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 JUNE 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  July  31,  2003,  319,887,560  ordinary shares, par value $0.01 per
share,  were  outstanding.
================================================================================


<PAGE>
<TABLE>
<CAPTION>
                                 TRANSOCEAN INC.

                               INDEX TO FORM 10-Q

                           QUARTER ENDED JUNE 30, 2003

                                                                                Page
                                                                                ----
<S>           <C>                                                               <C>

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

     ITEM 1.  Financial Statements (Unaudited)

              Condensed Consolidated Statements of Operations
                Three and Six Months Ended June 30, 2003 and 2002. . . . . . . .    2

              Condensed Consolidated Statements of Comprehensive Income (Loss)
                Three and Six Months Ended June 30, 2003 and 2002. . . . . . . .    3

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

              Condensed Consolidated Statements of Cash Flows
                Six Months Ended June 30, 2003 and 2002. . . . . . . . . . . . .    5

              Notes to Condensed Consolidated Financial Statements . . . . . . .    7

     ITEM 2.  Management's Discussion and Analysis of Financial
              Condition and Results of Operations. . . . . . . . . . . . . . . .   21

     ITEM 3.  Quantitative and Qualitative Disclosures about Market Risk . . . .   44

     ITEM 4.  Controls and Procedures. . . . . . . . . . . . . . . . . . . . . .   45

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

     ITEM 1.  Legal Proceedings. . . . . . . . . . . . . . . . . . . . . . . . .   46

     ITEM 4.  Submission of Matters to a Vote of Security Holders. . . . . . . .   46

     ITEM 6.  Exhibits and Reports on Form 8-K . . . . . . . . . . . . . . . . .   48
</TABLE>


<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 June 30,      Six Months Ended June 30,
                                                            -------------------------------  -----------------------------
                                                                 2003            2002            2003           2002
                                                            --------------  ---------------  ------------  ---------------
<S>                                                         <C>             <C>              <C>           <C>
Operating Revenues
  Contract drilling revenues                                $       576.6   $        646.2   $   1,166.2   $      1,314.1
  Client reimbursable revenues                                       27.3                -          53.7                -
--------------------------------------------------------------------------------------------------------------------------
                                                                    603.9            646.2       1,219.9          1,314.1
--------------------------------------------------------------------------------------------------------------------------
Costs and Expenses
  Operating and maintenance                                         426.5            365.6         800.6            746.6
  Depreciation                                                      127.5            124.3         254.3            249.9
  General and administrative                                         14.9             16.0          28.8             35.8
  Impairment loss on long-lived assets                               15.8                -          16.8              1.1
  (Gain) loss from sale of assets, net                               (0.6)             1.3          (2.0)            (0.6)
--------------------------------------------------------------------------------------------------------------------------
                                                                    584.1            507.2       1,098.5          1,032.8
--------------------------------------------------------------------------------------------------------------------------

Operating Income                                                     19.8            139.0         121.4            281.3

Other Income (Expense), net
  Equity in earnings of joint ventures                                1.8              2.5           5.4              4.4
  Interest income                                                     5.8              5.7          12.7              9.9
  Interest expense                                                  (52.8)           (52.5)       (105.4)          (108.4)
  Loss on retirement of debt                                        (15.7)               -         (15.7)               -
  Loss on impairment of note receivable from related party          (21.3)               -         (21.3)               -
  Other, net                                                         (2.7)            (0.4)         (3.3)            (1.1)
--------------------------------------------------------------------------------------------------------------------------
                                                                    (84.9)           (44.7)       (127.6)           (95.2)
--------------------------------------------------------------------------------------------------------------------------
Income (Loss) Before Income Taxes, Minority Interest and
  Cumulative Effect of a Change in Accounting Principle             (65.1)            94.3          (6.2)           186.1
Income Tax Expense (Benefit)                                        (20.8)            13.9          (9.0)            27.7
Minority Interest                                                     0.2              0.4           0.1              1.1
--------------------------------------------------------------------------------------------------------------------------

Net Income (Loss) Before Cumulative Effect of a Change in
  Accounting Principle                                              (44.5)            80.0           2.7            157.3
Cumulative Effect of a Change in Accounting Principle                   -                -             -         (1,363.7)
--------------------------------------------------------------------------------------------------------------------------

Net Income (Loss)                                           $       (44.5)  $         80.0   $       2.7   $     (1,206.4)
==========================================================================================================================

Basic Earnings (Loss) Per Share
  Income (Loss) Before Cumulative Effect of a Change in
    Accounting Principle                                    $       (0.14)  $         0.25   $      0.01   $         0.49
  Loss on Cumulative Effect of a Change in Accounting
    Principle                                                           -                -             -            (4.27)
--------------------------------------------------------------------------------------------------------------------------
   Net Income (Loss)                                        $       (0.14)  $         0.25   $      0.01   $        (3.78)
==========================================================================================================================

Diluted Earnings (Loss) Per Share
  Income (Loss) Before Cumulative Effect of a Change in     $       (0.14)  $         0.25   $      0.01   $         0.49
    Accounting Principle
  Loss on Cumulative Effect of a Change in   Accounting
    Principle                                                           -                -             -            (4.22)
--------------------------------------------------------------------------------------------------------------------------
   Net Income (Loss)                                        $       (0.14)  $         0.25   $      0.01   $        (3.73)
==========================================================================================================================


Weighted Average Shares Outstanding
  Basic                                                             319.8            319.1         319.7            319.1
--------------------------------------------------------------------------------------------------------------------------
  Diluted                                                           319.8            323.9         321.5            323.6
--------------------------------------------------------------------------------------------------------------------------


Dividends Paid per Share                                    $           -   $         0.03   $         -   $         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 June 30,     Six Months Ended June 30,
                                                              -------------------------------  -----------------------------
                                                                   2003            2002            2003           2002
                                                              --------------  ---------------  ------------  ---------------
<S>                                                           <C>             <C>              <C>           <C>

Net income (loss)                                             $       (44.5)  $         80.0   $       2.7   $     (1,206.4)
----------------------------------------------------------------------------------------------------------------------------
Other comprehensive income (loss), net of tax
  Amortization of gain on terminated interest rate swaps               (0.1)               -          (0.1)            (0.1)
  Change in unrealized loss on securities available for sale            0.2                -           0.2              0.1
  Change in share of unrealized loss in unconsolidated
    joint venture's interest rate swaps                                 1.4             (1.0)          1.1              2.1
  Minimum pension liability adjustments                                 0.1                -           0.8                -
----------------------------------------------------------------------------------------------------------------------------
Other comprehensive income (loss)                                       1.6             (1.0)          2.0              2.1
----------------------------------------------------------------------------------------------------------------------------
Total comprehensive income (loss)                             $       (42.9)  $         79.0   $       4.7   $     (1,204.3)
============================================================================================================================
</TABLE>


                             See accompanying notes.
                                        3
<PAGE>
<TABLE>
<CAPTION>
                                 TRANSOCEAN INC. AND SUBSIDIARIES
                               CONDENSED CONSOLIDATED BALANCE SHEETS
                                            (In millions)
                                             (Unaudited)



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

                                               ASSETS

<S>                                                                   <C>           <C>
Cash and Cash Equivalents                                             $     714.0   $     1,214.2
Accounts Receivable, net of allowance for doubtful accounts of $19.8
    and $20.8 at June 30, 2003 and December 31, 2002, respectively          442.3           499.3
Materials and Supplies, net of allowance for obsolescence of $18.6          160.0           155.8
    at June 30, 2003 and December 31, 2002
Deferred Income Taxes                                                        19.7            21.9
Other Current Assets                                                         91.0            20.5
--------------------------------------------------------------------------------------------------
    Total Current Assets                                                  1,427.0         1,911.7
--------------------------------------------------------------------------------------------------


Property and Equipment                                                   10,196.5        10,198.0
Less Accumulated Depreciation                                             2,413.8         2,168.2
--------------------------------------------------------------------------------------------------
    Property and Equipment, net                                           7,782.7         8,029.8
--------------------------------------------------------------------------------------------------


Goodwill, net                                                             2,222.9         2,218.2
Investments in and Advances to Joint Ventures                                68.3           108.5
Deferred Income Taxes                                                        26.2            26.2
Other Assets                                                                178.7           370.7
--------------------------------------------------------------------------------------------------
    Total Assets                                                      $  11,705.8   $    12,665.1
==================================================================================================


                              LIABILITIES AND SHAREHOLDERS' EQUITY

Accounts Payable                                                      $     140.0   $       134.1
Accrued Income Taxes                                                         64.4            59.5
Debt Due Within One Year                                                    282.3         1,048.1
Other Current Liabilities                                                   239.2           262.2
--------------------------------------------------------------------------------------------------
    Total Current Liabilities                                               725.9         1,503.9
--------------------------------------------------------------------------------------------------

Long-Term Debt                                                            3,476.0         3,629.9
Deferred Income Taxes                                                        50.7           107.2
Other Long-Term Liabilities                                                 291.7           282.7
--------------------------------------------------------------------------------------------------
    Total Long-Term Liabilities                                           3,818.4         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,              3.2             3.2
    319,853,774 and 319,219,072 shares issued and outstanding at
    June 30, 2003 and December 31, 2002, respectively
Additional Paid-in Capital                                               10,638.5        10,623.1
Accumulated Other Comprehensive Loss                                        (29.5)          (31.5)
Retained Deficit                                                         (3,450.7)       (3,453.4)
--------------------------------------------------------------------------------------------------
    Total Shareholders' Equity                                            7,161.5         7,141.4
--------------------------------------------------------------------------------------------------
    Total Liabilities and Shareholders' Equity                        $  11,705.8   $    12,665.1
==================================================================================================
</TABLE>


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



                                                                         Six Months Ended
                                                                             June 30,
                                                                      ----------------------
                                                                        2003        2002
                                                                      ---------  -----------
<S>                                                                   <C>        <C>
CASH FLOWS FROM OPERATING ACTIVITIES
  Net income (loss)                                                   $    2.7   $ (1,206.4)
  Adjustments to reconcile net income (loss) to
   net cash provided by operating activities
    Depreciation                                                         254.3        249.9
    Impairment loss on goodwill                                              -      1,363.7
    Stock-based compensation expense                                       2.9          0.4
    Deferred income taxes                                                (59.5)       (38.3)
    Equity in earnings of joint ventures                                  (5.4)        (4.4)
    Net loss from disposal of assets                                       7.8          2.3
    Loss on retirement of debt                                            15.7            -
    Impairment loss on long-lived assets                                  16.8          1.1
    Impairment of note receivable from related party                      21.3            -
    Amortization of debt-related discounts/premiums, fair value           (7.9)         2.9
     adjustments and issue costs, net
    Deferred income, net                                                  (1.6)        (6.0)
    Deferred expenses, net                                                 2.7          7.0
    Other, net                                                            13.5          9.3
    Changes in operating assets and liabilities
      Accounts receivable                                                 51.6         84.1
      Accounts payable and other current liabilities                       4.0        (84.7)
      Income taxes receivable/payable, net                                 9.6         22.3
      Other current assets                                               (23.3)       (22.7)
--------------------------------------------------------------------------------------------
Net Cash Provided by Operating Activities                                305.2        380.5
--------------------------------------------------------------------------------------------


CASH FLOWS FROM INVESTING ACTIVITIES
  Capital expenditures                                                   (50.2)       (81.2)
  Note issued to related party, net of repayments                        (45.3)           -
  Proceeds from disposal of assets, net                                    3.2         65.0
  Acquisition of 40 percent interest in Deepwater Drilling II L.L.C.,     18.1            -
   net of cash acquired
  Joint ventures and other investments, net                                2.2            -
--------------------------------------------------------------------------------------------
Net Cash Used in Investing Activities                                    (72.0)       (16.2)
--------------------------------------------------------------------------------------------
</TABLE>


                             See accompanying notes.
                                        5
<PAGE>
<TABLE>
<CAPTION>
                        TRANSOCEAN INC. AND SUBSIDIARIES
                 CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
                                  (In millions)
                                   (Unaudited)



                                                        Six Months Ended
                                                            June 30,
                                                     ----------------------
                                                       2003        2002
                                                     ---------  -----------
<S>                                                  <C>        <C>
CASH FLOWS FROM FINANCING ACTIVITIES
  Repayments under commercial paper program                 -       (326.4)
  Repayments on other debt instruments                 (919.2)      (119.6)
  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                       11.7         10.3
  Dividends paid                                            -        (19.1)
  Financing costs                                        (0.1)        (8.1)
  Other, net                                             (0.5)         1.1
---------------------------------------------------------------------------
Net Cash Used in Financing Activities                  (733.4)      (461.8)
---------------------------------------------------------------------------

Net Decrease in Cash and Cash Equivalents              (500.2)       (97.5)
---------------------------------------------------------------------------
Cash and Cash Equivalents at Beginning of Period      1,214.2        853.4
---------------------------------------------------------------------------
Cash and Cash Equivalents at End of Period           $  714.0   $    755.9
===========================================================================
</TABLE>


                             See accompanying notes.
                                        6
<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  June  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
six  months  ended  June  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  that  are  believed  to  be reasonable under the circumstances, the
results  of  which form the basis for making judgments about the carrying values
of  assets  and  liabilities  that  are not readily apparent from other sources.
Actual  results  could  differ  from  such  estimates.

     SUPPLEMENTARY CASH FLOW INFORMATION - Cash payments for interest and income
taxes,  net,  were  $106.1  million and $40.9 million, respectively, for the six
months  ended  June 30, 2003 and $109.8 million and $44.2 million, respectively,
for  the  six  months  ended  June  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,


                                        7
<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) 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 June 30, 2003. The
changes  in  the carrying amount of goodwill as of June 30, 2003 were as follows
(in  millions):

<TABLE>
<CAPTION>
                                                           Balance at               Balance at
                                                           January 1,                June 30,
                                                              2003      Other (a)      2003
                                                           -----------  ----------  -----------
<S>                                                        <C>          <C>         <C>
International and U.S. Floater Contract Drilling Services  $   2,218.2  $      4.7  $   2,222.9

<FN>
_________________
(a)  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.


                                        8
<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 June 30, 2003 and December 31, 2002 are as
follows  (in  millions):

<TABLE>
<CAPTION>
                                                Unrealized         Other
                                  Gain on        Loss on       Comprehensive
                                Terminated      Available-    Loss Related to     Minimum      Total 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)
  Other comprehensive income            (0.1)          0.2                1.1          0.8              2.0
    (loss), net of tax
                              ---------------  ------------  -----------------  -----------  ---------------
Balance at June 30, 2003      $          3.5   $      (0.4)  $           (0.9)  $    (31.7)  $        (29.5)
                              ===============  ============  =================  ===========  ===============
</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
clients.  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.


                                        9
<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        Six Months Ended
                                                                             June 30,                 June 30,
                                                                     ------------------------  ----------------------
                                                                        2003         2002         2003        2002
                                                                     -----------  -----------  ----------  ----------
<S>                                                                  <C>          <C>          <C>         <C>
Net Income (Loss) as Reported                                        $    (44.5)  $     80.0   $     2.7   $(1,206.4)
  Add back: Stock-based compensation expense included in                    1.3          0.2         2.5         0.4
   reported net income (loss), net of related tax effects

Deduct: Total stock-based compensation expense determined
  under fair value based method for all awards, net of related
  tax effects
    Long-Term Incentive Plan                                               (3.7)        (5.7)       (8.3)      (10.1)
    Employee Stock Purchase Plan                                           (1.2)        (0.6)       (2.1)       (1.2)

                                                                     -----------  -----------  ----------  ----------
  Pro Forma Net Income (Loss)                                        $    (48.1)  $     73.9   $    (5.2)  $(1,217.3)
                                                                     ===========  ===========  ==========  ==========

Basic Earnings (Loss) Per Share
  As Reported                                                        $    (0.14)  $     0.25   $    0.01   $   (3.78)
  Pro Forma                                                               (0.15)        0.23       (0.02)      (3.81)

Diluted Earnings (Loss) Per Share
  As Reported                                                        $    (0.14)  $     0.25   $    0.01   $   (3.73)
  Pro Forma                                                               (0.15)        0.23       (0.02)      (3.76)
</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 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 Interpretation is
effective  as  of the beginning of the first interim period beginning after June
15,  2003  for  existing interests and immediately for new interests. 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  investments  in  and advances to six joint ventures. One
joint  venture,  Deepwater  Drilling  L.L.C. ("DD LLC"), was established for the
purpose of constructing and leasing a drillship. One joint venture, Delta Towing
Holdings,  LLC  ("Delta  Towing"), was established for the purpose of owning and
operating  inland  and  shallow  water  marine  support  vessel  equipment.  The
remaining  four  joint  ventures  were  primarily established for the purpose of
owning  and operating certain drilling units. While the operations of DD LLC are
funded  by cash flows from operating activities, the Company guarantees the debt
and  equity  financing  on the drillship equally with its joint venture partner.
The  debt  and  equity  financing  balance  for  the leased drillship was $194.1
million  at  June  30,  2003.  The Company holds notes receivable from the Delta
Towing  joint  venture  with a carrying value of $54.8 million at June 30, 2003.
The  remaining  joint ventures are funded primarily by cash flows from operating
activities.

     The  Company  accounts  for  these  investments  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.


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


     At  the  time  the  Delta Towing joint venture 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 Delta Towing joint venture also issued a
$3.0  million  note to the 75 percent joint venture partner. Because the Company
has  the  largest  percentage of investment at risk through the notes receivable
and  Delta  Towing's equity is not sufficient to absorb its expected losses, the
Company  is  expected  to  absorb  the  majority of the joint venture's expected
losses  and,  therefore,  the Company is deemed to be the primary beneficiary of
Delta  Towing  for  accounting  purposes.  As such, the Company will consolidate
Delta  Towing  effective  July 1, 2003. The Company expects the consolidation of
Delta  Towing  to  result in an increase in current assets of approximately $5.0
million,  an  increase  in  property  and  equipment, net of approximately $55.0
million,  a  decrease  in  investments  in  and  advances  to  joint ventures of
approximately $55.0 million, an increase in current liabilities of approximately
$1.0  million  and  an increase in long-term debt of approximately $3.0 million.

     The  Company  is  currently  evaluating  the  effects  of  adopting  the
Interpretation  on  the accounting for its ownership interest in its other joint
ventures.

     The  Company  has  a  wholly owned subsidiary, Deepwater Drilling II L.L.C.
("DDII  LLC"),  that was established as a joint venture with a major oil company
for the purpose of constructing and leasing a drillship, the Deepwater Frontier.
The  drillship  was  purchased  by  a  trust that was established to finance the
purchase  through  debt  and  equity financing, which the Company, under certain
circumstances,  fully  guarantees.  On  May  29, 2003, the Company purchased the
entire  40  percent  interest  of the major oil company in DDII LLC. The Company
currently  accounts for DDII LLC's lease of the drillship as an operating lease.
The  balance  of  the  trust's  debt  and  equity financing at June 30, 2003 was
approximately  $162.0  million.  Because the Company is at risk for this amount,
the  Company is deemed to be the primary beneficiary of the trust for accounting
purposes  and  will  consolidate the trust effective July 1, 2003. The drillship
serves  as  collateral for the trust's debt and equity financing. Effective with
the consolidation of the trust, the debt and equity financing to be reflected in
the  Company's  balance  sheet  will  be  approximately  $153.0 million and $9.0
million,  respectively.  The debt financing will be reflected as debt due within
one  year  while  the  equity  financing  will be reflected as minority interest
within  other long-term liabilities in the Company's balance sheet. In addition,
the  Company  will  record  approximately  $207.0  million  for the drillship as
property  and  equipment,  net in its balance sheet and will eliminate its notes
receivable  to  related  party  of  $45.3  million  (see  Note  11).

     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  clients  on  a reimbursable basis are recognized as
operating  and  maintenance  expense.  In  addition,  the  amounts billed to the
Company's  clients 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. This statement
requires  an  issuer  to  measure  and classify as liabilities certain financial
instruments  that  have  characteristics  of  both  liabilities  and  equity  as
liabilities.  SFAS  150  applies  to  those  instruments  that represent, or are
indexed  to,  an obligation to buy back the issuer's shares and obligations that
can  be  settled  in  shares  and meet certain conditions. It does not, however,
apply to financial instruments that are indexed to and potentially settled in an
issuer's  own  shares.  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
will  adopt  this statement effective July 1, 2003. However, management does not
expect  the


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


adoption  of  this  statement  to  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.

NOTE  3  -  DEBT

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

<TABLE>
<CAPTION>
                                                                                     June 30,   December 31,
                                                                                       2003         2002
                                                                                     ---------  -------------
<S>                                                                                  <C>        <C>
6.5% Senior Notes, due April 2003                                                    $       -  $       239.7
9.125% Senior Notes, due December 2003                                                    88.2           89.5
Amortizing Term Loan Agreement - Final Maturity December 2004                            225.0          300.0
6.75% Senior Notes, due April 2005 (a)                                                   365.4          371.8
7.31% Nautilus Class A1 Amortizing Notes - Final Maturity May 2005                        84.6          104.7
9.41% Nautilus Class A2 Notes, due May 2005                                                  -           51.7
6.95% Senior Notes, due April 2008 (a)                                                   271.6          277.2
9.5% Senior Notes, due December 2008 (a)                                                 362.7          371.8
6.625% Notes, due April 2011 (a)                                                         802.8          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)                                                                       16.3          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)                          94.7           94.6
7.5% Notes, due April 2031                                                               597.4          597.4
Other                                                                                      1.0            0.2
                                                                                     ---------  -------------
   Total Debt                                                                          3,758.3        4,678.0
   Less Debt Due Within One Year (b)                                                     282.3        1,048.1
                                                                                     ---------  -------------
   Total Long-Term Debt                                                              $ 3,476.0  $     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 June 30, 2003, the remaining balance was classified as long-term debt.
</TABLE>


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


     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  June  30  (in  millions):

<TABLE>
<CAPTION>
<S>                                          <C>
                            2004             $  281.2
                            2005                467.3
                            2006                400.0
                            2007                100.0
                            2008                269.0
                            Thereafter        2,050.0
                                             --------
                            Total            $3,567.5
                                             ========
</TABLE>


     Commercial Paper Program - The Company has two revolving credit agreements,
described  below,  which  provide  liquidity for commercial paper borrowings. At
June  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 June 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 June 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 June 30, 2003, $225.0
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.


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


     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 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

     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, as well as tax benefits resulting from non-cash
impairments  and  loss  on debt retirements. As a result of the deterioration in
2003  profitability,  the  annual  effective  tax  rate  is  now estimated to be
approximately  38 percent during 2003 on earnings before asset impairments, note
receivable  impairments  and  loss on debt retirements. Due to the change in the
estimated  annual  effective tax rate from approximately 20 percent at March 31,
2003,  earnings  for  the three months ended June 30, 2003 were reduced by $10.7
million ($0.03 per diluted share) as a result of applying the adjusted estimated
annual  effective  tax  rate  to  the  three  months  ended  March  31,  2003.

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  June  30, 2003, the Company had no material open foreign exchange
contracts.


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


     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 for the six months
ended  June  30,  2003.

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 that have
aggregate market values netting to a liability of $2.9 million at June 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 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 clients.
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 (loss) before income taxes, minority interest
and  cumulative  effect  of  a  change in accounting principle by segment are as
follows  (in  millions):

<TABLE>
<CAPTION>
                                                                 Three Months Ended       Six Months Ended
                                                                      June 30,                June 30,
                                                              ------------------------  ----------------------
                                                                 2003         2002        2003        2002
                                                              -----------  -----------  ---------  -----------
<S>                                                           <C>          <C>          <C>        <C>
Operating Revenues
International and U.S. Floater Contract Drilling Services     $    548.5   $    609.1   $1,111.2   $  1,232.3
   Gulf of Mexico Shallow and Inland Water                          55.4         37.1      108.7         81.8
                                                              -----------  -----------  ---------  -----------
      Total Operating Revenues                                $    603.9   $    646.2   $1,219.9   $  1,314.1
                                                              -----------  -----------  ---------  -----------

Operating income (loss) before general and administrative
   expense
   International and U.S. Floater Contract Drilling Services  $     84.2   $    185.9   $  228.2   $    380.8
   Gulf of Mexico Shallow and Inland Water                         (49.5)       (30.9)     (78.0)       (63.7)
                                                              -----------  -----------  ---------  -----------
                                                                    34.7        155.0      150.2        317.1
   Unallocated general and administrative expense                  (14.9)       (16.0)     (28.8)       (35.8)
   Unallocated other income (expense), net                         (84.9)       (44.7)    (127.6)       (95.2)
                                                              -----------  -----------  ---------  -----------
      Income (Loss) before Income Taxes, Minority Interest
         and Cumulative Effect of a Change in Accounting
         Principle                                            $    (65.1)  $     94.3   $   (6.2)  $    186.1
                                                              ===========  ===========  =========  ===========
</TABLE>

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

<TABLE>
<CAPTION>
                                                           June 30,   December 31,
                                                             2003         2002
                                                           ---------  -------------
<S>                                                        <C>        <C>
International and U.S. Floater Contract Drilling Services  $10,913.8  $    11,804.1
Gulf of Mexico Shallow and Inland Water                        792.0          861.0
                                                           ---------  -------------
   Total Assets                                            $11,705.8  $    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 six months ended June 30, 2003, the Company settled an insurance
claim  and  sold  certain  other  assets  for net proceeds of approximately $3.2
million  and  recorded  net after-tax gains of $1.4 million in its International
and U.S. Floater Contract Drilling Services segment and $0.2 million, net of tax
of  $0.1  million,  in  its  Gulf  of  Mexico  Shallow and Inland Water segment.

     During  the  six  months ended June 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 six months ended June 30, 2002, the Company settled an insurance
claim  and  sold  certain  other  assets for net proceeds of approximately $15.6
million  and  recorded  net  gains  of  $1.0  million,  net  of  tax  of  $0.5


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


million,  in  its  International  and  U.S.  Floater  Contract Drilling Services
segment  and net losses of $0.3 million, net of tax of $0.1 million, in its Gulf
of  Mexico  Shallow  and  Inland  Water  segment.

     Impairments  -  During  the  six  months  ended  June 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
approximately  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  six  months  ended  June  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 six months ended June 30, 2002, the Company recorded a non-cash
impairment  charge  of  $0.7  million, net of tax of $0.4 million, related to an
asset  held  for  sale  in  the Gulf of Mexico Shallow and Inland Water 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.


                                       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 per share is as follows (in millions,
except  per  share  data):

<TABLE>
<CAPTION>
                                                                     Three Months Ended       Six Months Ended
                                                                           June 30,              June 30,
                                                                   -----------------------  ---------------------
                                                                      2003         2002       2003       2002
                                                                   -----------  ----------  --------  -----------
<S>                                                                <C>          <C>         <C>       <C>
NUMERATOR FOR BASIC AND DILUTED EARNINGS (LOSS) PER SHARE
Income (Loss) Before Cumulative Effect of a Change in
  Accounting Principle                                             $    (44.5)  $     80.0  $    2.7  $    157.3
Cumulative Effect of a Change in Accounting Principle                       -            -         -    (1,363.7)
                                                                   -----------  ----------  --------  -----------
Net Income (Loss)                                                  $    (44.5)  $     80.0  $    2.7  $ (1,206.4)
                                                                   ===========  ==========  ========  ===========

DENOMINATOR FOR DILUTED EARNINGS (LOSS) PER SHARE
Weighted-average shares outstanding for basic earnings per share        319.8        319.1     319.7       319.1
  Effect of dilutive securities:
    Employee stock options and unvested stock grants                        -          2.7       1.2         2.6
    Warrants to purchase ordinary shares                                    -          2.1       0.6         1.9
                                                                   -----------  ----------  --------  -----------
Adjusted weighted-average shares and assumed
    conversions for diluted earnings per share                          319.8        323.9     321.5       323.6
                                                                   ===========  ==========  ========  ===========

BASIC EARNINGS (LOSS) PER SHARE
  Income (Loss) Before Cumulative Effect of a Change in
    Accounting Principle                                           $    (0.14)  $     0.25  $   0.01  $     0.49
  Cumulative Effect of a Change in Accounting Principle                     -            -         -       (4.27)
                                                                   -----------  ----------  --------  -----------
  Net Income (Loss)                                               $    (0.14)  $     0.25  $   0.01  $    (3.78)
                                                                   ===========  ==========  ========  ===========

DILUTED EARNINGS (LOSS) PER SHARE
  Income (Loss) Before Cumulative Effect of a Change in
    Accounting Principle                                           $    (0.14)  $     0.25  $   0.01  $     0.49
  Cumulative Effect of a Change in Accounting Principle                     -            -         -       (4.22)
                                                                   -----------  ----------  --------  -----------
  Net Income (Loss)                                                $    (0.14)  $     0.25  $   0.01  $    (3.73)
                                                                   ===========  ==========  ========  ===========
</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 all periods
presented.  Incremental  shares  related to stock options, unvested stock grants
and  warrants  are  not included in the calculation of adjusted weighted-average
shares  and  assumed  conversions  for  diluted earnings per share for the three
months  ended  June  30,  2003,  because the effect of including those shares is
anti-dilutive  for  that  period.

NOTE  10  -  CONTINGENCIES

     Legal Proceedings - In March 1997, an action was filed by Mobil Exploration
and  Producing U.S. Inc. and affiliates, St. Mary Land & Exploration Company and
affiliates  and  Samuel  Geary  and  Associates Inc. against a subsidiary of the
Company,  Cliffs  Drilling, its underwriters at Lloyd's (the "Underwriters") and
an  insurance  broker  in  the  16th Judicial District Court of St. Mary Parish,
Louisiana. The plaintiffs alleged damages in excess of $50 million in connection
with  the drilling of a turnkey well in 1995 and 1996. The case was tried before
a  jury  in  January  and  February  2000,  and  the  jury returned a verdict of
approximately  $30 million in favor of the plaintiffs for excess drilling costs,
loss  of  insurance  proceeds, loss of hydrocarbons, expenses, and interest. The
Company  and the Underwriters appealed such judgment, and the Louisiana Court of
Appeals reduced the amount for which the Company may be responsible to less than
$10  million.  The  plaintiffs  requested  that  the  Supreme Court of Louisiana
consider  the  matter  and  reinstate  the original verdict. The Company and the
Underwriters  also  appealed  to  the  Supreme  Court  of  Louisiana


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


requesting  that  the  Court  reduce  the  verdict  or,  in  the  case  of  the
Underwriters,  eliminate  any  liability  for  the verdict. Prior to the Supreme
Court  of  Louisiana ruling on these petitions, the Company settled with the St.
Mary  group  of plaintiffs and the State of Louisiana. Subsequently, the Supreme
Court  of  Louisiana  denied  the  applications of all remaining plaintiffs. The
Company settled with all remaining plaintiffs in the second quarter of 2003. The
Company  believes  that  the amounts, apart from a small deductible, paid in the
settlement  are  covered  by  relevant  primary  and  excess liability insurance
policies.  However,  the insurers and the Underwriters have denied all coverage.
The Company has instituted litigation against those insurers and Underwriters to
enforce  its  rights  under  the  relevant  policies.  One  group of issuers has
asserted a counterclaim against the Company claiming that they issued the policy
as  a  result  of  misrepresentation.  The  settlements  did not have a material
adverse effect on the Company's business or consolidated financial position. The
Company  does  not  expect  the  ultimate outcome of the case to have a material
adverse  effect  on  its  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  June  30,  2003 totaling $78.7 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  $159.6  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,  Delta  Towing failed to make another scheduled quarterly interest payment
of $1.6 million. During the six months ended June 30, 2003, the Company received
partial  interest  payments of approximately $0.6 million. At June 30, 2003, the
Company  had  interest receivable from Delta Towing of $4.3 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 June 30,
2003,  the  carrying value of the notes receivable, net of the related allowance
for  credit  losses, was $54.8 million. The Company will establish a reserve for
future  interest  income  earned  and  recorded on the notes receivable and 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 Deepwater Frontier. In May 2003,
WestLB AG, one of the lenders in the synthetic lease financing facility to which
DDII  LLC  is  the  lessee, 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


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


of  WestLB  AG. The balance of the note receivable was $45.3 million at June 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  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 June 30, 2003, $2.1 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 June 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 June 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>
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 July 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 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  clients.

     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 clients on a reimbursable basis are being
recognized  as operating and maintenance expense beginning in 2003. In addition,
the  amounts  billed to our clients 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 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


                                       21
<PAGE>
the  entity that owns that business in preparation of the offering. We expect to
complete  the initial public offering when market conditions warrant, subject to
various  factors.  Given  the current general uncertainty in the equity and U.S.
natural  gas  drilling  markets,  we  are  unsure  when the transaction could be
completed  on  terms  acceptable  to  us.  We  do  not expect to sell all of our
interest  in TODCO in the initial public offering. Until we complete the initial
public  offering  transaction, we will continue to operate and account for TODCO
as  our  Gulf  of  Mexico  Shallow  and  Inland  Water  segment.

     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 National Union of Petroleum and Natural Gas Workers on the
semisubmersible  rigs  M.G. Hulme, Jr. and Sedco 709 and the jackup rigs Trident
VI  and  Trident  VIII.  All rigs have since returned to operations. We continue
negotiations  to  resolve  the  issues  relating to the labor strike 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 has resumed operations
but  we  are  in  discussion with our customer regarding the appropriate dayrate
treatment.  See  "-Operating  Results."

     In  June  2003,  we  incurred a loss as a result of a well blowout and fire
aboard  our  inland  barge  Rig  62.  Our insurance coverage has a $12.5 million
aggregate  deductible  for  this  incident.  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  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


                                       22
<PAGE>
receivables are concentrated in certain oil-producing countries. We generally do
not  require  collateral or other security to support client receivables. If the
financial  condition of our clients was to deteriorate or their access to freely
convertible currency was restricted, resulting in impairment of their ability to
make  the  required  payments,  additional  allowances  may  be  required.

     Valuation allowance for deferred tax assets-We record a valuation allowance
to  reduce our deferred tax assets to the amount that is more likely than not to
be realized. 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, an adjustment to the
valuation  allowance  would increase income in the period such determination was
made.  Likewise,  should we determine that we would more likely than not be able
to  realize  all  or  part  of  our  net  deferred  tax  asset in the future, an
adjustment  to  the  valuation  allowance would reduce income in the period such
determination  was  made.

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

     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


                                       23
<PAGE>
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 JUNE 30, 2003 COMPARED TO QUARTER ENDED JUNE 30, 2002

     Our revenues for the quarter ended June 30, 2003 decreased by $42.3 million
and our operating and maintenance expense increased by $60.9 million compared to
the  quarter  ended  June  30,  2002. Our overall average dayrate decreased from
$78,000  for  the  quarter  ended June 30, 2002 to $65,300 for the quarter ended
June  30,  2003, while utilization remained flat at 56 percent for each of these
periods.  The  decreases  in  our contract drilling revenue and average dayrates
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  labor  strike  in  Nigeria,  the riser separation
incident  on  the  drillship Discoverer Enterprise, the well control incident on
inland  barge  Rig 62 and the electrical fire on the Peregrine I. 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>
                                                         Three Months Ended
                                                              June 30,
                                                     ----------------------------
                                                         2003           2002          Change      % Change
                                                     ------------  --------------  -------------  ---------
                                                        (In millions, except day amounts and percentages)
<S>                                                  <C>           <C>             <C>            <C>
Operating days (a)                                       5,887.1         6,487.4         (600.3)     (9.3)%
Utilization (a) (b) (d)                                     67.9%           78.4%           N/A     (13.4)%
Average dayrate (a) (c) (d)                          $    88,900   $      93,500   $     (4,600)     (4.9)%

Contract drilling revenues                           $     525.5   $       609.1   $      (83.6)    (13.7)%
Client reimbursable revenues                                23.0               -           23.0       N/M
                                                     ------------  --------------  -------------  ---------
                                                           548.5           609.1          (60.6)     (9.9)%
Operating and maintenance                                  355.9           320.1           35.8      11.2%
Depreciation                                               104.4           101.4            3.0       3.0%
Impairment loss on long-lived assets                         4.2               -            4.2       N/M
(Gain) loss from sale of assets, net                        (0.2)            1.7           (1.9)      N/M
                                                     ------------  --------------  -------------  ---------
Operating income before general and administrative
  expense                                            $      84.2   $       185.9   $     (101.7)    (54.7)%
                                                     ============  ==============  =============  =========
<FN>
_________________
"N/A"  means  not  applicable
"N/M"  means  not  meaningful

(a)  Applicable  to  all  rigs.


                                       24
<PAGE>
(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>

     Lower  average  dayrates  and  utilization  resulted  in a decrease in this
segment's  contract  drilling revenues of approximately $68.0 million, excluding
the  impact  of the items discussed separately below. Contract drilling revenues
were  also  adversely  impacted  by approximately $22.0 million due to the labor
strike  in  Nigeria,  the riser separation incident on the Discoverer Enterprise
and  the  electrical  fire  on the Peregrine I. Decreases also resulted from the
sale of a rig and a leased rig returned to its owner during or subsequent to the
second  quarter of 2002 ($2.8 million). These decreases were partially offset by
increases in contract drilling revenues from a rig transferred into this segment
from  the  Gulf  of  Mexico  Shallow  and Inland Water segment during the second
quarter  of  2002 ($4.7 million) and from the Deepwater Frontier ($4.8 million),
as  a  result  of  the  consolidation  of  DDII  LLC.  See  "-Overview."

     Operating  revenues for the three months ended June 30, 2003 included $23.0
million related to costs incurred and billed to clients 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  higher  shipyard  and  maintenance  expenses, including $5.2
million in costs associated with the riser separation incident on the Discoverer
Enterprise.  Rig  hire  expense  increased  by  $2.2  million resulting from the
consolidation of DDII LLC, which leases the Deepwater Frontier. We also incurred
additional  expense in the second quarter of 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 ($2.7 million), costs incurred related
to  the  labor  strike  in Nigeria ($2.6 million), costs incurred related to the
electrical  fire  on the Peregrine I ($2.2 million) and an increase in allowance
for  doubtful  accounts  related  to  two  client receivables ($4.5 million). In
addition,  expenses increased due to additional costs incurred and 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  rigs  sold  or  returned  to owner during and subsequent to the
second quarter of 2002 ($2.4 million). We also recognized a $4.1 million release
of a litigation reserve in the second quarter of 2003 relating to the settlement
of  a  dispute.

     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 three months
ended June 30, 2002. These increases were partially offset by lower depreciation
expense  following  the  sale  of  a  rig classified as held and used during the
second  quarter  of  2002.

     During  the  three  months  ended  June  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.


                                       25
<PAGE>
GULF OF MEXICO SHALLOW AND INLAND WATER SEGMENT

<TABLE>
<CAPTION>
                                                       Three Months Ended
                                                            June 30,
                                                   ---------------------------
                                                       2003          2002          Change      % Change
                                                   ------------  -------------  -------------  ---------
                                                      (In millions, except day amounts and percentages)
<S>                                                <C>           <C>            <C>            <C>
Operating days (a)                                     2,918.7        1,765.7        1,153.0       65.3%
Utilization (a) (b) (d)                                   42.2%          27.0%           N/A       56.3%
Average dayrate (a) (c) (d)                        $    17,500   $     21,000   $     (3,500)    (16.7)%

Contract drilling revenues                         $      51.1   $       37.1   $       14.0       37.7%
Client reimbursable revenues                               4.3              -            4.3        N/M
                                                   ------------  -------------  -------------  ---------
                                                          55.4           37.1           18.3       49.3%
Operating and maintenance                                 70.6           45.5           25.1       55.2%
Depreciation                                              23.1           22.9            0.2        0.9%
Impairment loss on long-lived assets                      11.6              -           11.6        N/M
Gain from sale of assets, net                             (0.4)          (0.4)             -        N/M
                                                   ------------  -------------  -------------  ---------
Operating loss before general and administrative
  expense                                          $     (49.5)  $      (30.9)  $      (18.6)    (60.2)%
                                                   ============  =============  =============  =========
<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  revenues  of  $25.7  million,  partially  offset  by decreased average
dayrates ($10.4 million) and the transfer of a jackup rig from this segment into
the International and U.S. Floater Contract Drilling Services segment during the
second  quarter  of  2002  ($1.4  million).

     Operating  revenues  for the three months ended June 30, 2003 included $4.3
million related to costs incurred and billed to clients 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 costs associated with the well control incident on inland barge
Rig  62  ($7.2  million), an increase in insurance expense ($2.4 million) and an
increase  in  activity  ($11.9  million). In addition, operating and maintenance
expenses  increased  due  to  costs  incurred  and  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 was a decrease resulting from the transfer of a jackup rig from
this  segment into the International and U.S. Floater Contract Drilling Services
segment  in  the  second  quarter  of  2002  ($1.1  million).

     During  the  three  months  ended  June  30,  2003,  we recorded a non-cash
impairment  charge  of  $10.6  million  in this segment, which resulted from our
decision  to  take  five jackup rigs out of 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.


                                       26
<PAGE>
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. During
the  three  months  ended  June 30, 2003, we also recorded a non-cash impairment
charge  of  $1.0  million in this segment, which resulted from our determination
that  the  fair  value of 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.

TOTAL  COMPANY  RESULTS  OF  OPERATIONS

<TABLE>
<CAPTION>
                                                              Three Months Ended
                                                                     June 30,
                                                             ------------------------
                                                                2003         2002       Change   % Change
                                                             -----------  -----------  --------  ---------
                                                                       (In millions, except % change)
<S>                                                          <C>          <C>          <C>       <C>
General and Administrative Expense                           $     14.9   $     16.0   $  (1.1)     (6.9)%
Other (Income) Expense, net
  Equity in earnings of joint ventures                             (1.8)        (2.5)      0.7     (28.0)%
  Interest income                                                  (5.8)        (5.7)     (0.1)       1.8%
  Interest expense                                                 52.8         52.5       0.3      (0.6)%
  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                                                        2.7          0.4       2.3       N/M
  Income Tax Expense (Benefit)                                    (20.8)        13.9     (34.7)      N/M
<FN>
_________________
"N/M"  means  not  meaningful
</TABLE>

     The  decrease  in  general  and  administrative expense was attributable to
decreased  personnel  expenses  of  $1.2  million primarily due to lower pension
expense  in  2003  and  an  adjustment to cash surrender value of executive life
insurance.

     The  decrease in equity in earnings of joint ventures was primarily related
to  our  25  percent  share  of  losses  from Delta Towing Holdings, LLC ("Delta
Towing"),  which included our share of a $2.5 million non-cash impairment charge
on  the  carrying  value  of  idle  equipment  recorded  by  the  joint venture.
Offsetting  the decrease was our 60 percent share of earnings of DDII LLC, which
leases  the  Deepwater  Frontier.  The rig experienced increased utilization and
average  dayrates  during the two month period ended May 31, 2003, at which time
we  completed  the  buyout  of  ConocoPhillips' 40 percent interest in the joint
venture,  compared  to  the  three  months  ended June 30, 2002. The increase in
interest  income  was  primarily  due  to interest earned on higher average cash
balances for the three months ended June 30, 2003 compared to the same period in
2002.  The  increase in interest expense was primarily due to the termination of
our  fixed  to  floating interest rate swaps in the first quarter of 2003, which
resulted  in  an  increase  of  $13.5 million, partially offset by 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"). Debt
repaid  or retired during and subsequent to the three months ended June 30, 2002
resulted  in  an  additional  $6.8  million  reduction  in  interest  expense.

     During  the three months ended June 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  three  months ended June 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 revaluation
of  a local currency into functional U.S dollars for the three months ended June
30,  2003  (see  "-Item 3. Quantitative and Qualitative Disclosures about Market
Risk-Foreign  Exchange  Risk").


                                       27
<PAGE>
     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  three  months ended June 30, 2003 included a tax benefit of
$14.6  million attributable to the favorable resolution of a non-U.S. income tax
liability  and  income tax benefits resulting from non-cash impairments and loss
on debt retirements. As a result of the deterioration in 2003 profitability, our
annual effective tax rate is now estimated to be approximately 38 percent during
2003  on earnings before asset impairments, notes receivable impairment and loss
on  debt  retirements.  Due  to  this  change  in estimate from approximately 20
percent  at  March  31,  2003, earnings for the three months ended June 30, 2003
were  reduced  by  $10.7  million as a result of applying the adjusted estimated
annual  effective  tax  rate  to  the  three  months  ended  March  31,  2003.

     SIX  MONTHS  ENDED JUNE 30, 2003 COMPARED TO SIX MONTHS ENDED JUNE 30, 2002

     Our  revenues  for  the  six  months ended June 30, 2003 decreased by $94.2
million  and  our  operating  and maintenance expense increased by $54.0 million
compared to the six months ended June 30, 2002. In addition, our overall average
dayrate and utilization decreased from $75,100 and 59 percent, respectively, for
the  six months ended June 30, 2002 to $67,100 and 56 percent for the six months
ended  June  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 and the electrical fire on the Peregrine I.
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.

<TABLE>
<CAPTION>
                                                                    Six Months Ended
                                                                        June 30,
                                                             ------------------------------
                                                                    2003            2002       Change    % Change
                                                             ------------------  ----------  ----------  ---------
                                                               (In millions, except day amounts and percentages)
<S>                                                          <C>                 <C>         <C>         <C>
Operating days (a)                                                    11,769.4    13,371.3    (1,601.9)    (12.0)%
Utilization (a) (b) (d)                                                   68.3%       80.2%        N/A     (14.8)%
Average dayrate (a) (c) (d)                                  $          90,300   $  91,800   $  (1,500)     (1.6)%

Contract drilling revenues                                   $         1,066.6   $ 1,232.3   $  (165.7)    (13.4)%
Client reimbursable revenues                                              44.6           -        44.6        N/M
                                                             ------------------  ----------  ----------  ---------
                                                                       1,111.2     1,232.3      (121.1)     (9.8)%
Operating and maintenance                                                671.4       648.8        22.6        3.5%
Depreciation                                                             208.0       203.7         4.3        2.1%
Impairment loss on long-lived assets                                       5.2           -         5.2        N/M
Gain from sale of assets, net                                             (1.6)       (1.0)       (0.6)      60.0%
                                                             ------------------  ----------  ----------  ---------
Operating income before general and administrative expense   $           228.2   $   380.8   $  (152.6)    (40.1)%
                                                             ==================  ==========  ==========  =========
<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.


                                       28
<PAGE>
(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>

     Lower  average  dayrates  and  utilization  resulted  in a decrease in this
segment's  contract drilling revenues of approximately $144.0 million, excluding
the  impact  of the items discussed separately below. Contract drilling revenues
were  also  adversely  impacted  by approximately $22.0 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 ($7.9 million), the return of a leased rig to its owner ($2.8
million)  and  the  transfer  of  a  jackup rig from this segment to the Gulf of
Mexico  Shallow  and  Inland  Water  segment  ($2.1  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 ($9.3 million) and from the
Deepwater Frontier ($4.2 million), as a result of the consolidation of DDII LLC.
See  "-Overview."

     Operating  revenues  for  the six months ended June 30, 2003 included $44.6
million related to costs incurred and billed to clients 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  higher  shipyard  and  maintenance  expenses, including $5.2
million in costs associated with the riser separation incident on the Discoverer
Enterprise.  Rig  hire  expenses  increased  by  $2.2 million resulting from the
consolidation of DDII LLC, which leases the Deepwater Frontier. We also incurred
additional expense 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  ($5.3  million),  costs incurred related to the labor
strike  in Nigeria ($2.6 million), costs incurred related to the electrical fire
on  the  Peregrine  I  ($2.2  million) and an increase in allowance for doubtful
accounts related to two client receivables ($4.5 million). In addition, expenses
increased  due  to  additional  costs  incurred  and 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 rigs
sold ($6.2 million) or returned to owner ($2.6 million) during and subsequent to
the six months ended June 30, 2002. We also recognized a $4.1 million release of
a litigation reserve in the second quarter of 2003 relating to the settlement of
a  dispute  and  a  $2.6  million  expense  reduction  from the settlement of an
insurance  claim  during  the  six  months  ended  June  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 six months
ended June 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  six  months  ended  June  30,  2002.

     During  the  six  months  ended  June  30,  2003,  we  recorded  a non-cash
impairment  charge  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 six months ended June
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.


                                       29
<PAGE>
<TABLE>
<CAPTION>

GULF  OF  MEXICO  SHALLOW  AND  INLAND  WATER  SEGMENT

                                                           Six Months Ended
                                                               June 30,
                                                   --------------------------------
                                                          2003             2002         Change       % Change
                                                   ------------------  ------------  ------------  ------------
                                                         (In millions, except day amounts and percentages)
<S>                                                <C>                 <C>           <C>           <C>

Operating days (a)                                           5,540.7       4,047.0       1,493.7          36.9%
Utilization (a) (b) (d)                                         40.3%         30.9%          N/A          30.4%
Average dayrate (a) (c) (d)                        $          18,000   $    20,200        (2,200)       (10.9)%
                                                                                                              %
Contract drilling revenues                         $            99.6   $      81.8          17.8          21.8%
Client reimbursable revenues                                     9.1             -           9.1           N/M
                                                   ------------------  ------------  ------------  ------------
                                                               108.7          81.8          26.9          32.9%
Operating and maintenance                                      129.2          97.8          31.4          32.1%
Depreciation                                                    46.3          46.2           0.1           0.2%
Impairment loss on long-lived assets                            11.6           1.1          10.5           N/M
(Gain) loss from sale of assets, net                            (0.4)          0.4          (0.8)          N/M
                                                   ------------------  ------------  ------------  ------------
Operating loss before general and administrative
  expense                                          $           (78.0)  $     (63.7)        (14.3)       (22.4)%
                                                   ==================  ============  ============  ============
<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  $34.5  million,  partially  offset  by  decreased average
dayrates ($14.7 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  six  months  ended  June  30,  2002  ($2.0  million).

     Operating  revenues  for  the  six months ended June 30, 2003 included $9.1
million related to costs incurred and billed to clients 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 due
primarily to costs associated with the well control incident on inland barge Rig
62 ($7.2 million) and an increase in activity of approximately $15.0 million. In
addition, operating and maintenance expenses increased due to costs incurred and
recognized  as operating and maintenance expense relating to client reimbursable
expenses as a result of implementing EITF 99-19 during the six months ended June
30,  2003  (see  "-Overview"). Operating and maintenance expenses also increased
due  to  an  insurance  claim  provision  ($2.5  million).  These increases were
partially  offset  by  the  release  of  a provision for doubtful accounts ($1.8
million)  during  the  first  six  months  of  2003  upon  collection of amounts
previously  reserved  and  by  lower  expenses  resulting from the transfer of a
jackup  rig  from  this segment into the International and U.S. Floater Contract
Drilling  Services  segment  ($1.9  million)  during the second quarter of 2002.


                                       30
<PAGE>
     During  the  six  months  ended  June  30,  2003,  we  recorded  a non-cash
impairment  charge  of  $10.6  million  in this segment, which resulted from our
decision  to  take  five jackup rigs out of 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 six months
ended  June  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  six months ended June 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.

TOTAL  COMPANY  RESULTS  OF  OPERATIONS

<TABLE>
<CAPTION>
                                                                   Six Months Ended
                                                                       June 30,
                                                           --------------------------------
                                                                  2003             2002         Change        % Change
                                                           ------------------  ------------  -------------  ------------
                                                                            (In millions, except % change)
<S>                                                        <C>                 <C>           <C>            <C>

General and Administrative Expense                         $            28.8   $      35.8   $       (7.0)       (19.6)%
Other (Income) Expense, net
  Equity in earnings of joint ventures                                  (5.4)         (4.4)          (1.0)         22.7%
  Interest income                                                      (12.7)         (9.9)          (2.8)         28.3%
  Interest expense                                                     105.4         108.4           (3.0)        (2.8)%
  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                                                             3.3           1.1            2.2           N/M
  Income Tax Expense (Benefit)                                          (9.0)         27.7          (36.7)          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>

     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.  In  addition, personnel expenses decreased
$2.2  million  primarily  due  to  lower  pension  expense  in  2003, a one-time
curtailment  gain  related  to  retiree life insurance and an adjustment to cash
surrender  value  of  executive  life  insurance.

     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 six months of 2002, due to
shipyard  downtime  in  2002.  Offsetting  the increase in equity in earnings of
joint  ventures  was  our  25  percent  share of losses from Delta Towing, which
included  our share of a $2.5 million non-cash impairment charge on the carrying
value  of idle equipment recorded by the joint venture. The increase in interest
income  was primarily due to interest earned on higher average cash balances for
the  six  months  ended  June  30, 2003 compared to the same period in 2002. The
decrease  in interest expense was attributable to reductions of interest expense
of  $8.1  million  associated with debt refinanced, repaid or retired during and
subsequent  to June 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  $17.1  million,


                                       31
<PAGE>
partially  offset by a $10.0 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  six  months ended June 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  six  months  ended  June 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 revaluation
of  a  local  currency into functional U.S dollars for the six months ended June
30,  2003  (see  "-Item 3. Quantitative and Qualitative Disclosures about Market
Risk-Foreign  Exchange  Risk").

     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 six months ended June 30, 2003 included a tax benefit of $14.6
million  attributable  to  the  favorable  resolution  of  a non-U.S. income tax
liability  and  income tax benefits resulting from non-cash impairments and loss
on  debt  retirements,  partially  offset by an increase in the estimated annual
effective  tax  rate  for the six months ended June 30, 2003 to approximately 38
percent  of  earnings  before asset impairments, notes receivable impairment and
loss on debt retirements compared to approximately 15 percent for the comparable
period  in  2002.

     During the six months ended June 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.

FINANCIAL  CONDITION

<TABLE>
<CAPTION>
                                                           June 30,   December 31,                %
                                                             2003         2002        Change   Change
                                                           ---------  -------------  --------  -------
                                                                         (In millions)
<S>                                                        <C>        <C>            <C>       <C>
   TOTAL ASSETS
International and U.S. Floater Contract Drilling Services  $10,913.8  $    11,804.1  $(890.3)   (7.5)%
Gulf of Mexico Shallow and Inland Water                        792.0          861.0    (69.0)   (8.0)%
                                                           ---------  -------------  --------  -------
                                                           $11,705.8  $    12,665.1  $(959.3)   (7.6)%
                                                           =========  =============  ========  =======
</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  ($514.5 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  Note  6  to  our  condensed consolidated financial
statements).  In  addition,  the  sale  of  a jackup rig ($18.0 million net book
value),  normal  depreciation  ($208.0  million)  and  asset  impairments  ($5.2
million)  during  2003 further reduced the assets in this segment (see Note 8 to
our  condensed consolidated financial statements). The decrease in the assets of
the  Gulf of Mexico Shallow and Inland Water segment was primarily due to normal
depreciation  ($46.3  million)  and  asset  impairments  ($11.6 million) and the
impairment  of  a related party note receivable ($21.3 million) during 2003 (see
Notes  8  and  11  to  our  condensed  consolidated  financial  statements).


                                       32
<PAGE>
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  June  30,  2003, $2.1 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 June 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 June 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.


                                       33
<PAGE>
OUTLOOK

     Fleet  utilization  and average dayrates decreased within our International
and  U.S.  Floater Contract Drilling Services business segment during the second
quarter  of  2003  compared  with  the first quarter of 2003. Within our Gulf of
Mexico  Shallow  and  Inland  Water business segment fleet utilization increased
slightly  and  average  dayrates  decreased  during  the  second quarter of 2003
compared  with  the  first  quarter  of  2003.

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

<TABLE>
<CAPTION>
                                                                                  Three Months Ended
                                                                     ---------------------------------------------
                                                                         June 30,         March 31,      June 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                                                   $      185,100   $       183,800   $ 188,400
    Other Deepwater                                                  $      111,500   $       113,600   $ 124,300
  Total Deepwater                                                    $      147,500   $       147,500   $ 152,200
    Mid-Water                                                        $       73,600   $        77,200   $  81,300
    Jackups - Non-U.S.                                               $       57,400   $        56,900   $  57,400
    Other Rigs                                                       $       41,500   $        43,200   $  40,400
                                                                     ---------------  ----------------  ----------
Segment Total                                                        $       88,900   $        91,600   $  93,500
                                                                     ---------------  ----------------  ----------

GULF OF MEXICO SHALLOW AND INLAND WATER SEGMENT:
    Jackups and Submersibles                                         $       18,200   $        19,700   $  20,200
    Inland Barges                                                    $       16,100   $        17,600   $  20,200
    Other Rigs                                                       $       18,600   $        19,000   $  24,100
                                                                     ---------------  ----------------  ----------
Segment Total                                                        $       17,500   $        18,500   $  21,000
                                                                     ---------------  ----------------  ----------

Total Mobile Offshore Drilling Fleet                                 $       65,300   $        69,100   $  78,000
                                                                     ===============  ================  ==========

UTILIZATION (A)(C)(D)

INTERNATIONAL AND U.S. FLOATER CONTRACT DRILLING SERVICES SEGMENT:
  Deepwater
    5th Generation                                                               88%               97%         89%
    Other Deepwater                                                              70%               76%         85%
  Total Deepwater                                                                78%               85%         87%
    Mid-Water                                                                    55%               53%         72%
    Jackups - Non-U.S.                                                           86%               87%         82%
    Other Rigs                                                                   41%               36%         64%
                                                                     ---------------  ----------------  ----------
Segment Total                                                                    68%               69%         78%
                                                                     ---------------  ----------------  ----------

GULF OF MEXICO SHALLOW AND INLAND WATER SEGMENT:
   Jackups and Submersibles                                                      44%               31%         27%
   Inland Barges                                                                 39%               47%         24%
   Other Rigs                                                                    44%               35%         37%
                                                                     ---------------  ----------------  ----------
Segment Total                                                                    42%               38%         27%
                                                                     ---------------  ----------------  ----------

Total Mobile Offshore Drilling Fleet                                             56%               55%         56%
                                                                     ===============  ================  ==========
<FN>
_________________
(a)  Applicable  to  all  rigs.


                                       34
<PAGE>
(b)  Average  dayrate  is  defined  as  contract  drilling  revenue  earned  per  revenue  earning  day.
(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  continued at relatively strong levels during 2003.
Demand  for  our  drilling  rigs is driven in part by our clients' perception of
future  commodity  prices, coupled with a number of associated factors including
the  availability of drilling prospects, relative production costs, the stage of
reservoir  development and political environments. It is unclear why the current
strong  commodity  prices  have not translated into increased drilling activity,
and  we  do  not  see  any  significant  indication  that activity will increase
materially  in  the  near-term  with  the  exception  of  Mexico and India where
activity  continues  to  increase.

     We  see  mixed  signals  in the short-term outlook for our deepwater fleet.
There  are  opportunities in the short-term for deepwater rigs in India and West
Africa  although we are concerned about the existing oversupply in the U.S. Gulf
of  Mexico.  However,  we  remain  optimistic  about  the  longer-term deepwater
outlook. The number of large discoveries in West Africa combined with continuing
exploratory  interest  in that region and demand for deepwater rigs in India are
positive  developments  supporting  long-term  deepwater  activity.

     The  non-U.S. jackup market sector remains strong despite some current idle
capacity in West Africa, and we look for this activity level to continue through
2003.  Opportunities  in  Mexico  and  India  are  contributing  to  an  already
relatively  strong  market  sector.

     The  mid-water  floater  business  remains  extremely  weak as this segment
continues  to  be  significantly  oversupplied  globally.  While we have seen an
increase  in activity for mid-water rigs in the North Sea due to seasonal summer
work,  the outlook there and elsewhere appears poor beyond that point. We expect
the  global  mid-water  sector  to  continue to be oversupplied throughout 2003.

     The  recovery  in the U.S. Gulf of Mexico shallow and inland market segment
has  been  limited to date. Dayrates for shallow water jackups have strengthened
marginally  and  the  demand  for jackups in Mexico and India should continue to
indirectly  help  this  sector  as  rigs leave the U.S. Gulf of Mexico for these
countries.  The  inland  barge  drilling  market  continues  to  be  soft  and
industry-wide  utilization  has  decreased  since  the  beginning  of  2003.

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

     In  May 2003, we purchased ConocoPhillips' 40 percent interest in 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 during the second quarter of 2003. Pursuant
to the lease financings, the rig is owned by a special purpose entity and leased
to  DDII  LLC.  In  July  2003,  the  value  of  the rig and the debt and equity
financing  associated with the lease will be reflected on our balance sheet as a
result of the application of the Financial Accounting Standards Board's ("FASB")
Interpretation  ("FIN")  46,  Consolidation  of  Variable  Interest Entities, an
Interpretation  of  Accounting Research Bulletin No. 51. We expect the amount of
the rig and debt and equity financing to be reflected on our balance sheet to be
approximately $207 million and $162 million, respectively. See "-Special Purpose
Entities,  Sale/Leaseback  Transaction  and  Related  Party  Transactions."

     During the quarter ended June 30, 2003, we deferred costs primarily related
to  mobilizations  and  contract  preparation  of  $19.7  million and recognized
amortization  expense  of  previously  deferred  mobilization  and  contract
preparation costs of $26.8 million. We expect to defer approximately $31 million
in  mobilization  and  contract  preparation  costs  and  to amortize to expense
approximately  $26  million  in  the third quarter of 2003. Our expectations are
based  upon certain of our rigs being awarded contracts for which bids have been
submitted  and  for  those  contracts  that  have  been  awarded to begin at the
contractual start date. We cannot provide any assurance that the contracts under


                                       35
<PAGE>
bid will be awarded to us or that awarded contracts will begin when anticipated.
As  such,  actual  cost  deferrals  and  amortizations  could  vary  from  these
estimates.

     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 the 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  additional assessments, which have been asserted, and may
contest  any  future  assessments. While the outcome of these assessments is not
presently  known,  we  do  not  believe  that  the  ultimate resolution of these
asserted  income  tax  liabilities  will  have  a material adverse effect on our
business or consolidated financial position. As a result of the deterioration in
2003  profitability,  our  annual  effective  tax  rate  is  now estimated to be
approximately 38 percent for 2003, excluding the income tax benefit attributable
to  the  favorable  resolution  of a non-U.S. income tax liability, the non-cash
asset  impairments  and  the  loss  on  retirements  of  debt.

     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
now expect to make no annual 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. Continued 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.

     As  of  July  29,  2003,  approximately  58  percent  and 32 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 10
percent  for  the  remainder of 2003 and five percent is currently committed for
the  year  2004.

LIQUIDITY  AND  CAPITAL  RESOURCES


     SOURCES  AND  USES  OF  CASH

<TABLE>
<CAPTION>
                                               Six Months Ended June 30,
                                            --------------------------------
                                                 2003             2002          Change
                                            --------------  ----------------  ----------
                                                             (In millions)
<S>                                         <C>             <C>               <C>
NET CASH PROVIDED BY OPERATING ACTIVITIES
  Net income (loss)                         $          2.7  $      (1,206.4)  $ 1,209.1
  Depreciation                                       254.3            249.9         4.4
  Other non-cash items                                 6.3          1,338.0    (1,331.7)
  Changes in working capital items                    41.9             (1.0)       42.9
                                            --------------  ----------------  ----------
                                            $        305.2  $         380.5   $   (75.3)
                                            ==============  ================  ==========
</TABLE>

     Cash  generated  from  net  income  items  adjusted  for  non-cash activity
decreased $118.2 million. Cash provided by working capital items increased $42.9
million  due  to  lower  revenue resulting in a reduction in accounts receivable
coupled  with  an increase in net interest payable due to 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.


                                       36
<PAGE>
<TABLE>
<CAPTION>
                                                                     Six Months Ended June 30,
                                                                 ---------------------------------
                                                                        2003            2002         Change
                                                                 ---------------  ----------------  --------
                                                                                   (In millions)
<S>                                                              <C>              <C>               <C>
NET CASH USED IN INVESTING ACTIVITIES
  Capital expenditures                                           $        (50.2)  $         (81.2)  $  31.0
  Note issued to related party, net of repayments                         (45.3)                -     (45.3)
  Proceeds from disposal of assets                                          3.2              65.0     (61.8)
  Acquisition of 40% interest in DDII LLC, net of cash acquired            18.1                 -      18.1
  Other, net                                                                2.2                 -       2.2
                                                                 ---------------  ----------------  --------
                                                                 $        (72.0)  $         (16.2)  $ (55.8)
                                                                 ===============  ================  ========
</TABLE>

     Net  cash  used  in investing activities increased for the six months ended
June 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  quarter  capital  expenditures  (see "- Capital
Expenditures"). A note receivable of $46.1 million was issued to a related party
and we acquired ConocoPhillips' 40 percent interest in DDII LLC in May 2003 (see
Note  11  to  our  condensed  consolidated  financial  statements).

<TABLE>
<CAPTION>
                                                             Six Months Ended June 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                                 (919.2)           (119.6)   (799.6)
  Other, net                                                       12.3             (15.8)     28.1
                                                         ---------------  ----------------  --------
                                                         $       (733.4)  $        (461.8)  $(271.6)
                                                         ===============  ================  ========
</TABLE>

     We  repaid $326.4 million under our commercial paper program during the six
months ended June 30, 2002 while no such payment was made for the same period in
2003.  For  the  six  months ended June 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 $342.0 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
$69.0  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 R&B Falcon 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 six
months  ended  June  30,  2002.  Payment of dividends was discontinued after the
second  quarter  of  2002.

     CAPITAL  EXPENDITURES

     Capital expenditures totaled $50.2 million during the six months ended June
30,  2003.  During  2003,  we  expect to spend between $140.0 million and $150.0
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  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.


                                       37
<PAGE>
     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 net after-tax gain of $0.2 million.
The  proceeds  were  received  in  December  2002.

     During  the  six  months ended June 30, 2003, we settled an insurance claim
and sold certain other assets for net proceeds of approximately $3.2 million and
recorded  net  after-tax  gains  of  $1.4  million in our International and U.S.
Floater  Contract  Drilling  Services  segment  and  $0.2 million in our Gulf of
Mexico  Shallow  and  Inland  Water  segment.

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

     SOURCES  OF  LIQUIDITY

     Our  primary  sources  of  liquidity in the second quarter of 2003 were our
cash  flows  from operations and existing cash balances. The primary use of cash
was  debt  repayment.  At  June 30, 2003, we had $714.0 million in cash and cash
equivalents.

     We  anticipate  that we will rely primarily upon existing cash balances and
internally  generated  cash  flows  to maintain liquidity in 2003, as cash flows
from  operations  are  expected  to be positive and, together with existing cash
balances,  adequate  to  fulfill  anticipated  obligations.  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 initial public offering of our Gulf
of  Mexico Shallow and Inland Water business, as well as any proceeds from asset
sales  (see  "-Acquisitions  and  Dispositions"),  to  further  reduce  our debt
balances.

     We intend to use cash from operations primarily to pay debt as it comes due
and  to  fund  capital  expenditures.  If  we seek to reduce our debt other than
through  scheduled  maturities,  we  could  do  so  through  repayment  of  bank
borrowings  or through repurchases or redemptions of, or tender offers for, debt
securities.  At June 30, 2003 and December 31, 2002, our total debt was $3,758.3
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 six months ended June 30, 2003, we reduced
net  debt,  defined  as  total  debt  less  swap  receivables  and cash and cash
equivalents,  by  $238.2  million.  The components of net debt at carrying value
were  as  follows  (in  millions):

<TABLE>
<CAPTION>
                                  June 30,    December 31,
                                    2003          2002
                                 ----------  --------------
<S>                              <C>         <C>
Total Debt                       $ 3,758.3   $     4,678.0
Less: Cash and cash equivalents     (714.0)       (1,214.2)
   Swap receivables                      -          (181.3)
</TABLE>


                                       38
<PAGE>
     We  believe net debt provides useful information regarding the level of our
indebtedness  by  reflecting  cash  and  investments that could be 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 segments in which we operate. Should the drilling market deteriorate
further,  or should we experience poor results in our operations, cash flow from
operations  may be reduced. However, we have continued to generate positive cash
flow  from  operating  activities  over  recent  years.

     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 June 30, 2003,
none  of  the  credit  line  capacity  was  utilized.

     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  June  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.

<TABLE>
<CAPTION>
                                   For the twelve months ending June 30,
                         ----------------------------------------------------------
                          Total     2004      2005-2006     2007-2008   Thereafter
                         --------  -------  --------------  ----------  -----------
                                            (In millions)
<S>                      <C>       <C>      <C>             <C>         <C>
CONTRACTUAL OBLIGATIONS
Debt                     $3,567.5  $ 281.2  $        867.3  $    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


                                       39
<PAGE>
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  June  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  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 to repay our portion of the debt
and  equity  financing  with respect to Deepwater Drilling L.L.C. ("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. We could, however, decide
to  finance  these  amounts  with  new  debt.

<TABLE>
<CAPTION>
                                                          For the twelve months ending June 30,
                                                ----------------------------------------------------------
                                                 Total     2004      2005-2006     2007-2008   Thereafter
                                                --------  -------  --------------  ----------  -----------
                                                                   (In millions)
<S>                                             <C>       <C>      <C>             <C>         <C>
OTHER COMMERCIAL COMMITMENTS
Standby Letters of Credit                       $   78.7  $  65.2  $          6.3  $      7.2  $         -
Surety Bonds                                       159.6     96.5            63.1           -            -
Purchase Option Guarantees- Related Party (a)      151.8    151.8               -           -            -
Purchase Option Guarantees- Joint Ventures (a)      92.6     92.6               -           -            -
Other Commitments                                    0.1        -             0.1           -            -
                                                --------  -------  --------------  ----------  -----------
Total                                           $  482.8  $ 406.1  $         69.5  $      7.2  $         -
                                                ========  =======  ==============  ==========  ===========
<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 that have
aggregate market values netting to a liability of $2.9 million at June 30, 2003.
Our interest in these swaps has been included in accumulated other comprehensive
income,  net  of  tax,  with


                                       40
<PAGE>
corresponding  reductions  to  deferred  income  taxes  and  investments  in and
advances  to  joint  ventures  in  our  condensed  consolidated  balance  sheet.

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.

     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, Delta Towing also
failed  to  make  another  scheduled quarterly interest payment of $1.6 million.
During the six months ended June 30, 2003, we received partial interest payments
of approximately $0.6 million. At June 30, 2003, we had interest receivable from
Delta  Towing  of  $4.3  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 June
30,  2003,  the  carrying  value  of  the  notes  receivable, net of the related
allowance  for credit losses, was $54.8 million. We will establish a reserve for
interest  income  earned on the notes receivable and will apply cash payments to
interest  receivable currently outstanding and then to interest income for which
a  reserve  has  been  established.

     In May 2003, WestLB AG, one of the lenders in the synthetic lease financing
facility  to  which DDII LLC is the lessee, 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 June 30,
2003,  the  balance of the note receivable was $45.3 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 FIN 46, Consolidation of Variable Interest
Entities,  an  Interpretation  of  Accounting  Research  Bulletin  No.  51  (the
"Interpretation").  The Interpretation requires the consolidation of 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
Interpretation  is  effective  as  of  the beginning of the first interim period
beginning  after  June  15,  2003 for existing interests and immediately for new
interests.  Currently,  we  generally  consolidate  an  entity  when  we  have a
controlling  interest  through  ownership  of  a majority voting interest in the
entity.

     We  have  investments  in  and  advances  to  six joint ventures. One joint
venture,  DD  LLC, was established for the purpose of constructing and leasing a
drillship.  One  joint venture, Delta Towing, was established for the purpose of
owning  and  operating inland and shallow water marine support vessel equipment.
The  remaining four joint ventures were primarily established for the purpose of
owning  and operating certain drilling units. While the operations of DD LLC are
funded  from  cash  flows  from  operating activities, we guarantee the debt and
equity  financing  on  the drillship equally with our joint venture partner. The
debt  and  equity  financing  balance  for  the  leased  drillship  was  $192.6


                                       41
<PAGE>
million  at  August  1,  2003. We hold notes receivable from Delta Towing with a
carrying  value of $54.7 million at August 1, 2003. The remaining joint ventures
are  funded  primarily  by  cash  flows  from  operating  activities.

     We  account  for  these  investments 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.

     At  the  time  the  Delta Towing joint venture 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  Delta Towing joint venture also issued a $3.0
million  note  to  the  75  percent  joint  venture partner. Because we have the
largest  percentage  of investment at risk through the notes receivable, we will
absorb  the  majority  of the joint venture's expected losses and, therefore, we
are  deemed  to  be  the  primary  beneficiary  of  Delta  Towing for accounting
purposes.  As  such, we will consolidate Delta Towing effective July 1, 2003. We
expect  the  consolidation  of  Delta Towing to result in an increase in current
assets of approximately $5.0 million, an increase in property and equipment, net
of  approximately  $55.0  million,  a decrease in investments in and advances to
joint  ventures  of  approximately  $55.0  million,  an  increase  in  current
liabilities  of  approximately $1.0 million and an increase in long-term debt of
approximately  $3.0  million.

     We  are  currently evaluating the effects of adopting the Interpretation on
the  accounting  for  our  ownership  interest  in  our  other  joint  ventures.

     We  have  a  wholly  owned  subsidiary, DDII LLC, that was established as a
joint  venture  with  a  major  oil  company for the purpose of constructing and
leasing  a  drillship,  the Deepwater Frontier. The drillship was purchased by a
trust  that  was  established  to  finance  the purchase through debt and equity
financing,  which  we,  under certain circumstances, fully guarantee. On May 29,
2003,  the  Company  purchased  the  entire 40 percent interest of the major oil
company  in DDII LLC. We currently account for DDII LLC's lease of the drillship
as  an  operating lease. The balance of the trust's debt and equity financing at
June  30, 2003 was approximately $162.0 million. Because we are at risk for this
amount,  we are deemed to be the primary beneficiary of the trust for accounting
purposes  and  will  consolidate the trust effective July 1, 2003. The drillship
serves  as  collateral for the trust's debt and equity financing. Effective with
the consolidation of the trust, the debt and equity financing to be reflected in
our  balance  sheet  will  be  approximately  $153.0  million  and $9.0 million,
respectively.  The  debt financing will be reflected as debt due within one year
while  the  equity financing will be reflected as minority interest within other
long-term  liabilities  in  our  balance  sheet.  In  addition,  we  will record
approximately $207.0 million for the drillship as property and equipment, net in
our  balance  sheet  and  will eliminate our note receivable to related party of
$45.3  million (see Note 11 to our condensed consolidated financial statements).

     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 clients on a reimbursable basis are
recognized as operating and maintenance expense. In addition, the amounts billed
to  our clients 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. This statement
requires  an  issuer  to  measure  and classify as liabilities certain financial
instruments  that  have characteristics of both liabilities and equity. SFAS 150
applies to those instruments that represent, or are indexed to, an obligation to
buy  back  the issuer's shares and obligations that can be settled in shares and
meet  certain  conditions.  It does not, however, apply to financial instruments
that  are  indexed  to  and  potentially settled in an issuer's own shares. 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


                                       42
<PAGE>
will  adopt  this statement effective July 1, 2003. However, management does not
expect  the  adoption  of  this  statement  to  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 and West Africa,
oversupply  in  the  global  mid-water sector, outlook for the deepwater 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, the outcome and effect of the U.S. Internal
Revenue  Service  audit  and  the  various  tax  assessments,  deferred  costs,
amortization  expense, the planned initial public offering of our Gulf of Mexico
Shallow  and  Inland  Water  business  (including the timing of the offering and
portion  sold), the U.S. gas drilling market, planned asset sales, the Company's
other expectations with regard to market outlook, expected capital expenditures,
results and effects of legal proceedings, liabilities for tax issues, liquidity,
positive  cash  flow  from  operations, the exercise of the option of holders of
7.5% Notes, 1.5% Convertible Debentures or Zero Coupon Convertible Debentures to
require the Company to repurchase their securities, 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  and  DDII  LLC, adequacy of cash flow for 2003
obligations,  effects  of  accounting  changes,  and  the  timing  and  cost  of
completion  of  capital projects. Such statements are subject to numerous risks,
uncertainties  and  assumptions, including, but not limited to, worldwide demand
for oil and gas, uncertainties relating to the level of activity in offshore oil
and  gas  exploration and development, exploration success by producers, oil and
gas  prices  (including  U.S. natural gas prices), securities market conditions,
demand  for offshore and inland water rigs, competition and market conditions in
the  contract  drilling  industry,  our  ability  to  successfully integrate the
operations  of acquired businesses, delays or terminations of drilling contracts
due  to a number of events, delays or cost overruns on construction and shipyard
projects  and  possible cancellation of drilling contracts as a result of delays
or performance, our ability to enter into and the terms of future contracts, the
availability  of  qualified  personnel,  labor  relations  and  the  outcome  of
negotiations  with unions representing workers, operating hazards, political and
other  uncertainties  inherent  in  non-U.S.  operations (including exchange and
currency  fluctuations),  risks  of  war,  terrorism  and  cancellation  or
unavailability  of  certain  insurance coverage, the impact of governmental laws
and regulations, the adequacy of sources of liquidity, the effect and results of
litigation,  audits  and contingencies and other factors discussed in 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.


                                       43
<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 June 30 relating to debt obligations as of
June  30, 2003. Weighted-average variable rates are based on LIBOR rates at June
30,  2003,  plus  applicable  margins.

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

<TABLE>
<CAPTION>
                                                  Scheduled Maturity Date (a) (b)                    Fair Value
                            -----------------------------------------------------------------------  -----------
                             2004      2005      2006      2007     2008     Thereafter     Total     06/30/03
                            -------  ---------  -------  --------  -------  ------------  ---------  -----------
<S>                         <C>      <C>        <C>      <C>       <C>      <C>           <C>        <C>
Total debt
  Fixed Rate                $131.2   $  392.3   $400.0   $ 100.0   $269.0   $   2,050.0   $3,342.5   $   3,868.5
    Average interest rate      8.5%       6.8%     1.5%      7.5%     6.7%          7.5%       6.7%
  Variable Rate             $150.0   $   75.0        -         -        -             -   $  225.0   $     225.0
    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 June 30, 2003, we had approximately $225.0 million of variable rate debt
at face value (six 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 $1.2 million in
interest expense per year. Offsetting this, a large part of our cash investments
would  earn  commensurately  higher  rates  of  return. Using June 30, 2003 cash
investment  levels,  a  one  percent  increase in interest rates would result in
approximately  $7.1  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 client
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  client  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 June 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 $1.5
million  after-tax loss on the revaluation of the local currency into functional
U.S  dollars  for  the  six  months  ended  June  30,  2003.


                                       44
<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 June 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 June 30, 2003 that has materially
affected,  or  is  reasonably likely to materially affect, our internal controls
over  financial  reporting.


                                       45
<PAGE>
PART  II  -  OTHER  INFORMATION

ITEM  1.  LEGAL  PROCEEDINGS

     In  March 1997, an action was filed by Mobil Exploration and Producing U.S.
Inc.  and  affiliates,  St.  Mary  Land & Exploration Company and affiliates and
Samuel  Geary  and  Associates  Inc.  against  one  of  our subsidiaries, Cliffs
Drilling,  our  underwriters  at  Lloyd's  (the "Underwriters") and an insurance
broker  in  the  16th Judicial District Court of St. Mary Parish, Louisiana. The
plaintiffs  alleged  damages  in  excess  of  $50 million in connection with the
drilling of a turnkey well in 1995 and 1996. The case was tried before a jury in
January  and February 2000, and the jury returned a verdict of approximately $30
million  in favor of the plaintiffs for excess drilling costs, loss of insurance
proceeds,  loss  of hydrocarbons, expenses and interest. We and the Underwriters
appealed  such  judgment,  and the Louisiana Court of Appeals reduced the amount
for  which  we  may  be  responsible  to  less  than $10 million. The plaintiffs
requested  that the Supreme Court of Louisiana consider the matter and reinstate
the original verdict. We and the Underwriters also appealed to the Supreme Court
of Louisiana requesting that the Court reduce the verdict or, in the case of the
Underwriters,  eliminate  any  liability  for  the verdict. Prior to the Supreme
Court of Louisiana ruling on these petitions, we settled with the St. Mary group
of  plaintiffs  and  the  State of Louisiana. Subsequently, the Supreme Court of
Louisiana  denied  the applications of all remaining plaintiffs. We settled with
all  remaining  plaintiffs  in  the  second quarter of 2003. We believe that any
amounts,  apart  from  a small deductible, paid in the settlement are covered by
relevant  primary and excess liability insurance policies. However, the insurers
and  the  Underwriters  have  denied all coverage. We have instituted litigation
against those insurers and Underwriters to enforce our rights under the relevant
policies.  One  group of issuers has asserted a counterclaim against us claiming
that  they  issued  the policy as a result of misrepresentation. The settlements
did not have a material adverse effect on our business or consolidated financial
position.  We  do not expect the ultimate outcome of the case to 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.

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

     At  the  Annual  General  Meeting  of  Transocean Inc. held on May 8, 2003,
272,757,297  shares  were  represented  in person or by proxy out of 319,767,820
shares  entitled  to  vote  as  of  the  record  date,  constituting  a  quorum.

     The  matters  submitted  to a vote of shareholders were (i) the election of
Class  I Directors as set forth in the Company's Proxy Statement relating to the
meeting;  (ii)  the amendment of the Company's Long-Term Incentive Plan to allow
grants  or  incentive  stock options for an additional ten year period to May 1,
2013  and  to  allow  a  continuing  right  to  grant  stock  options  and share
appreciation  rights  to  our  outside  directors;  (iii)  the  amendment of the
Company's Employee Stock Purchase Plan to increase the number of ordinary shares
reserved  for  issuance under the plan from 1,500,000 to 2,500,000; and (iv) the
approval  of  appointment of Ernst & Young LLP as independent auditors for 2003.
With respect to the re-election of directors, the following number of votes were
cast  as to the Class I Director nominees: Victor E. Grijalva, 240,921,742 votes
for  and 31,835,555 votes withheld; Arthur Lindenauer, 260,182,393 votes for and
12,574,904 withheld; Richard A. Pattarozzi, 260,792,569 votes for and 11,964,728
votes  withheld;  Kristian  Siem, 258,264,644 votes for and 14,492,653 withheld;
and  J.  Michael  Talbert,  259,108,809 votes for and 13,648,488 votes withheld.
With  respect  to  the  amendment  of  the  Company's  Long-Term Incentive Plan,
242,440,573  votes  were  cast  for  the proposal and 26,645,604 votes were cast
against  the  proposal.  There  were  2,668,773 abstentions and 1,002,347 broker
non-votes  in  the  vote  on  the proposal. With respect to the amendment of the
Company's  Employee  Stock  Purchase  Plan,  264,793,085 votes were cast for the
proposal  and  4,412,002  votes  were  cast  against  the  proposal.  There were
2,549,863  abstentions  and  1,002,347  broker  non-votes  in  the  vote  on the


                                       46
<PAGE>
proposal.  With  respect  to  the Company's appointment of independent auditors,
there  were 239,819,902 votes for and 11,517,370 votes withheld on the proposal.
There  were  21,420,025  abstentions  and  no  broker non-votes on the proposal.






                                       47
<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)

+10.1     Amended  and  Restated  Long-Term  Incentive  Plan of Transocean Inc.,
          effective  May  8,  2003

*10.2     Amended  and Restated Employee Stock Purchase Plan of Transocean Inc.,
          effective  May  8,  2003 (incorporated by reference to Exhibit 10.1 to
          the  Registration  Statement on Form S-8 (Registration No. 333-106026)
          filed  by  the  Company  on  June  11,  2003)

+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 May 6, 2003 (information
furnished  not  filed)  announcing  the issuance of first quarter 2003 financial
results  and a Current Report on Form 8-K on May 28, 2003 (information furnished
not  filed)  announcing  financial  information  pertaining  to  operating  and
maintenance  expense  and cash operating costs for the first quarter of 2003 and
the  fourth  quarter  of  2002.


                                       48
<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  August 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)


                                       49
<PAGE>