss)                                     0.5      (0.5)     2.5       1.6
-------------------------------------------------------------------------------------------------------
Total Comprehensive Income (Loss)                                 $  11.5   $ 254.7   $ 16.2   $(949.6)
=======================================================================================================
</TABLE>
                             See accompanying notes.


                                        3
<PAGE>
<TABLE>
<CAPTION>
                        TRANSOCEAN INC. AND SUBSIDIARIES
                      CONDENSED CONSOLIDATED BALANCE SHEETS
                        (In millions, except share data)
                                   (Unaudited)




                                                                        September 30,    December 31,
                                                                            2003             2002
                                                                        --------------  --------------
                                                                         (Unaudited)

                                 ASSETS
<S>                                                                    <C>              <C>
Cash and Cash Equivalents                                              $        806.3   $     1,214.2
Accounts Receivable, net of allowance for doubtful accounts of $25.9
  and $20.8 at September 30, 2003 and December 31, 2002, respectively           486.6           499.3
Materials and Supplies, net of allowance for obsolescence of $18.6
  at September 30, 2003 and December 31, 2002                                   156.4           155.8
Deferred Income Taxes                                                            14.1            21.9
Other Current Assets                                                             79.1            20.5
------------------------------------------------------------------------------------------------------
  Total Current Assets                                                        1,542.5         1,911.7
------------------------------------------------------------------------------------------------------

Property and Equipment                                                       10,214.9        10,198.0
Less Accumulated Depreciation                                                 2,535.4         2,168.2
------------------------------------------------------------------------------------------------------
  Property and Equipment, net                                                 7,679.5         8,029.8
------------------------------------------------------------------------------------------------------

Goodwill                                                                      2,223.4         2,218.2
Investments in and Advances to Joint Ventures                                    70.0           108.5
Deferred Income Taxes                                                            26.2            26.2
Other Assets                                                                    176.1           370.7
------------------------------------------------------------------------------------------------------
    Total Assets                                                       $     11,717.7   $    12,665.1
======================================================================================================

                   LIABILITIES AND SHAREHOLDERS' EQUITY

Accounts Payable                                                       $        147.2   $       134.1
Accrued Income Taxes                                                             62.0            59.5
Debt Due Within One Year                                                        282.1         1,048.1
Other Current Liabilities                                                       293.7           262.2
------------------------------------------------------------------------------------------------------
  Total Current Liabilities                                                     785.0         1,503.9
------------------------------------------------------------------------------------------------------

Long-Term Debt                                                                3,419.3         3,629.9
Deferred Income Taxes                                                            55.4           107.2
Other Long-Term Liabilities                                                     283.1           282.7
------------------------------------------------------------------------------------------------------
  Total Long-Term Liabilities                                                 3,757.8         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,
  319,890,650 and 319,219,072 shares issued and outstanding at
  September 30, 2003 and December 31, 2002, respectively                          3.2             3.2
Additional Paid-in Capital                                                   10,640.4        10,623.1
Accumulated Other Comprehensive Loss                                            (29.0)          (31.5)
Retained Deficit                                                             (3,439.7)       (3,453.4)
------------------------------------------------------------------------------------------------------
  Total Shareholders' Equity                                                  7,174.9         7,141.4
------------------------------------------------------------------------------------------------------
  Total Liabilities and Shareholders' Equity                           $     11,717.7   $    12,665.1
======================================================================================================
</TABLE>


                             See accompanying notes.

                                        4
<PAGE>
<TABLE>
<CAPTION>
                                 TRANSOCEAN INC. AND SUBSIDIARIES
                         CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
                                           (In millions)
                                           (Unaudited)

                                                               Three Months Ended    Nine Months Ended
                                                                 September 30,         September 30,
                                                              --------------------  --------------------
                                                                 2003       2002       2003       2002
                                                              ---------  ---------  ---------  ---------
<S>                                                           <C>        <C>        <C>        <C>
CASH FLOWS FROM OPERATING ACTIVITIES
  Net Income (Loss)                                           $   11.0   $  255.2   $   13.7   $ (951.2)
  Adjustments to reconcile net income (loss) to
    net cash provided by operating activities
      Depreciation                                               126.8      124.2      381.1      374.1
      Impairment loss on goodwill                                    -          -          -    1,363.7
      Stock-based compensation expense                             1.4        0.2        4.3        0.6
      Deferred income taxes                                       19.1     (151.5)     (40.4)    (189.8)
      Equity in earnings of joint ventures                        (1.9)      (0.4)      (7.3)      (4.8)
      Net (gain) loss from disposal of assets                      4.4       (1.1)      12.2        1.2
      Loss on retirement of debt                                     -          -       15.7          -
      Impairment loss on long-lived assets                           -       40.9       16.8       42.0
      Impairment loss on note receivable from related party          -          -       21.3          -
      Amortization of debt-related discounts/premiums, fair
        value adjustments and issue costs, net                    (8.2)       1.7      (16.1)       4.6
      Deferred income, net                                        (5.3)      (3.3)      (6.9)      (9.3)
      Deferred expenses, net                                      (5.1)     (14.7)      (2.4)      (7.7)
      Other long-term liabilities                                  0.2        2.7       13.7       10.3
      Other, net                                                  12.1       (0.7)      12.1        1.0
      Changes in operating assets and liabilities
        Accounts receivable                                      (44.0)      47.9        7.6      132.0
        Accounts payable and other current liabilities            42.6       42.8       46.6      (41.9)
        Income taxes receivable/payable, net                      (8.0)     (38.2)       1.6      (15.9)
        Other current assets                                      14.3       14.0       (9.0)      (8.7)
--------------------------------------------------------------------------------------------------------
Net Cash Provided by Operating Activities                        159.4      319.7      464.6      700.2
--------------------------------------------------------------------------------------------------------

CASH FLOWS FROM INVESTING ACTIVITIES
  Capital expenditures                                           (23.4)     (33.4)     (73.6)    (114.6)
  Note issued to related party, net of repayments                  1.1          -      (44.2)         -
  Proceeds from disposal of assets, net                            0.9        8.6        4.1       73.6
  Acquisition of 40 percent interest in Deepwater Drilling II
    L.L.C., net of cash acquired                                     -          -       18.1          -
  Joint ventures and other investments, net                        0.6        4.6        2.8        4.6
--------------------------------------------------------------------------------------------------------
Net Cash Used in Investing Activities                            (20.8)     (20.2)     (92.8)     (36.4)
--------------------------------------------------------------------------------------------------------

CASH FLOWS FROM FINANCING ACTIVITIES
  Borrowings under capital lease obligations                       1.0          -        1.0           -
  Repayments under commercial paper program                          -          -          -     (326.4)
  Repayments on other debt instruments                           (48.0)     (34.7)    (967.2)    (154.3)
  Cash from termination of interest rate swaps                       -          -      173.5          -
  Decrease in cash dedicated to debt service                         -          -        1.2          -
  Net proceeds from issuance of ordinary shares under
    stock-based compensation plans                                 0.6       (0.1)      12.3       10.2
  Dividends paid                                                     -          -          -      (19.1)
  Financing costs                                                  0.1          -          -       (8.1)
  Other, net                                                         -        1.2       (0.5)       2.3
--------------------------------------------------------------------------------------------------------
Net Cash Used in Financing Activities                            (46.3)     (33.6)    (779.7)    (495.4)
--------------------------------------------------------------------------------------------------------

Net Increase (Decrease) in Cash and Cash Equivalents              92.3      265.9     (407.9)     168.4
--------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at Beginning of Period                 714.0      755.9    1,214.2      853.4
--------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at End of Period                    $  806.3   $1,021.8   $  806.3   $1,021.8
========================================================================================================
</TABLE>

                             See accompanying notes.

                                        5
<PAGE>
                        TRANSOCEAN INC. AND SUBSIDIARIES
              NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
                                   (Unaudited)


NOTE  1  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  and inland marine contract drilling services for oil and
gas  wells.  As  of September 30, 2003, the Company owned, had partial ownership
interests in or operated more than 160 mobile offshore and barge drilling units.
The  Company  contracts  its  drilling  rigs,  related  equipment and work crews
primarily  on  a  dayrate  basis  to  drill  oil  and  gas  wells.

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

NOTE  2  GENERAL

     BASIS  OF CONSOLIDATION - The accompanying condensed consolidated financial
statements  of  the  Company have been prepared without audit in accordance with
accounting  principles  generally  accepted  in  the  United States ("U.S.") for
interim financial information and with the instructions to Form 10-Q and Article
10  of  Regulation  S-X  of the Securities and Exchange Commission. Accordingly,
pursuant  to  such  rules  and  regulations,  these  financial statements do not
include  all disclosures required by accounting principles generally accepted in
the  U.S. for complete financial statements. Operating results for the three and
nine  months  ended  September  30,  2003  are not necessarily indicative of the
results  that  may  be expected for the year ending December 31, 2003 or for any
future  period. The accompanying condensed consolidated financial statements and
notes  thereto  should  be  read  in  conjunction  with the audited consolidated
financial  statements  and notes thereto included in the Company's Annual Report
on  Form  10-K  for  the  year  ended  December  31,  2002.

     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  post-retirement  and  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.

     SUPPLEMENTARY CASH FLOW INFORMATION - Cash payments for interest and income
taxes,  net,  were  $108.5 million and $56.5 million, respectively, for the nine
months  ended  September  30,  2003  and  $116.3  million  and  $74.0  million,
respectively,  for  the  nine  months  ended  September  30,  2002.

     GOODWILL  -  In  accordance with the Financial Accounting Standards Board's
("FASB")  Statement of Financial Accounting Standards ("SFAS") 142, Goodwill and
Other Intangible Assets, goodwill is 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  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 merger transaction with Sedco Forex Holdings Limited
was  allocated  100  percent  to  the  Company's  International and U.S. Floater
Contract  Drilling  Services  segment.  Goodwill  resulting  from  the  merger
transaction (the "R&B Falcon merger") with R&B Falcon Corporation ("R&B Falcon",
now  known  as  "TODCO")  was  allocated  to  the Company's two reporting units,


                                        6
<PAGE>
                        TRANSOCEAN INC. AND SUBSIDIARIES
        NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
                                   (Unaudited)


International  and  U.S.  Floater  Contract Drilling Services and Gulf of Mexico
Shallow and Inland Water, at a ratio of 68 percent and 32 percent, respectively.
The  allocation  was determined based on the percentage of each reporting unit's
assets  at  fair  value  to  the  total fair value of assets acquired in the R&B
Falcon  merger.  The  fair  value  was  determined from a third party valuation.

     During  the  first  quarter  of  2002, the Company implemented SFAS 142 and
performed the initial test of impairment of goodwill on its two reporting units.
The  test  was applied utilizing the estimated fair value of the reporting units
as of January 1, 2002 determined based on a combination of each reporting unit's
discounted  cash  flows  and  publicly  traded company multiples and acquisition
multiples  of  comparable  businesses.  There was no goodwill impairment for the
International  and  U.S.  Floater  Contract  Drilling  Services  reporting unit.
However, because of deterioration in market conditions that affected the Gulf of
Mexico Shallow and Inland Water business segment since the completion of the R&B
Falcon  merger, a $1,363.7 million ($4.22 per diluted share) non-cash impairment
of  goodwill  was  recognized  as  a cumulative effect of a change in accounting
principle  in  the  first  quarter  of  2002.

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

     The  Company's  goodwill balance was $2.2 billion as of September 30, 2003.
The  changes in the carrying amount of goodwill as of September 30, 2003 were as
follows  (in  millions):

<TABLE>
<CAPTION>
                                                           Balance at                 Balance at
                                                           January 1,               September 30,
                                                              2003      Other (a)        2003
                                                           -----------  ----------  --------------
<S>                                                        <C>          <C>         <C>
International and U.S. Floater Contract Drilling Services  $   2,218.2  $      5.2  $      2,223.4
<FN>
_________________
(a)     Primarily  represents  net unfavorable adjustments during 2003 of income
tax-related  pre-acquisition  contingencies  related  to  the R&B Falcon merger.
</TABLE>

     IMPAIRMENT  OF  OTHER  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  8.

     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 we operate 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.  These factors combined with lower expected
financial  results  for  the year are expected to lead to a higher effective tax
rate  than  in  2002  (see  Note  4).


                                        7
<PAGE>
                        TRANSOCEAN INC. AND SUBSIDIARIES
        NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
                                   (Unaudited)

     COMPREHENSIVE  INCOME - The  components  of accumulated other comprehensive
income (loss), net of tax, as of September 30, 2003 and December 31, 2002 are as
follows  (in  millions):

<TABLE>
<CAPTION>
                                                   Unrealized         Other
                                     Gain on        Loss on       Comprehensive                   Accumulated
                                   Terminated      Available-    Loss Related to     Minimum         Other
                                  Interest Rate     for-Sale     Unconsolidated      Pension     Comprehensive
                                      Swap         Securities     Joint Venture     Liability    Income (Loss)
                                 ---------------  ------------  -----------------  -----------  ---------------
<S>                              <C>              <C>           <C>                <C>          <C>
Balance at December 31, 2002     $          3.6   $      (0.6)  $           (2.0)  $    (32.5)  $        (31.5)
  Change in other comprehensive
      (income) loss, net of tax            (0.2)          0.1                1.8          0.8              2.5
                                 ---------------  ------------  -----------------  -----------  ---------------
Balance at September 30, 2003    $          3.4   $      (0.5)  $           (0.2)  $    (31.7)  $        (29.0)
                                 ===============  ============  =================  ===========  ===============
</TABLE>

     SEGMENTS - The  Company's  operations  are aggregated  into  two reportable
segments: (i) International and U.S. Floater Contract Drilling Services and (ii)
Gulf  of  Mexico  Shallow  and  Inland Water. The Company provides services with
different  types  of  drilling  equipment  in  several  geographic  regions. The
location  of  the  Company's operating assets and the allocation of resources to
build  or  upgrade  drilling  units is determined by the activities and needs of
customers.  See  Note  7.

     INTERIM  FINANCIAL  INFORMATION - The  condensed  consolidated  financial
statements  reflect  all  adjustments,  which are, in the opinion of management,
necessary for a fair statement of results of operations for the interim periods.
Such  adjustments  are  considered  to  be  of  a normal recurring nature unless
otherwise  identified.

     STOCK-BASED COMPENSATION - Through December 31, 2002 and 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. Effective January 1,
2003,  the  Company  adopted the fair value method of accounting for stock-based
compensation  using  the  prospective  method  of  transition  under  SFAS  123.


                                        8
<PAGE>
                        TRANSOCEAN INC. AND SUBSIDIARIES
        NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
                                   (Unaudited)

     If  compensation  expense  for  grants  to  employees  under  the Company's
long-term  incentive  plan  and employee stock purchase plan prior to January 1,
2003  was  recognized  using  the fair value method of accounting under SFAS 123
rather  than  the  intrinsic  value  method  under APB 25, net income (loss) and
earnings  (loss)  per  share  would  have  been reduced to the pro forma amounts
indicated  below  (in  millions,  except  per  share  data):

<TABLE>
<CAPTION>
                                                            Three Months Ended  Nine Months Ended
                                                              September 30,      September 30,
                                                            ------------------  -----------------

                                                              2003      2002     2003      2002
                                                            --------  --------  -------  --------
<S>                                                         <C>       <C>       <C>      <C>
Net Income (Loss) as Reported                               $  11.0   $ 255.2   $ 13.7   $(951.2)
                                                            --------  --------  -------  --------
  Add back: Stock-based compensation expense included in
    reported net income (loss), net of related tax effects      0.1       2.3      2.6       2.7

  Deduct: Total stock-based compensation expense
    determined under the fair value method for all awards,
    net of related tax effects
        Long-Term Incentive Plan                               (4.2)     (7.5)   (12.5)    (17.6)
        Employee Stock Purchase Plan                            0.4      (0.5)    (1.7)     (1.7)

  Pro Forma Net Income (Loss)                               $   7.3   $ 249.5   $  2.1   $(967.8)
                                                            ========  ========  =======  ========

Basic Earnings (Loss) Per Share
  As Reported                                               $  0.03   $  0.80   $ 0.04   $ (2.98)
  Pro Forma                                                    0.02      0.78     0.01     (3.03)

Diluted Earnings (Loss) Per Share
  As Reported                                               $  0.03   $  0.79   $ 0.04   $ (2.94)
  Pro Forma                                                    0.02      0.76     0.01     (3.00)
</TABLE>


     NEW  ACCOUNTING  PRONOUNCEMENTS - In  January  2003,  the  FASB  issued
Interpretation  No.  46,  Consolidation  of  Variable  Interest  Entities,  an
Interpretation  of  Accounting  Research Bulletin No. 51 (the "Interpretation").
The  Interpretation  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  the  Interpretation are effective immediately for those variable
interest  entities  created  after January 31, 2003. The provisions, as amended,
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. The
Company  will  adopt  the  Interpretation  and consolidate its variable interest
entities  as  required  on  December  31, 2003. Currently, the Company generally
consolidates an entity when it has a controlling interest through ownership of a
majority  voting  interest  in  the  entity.

     The  Company  has a 25 percent ownership interest in Delta Towing Holdings,
LLC  ("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  assets  serve as collateral for the Company's notes receivable.
The  carrying  value  of  the  notes  receivable  included in investments in and
advances  to  joint  ventures  in  the  Company's condensed consolidated balance
sheets,  net  of  allowance  for  credit  losses  and equity losses in the joint
venture,  was  $53.6  million  at September 30, 2003. Delta Towing also issued a
$3.0  million  note  to  the  75  percent  joint  venture partner. Because Delta
Towing's  equity is not sufficient to absorb its expected losses and the Company
has  the  largest percentage of investment at risk through the notes receivable,
the  Company  would  absorb the majority of the joint venture's expected losses;
therefore,  the  Company is deemed to be the primary beneficiary of Delta Towing
for  accounting  purposes.  As  such,  the  Company


                                        9
<PAGE>
                        TRANSOCEAN INC. AND SUBSIDIARIES
        NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
                                   (Unaudited)

will  consolidate  Delta  Towing  effective December 31, 2003. While the Company
expects the consolidation of Delta Towing to result in an increase in net assets
of  approximately  $1.0  million,  based  on balances at September 30, 2003, the
expected  amounts  may  be adjusted upon consolidation at December 31, 2003 with
application  of  the  provisions  of  the  Interpretation.

     The  Company  has  a  50  percent  ownership interest in Deepwater Drilling
L.L.C.  ("DD  LLC").  DD LLC was established for the purpose of constructing and
contracting  the drillship Deepwater Pathfinder.  The drillship was purchased by
a  trust  that  was  established to finance the purchase through debt and equity
financing  and  to  lease the drillship back to DD LLC through a synthetic lease
financing  arrangement  with the drillship serving as collateral. The balance of
the  trust's  debt  and  equity  financing  was  approximately $189.7 million at
September  30,  2003.  The scheduled expiration of the lease is January 2004, at
which  time  DD  LLC may purchase the drillship from the trust for approximately
$185  million.  While  the  operations  of  DD LLC are funded by cash flows from
operating  activities,  the Company guarantees, under certain circumstances, the
debt and equity financing on the leased drillship equally with its joint venture
partner. The Company has determined through its application of the provisions of
the Interpretation for determining an entity's primary beneficiary that it is DD
LLC's  primary  beneficiary  for  accounting  purposes  and will consolidate the
entity effective December 31, 2003.  While the Company expects the consolidation
of  DD LLC to result in an increase in net assets of approximately $116 million,
based  on  balances  at September 30, 2003, the expected amounts may be adjusted
upon  consolidation  at  December 31, 2003 with application of the provisions of
the  Interpretation.

     The  Company  has  investments  in  and  advances  to four additional joint
ventures. These remaining four joint ventures were primarily established for the
purpose  of owning and operating certain drilling units and are funded primarily
by  cash  flows  from  operating  activities.  Based  on  the  Company's initial
assessment,  these entities would not be deemed variable interest entities under
the  Interpretation.  The  Company  expects  to  complete  the analysis of these
entities  during  the fourth quarter of 2003. The Company currently accounts for
its  investments  in  joint  ventures  using  the  equity  method of accounting,
recording  its share of the net income or loss based upon the terms of the joint
venture  agreements.  Because  the  Company  has  a 50 percent or less ownership
interest in these joint ventures, it does not have a controlling interest in the
joint  ventures  nor  does it have the ability to exercise significant influence
over  operating  and  financial  policies.

     The  Company's wholly owned subsidiary, Deepwater Drilling II L.L.C. ("DDII
LLC")  was  originally  established  as  a  joint  venture  with a subsidiary of
ConocoPhillips  for  the  purpose  of constructing and contracting the drillship
Deepwater  Frontier. The drillship was purchased by a trust that was established
to  finance  the  purchase  through  debt  and equity financing and to lease the
drillship  back to DDII LLC through a synthetic lease financing arrangement with
the  drillship serving as collateral. The balance of the trust's debt and equity
financing  at September 30, 2003 was approximately $158.0 million, net of a note
receivable - related party (see Note 11). On May 29, 2003, the Company purchased
ConocoPhillips' 40 percent interest in DDII LLC.  The Company currently accounts
for  DDII LLC's lease of the drillship as an operating lease. As a result of the
Company's  purchase  of  ConocoPhillips'  40  percent  interest in DDII LLC, the
Company,  under  certain  circumstances,  fully  guarantees  the debt and equity
financing.  Because  the  Company is at risk for the full amount of the debt and
equity  financing,  the  Company  is deemed to be the primary beneficiary of the
trust  for  accounting  purposes  and expects to consolidate the trust effective
December  31, 2003.  While the Company expects the consolidation of the trust to
result  in  an  increase  in  net  assets of approximately $27 million, based on
balances  at  September  30,  2003,  the  expected  amounts may be adjusted upon
consolidation  at  December  31,  2003 with application of the provisions of the
Interpretation.  See  Note  11.

     In addition to the joint ventures and DDII LLC discussed above, the Company
is  party  to  a sale/leaseback transaction for the semisubmersible drilling rig
M.G.  Hulme,  Jr.  with  an  unrelated  third  party.  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.
The  Company is currently evaluating whether the unrelated third party lessor is
a  variable  interest entity and, if so, which company would be deemed to be the
primary  beneficiary.  The  Company  currently  accounts  for  the lease of this
semisubmersible  drilling  rig  as  an  operating  lease.


                                       10
<PAGE>
                        TRANSOCEAN INC. AND SUBSIDIARIES
        NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
                                   (Unaudited)

     The Company is currently evaluating the cumulative effect of the accounting
change  on its results of operations that will result from the implementation of
the  Interpretation.

     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,  the  amounts billed to the
Company's  customers  associated  with  these  reimbursable  costs  are  being
recognized  as  client  reimbursable  revenue.  Management  expects  client
reimbursable  revenues  and  operating and maintenance expense to be between $90
million  and  $110  million  in  2003  as a result of the implementation of EITF
99-19.  The  change in accounting principle will have no effect on the Company's
results of operations or consolidated financial position. Prior periods have not
been  reclassified,  as  these  amounts  were  not  material.

     In  May  2003,  the  FASB issued SFAS 150, Accounting for Certain Financial
Instruments  with  Characteristics of both Liabilities and Equity. The statement
clarifies  the accounting for certain financial instruments that, under previous
guidance, issuers could account for as equity. This statement requires an issuer
to measure and classify as liabilities, or assets in some circumstances, certain
classes  of  freestanding  financial instruments that embody obligations for the
issuer.  In  addition to this requirement for the classification and measurement
of  financial instruments in its scope, SFAS 150 also requires disclosures about
alternative ways of settling the instruments and the identity of the entity that
controls  the settlement alternatives. This statement is effective for financial
instruments  entered  into  or  modified  after  May  31, 2003, and otherwise is
effective  at the beginning of the first interim period beginning after June 15,
2003. The Company adopted this statement effective July 1, 2003. The adoption of
this  statement  did  not  have  a material effect on the Company's consolidated
financial  position  or  results  of  operations.

     RECLASSIFICATIONS  -  Certain  reclassifications  have  been  made to prior
period amounts to conform with the current period's presentation.


                                       11
<PAGE>
                        TRANSOCEAN INC. AND SUBSIDIARIES
        NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
                                   (Unaudited)

NOTE  3  -  DEBT

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

<TABLE>
<CAPTION>
                                                                                September 30,   December 31,
                                                                                    2003           2002
                                                                               --------------  -------------
<S>                                                                            <C>             <C>
6.5% Senior Notes, due April 2003                                              $            -  $       239.7
9.125% Senior Notes, due December 2003                                                   87.6           89.5
Amortizing Term Loan Agreement - Final Maturity December 2004                           187.5          300.0
6.75% Senior Notes, due April 2005 (a)                                                  363.4          371.8
7.31% Nautilus Class A1 Amortizing Notes - Final Maturity May 2005                       74.2          104.7
9.41% Nautilus Class A2 Notes, due May 2005                                                 -           51.7
6.95% Senior Notes, due April 2008 (a)                                                  270.5          277.2
9.5% Senior Notes, due December 2008 (a)                                                360.0          371.8
6.625% Notes, due April 2011 (a)                                                        800.0          803.7
7.375% Senior Notes, due April 2018                                                     250.5          250.5
Zero Coupon Convertible Debentures, due May 2020 (put options exercisable
   May 2008 and May 2013) (b)                                                            16.4          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                                                              597.4          597.4
Other                                                                                     1.0            0.2
                                                                               --------------  -------------
   Total Debt                                                                         3,701.4        4,678.0
                                                                               --------------  -------------
   Less Debt Due Within One Year (b)                                                    282.1        1,048.1
                                                                               --------------  -------------
   Total Long-Term Debt                                                        $      3,419.3  $     3,629.9
                                                                               ==============  =============
<FN>
_________________
(a)   At  December  31,  2002,  the  Company  was  a party to interest rate swap
      agreements  with  respect  to  these  debt  instruments.  See  Note  6.
(b)   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 September 30, 2003, the remaining balance of
      the  debentures  not put back to the Company in May 2003 was classified as
      long-term  debt.
</TABLE>

     The  scheduled maturity of the face value of the Company's debt assumes the
bondholders exercise their options to require the Company to repurchase the 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 for the
twelve  months  ending  September  30  (in  millions):


                   2004 . . .  $  281.5
                   2005 . . .     419.0
                   2006 . . .     400.0
                   2007 . . .     100.0
                   2008 . . .     269.0
                   Thereafter   2,050.0
                               --------
                     Total. .  $3,519.5
                               ========


                                       12
<PAGE>
                        TRANSOCEAN INC. AND SUBSIDIARIES
        NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
                                   (Unaudited)

     Commercial Paper Program - The Company has two revolving credit agreements,
described  below,  which  provide  liquidity for commercial paper borrowings. At
September  30,  2003,  no  amounts  were  outstanding under the Commercial Paper
Program.

     Revolving  Credit  Agreements  -  The  Company  is a party to two revolving
credit  agreements,  a $550.0 million five-year revolving credit agreement dated
December  29, 2000 and a $250.0 million 364-day revolving credit agreement dated
December  26,  2002.  In  addition to providing for commercial paper borrowings,
these  credit  lines  may  also  be drawn on directly. At September 30, 2003, no
amounts  were  outstanding  under  either  of these revolving credit agreements.

     Term  Loan  Agreement  -  The Company is a party to an amortizing unsecured
five-year term loan agreement dated December 16, 1999. Amounts outstanding under
the  Term  Loan Agreement bear interest, at the Company's option, at a base rate
or  London  Interbank Offered Rate ("LIBOR") plus a margin that varies depending
on the Company's senior unsecured public debt rating. At September 30, 2003, the
margin  was 0.70 percent per annum. The debt began to amortize in March 2002, at
a  rate  of  $25.0  million  per  quarter  in  2002.  In 2003 and 2004, the debt
amortizes  at  a  rate  of  $37.5 million per quarter. As of September 30, 2003,
$187.5  million  was  outstanding  under  this  agreement.

     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% (see
"-Retired  and  Repurchased Debt"), 6.75%, 6.95%, 7.375%, 9.125% and 9.5% Senior
Notes,  respectively,  not exchanged remain the obligation of TODCO. These notes
are combined with the notes of the corresponding series issued by the Company in
the  above table. In connection with the Exchange Offer, TODCO paid $8.3 million
in  consent payments to holders of TODCO's notes whose notes were exchanged. The
consent payments are being amortized as an increase to interest expense over the
remaining  term  of the respective notes and such amortization is expected to be
approximately  $1.1  million  in  2003.

     Retired and Repurchased Debt - In April 2003, the Company repaid all of the
$239.5  million principal amount outstanding 6.5% Senior Notes, plus accrued and
unpaid interest, in accordance with their scheduled maturity. 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  April  2003,  the  Company  announced  that  holders of its Zero Coupon
Convertible Debentures due May 24, 2020 had the option to require the Company to
repurchase  their  debentures  in  May 2003. 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


                                       13
<PAGE>
                        TRANSOCEAN INC. AND SUBSIDIARIES
        NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
                                   (Unaudited)

repurchased  debentures.  The  holders  of the $26.4 million aggregate principal
amount  of  debentures  that  remain  outstanding  have the right to require the
Company  to  repurchase  the  debentures  in  May 2008 at a price of $720.55 per
$1,000  principal amount. The Company also has the right to redeem the remaining
debentures  at any time at a price equal to the debentures' then accreted value.
The  outstanding  debentures  are convertible, at the option of the holder, into
8.1566  of the Company's ordinary shares per $1,000 principal amount, subject to
adjustment  under  certain  circumstances.

NOTE  4  -  INCOME  TAXES

     As  a result of a change in anticipated 2003 earnings, the annual effective
tax  rate  is  estimated  to be approximately 43 percent during 2003 on earnings
before  non-cash  note  receivable  and  other  asset  impairments, loss on debt
retirements  and  initial  public offering related costs. Due to the increase in
the  estimated  annual  effective tax rate from approximately 38 percent at June
30, 2003, earnings for the three months ended September 30, 2003 were reduced by
$2.6  million  ($0.01  per  diluted  share) as a result of applying the adjusted
estimated  annual  effective  tax  rate  to  the six months ended June 30, 2003.

     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.

     In September 2002, the Company recorded a $176.2 million ($0.55 per diluted
share) foreign tax benefit attributable to the restructuring of certain non-U.S.
operations.  As  a  result  of the restructuring, previously unrecognized losses
were  offset  against  deferred  gains,  resulting in a reduction of non-current
deferred  taxes  payable.

NOTE  5  -  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  September  30,  2003,  the  Company  had no material open foreign
exchange  contracts.

     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,


                                       14
<PAGE>
                        TRANSOCEAN INC. AND SUBSIDIARIES
        NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
                                   (Unaudited)

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.

NOTE  6  -  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 the floating rate (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 is
expected  to  be  approximately $23.1 million ($0.07 per diluted share) in 2003.

     DD  LLC, an unconsolidated subsidiary in which the Company has a 50 percent
ownership  interest,  entered  into  interest  rate swaps in August 1998 with an
expiration  date  of October 2003 that have aggregate market values netting to a
liability of $0.7 million at September 30, 2003. The Company's interest in these
swaps  has  been included in accumulated other comprehensive income, net of tax,
with  corresponding  reductions  to deferred income taxes and investments in and
advances  to  joint  ventures.

NOTE  7  -  SEGMENTS

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


                                       15
<PAGE>
                        TRANSOCEAN INC. AND SUBSIDIARIES
        NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
                                   (Unaudited)

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

<TABLE>
<CAPTION>
                                                  Three Months Ended    Nine Months Ended
                                                     September 30,        September 30,
                                                  ------------------  --------------------

                                                    2003      2002      2003       2002
                                                  --------  --------  ---------  ---------
<S>                                               <C>       <C>       <C>        <C>
Operating Revenues
  International and U.S. Floater Contract
    Drilling Services                             $ 564.4   $ 641.2   $1,675.6   $1,873.5
  Gulf of Mexico Shallow and Inland Water            58.5      54.0      167.2      135.8
                                                  --------  --------  ---------  ---------
    Total Operating Revenues                      $ 622.9   $ 695.2   $1,842.8   $2,009.3
                                                  --------  --------  ---------  ---------

Operating income (loss) before general and
    administrative expense
  International and U.S. Floater Contract
    Drilling Services                             $ 118.9   $ 190.0   $  347.1   $  570.8
  Gulf of Mexico Shallow and Inland Water           (24.9)    (38.1)    (102.9)    (101.8)
                                                  --------  --------  ---------  ---------
                                                     94.0     151.9      244.2      469.0
                                                  --------  --------  ---------  ---------
Unallocated general and administrative expense      (21.2)    (15.8)     (50.0)     (51.6)
Unallocated other income (expense), net             (44.3)    (44.5)    (171.9)    (139.7)
                                                  --------  --------  ---------  ---------
  Income before Income Taxes, Minority Interest
    and Cumulative Effect of a Change in
    Accounting Principle                          $  28.5   $  91.6   $   22.3   $  277.7
                                                  ========  ========  =========  =========
</TABLE>


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

<TABLE>
<CAPTION>
                                                           September 30,   December 31,
                                                                2003           2002
                                                           --------------  -------------
<S>                                                        <C>             <C>
International and U.S. Floater Contract Drilling Services  $     10,996.6  $    11,804.1
Gulf of Mexico Shallow and Inland Water                             721.1          861.0
                                                           --------------  -------------
Total Assets                                               $     11,717.7  $    12,665.1
                                                           ==============  =============
</TABLE>


NOTE  8  -  ASSET  DISPOSITIONS  AND  IMPAIRMENT  LOSS

     Asset Dispositions - In January 2003, in the International and U.S. Floater
Contract  Drilling  Services segment, the Company completed the sale of a jackup
rig,  the  RBF  160,  for net proceeds of $13.0 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  nine  months  ended September 30, 2003, the Company settled an
insurance  claim and sold certain other assets for net proceeds of approximately
$4.1  million  and recorded net gains of $1.9 million ($0.01 per diluted share),
net  of  tax  of  $0.2  million,  in its International and U.S. Floater Contract
Drilling  Services  segment and $0.3 million, net of tax of $0.2 million, in its
Gulf  of  Mexico  Shallow  and  Inland  Water  segment.

     During  the  nine months ended September 30, 2002, in the International and
U.S. Floater Contract Drilling Services 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  nine  months  ended September 30, 2002, the Company settled an
insurance  claim and sold certain other assets for net proceeds of approximately
$24.2  million  and  recorded  net  gains  of  $2.9  million  ($0.01 per diluted


                                       16
<PAGE>
                        TRANSOCEAN INC. AND SUBSIDIARIES
        NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
                                   (Unaudited)

share),  net  of  tax  of  $0.3  million,  in its International and U.S. Floater
Contract Drilling Services segment and $0.4 million, net of tax of $0.3 million,
in  its  Gulf  of  Mexico  Shallow  and  Inland  Water  segment.

     Impairments  - During the nine months ended September 30, 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 Gulf of Mexico Shallow and Inland Water
segment, which resulted from 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. As a result of this decision, and 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  Company  also  recorded  a  non-cash impairment charge in this
segment  of $0.7 million, net of tax of $0.3 million, related to its approximate
12 percent investment in Energy Virtual Partners, LP and Energy Virtual Partners
Inc., which 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 condensed
consolidated balance sheets. The impairment was determined and measured based on
the remaining book value of the Company's investment and management's assessment
of  the  fair  value  of  that  investment  at  the  time the decision was made.

     During  the  nine  months ended September 30, 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 International and U.S. Floater Contract
Drilling  Services segment, which resulted from 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, which
resulted  from  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.

     During  the  nine  months  ended  September  30, 2002, the Company recorded
non-cash  impairment  charges of $13.1 million ($0.04 per diluted share), net of
tax  of  $7.1 million, and $9.9 million ($0.03 per diluted share), net of tax of
$5.3  million,  in its International and U.S. Floater Contract Drilling Services
and  Gulf of Mexico Shallow and Inland Water segments, respectively, relating to
the  reclassification  of  assets  held  for  sale  to assets held and used. The
impairment  of  these  assets resulted from management's assessment that they no
longer  met  the  held for sale criteria under SFAS 144. In accordance with SFAS
144, the carrying value of these assets was adjusted to the lower of fair market
value  or carrying value adjusted for depreciation from the date the assets were
classified  as  held for sale. The fair market values of these assets were based
on  third  party  valuations.

     During  the  nine  months ended September 30, 2002, due to deterioration in
market  conditions,  the  Company  recorded  non-cash impairment charges 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,  in the International and U.S. Floater Contract
Drilling  Services  and  Gulf  of  Mexico  Shallow  and  Inland  Water segments,
respectively,  related  to assets held for sale. The impairments were determined
and  measured  based  on  an  estimate  of  fair  value derived from offers from
potential  buyers.


                                       17
<PAGE>
                        TRANSOCEAN INC. AND SUBSIDIARIES
        NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
                                   (Unaudited)

NOTE  9  -  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):

<TABLE>
<CAPTION>
                                                                           Three Months Ended      Nine Months Ended
                                                                             September 30,           September 30,
                                                                         ----------------------  ----------------------
                                                                            2003        2002       2003        2002
                                                                         ----------  ----------  ---------  -----------
<S>                                                                      <C>         <C>         <C>        <C>
NUMERATOR FOR BASIC EARNINGS (LOSS) PER SHARE
Income Before Cumulative Effect of a Change in Accounting
   Principle                                                             $     11.0  $    255.2  $    13.7  $    412.5
Cumulative Effect of a Change in Accounting Principle                             -           -          -    (1,363.7)
                                                                         ----------  ----------  ---------  -----------
Net Income (Loss) for basic earnings per share                           $     11.0  $    255.2  $    13.7  $   (951.2)
                                                                         ==========  ==========  =========  ===========

NUMERATOR FOR DILUTED EARNINGS (LOSS) PER SHARE
Income Before Cumulative Effect of a Change in Accounting
  Principle                                                              $     11.0  $    255.2  $    13.7  $    412.5
Add back effect of dilutive zero coupon convertible debentures                    -         3.8          -           -
                                                                         ----------  ----------  ---------  -----------
Income Before Cumulative Effect of a Change in Accounting
  Principle                                                              $     11.0  $    259.0  $    13.7  $    412.5
Cumulative Effect of a Change in Accounting Principle                             -           -          -    (1,363.7)
                                                                         ----------  ----------  ---------  -----------
Net Income (Loss) for diluted earnings per share                         $     11.0  $    259.0  $    13.7  $   (951.2)
                                                                         ==========  ==========  =========  ===========

DENOMINATOR FOR DILUTED EARNINGS (LOSS) PER SHARE
Weighted-average shares outstanding for basic earnings per share              319.9       319.2      319.8       319.1
  Effect of dilutive securities:
    Employee stock options and unvested stock grants                            0.9         1.5        1.1         2.3
    Warrants to purchase ordinary shares                                        0.3         1.0        0.5         1.6
    Zero coupon convertible debentures                                            -         7.1          -           -
                                                                         ----------  ----------  ---------  -----------
Adjusted weighted-average shares and assumed
  conversions for diluted earnings per share                                  321.1       328.8      321.4       323.0
                                                                         ==========  ==========  =========  ===========

BASIC EARNINGS (LOSS) PER SHARE
   Income Before Cumulative Effect of a Change in Accounting Principle   $     0.03  $     0.80  $    0.04  $     1.29
   Cumulative Effect of a Change in Accounting Principle                          -           -          -       (4.27)
                                                                         ----------  ----------  ---------  -----------
   Net Income (Loss)                                                     $     0.03  $     0.80  $    0.04  $    (2.98)
                                                                         ==========  ==========  =========  ===========

DILUTED EARNINGS (LOSS) PER SHARE
  Income Before Cumulative Effect of a Change in Accounting
     Principle                                                           $     0.03  $     0.79  $    0.04  $     1.28
  Cumulative Effect of a Change in Accounting Principle                           -           -          -       (4.22)
                                                                         ----------  ----------  ---------  -----------
  Net Income (Loss)                                                      $     0.03  $     0.79  $    0.04  $    (2.94)
                                                                         ==========  ==========  =========  ===========
</TABLE>

     Ordinary  shares subject to issuance pursuant to the conversion features of
the  convertible  debentures  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 three and
nine  months  ended  September  30, 2003 and the nine months ended September 30,
2002.


                                       18
<PAGE>
                        TRANSOCEAN INC. AND SUBSIDIARIES
        NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
                                   (Unaudited)

NOTE  10  -  CONTINGENCIES

     Legal  Proceedings  -  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  has  certain  other  actions or claims pending that have been
previously  discussed  and  reported in the Company's Annual Report on Form 10-K
for  the year ended December 31, 2002 and the Company's other reports filed with
the Securities and Exchange Commission. There have been no material developments
in  these  previously  reported  matters.  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.

     Letters  of  Credit  and  Surety  Bonds - The Company had letters of credit
outstanding  at  September  30,  2003  totaling $204.1 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  $169.8  million  in  place that secure customs
obligations  relating to the importation of its rigs and certain performance and
other  obligations.

NOTE  11  -  RELATED  PARTY  TRANSACTIONS

     Delta  Towing  - In January 2003, Delta Towing failed to make its scheduled
quarterly  interest payment of $1.7 million on the notes receivable. The Company
signed  a  90-day  waiver  of  the terms requiring payment of interest. In April
2003,  Delta  Towing  again  failed to make its interest payment of $1.7 million
originally due January 2003 after expiration of the 90-day waiver. In April 2003
and  July  2003,  Delta  Towing  failed  to  make additional scheduled quarterly
interest  payments  on  the  notes  receivable of $1.6 million and $1.7 million,
respectively.  During  the  nine  months  ended  September 30, 2003, the Company
received  partial  interest  payments  of  approximately  $1.0  million and $1.1
million  of  payments  applied  to  principal on the three-year revolving credit
facility.  At September 30, 2003, the Company had interest receivable from Delta
Towing of $4.0 million. As a result of the Company's continued evaluation of the
collectibility  of the Delta Towing notes, the Company recorded an impairment on
the  notes  receivable of $13.8 million ($0.04 per diluted share), net of tax of
$7.5  million,  in the second quarter of 2003 as an allowance for credit losses.
The  Company  based  the  impairment on Delta Towing's discounted projected cash
flows  over  the  term of the notes, which deteriorated in the second quarter of
2003  as  a  result of the continued decline in Delta Towing's business outlook.
The amount of the notes receivable outstanding prior to the impairment was $82.8
million.  At  September  30,  2003,  the  carrying value of the notes receivable
included  in  investments  in  and  advances  to joint ventures in the Company's
condensed  consolidated  balance sheets, net of the related allowance for credit
losses  and  equity losses in the joint venture, was $53.6 million. In September
2003,  the  Company  established  a  reserve of $1.6 million for interest income
earned  during  the  third  quarter on the notes receivable and will continue to
reserve  future  interest  income  earned until the scheduled quarterly interest
payments  have  been  brought  current.  The  Company  will


                                       19
<PAGE>
                        TRANSOCEAN INC. AND SUBSIDIARIES
        NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
                                   (Unaudited)

apply future cash payments to interest receivable currently outstanding and then
to  interest  income  for  which  a  reserve  has  been  established.

     DDII LLC is the lessee in a synthetic lease financing facility entered into
in  connection with the construction of the drillship Deepwater Frontier. In May
2003,  WestLB  AG, one of the lenders in the synthetic lease financing facility,
assigned  its  $46.1 million remaining promissory note receivable to the Company
in  exchange  for  cash  of  $46.1  million. As a result of this assignment, the
Company  assumed all the rights and obligations of WestLB AG. The balance of the
note receivable was $44.2 million at September 30, 2003 and is included in other
current  assets  in  the  Company's  condensed  consolidated  balance  sheets.

     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 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.

NOTE  12  -  RESTRUCTURING  CHARGES

     In  September  2002, the Company committed to a restructuring plan to close
its engineering office in Montrouge, France. The Company established a liability
of  $2.8  million  for the estimated severance-related costs associated with the
involuntary  termination  of  16 employees pursuant to this plan. The charge was
reported  as  operating  and  maintenance  expense in the International and U.S.
Floater  Contract  Drilling  Services  segment  in  the  Company's  condensed
consolidated  statements of operations. Through September 30, 2003, $2.5 million
had  been  paid  representing full or partial payments to all 16 employees whose
positions  were  eliminated  as  a result of this plan. The Company released the
expected  surplus liability of $0.3 million to operating and maintenance expense
in  June  2003.

     In  September  2002,  the  Company  committed to a restructuring plan for a
staff  reduction  in Norway as a result of a decline in activity in that region.
The  Company  established  a  liability  of  $1.2  million  for  the  estimated
severance-related  costs  associated  with  the involuntary termination of eight
employees  pursuant  to  this  plan.  The  charge  was reported as operating and
maintenance  expense  in  the  International  and U.S. Floater Contract Drilling
Services  segment  in  the  Company's  condensed  consolidated  statements  of
operations.  Through September 30, 2003, $0.8 million had been paid representing
full or partial payments to eight employees whose positions are being eliminated
as a result of this plan. The Company anticipates that substantially all amounts
will  be  paid  by  the  end  of  the  first  quarter  of  2005.

     In  September  2002,  the  Company  committed  to  a  restructuring plan to
consolidate certain functions and offices utilized in its Gulf of Mexico Shallow
and  Inland Water segment. The plan resulted in the closure of an administrative
office  and  warehouse in Louisiana and relocation of most of the operations and
administrative  functions  previously  conducted  at  that location. The Company
established  a  liability  of  $1.2  million for the estimated severance-related
costs  associated  with  the involuntary termination of 57 employees pursuant to
this  plan.  The charge was reported as operating and maintenance expense in the
Company's condensed consolidated statements of operations. Through September 30,
2003, substantially all of the $1.2 million previously established liability was
paid  to  50 employees whose employment was terminated as a result of this plan.


                                       20
<PAGE>
                        TRANSOCEAN INC. AND SUBSIDIARIES
        NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
                                   (Unaudited)

NOTE  13  -  RETIREMENT  PLANS  AND  OTHER  POST  EMPLOYMENT  BENEFITS

     Nigerian  Severance  Plan  -  The  Company  maintains a severance plan (the
"Nigeria  Plan"),  which  provides  postretirement benefits to certain employees
under  a  labor  contract  with the Nigeria labor unions. Under the Nigeria Plan
provisions,  employees  receive  postretirement  benefits  in  the  event  of
retirement,  termination for redundancy, or death. The Company made 83 employees
redundant  effective  May 2003. In accordance with the provisions of the Nigeria
Plan,  the  Company  paid  approximately $2.6 million in termination benefits in
August  2003. Additionally, as a result of these terminations, and in accordance
with  the  provisions  of  SFAS  88,  Employers'  Accounting for Settlements and
Curtailments  of  Defined  Benefit Pension Plans and for Termination Benefits, a
plan curtailment gain of $0.8 million, net of a settlement loss of $0.3 million,
was  recorded.


                                       21
<PAGE>
ITEM  2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
         OF  OPERATIONS

     The  following  information  should be read in conjunction with the audited
consolidated  financial  statements  and  the  notes  thereto  included  in  the
Company's  Annual  Report  on  Form  10-K  for the year ended December 31, 2002.

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  and inland marine
contract  drilling  services  for  oil and gas wells. As of October 31, 2003, we
owned,  had  partial  ownership  interests  in  or operated more than 160 mobile
offshore  and  barge  drilling  units.  As  of  this date, our fleet included 13
fifth-generation  semisubmersibles  and  drillships  ("floaters"),  15  other
deepwater floaters, 31 mid-water floaters and 50 jackup drilling rigs. Our fleet
also included 34 drilling barges, four tenders, three submersible drilling rigs,
two  platform  drilling  rigs,  a  mobile  offshore  production  unit and a land
drilling  rig,  as well as nine land rigs and three lake barges in Venezuela. We
contract  our  drilling  rigs,  related  equipment and work crews primarily on a
dayrate  basis  to drill oil and gas wells. We also provide additional services,
including  management  of  third-party  well  service  activities.

     We  have reclassified our floaters into a deepwater category, consisting of
our  fifth-generation  floaters  and  other  deepwater floaters, and a mid-water
category.  We  have  also reviewed 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  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. Within our deepwater category, we
consider our fifth-generation rigs 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. The floaters comprising the other deepwater
category  are those semisubmersible rigs and drillships which have a water depth
capacity  of  at  least 4,500 feet. The mid-water category is comprised of those
floaters  with  a  water  depth  capacity  of  less  than  4,500  feet.  We have
reclassified  these  rigs  to better reflect how we view, and how we believe our
investors  and  the  industry  view,  our  fleet.

     Our  operations  are  aggregated  into  two  reportable  segments:  (i)
International  and  U.S.  Floater  Contract  Drilling  Services and (ii) Gulf of
Mexico  Shallow  and  Inland  Water. The International and U.S. Floater Contract
Drilling  Services  segment consists of floaters, non-U.S. jackups, other mobile
offshore  drilling  units  and other assets used in support of offshore drilling
activities  and offshore support services. The Gulf of Mexico Shallow and Inland
Water segment consists of jackup and submersible drilling rigs located in the U.
S.  Gulf of Mexico, Mexico and Trinidad and U.S. inland drilling barges, as well
as  land and lake barge drilling units located in 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.

     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. We expect the increase in
operating  revenues  and  operating  and maintenance expense resulting from this
implementation  to  be  between  $90 million and $110 million for the year 2003.
This  change  in  the accounting treatment for client reimbursables will have no
effect  on  our  results  of  operations  or consolidated financial position. We
previously  recorded  these charges and related reimbursements on a net basis in
operating  and  maintenance  expense.  Prior  period  amounts  have  not  been
reclassified,  as  the  amounts  were  not  material.

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


                                       22
<PAGE>
the  entity that owns that business in preparation of the offering. We expect to
complete  the  IPO  when  market conditions warrant, subject to various factors.
Given  the  current  general  uncertainty  in  the  equity  and U.S. natural gas
drilling markets, we are unsure when the transaction could be completed on terms
acceptable  to  us. However, we do not anticipate completion of the IPO prior to
2004. We do not expect to sell all of our interest in TODCO in the IPO. Until we
complete  the IPO transaction, we will continue to operate and account for TODCO
as  our Gulf of Mexico Shallow and Inland Water segment. Because the IPO had not
been  completed  by  the  end  of  the third quarter of 2003, we recognized $8.0
million  of  costs relating to the IPO in general and administrative expense for
the three months ended September 30, 2003, of which $6.4 million was deferred in
previous  periods.  Future  IPO-related  costs  will  be  expensed  as incurred.

     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. See "-Operating
Results."

     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. We continue negotiations
to  resolve  various  labor  issues  in  Nigeria.

     In  May 2003, we purchased ConocoPhillips' 40 percent interest in Deepwater
Drilling  II  L.L.C.  ("DDII  LLC"). DDII LLC is the lessee in a synthetic lease
financing  facility  entered  into  in  connection  with the construction of the
Deepwater  Frontier.  As  a result of this purchase, we consolidated DDII LLC in
the  second  quarter  of  2003.  See  "-Special Purpose Entities, Sale/Leaseback
Transaction  and  Related  Party  Transactions."

     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, but we are in discussion with our customer regarding the appropriate
dayrate  treatment.  Results  for the three months ended September 30, 2003 were
negatively  impacted by approximately $17 million due to an ongoing disagreement
with  our  customer  concerning  the  applicable  dayrate  and  other costs. See
"-Operating  Results"  and  "-Outlook."

     In  June  2003,  we  incurred a loss as a result of a well blowout and fire
aboard our inland barge Rig 62. During the nine months ended September 30, 2003,
we  incurred a $7.6 million loss relating to this incident.  While our insurance
coverage  has  a $12.5 million aggregate 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  condensed  consolidated  financial
statements  or  results  of  operations.  See  "-Operating  Results."

     In  September 2003, we recorded a loss of approximately $3.5 million on our
inland  barge  Rig  20 as a result of a fire. While our insurance coverage has a
$12.5  million  aggregate  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 condensed consolidated financial statements or
results  of  operations.  See  "-Operating  Results."

CRITICAL  ACCOUNTING  POLICIES  AND  ESTIMATES

     Our  discussion  and  analysis  of  our  financial condition and results of
operations  are based upon our condensed consolidated financial statements. This
discussion  should be read in conjunction with disclosures included in the notes
to  our  condensed  consolidated  financial  statements  related  to  estimates,
contingencies and new accounting pronouncements. Significant accounting policies
are  discussed  in  Note  2  to  our condensed consolidated financial statements
included elsewhere and in Note 2 to our consolidated financial statements in our
Annual Report on Form 10-K for the year ended December 31, 2002. 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


                                       23
<PAGE>
goodwill,  income  taxes, financing operations, workers' insurance, pensions and
other  post-retirement  and  employment  benefits and contingent liabilities. We
base  our  estimates  on  historical experience and on various other assumptions
that are believed to be reasonable under the circumstances, the results of which
form  the  basis  for  making  judgments about the carrying values of assets and
liabilities that are not readily apparent from other sources. Actual results may
differ  from  these  estimates  under  different  assumptions  or  conditions.

     We  believe  the following are our most critical accounting policies. These
policies  require significant judgments and estimates used in the preparation of
our  consolidated  financial  statements. 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  customer  receivables.  If the financial condition of our
customers  was to deteriorate or their access to freely convertible currency was
restricted,  resulting  in  impairment  of  their  ability  to make the required
payments,  additional  allowances  may  be  required.

     Valuation allowance for deferred tax assets-We record a valuation allowance
to  reduce  our deferred tax assets to the amount that we believe is more likely
than  not to be realized. Deferred tax assets generally represent items that can
be used as a tax deduction or credit in our tax return in future years for which
we  have already recorded the tax benefit in our income statement. While we have
considered  future  taxable income and ongoing prudent and feasible tax planning
strategies  in  assessing  the  need  for  the  valuation  allowance,  should we
determine that we would more likely than not be able to realize our deferred tax
assets  in  the  future  in excess of our net recorded amount, a decrease to the
valuation  allowance  would increase income in the period such determination was
made. Likewise, should we determine that we would more likely than not be unable
to  realize all or part of our net deferred tax asset in the future, an increase
to  the valuation allowance would reduce income in the period such determination
was  made.

     Goodwill  impairment-We  perform  a  test  for  impairment  of our goodwill
annually  as  of  October  1  as prescribed by Statement of Financial Accounting
Standards  ("SFAS") 142, Goodwill and Other Intangibles. Because our business is
cyclical  in  nature, goodwill could be significantly impaired depending on when
the  assessment  is  performed  in  the  business  cycle.  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. See Note 2 to our condensed
consolidated  financial  statements.

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


                                       24
<PAGE>
     Pension  and  Other Postretirement Benefits-Our defined benefit pension and
other  postretirement  benefit  (retiree  life  insurance  and medical benefits)
obligations  and  the related benefit costs are accounted for in accordance with
SFAS 87, Employers' Accounting for Pensions, and SFAS 106, Employers' Accounting
for  Postretirement  Benefits  Other  than  Pensions. Pension and postretirement
costs and obligations are actuarially determined and are affected by assumptions
including  expected  return  on  plan  assets,  discount  rates,  compensation
increases, employee turnover rates and health care cost trend rates. We evaluate
our  assumptions  periodically and make adjustments to these assumptions and the
recorded  liabilities  as  necessary.

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

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

OPERATING  RESULTS

     QUARTER  ENDED  SEPTEMBER  30, 2003 COMPARED TO QUARTER ENDED SEPTEMBER 30,
2002

     Our  revenues  for  the quarter ended September 30, 2003 decreased by $72.3
million  and  our  operating  and maintenance expense increased by $21.9 million
compared  to  the  quarter ended September 30, 2002. Our overall average dayrate
and  utilization  decreased  from  $74,500 and 61 percent, respectively, for the
quarter  ended  September  30, 2002 to $67,000 and 59 percent, respectively, for
the  quarter  ended  September  30, 2003. The decreases in our contract drilling
revenue,  average  dayrates  and  utilization  were  mainly  attributable to the
decline in overall market conditions. In addition, our revenues, utilization and
operating  and  maintenance  expense  were  negatively  impacted  by  the  riser
separation  incident  on  the  drillship Discoverer Enterprise, the well control
incident  on inland barge Rig 62, the electrical fire on the Peregrine I and the
fire  on  inland  barge  Rig  20.  Following  is  a  detailed  analysis  of  our
International  and  U.S.  Floater Contract Drilling Services segment and Gulf of
Mexico  Shallow  and  Inland  Water  segment  operating  results,  as well as an
analysis  of income and expense categories that we have not allocated to our two
segments.


                                       25
<PAGE>
INTERNATIONAL  AND  U.S.  FLOATER  CONTRACT  DRILLING  SERVICES  SEGMENT

<TABLE>
<CAPTION>
                                                       Three Months Ended
                                                         September 30,
                                                       ------------------
                                                         2003      2002     Change   % Change
                                                       --------  --------  --------  ---------
                                                          (In millions, except day amounts
                                                                 and percentages)

<S>                                                    <C>       <C>       <C>       <C>
Operating days (a)                                       6,101     6,600      (499)       (8)%
Utilization (a) (b) (d)                                     71%       79%      N/A       (10)%
Average dayrate (a) (c) (d)                            $89,000   $94,600   $(5,600)       (6)%

Contract drilling revenues                             $ 544.4   $ 641.2   $ (96.8)      (15)%
Client reimbursable revenues                              20.0         -      20.0         N/M
                                                       --------  --------  --------  ---------
                                                         564.4     641.2     (76.8)      (12)%
Operating and maintenance                                342.4     325.7      16.7          5%
Depreciation                                             103.9     101.6       2.3          2%
Impairment loss on long-lived assets                         -      25.7     (25.7)        N/M
Gain from sale of assets, net                             (0.8)     (1.8)      1.0       (56)%
                                                       --------  --------  --------  ---------
Operating income before general and administrative
   expense                                             $ 118.9   $ 190.0   $ (71.1)      (37)%
                                                       ========  ========  ========  =========
<FN>
_________________
"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  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  has  changed  to  include  all rigs based on contract drilling
     revenues.  Prior  periods  have  been  restated  to  reflect  the  change.
</TABLE>

     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  $88.0  million,  excluding  the impact of the items
discussed  separately  below.  Contract  drilling  revenues  were also adversely
impacted  in  the third quarter of 2003 by approximately $8.4 million due to the
riser  separation  incident on the Discoverer Enterprise and the electrical fire
on the Peregrine I. Other factors contributing to the decrease in revenue in the
third  quarter  of  2003  were  the  absence of revenue earned from a leased rig
returned  to  its  owner ($1.2 million) and the settlement of a contract dispute
($15.0  million),  both  of  which  occurred in the third quarter of 2002. These
decreases  were partially offset by increases in contract drilling revenues from
the Deepwater Frontier ($15.6 million) in the third quarter of 2003, as a result
of  the  consolidation  of  DDII  LLC  late  in  the second quarter of 2003. See
"-Overview."

     Operating  revenues  for the three months ended September 30, 2003 included
$20.0  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 expenses was
primarily  due to approximately $22.0 million of costs associated with the riser
separation incident on the Discoverer Enterprise, the consolidation of DDII LLC,
which  leases the Deepwater Frontier and the electrical fire on the Peregrine I.
In  addition,  expenses  increased  due  to  costs  recognized  as operating and
maintenance  expense  relating  to  client  reimbursable expenses as a result of
implementing  EITF  99-19  in 2003 (see "-Overview"). Partially offsetting these
increases  were  decreased  operating


                                       26
<PAGE>
and  maintenance  expenses  of  approximately $10.0 million resulting from a rig
returned  to its owner during the third quarter of 2002, a decrease in allowance
for  doubtful  accounts  related  to  the  collection  of  a previously reserved
customer  receivable  and  reduced  expense  relating  to our insurance program.
Additional  decreases  resulted from $6.8 million of costs incurred in the three
months  ended  September  30,  2002  associated with restructuring charges and a
litigation  provision  with  no  comparable  activity  in the three months ended
September  30,  2003.

     The increase in this segment's depreciation expense resulted primarily from
depreciation  expense  related  to assets reclassified from held for sale to our
active  fleet during and subsequent to the three months ended September 30, 2002
because they no longer met the criteria for assets held for sale under SFAS 144.

     During  the  three  months  ended  September 30, 2002, we recorded non-cash
impairment  charges  of  $20.2  million  in  this  segment,  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  the nine months ended
September  30,  2002,  we  also  recorded  a  non-cash impairment charge of $5.5
million  related to an asset held for sale, which resulted from deterioration in
market  conditions.  The  impairment  was  determined  and  measured based on an
estimate  of fair value derived from an offer from a potential buyer. See Note 8
to  our  condensed  consolidated  financial  statements.

GULF  OF  MEXICO  SHALLOW  AND  INLAND  WATER  SEGMENT

<TABLE>
<CAPTION>
                                                       Three Months Ended
                                                          September 30,
                                                       ------------------
                                                         2003      2002     Change   % Change
                                                       --------  --------  --------  ---------
                                                         (In millions, except day amounts
                                                                and percentages)

<S>                                                    <C>       <C>       <C>       <C>
Operating days (a)                                       2,808     2,497       311         12%
Utilization (a) (b) (d)                                     44%       38%      N/A         16%
Average dayrate (a) (c) (d)                            $19,300   $21,600   $(2,300)      (11)%

Contract drilling revenues                             $  54.1   $  54.0   $   0.1         N/M
Client reimbursable revenues                               4.4         -       4.4         N/M
                                                       --------  --------  --------  ---------
                                                          58.5      54.0       4.5          8%
Operating and maintenance                                 60.6      55.4       5.2          9%
Depreciation                                              22.9      22.6       0.3          1%
Impairment loss on long-lived assets                         -      15.2     (15.2)        N/M
Gain from sale of assets, net                             (0.1)     (1.1)      1.0       (91)%
                                                       --------  --------  --------  ---------
Operating loss before general and administrative
  expense                                              $ (24.9)  $ (38.1)  $  13.2         35%
                                                       ========  ========  ========  =========
<FN>
_________________
"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  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.
</TABLE>

     Operating  revenues  for the three months ended September 30, 2003 included
$4.4 million related to costs incurred and billed to customers on a reimbursable
basis.  See  "-Overview."


                                       27
<PAGE>
     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 expenses was
primarily  due  to  approximately  $4.0  million of costs associated with a fire
incident  on  inland  barge Rig 20 and the well control incident on inland barge
Rig 62, as well as an increase in activity of approximately $2.0 million and the
consolidation  of  a  joint  venture  that  owns  two land rigs during the third
quarter  of  2002  ($0.7  million). In addition, expenses increased due to costs
recognized  as operating and maintenance expense relating to client reimbursable
expenses  as  a result of implementing EITF 99-19 during 2003 (see "-Overview").
Partially  offsetting  the above increases were reduced expenses of $2.1 million
relating  to  our insurance program in the three months ended September 30, 2003
compared  to  the  same  period in 2002 and a decrease 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 three months ended September 30, 2002.

     During  the  three  months  ended  September 30, 2002, we recorded non-cash
impairment  charges  of  $15.2  million  in  this  segment  related  to  assets
reclassified  from  held for sale to our active fleet because they no longer met
the  held  for  sale  criteria  under  SFAS  144.  See  Note  8 to our condensed
consolidated  financial  statements.

TOTAL  COMPANY  RESULTS  OF  OPERATIONS

<TABLE>
<CAPTION>
                                       Three Months Ended
                                          September 30,
                                         2003      2002     Change   % Change
                                       -------  ---------  --------  ---------
                                            (In millions, except % change)
<S>                                    <C>      <C>       <C>       <C>
General and Administrative Expense     $ 21.2   $   15.8   $   5.4         34%
Other (Income) Expense, net
Equity in earnings of joint ventures     (1.9)      (0.4)     (1.5)        N/M
Interest income                          (3.0)      (6.1)      3.1         51%
Interest expense                         49.0       52.3      (3.3)       (6)%
Other, net                                0.2        1.3      (1.1)      (85)%
Income Tax Expense (Benefit)             17.3     (164.8)    182.1         N/M
<FN>
_________________
"N/M"  means  not  meaningful
</TABLE>

     The  increase  in  general  and  administrative  expense  was  primarily
attributable  to  $8.0  million  in  expenses relating to the planned IPO of the
company's Gulf of Mexico Shallow and Inland Water business segment for the three
months  ended September 30, 2003, of which $6.4 million was deferred in previous
periods.  Offsetting the increase was reduced expense of $2.0 million related to
employee  benefits for the three months ended September 30, 2003 compared to the
same  period  in  2002.

     The  increase in equity in earnings of joint ventures was primarily related
to  our  25  percent  share  of earnings from Delta Towing Holdings, LLC ("Delta
Towing"), in which we recorded a decreased loss in earnings for the three months
ended  September  30,  2003  compared  to  the  same  period  in 2002. Partially
offsetting  the  increase  was a decrease in our 60 percent share of earnings of
DDII  LLC,  which  leases the Deepwater Frontier. DDII LLC was consolidated as a
result of the buyout of ConocoPhillips' 40 percent interest in the joint venture
in May 2003, resulting in no equity in earnings of joint ventures being recorded
for  the  three  months  ended  September 30, 2003 compared to earnings recorded
during  the  same  period in 2002. The decrease in interest income was primarily
due  to  interest earned on lower average cash balances and to the establishment
of  a  reserve for interest income on Delta Towing during the three months ended
September 30, 2003 compared to the same period in 2002. The decrease in interest
expense was primarily due to debt repaid or retired during and subsequent to the
three  months  ended  September  30, 2002, which resulted in an additional $10.6
million reduction in interest expense and reductions in interest expense of $6.5
million  related  to  the  recognition  of  the gain from the termination of the
interest  rate  swaps  (see  "-Derivative  Instruments"),


                                       28
<PAGE>
partially offset by the termination of our fixed to floating interest rate swaps
in  the  first  quarter of 2003, which resulted in an increase of $13.4 million.

     The  decrease  in  other,  net  of $1.2 million resulted primarily from the
effect  of  foreign  currency  exchange  rate  changes on a UK pound denominated
escrow  deposit  in the three months ended September 30, 2003 with no comparable
activity  in  the  corresponding  period  in  2002.

     We  operate  internationally  and provide for income taxes based on the tax
laws and rates in the countries in which we operate and earn income. There is no
expected  relationship  between the provision for income taxes and income before
income  taxes.  As a result of a change in anticipated 2003 earnings, our annual
effective  tax  rate  is estimated to be approximately 43 percent during 2003 on
earnings  before  non-cash  note receivable and other asset impairments, loss on
debt  retirements  and  IPO-related  costs. Due to the increase in the estimated
annual  effective  tax  rate  from  approximately  38  percent at June 30, 2003,
earnings  for  the  three  months  ended September 30, 2003 were reduced by $2.6
million as a result of applying the adjusted estimated annual effective tax rate
to the six months ended June 30, 2003. The three months ended September 30, 2002
included  a  non-U.S.  tax  benefit  of  $176.2  million  attributable  to  the
restructuring  of  certain  non-U.S.  operations.

     NINE  MONTHS  ENDED  SEPTEMBER  30,  2003  COMPARED  TO  NINE  MONTHS ENDED
SEPTEMBER  30,  2002

     Our  revenues  for  the  nine  months ended September 30, 2003 decreased by
$166.5  million  and  our  operating  and maintenance expense increased by $75.9
million  compared  to the nine months ended September 30, 2002. In addition, our
overall  average  dayrate and utilization decreased from $74,900 and 59 percent,
respectively,  for  the  nine  months ended September 30, 2002 to $67,100 and 57
percent,  respectively,  for  the  nine  months  ended  September  30, 2003. The
decreases  in  our  revenue and average dayrates were mainly attributable to the
decline  in  overall  market  conditions.  In  addition,  our  contract drilling
revenues,  utilization  and  operating  and  maintenance expense were negatively
impacted  by  the  labor strike in Nigeria, the riser separation incident on the
drillship  Discoverer  Enterprise, the well control incident on inland barge Rig
62,  the electrical fire on the Peregrine I and the fire on inland barge Rig 20.
Following  is a detailed analysis of our International and U.S. Floater Contract
Drilling  Services  segment  and Gulf of Mexico Shallow and Inland Water segment
operating  results, as well as an analysis of income and expense categories that
we  have  not  allocated  to  our  two  segments.

INTERNATIONAL  AND  U.S.  FLOATER  CONTRACT  DRILLING  SERVICES  SEGMENT

<TABLE>
<CAPTION>
                                                        Nine Months Ended
                                                          September 30,
                                                       --------------------
                                                         2003       2002      Change   % Change
                                                       ---------  ---------  --------  ---------
                                                           (In millions, except day amounts
                                                                 and percentages)
<S>                                                    <C>        <C>        <C>       <C>
Operating days (a)                                       17,870     19,971    (2,101)      (11)%
Utilization (a) (b) (d)                                      69%        80%      N/A       (14)%
Average dayrate (a) (c) (d)                            $ 89,800   $ 92,700   $(2,900)       (3)%

Contract drilling revenues                             $1,611.0   $1,873.5   $(262.5)      (14)%
Client reimbursable revenues                               64.6          -      64.6         N/M
                                                       ---------  ---------  --------  ---------
                                                        1,675.6    1,873.5    (197.9)      (11)%
Operating and maintenance                               1,013.8      974.5      39.3          4%
Depreciation                                              311.9      305.3       6.6          2%
Impairment loss on long-lived assets                        5.2       25.7     (20.5)      (80)%
Gain from sale of assets, net                              (2.4)      (2.8)      0.4       (14)%
                                                       ---------  ---------  --------  ---------
Operating income before general and administrative
   expense                                             $  347.1   $  570.8   $(223.7)      (39)%
                                                       =========  =========  ========  =========
<FN>
_________________
"N/A"  means  not  applicable


                                       29
<PAGE>
"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  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  has  changed  to  include all rigs based on contract drilling
      revenues.  Prior  periods  have  been  restated  to  reflect  the  change.
</TABLE>

     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  $233.0  million,  excluding the impact of the items
discussed  separately  below.  Contract  drilling  revenues  were also adversely
impacted  by approximately $31.0 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 resulted from the sale of rigs ($8.0
million),  the  return of a leased rig to its owner ($4.0 million), the transfer
of a jackup rig from this segment to the Gulf of Mexico Shallow and Inland Water
segment  ($1.7 million) and the settlement of a contract dispute ($15.0 million)
during  2002.  These  decreases  were  partially offset by increases in contract
drilling  revenue  from  a  rig  transferred  into this segment from the Gulf of
Mexico Shallow and Inland Water segment during the second quarter of 2002 ($10.0
million)  and  from  the  Deepwater  Frontier ($19.8 million) as a result of the
consolidation  of  DDII LLC late in the second quarter of 2003. See "-Overview."

     Operating  revenues  for  the nine months ended September 30, 2003 included
$64.6  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
primarily  due to approximately $38.0 million of costs associated with the riser
separation incident on the Discoverer Enterprise, the consolidation of DDII LLC,
which  leases the Deepwater Frontier and costs related to the electrical fire on
the  Peregrine  I.  We  also incurred additional expense of $5.3 million in 2003
resulting  from  the transfer of a jackup rig into this segment from the Gulf of
Mexico  Shallow  and  Inland Water segment during the second quarter of 2002. In
addition,  expenses  increased  due  to  costs  recognized  as  operating  and
maintenance  expense  relating  to  client  reimbursable expenses as a result of
implementing  EITF  99-19  in 2003 (see "-Overview"). Partially offsetting these
increases were decreased operating and maintenance expenses resulting from lower
activity  of approximately $12.0 million and $10.0 million relating to rigs sold
or  returned  to  owner during and subsequent to the nine months ended September
30,  2002.  Expenses  were  further  reduced  by  $6.7  million  relating to the
settlements of a dispute and an insurance claim as well as $6.0 million relating
to  a  reduction  in  our insurance program expense during the nine months ended
September  30,  2003.  Additional  decreases resulted from $6.8 million of costs
incurred  in  the  nine  months  ended  September  30,  2002  associated  with
restructuring  charges and a litigation provision with no comparable activity in
the  nine  months  ended  September  30,  2003.

     The increase in this segment's depreciation expense resulted primarily from
the  transfer  of a rig from the Gulf of Mexico Shallow and Inland Water segment
into  this  segment and depreciation expense related to assets reclassified from
held  for  sale  to our active fleet because they no longer met the criteria for
assets  held  for  sale  under SFAS 144 during and subsequent to the nine months
ended  September  30,  2002.  These  increases  were  partially  offset by lower
depreciation  expense  following  the  sale  of rigs classified as held and used
during  and  subsequent  to  the  nine  months  ended  September  30,  2002.

     During  the  nine  months  ended  September  30, 2003, we recorded non-cash
impairment  charges  of  $4.2  million  related  to assets held and used in this
segment,  which  resulted  from  our  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. During the nine months


                                       30
<PAGE>
ended  September 30, 2003, we also recorded a non-cash impairment charge of $1.0
million  in  this  segment,  which resulted from our decision to discontinue the
leases on our oil and gas properties. The impairment was determined and measured
based  on  the  carrying  value of the leases at the time the decision was made.
During the nine months ended September 30, 2002, we recorded non-cash impairment
charges  of  $20.2  million  in this segment 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 the nine months ended September 30, 2002, we
also  recorded  a non-cash impairment charge of $5.5 million related to an asset
held  for  sale,  which  resulted  from  deterioration in market conditions. The
impairment  was  determined  and  measured  based  on  an estimate of fair value
derived  from  an  offer  from  a  potential  buyer. See Note 8 to our condensed
consolidated  financial  statements.

GULF  OF  MEXICO  SHALLOW  AND  INLAND  WATER  SEGMENT
<TABLE>
<CAPTION>
                                                        Nine Months Ended
                                                          September 30,
                                                       ------------------
                                                         2003      2002     Change   % Change
                                                       --------  --------  --------  ---------
                                                          (In millions, except day amounts
                                                                  and percentages)
<S>                                                    <C>       <C>       <C>       <C>

Operating days (a)                                       8,348     6,544     1,804         28%
Utilization (a) (b) (d)                                     41%       33%      N/A         24%
Average dayrate (a) (c) (d)                            $18,400   $20,800   $(2,400)      (12)%

Contract drilling revenues                             $ 153.7   $ 135.8   $  17.9         13%
Client reimbursable revenues                              13.5         -      13.5         N/M
                                                       --------  --------  --------  ---------
                                                         167.2     135.8      31.4         23%
Operating and maintenance                                189.8     153.2      36.6         24%
Depreciation                                              69.2      68.8       0.4          1%
Impairment loss on long-lived assets                      11.6      16.3      (4.7)      (29)%
Gain from sale of assets, net                             (0.5)     (0.7)      0.2       (29)%
                                                       --------  --------  --------  ---------
Operating loss before general and administrative
    expense                                            $(102.9)  $(101.8)  $  (1.1)       (1)%
                                                       ========  ========  ========  =========
<FN>
_________________
"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  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.
</TABLE>

     Higher  utilization  resulted  in  an  increase  in this segment's contract
drilling  revenue  of  $41.7  million,  partially  offset  by  decreased average
dayrates  ($21.9  million),  and  the transfer of a jackup rig from this segment
into  the  International and U.S. Floater Contract Drilling Services segment and
rigs  sold  during  the  nine  months  ended  September 30, 2002 ($2.0 million).

     Operating  revenues  for  the nine months ended September 30, 2003 included
$13.5  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.


                                       31
<PAGE>
     The  increase  in this segment's operating and maintenance expenses was due
primarily  to  an  increase  in  activity  of  approximately  $20.0  million and
approximately  $11.0  million of costs associated with the well control incident
on  inland barge Rig 62 and the fire incident on inland barge Rig 20, as well as
an  insurance  claim  provision  ($2.5 million) and the consolidation of a joint
venture that owns two land rigs during the third quarter of 2002 ($1.9 million).
In  addition,  expenses  increased  due  to  costs  recognized  as operating and
maintenance  expense  relating  to  client  reimbursable expenses as a result of
implementing  EITF  99-19  during  the nine months ended September 30, 2003 (see
"-Overview").  These  increases were partially offset by reduced expense of $3.1
million relating to our insurance program in the nine months ended September 30,
2003  compared  to  the  same  period  in  2002,  the release of a provision for
doubtful  accounts  ($1.8  million)  during  the  first nine months of 2003 upon
collection  of  amounts  previously  reserved, lower expenses resulting from the
transfer  of  a  jackup  rig  from  this segment into the International and U.S.
Floater  Contract  Drilling  Services  segment  ($1.8 million) during the second
quarter  of 2002 and a decrease 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  nine  months  ended  September  30,  2002.

     During  the  nine  months  ended  September  30, 2003, we recorded non-cash
impairment  charges  of  $10.6  million in this segment, which resulted from our
decision  to  remove  five jackup rigs from drilling service and market the rigs
for  alternative  uses.  We  do  not anticipate returning these rigs to drilling
service  as  we  believe  it  would  be  cost  prohibitive.  As a result of this
decision,  and  in  accordance with SFAS 144, the carrying value of these assets
was  adjusted  to  fair  market  value.  The fair market value of these units as
non-drilling  rigs  were based on third party valuations. During the nine months
ended  September 30, 2003, we also recorded a non-cash impairment charge of $1.0
million  in  this segment, which resulted from our determination that the assets
of  an entity in which we have an investment did not support our carrying value.
The  impairment was determined and measured based on the remaining book value of
our  investment  and  our assessment of the fair value of that investment at the
time  the decision was made. During the nine months ended September 30, 2002, we
recorded non-cash impairment charges of $15.2 million in this segment 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. Also during the nine
months  ended  September  30,  2002, we recorded a non-cash impairment charge of
$1.1  million  related to an asset held for sale in this segment, which resulted
from  deterioration  in  market  conditions.  The  impairment was determined and
measured  based  on  an  estimate  of  fair  value  derived from an offer from a
potential  buyer. See Note 8 to our condensed consolidated financial statements.

TOTAL  COMPANY  RESULTS  OF  OPERATIONS

<TABLE>
<CAPTION>
                                                          Nine Months Ended
                                                            September 30,
                                                        ---------------------
                                                          2003        2002       Change    % Change
                                                        ---------  ----------  ----------  ---------
                                                             (In millions, except % change)
<S>                                                     <C>        <C>         <C>         <C>
General and Administrative Expense                      $   50.0   $    51.6   $    (1.6)       (3)%
Other (Income) Expense, net
  Equity in earnings of joint ventures                      (7.3)       (4.8)       (2.5)        52%
  Interest income                                          (15.7)      (16.0)        0.3          2%
  Interest expense                                         154.4       160.7        (6.3)       (4)%
  Loss on retirement of debt                                15.7           -        15.7         N/M
  Loss on impairment of note receivable from related
    party                                                   21.3           -        21.3         N/M
  Other, net                                                 3.5        (0.2)        3.7         N/M
Income Tax Expense (Benefit)                                 8.3      (137.1)      145.4         N/M
Cumulative Effect of a Change in Accounting Principle          -     1,363.7    (1,363.7)        N/M
<FN>
_________________
"N/M"  means  not  meaningful
</TABLE>


                                       32
<PAGE>
     The  decrease  in  general  and  administrative  expense  was  primarily
attributable  to  $4.4 million of costs related to the exchange of our notes for
TODCO's  notes in March 2002, as more fully described in Note 3 to our condensed
consolidated  financial  statements,  reduced expense of $5.5 million related to
employee  benefits  in  the nine months ended September 30, 2003 compared to the
same  period  in  2002.  Offsetting these decreases was $8.0 million in expenses
relating  to  the planned IPO of the company's Gulf of Mexico Shallow and Inland
Water  business  segment  for the nine months ended September 30, 2003, of which
$3.1  million  was  deferred  in  previous  periods.

     The  increase in equity in earnings of joint ventures was primarily related
to  our 60 percent share of the earnings of DDII LLC, which leases the Deepwater
Frontier.  This  rig  experienced  increased  utilization during the five months
ended  May 31, 2003, at which time we completed the buyout of ConocoPhillips' 40
percent interest in DDII LLC, compared to the first nine months of 2002 in which
the  rig  experienced  shipyard  downtime.  Also contributing to the increase in
equity  in  earnings  of  joint ventures was our 50 percent share of earnings of
Deepwater  Drilling L.L.C. ("DD LLC"), which owns the Deepwater Pathfinder. This
rig  experienced  increased  utilization and average dayrates in the nine months
ended  September  2003 compared to the same period in 2002. Also contributing to
the  increase was our 25 percent share of earnings from Delta Towing in which we
recorded  a  decreased  loss in earnings for the nine months ended September 30,
2003  compared  to  the  same period in 2002, partially offset by our share of a
$2.5  million non-cash impairment charge on the carrying value of Delta Towing's
idle  equipment.

     The decrease in interest expense was attributable to reductions of interest
expense  of  $19.1  million  associated  with debt refinanced, repaid or retired
during  and  subsequent  to  the  nine  months ended September 30, 2002. We also
received  a  refund  of  interest in 2003 from a taxing authority compared to an
interest  payment  in  2002  that resulted in a reduction in interest expense of
$1.8  million.  We  terminated  our fixed to floating interest rate swaps in the
first  quarter  of  2003,  which  resulted in an increase in interest expense of
$30.5  million, partially offset by a $16.5 million decrease in interest expense
related  to  the  recognition of the gain from the termination of these interest
rate  swaps  (see  "-Derivative  Instruments").

     During  the  nine  months  ended  September 30, 2003, we recognized a $15.7
million  loss  on early retirements of debt as more fully described in Note 3 to
our  condensed  consolidated  financial  statements.

     During  the  nine  months  ended  September  30,  2003, we recorded a $21.3
million  impairment  of the notes receivable due from Delta Towing as more fully
described  in  Note  11  to  our  condensed  consolidated  financial statements.

     We  recognized  a $2.3 million loss in other, net relating to the effect of
foreign  currency  exchange  rate changes on our monetary assets and liabilities
denominated  in  Venezuelan bolivars (see "-Item 3. Quantitative and Qualitative
Disclosures  about  Market  Risk-Foreign  Exchange Risk"), partially offset by a
$1.2  million  gain  resulting from the effect of foreign currency exchange rate
changes  on  a  UK  pound  denominated  escrow deposit for the nine months ended
September  30,  2003  compared  to  the  same  period  in  2002.

     We  operate  internationally  and provide for income taxes based on the tax
laws and rates in the countries in which we operate and earn income. There is no
expected  relationship  between the provision for income taxes and income before
income taxes. The nine months ended September 30, 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  43  percent  for  2003 on earnings before non-cash note
receivable and other asset impairments, loss on debt retirements and IPO-related
costs  compared  to our effective tax rate of approximately 14 percent for 2002.
The  increase  in  our  estimated  effective  tax rate resulted from a change in
anticipated  2003  earnings. The nine months ended September 30, 2002 included a
non-U.S.  tax  benefit  of  $175.7  million attributable to the restructuring of
certain  non-U.S.  operations.

     During  the  nine months ended September 30, 2002, we recognized a $1,363.7
million  cumulative  effect  of  a change in accounting principle in our Gulf of
Mexico  Shallow  and  Inland Water segment related to the implementation of SFAS
142  as  more  fully described in Note 2 to our condensed consolidated financial
statements.


                                       33
<PAGE>
FINANCIAL  CONDITION

<TABLE>
<CAPTION>
                                                              September 30,   December 31,               %
                                                                   2003           2002        Change   Change
                                                              --------------  --------------------------------
                                                                            (In millions)
<S>                                                           <C>             <C>            <C>       <C>
TOTAL ASSETS
  International and U.S. Floater Contract Drilling Services   $     10,996.6  $    11,804.1  $(807.5)     (7)%
  Gulf of Mexico Shallow and Inland Water                              721.1          861.0   (139.9)    (16)%
                                                              --------------  --------------------------------
                                                              $     11,717.7  $    12,665.1  $(947.4)     (7)%
                                                              ==============  ================================
</TABLE>

     The  decrease  in the assets of the International and U.S. Floater Contract
Drilling  Services  segment  was  mainly  due  to  a  decrease  in cash and cash
equivalents  ($438.2 million) that resulted primarily from the repayment of debt
during  2003  (see  Note  3 to our condensed consolidated financial statements).
Also  contributing  to  the decrease in this segment's assets was a reduction in
other  assets  primarily  due  to the termination of interest rate swaps ($181.3
million) during 2003 (see "-Derivative Instruments"). In addition, the sale of a
jackup  rig ($12.5 million net book value), normal depreciation ($311.9 million)
and  asset  impairments ($5.2 million) during 2003 further reduced the assets in
this  segment  (see  "-Operating  Results").  Offsetting  this  decrease  was an
increase  in  accounts  receivable  ($47.2  million)  and  notes receivable from
related  party ($44.2 million). The decrease in the assets of the Gulf of Mexico
Shallow and Inland Water segment was primarily due to normal depreciation ($69.2
million),  a  decrease in accounts receivable ($62.2 million), asset impairments
($11.6  million)  and  the  impairment of a related party note receivable ($21.3
million)  during  2003  (see  "-Operating  Results").

RESTRUCTURING  CHARGES

     In  September  2002,  we committed to a restructuring plan to eliminate our
engineering  department located in Montrouge, France. We established a liability
of  $2.8  million  for the estimated severance-related costs associated with the
involuntary  termination  of  16 employees pursuant to this plan. The charge was
reported  as  operating  and  maintenance  expense in the International and U.S.
Floater  Contract  Drilling  Services  segment  in  our  condensed  consolidated
statements  of  operations. As of September 30, 2003, $2.5 million had been paid
representing  full  or partial payments to all 16 employees whose positions were
eliminated  as a result of this plan. We released the expected surplus liability
of  $0.3  million  to  operating  and  maintenance  expense  in  June  2003.

     In  September  2002,  we  committed  to  a  restructuring  plan for a staff
reduction  in  Norway  as  a  result of a decline in activity in that region. We
established  a  liability  of  $1.2  million for the estimated severance-related
costs associated with the involuntary termination of eight employees pursuant to
this  plan.  The charge was reported as operating and maintenance expense in the
International  and  U.S.  Floater  Contract  Drilling  Services  segment  in our
condensed  consolidated statements of operations. As of September 30, 2003, $0.8
million  had  been  paid representing full or partial payments to five employees
whose  positions  have  been  eliminated as a result of this plan. We anticipate
that  substantially  all amounts will be paid by the end of the first quarter of
2005.

     In  September  2002,  we  committed  to a restructuring plan to consolidate
certain  functions and offices utilized in our Gulf of Mexico Shallow and Inland
Water  segment. The plan resulted in the closure of an administrative office and
warehouse  in  Louisiana  and  relocation  of  most  of  the  operations  and
administrative functions previously conducted at that location. We established a
liability  of  $1.2 million for the estimated severance-related costs associated
with  the  involuntary  termination  of  57 employees pursuant to this plan. The
charge  was  reported  as  operating  and  maintenance  expense in our condensed
consolidated  statements  of operations. As of September 30, 2003, substantially
all  of  the  $1.2  million  previously  established  liability  was  paid to 50
employees  whose  employment  was  terminated  as  a  result  of  this  plan.


                                       34
<PAGE>
OUTLOOK

     Fleet  utilization  and average dayrates increased within our International
and  U.S.  Floater  Contract  Drilling  Services  and Gulf of Mexico Shallow and
Inland  Water  business  segments during the third quarter of 2003 compared with
the  second  quarter  of  2003.

     Comparative  average  dayrates and utilization figures are set forth in the
table  below.

<TABLE>
<CAPTION>
                                                                                Three Months Ended
                                                                     -------------------------------------------
                                                                      September 30,    June 30,    September 30,
                                                                          2003           2003          2002
                                                                     ---------------  ----------  ---------------
<S>                                                                  <C>              <C>         <C>
AVERAGE DAYRATES (a)(b)(d)

INTERNATIONAL AND U.S. FLOATER CONTRACT DRILLING SERVICES SEGMENT:
  Deepwater
    5th Generation                                                   $      176,600   $ 185,100   $      190,100
    Other Deepwater                                                  $      112,500   $ 111,500   $      115,200
  Total Deepwater                                                    $      145,500   $ 147,500   $      148,000
    Mid-Water                                                        $       70,900   $  73,600   $       83,000
    Jackups - Non-U.S.                                               $       54,400   $  57,400   $       60,400
    Other Rigs                                                       $       48,800   $  41,500   $       49,300
                                                                     ---------------  ----------  ---------------
Segment Total                                                        $       89,000   $  88,900   $       94,600
                                                                     ---------------  ----------  ---------------

GULF OF MEXICO SHALLOW AND INLAND WATER SEGMENT:
    Jackups and Submersibles                                         $       20,800   $  18,200   $       22,400
    Inland Barges                                                    $       16,900   $  16,100   $       20,700
    Other Rigs                                                       $       20,500   $  18,600   $       23,400
                                                                     ---------------  ----------  ---------------
Segment Total                                                        $       19,300   $  17,500   $       21,600
                                                                     ---------------  ----------  ---------------

Total Mobile Offshore Drilling Fleet                                 $       67,000   $  65,300   $       74,500
                                                                     ===============  ==========  ===============

UTILIZATION (a)(c)(d)

INTERNATIONAL AND U.S. FLOATER CONTRACT DRILLING SERVICES SEGMENT:
  Deepwater
    5th Generation                                                               97%         88%              90%
    Other Deepwater                                                              73%         70%              85%
  Total Deepwater                                                                84%         78%              87%
    Mid-Water                                                                    54%         55%              74%
    Jackups - Non-U.S.                                                           85%         86%              84%
    Other Rigs                                                                   49%         41%              56%
                                                                     ---------------  ----------  ---------------
Segment Total                                                                    71%         68%              79%
                                                                     ---------------  ----------  ---------------

GULF OF MEXICO SHALLOW AND INLAND WATER SEGMENT:
    Jackups and Submersibles                                                     54%         44%              32%
    Inland Barges                                                                38%         39%              47%
    Other Rigs                                                                   38%         44%              31%
                                                                     ---------------  ----------  ---------------
Segment Total                                                                    44%         42%              38%
                                                                     ---------------  ----------  ---------------

Total Mobile Offshore Drilling Fleet                                             59%         57%              61%
                                                                     ===============  ==========  ===============
<FN>
_________________

(a)   Applicable  to  all  rigs.
(b)   Average  dayrate  is  defined  as  contract  drilling revenue earned per revenue  earning  day.


                                       35
<PAGE>
(c)  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.
(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.
</TABLE>

     Commodity  prices have maintained historically strong levels throughout the
third  quarter,  and  we  believe the trading markets and other indicators point
towards  continued  near-term  strength  in  oil  and  gas  prices. While future
commodity  price expectations are a key driver for offshore drilling demand, the
availability  of  drilling  prospects,  relative  production costs, the stage of
reservoir  development  and  political/regulatory  environments  all  impact our
customers'  drilling  programs. Strong commodity prices have not translated into
overall  increased  offshore drilling activity in the recent quarter, or in 2003
generally.  On  a global basis, we do not expect a material increase in drilling
demand  over  the  next  six  to  nine  months.

     Prospects for our International and U.S. Floater Contract Drilling Services
business  segment  are  uncertain  over  the  next six to nine months. Over this
period,  market  dayrates for the industry's most technically advanced deepwater
rigs  will  be  difficult  to  predict  and  intermittent  idle  time  could  be
experienced  as  a  number  of these units, including four of our 5th Generation
deepwater  rigs,  conclude  contracts. We continue to believe that over the long
term,  deepwater  exploration  and development drilling opportunities in Angola,
Nigeria,  India and other emerging locations represent a potentially significant
source  of  future  rig  demand.

     A  stable  level  of  activity  is  expected  to  persist  in  most  of the
international jackup market sectors. The modest overcapacity present in the West
Africa  jackup  market  sector  is  expected  to  largely dissipate by mid-2004,
although  dayrates associated with near-term contract signings in the region are
expected  to  decline  from  average levels experienced over the past 12 months.
India  has remained a key destination for jackups, as evidenced by the number of
jackup  rigs that have been and are expected to be added over the second half of
2003.  The  Far  East  jackup  market sector activity has remained largely flat,
although  dayrates  have  held  up  as  rigs  have  moved  outside  the  region.

     The  mid-water  floater  business  remains  extremely  weak  as this sector
continues to be significantly oversupplied globally. We expect overall North Sea
utilization  to  remain  below  50% this winter, due in part to reduced drilling
programs  by  the major oil companies. In the U.S. Gulf of Mexico, mid-water rig
demand is currently further dampened by increased competition from underutilized
deepwater  rigs, which have greater operating and technical capability. Absent a
significant  pick-up  in overall offshore demand, we expect the global mid-water
sector  to  continue  to  be  oversupplied  through  2004.

     The  Gulf  of Mexico Shallow and Inland Water business 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.  Demand in the Gulf of Mexico inland barge fleet has trended lower,
while  total  supply  is  unchanged.  However,  deep gas drilling interest among
several  exploration and production companies operating in the Gulf of Mexico is
expected  to  increase,  offering  the  prospect  for  improving demand in 2004.

     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 demand and adversely affect utilization and day rates. 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.

     Effective  December  31, 2003 we will adopt the provisions of the Financial
Accounting  Standards  Board's ("FASB") Interpretation ("FIN") 46, Consolidation
of Variable Interest Entities, an Interpretation of Accounting Research Bulletin
No.  51.  As  a  result  of the adoption, we expect to consolidate certain joint
ventures.  See  "-New  Accounting  Pronouncements."


                                       36
<PAGE>
     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  the  outcome  of  existing  or future assessments cannot be
predicted,  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 a change in anticipated 2003
earnings,  our  annual  effective  tax  rate is estimated to be approximately 43
percent  for  2003  on  earnings before non-cash note receivable and other asset
impairments, loss on debt retirements and IPO-related costs. Included in the tax
provision  for  the  nine  months  ended September 30, 2003 was a tax benefit of
$14.6  million attributable to the favorable resolution of a non-U.S. income tax
liability.

     We  previously  reported  that  we  expected  to  begin  making  annual
contributions  to  our  qualified defined benefit pension plans (the "Retirement
Plans")  in  2003  of  approximately  $11  million  and that we expected pension
expense  related  to these plans to increase by approximately $7 million in 2003
as  compared to 2002. Based on the most recent actuarial valuations received, we
are  not  required to make a contribution to the Retirement Plans in 2003. Also,
we  expect  the  required  contribution  to  the  Retirement Plans in 2004 to be
approximately  $5 million and pension expense related to these plans to increase
by  approximately  $1  million in 2003 compared to 2002. Poor performance in the
equity  markets  and  significant  plan  changes  could  result  in  additional
significant  changes  to  the  accumulated other comprehensive loss component of
shareholders'  equity  and  additional  increases  in future pension expense and
funding  requirements.

     We  maintain  a  severance  plan  (the  "Nigeria  Plan"),  which  provides
postretirement  benefits  to  certain  employees under a labor contract with the
Nigeria  labor  unions.  Under  the  Nigeria  Plan provisions, employees receive
postretirement  benefits in the event of retirement, termination for redundancy,
or  death. We made 83 employees redundant effective May 2003. In accordance with
the  provisions  of  the Plan, we paid approximately $2.6 million in termination
benefits in August 2003. Additionally, as a result of these terminations, and in
accordance with the provisions of SFAS 88, Employers' Accounting for Settlements
and  Curtailments of Defined Benefit Pension Plans and for Termination Benefits,
we recorded a plan curtailment gain of $0.8 million, net of a settlement loss of
$0.3  million.

     We  are  engaged  in  negotiations  with the Nigeria labor unions for a new
labor  contract.  We  expect  these  negotiations  to  be resolved in the fourth
quarter of 2003 and to result in the settlement of the entire benefit obligation
and  other negotiated costs, and an amendment to the Nigeria Plan. In accordance
with  SFAS  87,  Employers'  Accounting  for Pensions, the benefit costs accrued
through  the  date  of  the amendment will be amortized over future periods as a
reduction  to  future  benefit costs. We expect the payment of approximately $21
million  in  settlement  of  the  entire benefit obligation and other negotiated
costs  to occur during the fourth quarter of 2003. As a result of the settlement
of  the  Nigeria Plan and the payment of the entire benefit obligation and other
negotiated  costs,  we  expect  to record additional expense up to approximately
$13.0  million  in  the  fourth  quarter  of  2003.

     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, but we are in discussion with our customer regarding the appropriate
dayrate  treatment.  Results  for the three months ended September 30, 2003 were
negatively  impacted by approximately $17 million due to an ongoing disagreement
with  our  customer  concerning  the  applicable  dayrate  and other costs. This
disagreement  has  continued  with respect to operations conducted in the fourth
quarter  and  will likely continue to adversely affect results for that quarter.

     We  are  in  discussions  with  ConocoPhillips concerning their 50 percent
interest  in  DD  LLC,  which  leases the Deepwater Pathfinder under a synthetic
lease financing arrangement. No definitive agreement or terms have been reached,
and  we  or ConocoPhillips may decide to discontinue these discussions. If we do
acquire  the  50  percent interest we do not already own, we would expect to use
cash  on hand and borrowings under available revolving credit facilities for the
purchase.  Even  if  we  do  not  acquire  ConocoPhillips' interest in the joint
venture,  we expect to consolidate DD LLC effective December 31, 2003 (see "-New
Accounting  Pronouncements").

     As  of  September  30, 2003, we had goodwill of approximately $2.2 billion,
all  of which is related to our International and U.S. Floater Contract Drilling
Services  segment.  In  accordance  with  SFAS  142,  we  are  in the process of
conducting  our annual test of goodwill impairment as of October 1 of this year.
Our  stock  price has declined slightly from October 1, 2002 to October 1, 2003,
which  is  an  indicator of a potential impairment of our goodwill. However,


                                       37
<PAGE>
the  amount  of  the impairment, if any, will not be known until we complete our
annual test during the fourth quarter. Any such impairment would affect only our
International and U.S. Floater Contract Drilling Services segment and would have
no  impact  on  our  bank  covenants.

     As  of  October  28,  2003,  approximately 67 percent and 36 percent of our
International  and  U.S.  Floater  Contract Drilling Services segment fleet days
were  committed  for  the remainder of 2003 and for the year 2004, respectively.
For our Gulf of Mexico Shallow and Inland Water segment, which has traditionally
operated  under short-term contracts, committed fleet days were approximately 20
percent  for the remainder of 2003 and 5 percent are currently committed for the
year  2004.

LIQUIDITY  AND  CAPITAL  RESOURCES

<TABLE>
<CAPTION>
     SOURCES  AND  USES  OF  CASH
                                                Nine Months Ended
                                                  September 30,
                                            -------------------------
                                                 2003         2002       Change
                                            --------------  ---------  ----------
                                                          (In millions)
<S>                                         <C>             <C>        <C>
NET CASH PROVIDED BY OPERATING ACTIVITIES
  Net income (loss)                         $         13.7  $ (951.2)  $   964.9
  Depreciation                                       381.1     374.1         7.0
  Other non-cash items                                23.0   1,211.8    (1,188.8)
  Changes in working capital items                    46.8      65.5       (18.7)
                                            --------------  ---------  ----------
                                            $        464.6  $  700.2   $  (235.6)
                                            ==============  =========  ==========
</TABLE>


     Net  cash provided by operating activities decreased during the nine months
ended  September  30,  2003 as compared to the same period in the previous year.
The  decrease was primarily related to a decrease in other non-cash items. Other
non-cash  items  during  the  nine  months  ended  September  30, 2003 consisted
primarily  of  $15.7 million, $21.3 million and $16.8 million related to loss on
retirement  of  debt,  an  impairment  of  notes receivable - related party, and
impairment of long-lived assets, respectively, partially offset by $30.7 million
related  to  deferred  and  other  items.  This compared to other non-cash items
during  the nine months ended September 30, 2002 of a goodwill impairment charge
of  $1,363.7  million,  a $175.7 million foreign tax benefit and a $42.0 million
impairment  of  long-lived  assets partially offset by $18.3 million in deferred
and  other  items.  Cash  provided by changes in working capital items decreased
during  the nine months ended September 30, 2003, as compared to the same period
in  2002  due  to lower revenues resulting in a reduction in accounts receivable
coupled  with  an  increase  in  net  interest  payable, which resulted from the
termination  of  our  interest  rate  swaps in the first quarter of 2003 (see "-
Derivative  Instruments"), partially offset by a decrease in income tax payable.

<TABLE>
<CAPTION>
                                                        Nine Months Ended
                                                          September 30,
                                                      --------------------
                                                          2003      2002    Change
                                                      ----------  --------  -------
                                                               (In millions)
<S>                                                   <C>         <C>       <C>
NET CASH USED IN INVESTING ACTIVITIES
  Capital expenditures                                $   (73.6)  $(114.6)  $ 41.0
  Note issued to related party, net of repayments         (44.2)        -    (44.2)
  Proceeds from disposal of assets                          4.1      73.6    (69.5)
  Acquisition of 40% interest in DDII LLC, net of
     cash aquired                                          18.1         -     18.1
  Other, net                                                2.8       4.6     (1.8)
                                                      ----------  --------  -------
                                                      $   (92.8)  $ (36.4)  $(56.4)
                                                      ==========  ========  =======
</TABLE>

     Net  cash  used in investing activities increased for the nine months ended
September  30,  2003  as  compared  to the same period in the previous year as a
result of the reduction in proceeds from asset sales, which was partially offset
by  the  reduction  in  current  year  capital  expenditures  (see  "-Capital
Expenditures"). A note receivable of $46.1


                                       38
<PAGE>
million was issued to a related party and we acquired ConocoPhillips' 40 percent
interest  in  DDII  LLC  in  May  2003  (see  "-Overview").

<TABLE>
<CAPTION>
                                                            Nine Months Ended
                                                              September 30,
                                                         ----------------------
                                                           2003        2002     Change
                                                         ------------  --------  --------
                                                                  (In millions)
<S>                                                      <C>           <C>       <C>
NET CASH USED IN FINANCING ACTIVITIES
  Repayments under commercial paper program              $         -   $(326.4)  $ 326.4
  Cash received from termination of interest rate swaps        173.5         -     173.5
  Repayments of debt obligations                              (967.2)   (154.3)   (812.9)
  Other, net                                                    14.0     (14.7)     28.7
                                                         ------------  --------  --------
                                                         $    (779.7)  $(495.4)  $(284.3)
                                                         ============  ========  ========
</TABLE>

     We repaid $326.4 million under our commercial paper program during the nine
months  ended September 30, 2002 with no comparable activity for the same period
in  2003.  During the nine months ended September 30, 2003, we received interest
rate  swap  termination  proceeds  of  $173.5  million  (see  "-Derivative
Instruments").  In  2003,  we used cash of $527.2 million to repurchase our Zero
Coupon Convertible Debentures that were put to us in May 2003, $50.0 million for
the early repayment of our 9.41% Nautilus Class A2 Notes, and $390.0 million for
other scheduled debt maturities. This compares to cash paid of $50.6 million for
the  early  repayment  of secured rig financing on the Trident IX and Trident 16
and  $103.7 million for other scheduled debt maturities in 2002. The increase in
cash  provided  in other, net is due to $8.3 million in consent payments in 2002
related to the exchange of our notes for TODCO's notes as well as an increase of
$2.2  million  in  proceeds  from  the  issuance of shares to the Employee Share
Purchase Program. Additionally, dividends of $19.1 million were paid in the nine
months ended September 30, 2002. Payment of dividends was discontinued after the
second  quarter  of  2002.

     CAPITAL  EXPENDITURES

     Capital  expenditures  totaled  $73.6  million during the nine months ended
September 30, 2003. During 2003, we expect to spend approximately $120.0 million
on  our  existing  fleet,  corporate  infrastructure  and  major  upgrades.  A
substantial majority of our expected capital expenditures in 2003 relates to the
International  and U.S. Floater Contract Drilling Services segment. We expect to
incur  capital expenditures of under approximately $100.0 million in 2004 on our
existing fleet, corporate infrastructure and major upgrades. We would expect any
additional  asset  acquisitions  and improved market conditions to affect future
capital  expenditures.

     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  borrowings  under our revolving credit
agreements  and  commercial  paper program (see "-Sources of Liquidity") and may
engage  in  other  commercial  bank  or  capital  market  financings.

     ACQUISITIONS  AND  DISPOSITIONS

     From  time  to  time,  we  review  possible acquisitions or dispositions 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  January  2003,  in our International and U.S. Floater Contract Drilling
Services  segment,  we  completed the sale of a jackup rig, the RBF 160, for net
proceeds  of  $13.0 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  nine  months ended September 30, 2003, we settled an insurance
claim  and  sold  certain  other  assets  for net proceeds of approximately $4.1
million and recorded net gains of $1.9 million ($0.01 per diluted share), net of


                                       39
<PAGE>
tax  of  $0.2  million,  in our International and U.S. Floater Contract Drilling
Services  segment  and  $0.3 million, net of tax of $0.2 million, in our Gulf of
Mexico  Shallow  and  Inland  Water  segment.

     In  November  2003, we purchased the remaining 25 percent minority interest
in the Caspian Sea Ventures International Limited ("CSVI") joint venture that we
did  not  already  own.  CSVI  owns  the  jackup  rig  Trident  20.

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

     SOURCES  OF  LIQUIDITY

     Our primary sources of liquidity in the third quarter of 2003 were our cash
flows  from operations and existing cash balances. The primary uses of cash were
debt  repayment  and  capital expenditures. At September 30, 2003, we had $806.3
million  in  cash  and  cash  equivalents.

     We  anticipate  that we will rely primarily upon existing cash balances and
internally  generated cash flows to maintain liquidity in 2003 and 2004, as cash
flows  from  operations  are expected to be positive and, together with existing
cash  balances,  adequate  to fulfill anticipated obligations. See Note 3 to our
condensed  consolidated financial statements. From time to time, we may also use
bank  lines  of credit and commercial paper to maintain liquidity for short-term
cash  needs.

     We  intend  to  use the proceeds from the IPO, as well as any proceeds from
asset  sales  (see "-Acquisitions and Dispositions"), to further reduce our debt
balances  and  for  general  corporate  purposes.

     We intend to use cash from operations primarily to pay debt as it comes due
and  to  fund  capital  expenditures.  If  we seek to reduce our debt other than
through  scheduled  maturities,  we  could  do  so  through  repayment  of  bank
borrowings  or through repurchases or redemptions of, or tender offers for, debt
securities.  At  September  30,  2003  and December 31, 2002, our total debt was
$3,701.4  million  and  $4,678.0  million,  respectively.  We have significantly
reduced  capital  expenditures  compared to prior years due to the completion of
our  newbuild  program in 2001. During the nine months ended September 30, 2003,
we  reduced  net  debt, defined as total debt less swap receivables and cash and
cash  equivalents,  by  $387.4  million.  The components of net debt at carrying
value  were  as  follows  (in  millions):

<TABLE>
<CAPTION>
                                   September 30,    December 31,
                                       2003             2002
                                 ---------------  --------------
<S>                              <C>              <C>
Total Debt                       $      3,701.4   $     4,678.0
                                 ---------------  --------------
Less: Cash and cash equivalents          (806.3)       (1,214.2)
      Swap receivables                        -          (181.3)
</TABLE>


     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 consistently reduced 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
further,  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.


                                       40
<PAGE>
     We  have access to $800 million in bank lines of credit under two revolving
credit  agreements,  a  364-day  revolving  credit  agreement providing for $250
million  in  borrowings  and expiring in December 2003 and a five-year revolving
credit  agreement  providing  for  $550  million  in  borrowings and expiring in
December  2005.  These  credit lines are used primarily to back our $800 million
commercial  paper program and may also be drawn on directly. As of September 30,
2003,  none of the credit line capacity was utilized. We do not presently intend
to  renew  the $250 million, 364-day credit facility when it expires in December
2003.  Instead,  we  intend  to  renew  the five-year facility during either the
fourth quarter of 2003 or the first quarter of 2004 for an increased capacity of
up  to  $800  million.

     The  bank  credit  lines  require  compliance  with  various  covenants and
provisions  customary  for  agreements  of  this  nature,  including an interest
coverage  ratio and leverage ratio, both as defined by the credit agreements, of
not  less  than  three  to one and not greater than 40 percent, respectively. In
calculating  the  leverage ratio, the credit agreements specifically exclude the
impact on total capital of all fair value adjustments attributable to current or
terminated  interest  rate swaps as well as non-cash goodwill impairment charges
recorded  in  compliance with SFAS 142 (see Note 2 to our condensed consolidated
financial  statements).  Other  provisions  of  the  credit  agreements  include
limitations  on  creating  liens,  incurring debt, transactions with affiliates,
sale/leaseback  transactions  and  mergers and sale of substantially all assets.
Should  we  fail  to comply with these covenants, we would be in default and may
lose  access to these facilities. A loss of the bank facilities would also cause
us  to  lose  access  to  the  commercial  paper markets. We are also subject to
various  covenants  under  the  indentures pursuant to which our public debt was
issued,  including  restrictions  on  creating liens, engaging in sale/leaseback
transactions  and  engaging  in  merger,  consolidation  or  reorganization
transactions.  A default under our public debt could trigger a default under our
credit  lines and cause us to lose access to these facilities. See Note 8 to our
consolidated financial statements in our Annual Report on Form 10-K for the year
ended  December  31,  2002  for  a description of our credit agreements and debt
securities.

     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  other
securities.  At September 30, 2003, $1.6 billion in gross proceeds of securities
remained  unissued  under  the  shelf  registration  statement.

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

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

<TABLE>
<CAPTION>
                               For the twelve months ending September 30,
                         -----------------------------------------------------
                          Total     2004   2005-2006   2007-2008   Thereafter
                         --------  ------  ----------  ----------  -----------
<S>                      <C>       <C>     <C>         <C>         <C>
CONTRACTUAL OBLIGATIONS
Debt                     $3,519.5  $281.5  $    819.0  $    369.0  $   2,050.0
                         ========  ======  ==========  ==========  ===========
</TABLE>

     The  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 as more fully
described  in  Note  8  to  our  consolidated financial statements in our Annual
Report  on  Form  10-K  for  the  year  ended  December  31,  2002.

     We  have  certain  operating leases that have been previously discussed and
reported in our Annual Report on Form 10-K for the year ended December 31, 2002.
There  have  been  no  material  changes  in  these previously reported leases.

      At  September 30, 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


                                       41
<PAGE>
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,  Brazil and Nigeria. 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.  It  should  be  noted that these
obligations  could  be  called  at  any  time  prior  to  the  expiration dates.

     We  currently  expect  to  use  cash on hand and borrowings under available
revolving  credit  facilities  to  repay  our  portion  of  the  debt and equity
financing  with  respect  to  DD  LLC  and  the  related  purchase  option
guarantees-joint  venture  and all of the debt and equity financing with respect
to  DDII  LLC  and  the purchase option guarantees-related party included in the
table  below.

<TABLE>
<CAPTION>
                                                          For the twelve months ending September 30,
                                               ------------------------------------------------------------
                                                    Total        2004    2005-2006    2007-2008  Thereafter
                                                --------------  ------  ----------  ----------  -----------
                                                                        (In millions)
<S>                                             <C>             <C>     <C>         <C>         <C>
OTHER COMMERCIAL COMMITMENTS
Standby Letters of Credit                       $        204.1  $180.3  $      6.0  $     17.8  $         -
Surety Bonds                                             169.8    66.6       103.2           -            -
Purchase Option Guarantees - Related Party (a)           151.8   151.8           -           -            -
Purchase Option Guarantees - Joint Ventures (a)           92.6    92.6           -           -            -
Other Commitments                                          1.2       -         1.2           -            -
                                                --------------  ------  ----------  ----------  -----------
Total                                           $        619.5  $491.3  $    110.4  $     17.8  $         -
                                                ==============  ======  ==========  ==========  ===========
<FN>
____________________________
(a)  See "-Special Purpose Entities, Sale/Leaseback Transaction and Related Party Transactions".
</TABLE>

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.

     As  more  fully described in Note 6 to our condensed consolidated financial
statements,  we  were a party to interest rate swap agreements with an aggregate
notional  amount  of  $1.6  billion  at  December  31, 2002. We terminated these
agreements  during the first quarter of 2003. As a result of these terminations,
we  had  an  aggregate  fair  value  adjustment  of approximately $173.5 million
included in long-term debt in our condensed consolidated balance sheet, which is
being  recognized  as  a  reduction  to  interest  expense  over the life of the
underlying  debt.

     DD  LLC,  an  unconsolidated  joint  venture  in which we have a 50 percent
ownership  interest,  entered  into  interest  rate swaps in August 1998 with an
expiration  date  of  October 2003 that had aggregate market values netting to a
liability of $0.7 million at September 30, 2003. Our interest in these swaps has
been  included  in  accumulated  other  comprehensive  income,  net of tax, with
corresponding  reductions  to  deferred  income  taxes  and  investments  in and
advances  to  joint ventures in our condensed consolidated balance sheet.  These
swaps  terminated  on  October  31,  2003.

SPECIAL  PURPOSE  ENTITIES,  SALE/LEASEBACK  TRANSACTION  AND  RELATED  PARTY
TRANSACTIONS

     We  have  transactions  with  certain  special purpose entities and related
parties  and  we are a party to a sale/leaseback transaction. These transactions
have  been  previously  discussed and reported in our Annual Report on Form 10-K
for  the  year  ended  December  31,  2002.


                                       42
<PAGE>
      In  January  2003,  Delta  Towing  failed  to make its scheduled quarterly
interest  payment of $1.7 million on the notes receivable and we signed a 90-day
waiver  of  the terms requiring payment of interest. In April 2003, Delta Towing
again failed to make its interest payment of $1.7 million originally due January
2003  after  expiration of the 90-day waiver. In April 2003 and July 2003, Delta
Towing  also  failed to make additional scheduled quarterly interest payments of
$1.6  million  and  $1.7  million,  respectively.  During  the nine months ended
September  30, 2003, we received partial interest payments of approximately $1.0
million  and  $1.1  million  of  payments applied to principal on the three-year
revolving  credit  facility.  At  September 30, 2003, we had interest receivable
from  Delta  Towing  of approximately $4.0 million. As a result of our continued
evaluation  of  the  collectibility  of  the  Delta Towing notes, we recorded an
impairment  on  the notes receivable of $13.8 million ($0.04 per diluted share),
net  of  tax  of $7.5 million, in the second quarter of 2003 as an allowance for
credit  losses.  We  based the impairment on Delta Towing's discounted projected
cash  flows over the term of the notes, which deteriorated in the second quarter
of 2003 as a result of the continued decline in Delta Towing's business outlook.
The amount of the notes receivable outstanding prior to the impairment was $82.8
million.  At  September  30,  2003,  the  carrying value of the notes receivable
included  in  investments  in  and  advances  to joint ventures in our condensed
consolidated  balance sheets, net of the related allowance for credit losses and
equity  losses  in  the  joint venture, was $53.6 million. In September 2003, we
established  a  reserve  of  $1.6  million for interest income earned during the
third  quarter  on  the  notes  receivable  and  will continue to reserve future
interest income earned until the scheduled quarterly interest payments have been
brought  current.  We  will apply cash payments to interest receivable currently
outstanding  and  then  to  interest  income  for  which  a  reserve  has  been
established.

     DDII LLC is the lessee in a synthetic lease financing facility entered into
in  connection with the construction of the drillship Deepwater Frontier. In May
2003,  WestLB  AG, one of the lenders in the synthetic lease financing facility,
assigned  its  $46.1  million  remaining  promissory  note  receivable  to us in
exchange for cash. As a result of this assignment, we assumed all the rights and
obligations  of  WestLB  AG.  At  September  30,  2003,  the balance of the note
receivable  was  $44.2  million  and was recorded as other current assets in our
condensed  consolidated  balance  sheets.

     Also  in May 2003, but subsequent to the WestLB AG assignment, we purchased
ConocoPhillips' 40 percent interest in DDII LLC for approximately $5 million. As
a  result  of  this  purchase, we consolidated DDII LLC in the second quarter of
2003.  In  addition,  we  acquired  certain  drilling  and  other contracts from
ConocoPhillips  for  approximately  $9  million.  See  "-New  Accounting
Pronouncements."

     There  have been no other material developments with regards to the special
purpose  entity  related  to  DD  LLC,  the  sale/leaseback transaction or other
related  party  transactions.

NEW  ACCOUNTING  PRONOUNCEMENTS

          In  January 2003, the FASB issued Interpretation No. 46, Consolidation
of Variable Interest Entities, an Interpretation of Accounting Research Bulletin
No.  51 (the "Interpretation"). The Interpretation 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 the Interpretation are effective
immediately for those variable interest entities created after January 31, 2003.
The provisions, as amended, 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.  We  will  adopt  the Interpretation and consolidate our
variable  interest  entities  as  required  on  December 31, 2003. Currently, we
generally  consolidate  an  entity  when  we have a controlling interest through
ownership  of  a  majority  voting  interest  in  the  entity.

     We  have  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 assets serve as
collateral  for our notes receivable. The carrying value of the notes receivable
included  in  investments  in  and  advances  to joint ventures in our condensed
consolidated  balance sheets was $53.6 million, net of the related allowance for
credit  losses  and  equity  losses in the joint venture, at September 30, 2003.
Delta  Towing  also  issued  a $3.0 million note to the 75 percent joint


                                       43
<PAGE>
venture  partner.  Because  we have the largest percentage of investment at risk
through  the  notes  receivable  and  Delta Towing's equity is not sufficient to
absorb  its expected losses, we would absorb the majority of the joint venture's
expected losses; therefore, we are deemed to be the primary beneficiary of Delta
Towing  for  accounting  purposes.  As  such,  we  will consolidate Delta Towing
effective  December  31, 2003. While we expect the consolidation of Delta Towing
to  result  in  an increase in net assets of approximately $1.0 million based on
balances  at  September  30,  2003,  the  expected  amounts may be adjusted upon
consolidation  at  December  31,  2003 with application of the provisions of the
Interpretation.

     We  have  a 50 percent ownership interest in DD LLC. DD LLC was established
for  the  purpose  of  constructing  and  contracting  the  drillship  Deepwater
Pathfinder.  The  drillship  was  purchased  by  a trust that was established to
finance  the  purchase  through  debt  and  equity  financing  and  to lease the
drillship  back  to  DD LLC through a synthetic lease financing arrangement with
the  drillship serving as collateral. The balance of the trust's debt and equity
financing  was approximately $189.7 million at September 30, 2003. The scheduled
expiration  of  the lease is January 2004, at which time DD LLC may purchase the
drillship  from  the  trust  for  approximately  $185  million. DD LLC currently
intends  to  exercise  its  purchase  option  early  in December 2003. While the
operations  of  DD  LLC  are  funded by cash flows from operating activities, we
guarantee,  under  certain  circumstances,  the debt and equity financing on the
leased  drillship  equally  with  our  joint venture partner. We have determined
through  application of the provisions of the Interpretation for determining the
primary  beneficiary  that  we are deemed to be DD LLC's primary beneficiary for
accounting purposes and will consolidate the entity effective December 31, 2003.
While  we  expect  the  consolidation  of DD LLC to result in an increase in net
assets  of  approximately  $116 million based on balances at September 30, 2003,
the  expected  amounts  may  be adjusted upon consolidation at December 31, 2003
with  application  of  the  provisions  of  the  Interpretation.  As  previously
discussed  (see  "-Outlook"),  we  are  in  negotiations  with ConocoPhillips to
purchase their 50 percent interest in the joint venture. If we are successful in
buying  ConocoPhillips'  interest  in  DD  LLC  prior  to December 31, 2003, the
provisions  of the Interpretation would not apply as we would consolidate DD LLC
as  a  wholly-owned  subsidiary. We would then expect consolidation of DD LLC to
result  in  an  increase  in  net  assets  of  approximately  $208  million.

     We  have  investments  in  and  advances to four additional joint ventures.
These  remaining  four joint ventures were primarily established for the purpose
of  owning and operating certain drilling units and are funded primarily by cash
flows from operating activities. Based on our initial assessment, these entities
would  not  be  deemed  variable  interest entities under the Interpretation. We
expect  to  complete our analysis of these entities during the fourth quarter of
2003.We currently account for our investments in joint ventures using the equity
method  of  accounting, recording our share of the net income or loss based upon
the  terms of the joint venture agreements. Because we have a 50 percent or less
ownership  interest  in  these  joint  ventures,  we  do  not have a controlling
interest  in  the  joint  ventures  nor  do  we  have  the  ability  to exercise
significant  influence  over  operating  and  financial  policies.

     Our wholly owned subsidiary, DDII LLC was originally established as a joint
venture  with a subsidiary of ConocoPhillips for the purpose of constructing and
contracting  the  drillship Deepwater Frontier. The drillship was purchased by a
trust  that  was  established  to  finance  the purchase through debt and equity
financing  and to lease the drillship back to DDII LLC through a synthetic lease
financing  arrangement  with the drillship serving as collateral. The balance of
the  trust's  debt  and equity financing at September 30, 2003 was approximately
$158.0  million, net of a note receivable - related party (see "-Special Purpose
Entities,  Sale/Leaseback  Transaction  and Related Party Transactions"). On May
29,  2003,  we  purchased  ConocoPhillips'  40 percent interest in DDII LLC.  We
currently  account  for DDII LLC's lease of the drillship as an operating lease.
As  a result of our purchase of ConocoPhillips' 40 percent interest in DDII LLC,
we,  under certain circumstances, fully guarantee the debt and equity financing.
Because  we are at risk for the full amount of the debt and equity financing, we
are  deemed  to  be the primary beneficiary of the trust for accounting purposes
and  expect  to  consolidate  the  trust  effective December 31, 2003.  While we
expect  the consolidation of the trust to result in an increase in net assets of
approximately  $27 million based on balances at September 30, 2003, the expected
amounts may be adjusted upon consolidation at December 31, 2003 with application
of  the  provisions  of  the  Interpretation.

     In  addition  to  the  joint  ventures and DDII LLC discussed above, we are
party  to a sale/leaseback transaction for the semisubmersible drilling rig M.G.
Hulme, Jr. with an unrelated third party. 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


                                       44
<PAGE>
approximately  $35.7  million. We are currently evaluating whether the unrelated
third party lessor is a variable interest entity and, if so, who would be deemed
to  be  the  primary  beneficiary.  We  currently  account for the lease of this
drilling  rig  as  an  operating  lease.

     We  are currently evaluating the cumulative effect of the accounting change
on  our  results  of  operations that will result from the implementation of the
Interpretation.

     Effective January 2003, we implemented EITF 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 our customers on a reimbursable basis
are  recognized  as  operating and maintenance expense. In addition, the amounts
billed  to  our  customers  associated  with  these reimbursable costs are being
recognized  as  client  reimbursable  revenue.  We  expect  client  reimbursable
revenues  and  operating  and  maintenance expense to be between $90 million and
$110  million in 2003 as a result of implementation of EITF 99-19. The change in
accounting  principle  will  have  no  effect  on  our  results of operations or
consolidated  financial  position.  Prior periods have not been reclassified, as
these  amounts  were  not  material.

     In  May  2003,  the  FASB issued SFAS 150, Accounting for Certain Financial
Instruments  with  Characteristics of both Liabilities and Equity. The statement
clarifies  the accounting for certain financial instruments that, under previous
guidance, issuers could account for as equity. This statement requires an issuer
to measure and classify as liabilities, or assets in some circumstances, certain
classes  of  freestanding  financial instruments that embody obligations for the
issuer. In addition to its requirement for the classification and measurement of
financial  instruments  in  its  scope, SFAS 150 also requires disclosures about
alternative ways of settling the instruments and the identity of the entity that
controls  the settlement alternatives. This statement is effective for financial
instruments  entered  into  or  modified  after  May  31, 2003, and otherwise is
effective  at the beginning of the first interim period beginning after June 15,
2003.  We  adopted  this  statement effective July 1, 2003. The adoption of this
statement  did not have a material effect on our consolidated financial position
or  results  of  operations.

FORWARD-LOOKING  INFORMATION

     The statements included in this quarterly 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 quarterly report include, but are
not  limited  to,  statements  involving  payment  of severance costs, potential
revenues,  increased expenses, the effect on revenues and expenses of the change
in  accounting  treatment  for  client  reimbursables, client drilling programs,
supply  and  demand,  utilization  rates,  dayrates,  planned shipyard projects,
expected  downtime,  opportunities  for deepwater rigs in India, West Africa and
other  emerging  locations,  oversupply in the global mid-water sector, expected
North  Sea utilization, outlook for the deepwater sector, oversupply in the West
Africa  jackup  market sector, activity in India and Mexico, market outlooks for
our  various  geographical operating sectors, the non-U.S. jackup market sector,
future  activity  in  the  International  and  U.  S.  Floater Contract Drilling
Services and Gulf of Mexico Shallow and Inland Water segments, expected deep gas
drilling  interest  in  the  Gulf  of  Mexico,  the  expected charge relating to
termination  of the Nigerian severance plan, expected resolution of negotiations
with  the  Nigeria  labor unions regarding a new labor contract, the outcome and
effect  of  the  U.S.  Internal  Revenue  Service  audit  and  the  various  tax
assessments,  deferred  costs, amortization expense, the planned IPO of our Gulf
of  Mexico  Shallow  and  Inland  Water  business  (including  the timing of the
offering,  portion  sold  and  expected  use of proceeds), the U.S. gas drilling
market,  planned  asset  sales,  the Company's other expectations with regard to
market  outlook,  the  effect  of  our  disagreement  relating to the Discoverer
Enterprise,  the  purchase  of  the  DD LLC interest, an impairment to goodwill,
expected capital expenditures, expected funding of capital expenditures, results
and  effects  of  legal  proceedings,  liabilities  for  tax  issues, liquidity,
intention  not  to renew the Company's 364-day credit facility, expected renewal
of  the Company's five-year credit facility, positive cash flow from operations,
repayment  of  debt  and  equity financings with respect to DD LLC and DDII LLC,
receipt  of  principal and interest on debt owed to the Company by Delta Towing,
effects  of  the  consolidation  of  Delta  Towing,


                                       45
<PAGE>
DD  LLC  and  DDII  LLC,  adequacy of cash flow for 2003 obligations, effects of
accounting  changes,  impact of consolidation of variable interest entities, and
the  timing  and  cost  of  completion  of capital projects. Such statements are
subject  to  numerous  risks,  uncertainties and assumptions, including, but not
limited  to,  worldwide  demand  for  oil and gas, uncertainties relating to the
level  of  activity  in  offshore  oil  and  gas  exploration  and  development,
exploration success by producers, oil and gas prices (including U.S. natural gas
prices),  securities  market  conditions,  demand  for offshore and inland water
rigs,  competition  and market conditions in the contract drilling industry, our
ability  to successfully integrate the operations of acquired businesses, delays
or  terminations of drilling contracts due to a number of events, delays or cost
overruns  on  construction  and  shipyard  projects and possible cancellation of
drilling  contracts  as  a result of delays or performance, our ability to enter
into and the terms of future contracts, the availability of qualified personnel,
labor  relations  and  the  outcome  of  negotiations  with  unions representing
workers,  operating  hazards,  political  and  other  uncertainties  inherent in
non-U.S.  operations  (including  exchange  and currency fluctuations), risks of
war, terrorism and cancellation or unavailability of certain insurance coverage,
the  impact  of  governmental  laws  and regulations, the adequacy of sources of
liquidity,  the  effect  and results of litigation, audits and contingencies and
other  factors  discussed  in  our Annual Report on Form 10-K for the year ended
December  31,  2002  and  in the Company's other filings with the SEC, which are
available free of charge on the SEC's website at www.sec.gov. Should one or more
of  these  risks  or uncertainties materialize, or should underlying assumptions
prove  incorrect,  actual  results may vary materially from those indicated. You
should  not  place  undue  reliance  on  forward-looking  statements.  Each
forward-looking  statement  speaks  only  as  of  the  date  of  the  particular
statement,  and  we  undertake  no  obligation  to publicly update or revise any
forward-looking  statements.


                                       46
<PAGE>
ITEM  3.  QUANTITATIVE  AND  QUALITATIVE  DISCLOSURES  ABOUT  MARKET  RISK

INTEREST  RATE  RISK

     Our exposure to market risk for changes in interest rates relates primarily
to  our  long-term  and  short-term  debt  obligations. The table below presents
scheduled  debt  maturities and related weighted-average interest rates for each
of  the twelve-month periods ending September 30 relating to debt obligations as
of  September 30, 2003. Weighted-average variable rates are based on LIBOR rates
in  effect  at  September  30,  2003,  plus  applicable  margins.

     At  September  30,  2003  (in  millions, except interest rate percentages):

<TABLE>
<CAPTION>
                                          Scheduled Maturity Date (a) (b)                         Fair Value
                            --------------------------------------------------------------------  ----------
                             2004     2005     2006     2007     2008     Thereafter     Total    09/30/03
                            -------  -------  -------  -------  -------  ------------  ---------  ----------
<S>                         <C>      <C>      <C>      <C>      <C>      <C>           <C>        <C>
Total debt
  Fixed Rate                $131.5   $381.5   $400.0   $100.0   $269.0   $   2,050.0   $3,332.0   $  3,753.7
     Average interest rate     8.5%     6.8%     1.5%     7.5%     6.7%          7.5%       6.7%
  Variable Rate             $150.0   $ 37.5        -        -        -             -     $187.5   $    187.5
     Average interest rate     1.7%     1.7%       -        -        -             -        1.7%
<FN>
__________________________
(a)  Maturity dates of the face value of our debt assumes the put options on 1.5% Convertible Debentures,
     7.45% Notes and the 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.
</TABLE>

     At September 30, 2003, we had approximately $187.5 million of variable rate
debt  at  face  value  (approximately five percent of total debt at face value).
This variable rate debt represented term bank debt. Given outstanding amounts as
of that date, a one percent rise in interest rates would result in an additional
$1.5  million in interest expense per year. Offsetting this, a large part of our
cash  investments  would  earn  commensurately  higher  rates  of  return. Using
September  30,  2003  cash investment levels, a one percent increase in interest
rates  would  result in approximately $8.1 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 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  September  30,  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. Our drilling contracts in Venezuela typically call for
payments  to  be made in local currency, even when the dayrate is denominated in
U.S.  dollars.  The  exchange controls could also result in an artificially high
value  being  placed on the local currency. 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.


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<PAGE>
ITEM  4.  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  September  30,  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  September  30,  2003 that has
materially  affected, or is reasonably likely to materially affect, our internal
controls  over  financial  reporting.


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<PAGE>
PART  II  -  OTHER  INFORMATION

ITEM  1.  LEGAL  PROCEEDINGS

     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 a labor
contractor  for us, 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  have  certain other actions or claims pending that have been previously
discussed  and  reported  in  our  Annual Report on Form 10-K for the year ended
December  31,  2002 and our other reports filed with the Securities and Exchange
Commission.  There  have  been  no  material  developments  in  these previously
reported  matters.  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.  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.


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<PAGE>
ITEM  6.  EXHIBITS  AND  REPORTS  ON  FORM  8-K

     (a)     Exhibits

The  following  exhibits  are  filed  in  connection  with  this  Report:

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

*3.1  Memorandum  of Association of Transocean 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 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  Amendment No. 1, dated December 27, 2001, to the Credit Agreement dated as
      of  December  29,  2000  among  the  Company,  the  Lenders party thereto,
      Suntrust  Bank,  Administrative Agent, ABN AMRO Bank, N.V., as Syndication
      Agent, Bank of America, N.V., as Documentation Agent, and Wells Fargo Bank
      Texas,  National  Association,  as  Senior  Managing  Agent

+4.2  Amendment No. 2, dated December 26, 2002, to the Credit Agreement dated as
      of  December  29,  2000  among  the  Company,  the  Lenders party thereto,
      Suntrust  Bank,  Administrative Agent, ABN AMRO Bank, N.V., as Syndication
      Agent, Bank of America, N.V., as Documentation Agent, and Wells Fargo Bank
      Texas,  National  Association,  as  Senior  Managing  Agent

+4.3  Amendment No. 1, dated December 27, 2001, to the Credit Agreement dated as
      of  December  16,  1999  among Transocean Offshore Inc., the Lenders party
      thereto,  and  Suntrust  Bank,  Atlanta,  as  Agent

+4.4  Amendment No. 2, dated December 26, 2002, to the Credit Agreement dated as
      of  December  16,  1999  among Transocean Offshore Inc., the Lenders party
      thereto,  and  Suntrust  Bank,  Atlanta,  as  Agent


+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
_________________________
*  Incorporated  by  reference  as  indicated.
+  Filed  herewith.

     (b)     Reports  on  Form  8-K

     The  Company  filed  a  Current  Report  on  Form  8-K  on  July  23,  2003
(information  furnished  not  filed)  announcing the issuance of expected second
quarter  2003  financial  results, a Current Report on Form 8-K on July 29, 2003
(information furnished not filed) announcing the issuance of second quarter 2003
financial  results  and  a  Current  Report  on  Form  8-K  on  August  11, 2003
(information furnished not filed) announcing financial information in connection
with  presentations  being  made  by  officers  of  the  Company.


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<PAGE>
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,  hereunto  duly  authorized, on November 12, 2003.

TRANSOCEAN  INC.


By:  /s/  Gregory  L.  Cauthen
     --------------------------
     Gregory  L.  Cauthen
     Senior  Vice  President  and  Chief  Financial  Officer
     (Principal  Financial  Officer)

By:  /s/  Brenda  S.  Masters
     -------------------------
     Brenda  S.  Masters
     Vice  President  and  Controller
     (Principal  Accounting  Officer)


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<PAGE>