~~YEAR~~UNITED WATER DRILLING ENTERED DEPTH DEPTH SERVICE/ CAPACITY CAPACITY ESTIMATED TYPE AND NAME UPGRADED(A) (IN FEET) (IN FEET) LOCATION CUSTOMER EXPIRATION (E) ---------------------------------- ----------- --------- --------- ---------------- ------------- --------------- HIGH-SPECIFICATION DRILLSHIPS (12) Deepwater Discovery (b) . . . . . . 2000 10,000 30,000 Angola ChevronTexaco December 2003 Deepwater Expedition (b). . . . . . 1999 10,000 30,000 Brazil Petrobras September 2005 Deepwater Frontier (b)(d) . . . . . 1999 10,000 30,000 Brazil Petrobras November 2003 Deepwater Millennium (b). . . . . . 1999 10,000 30,000 U.S. Gulf Marathon October 2002 Deepwater Pathfinder (b)(c) . . . . 1998 10,000 30,000 U.S. Gulf Conoco January 2004 Discoverer Deep Seas (b). . . . . . 2001 10,000 35,000 U.S. Gulf ChevronTexaco January 2006 Discoverer Enterprise (b) . . . . . 1999 10,000 35,000 U.S. Gulf BP December 2004 Discoverer Spirit (b) . . . . . . . 2000 10,000 35,000 U.S. Gulf Unocal September 2005 Deepwater Navigator (b) . . . . . . 2000 7,800 25,000 Brazil Petrobras July 2003 Peregrine I (b) . . . . . . . . . . 1982/1996 7,200 25,000 Brazil Petrobras June 2003 Discoverer 534 (b). . . . . . . . . 1975/1991 7,000 25,000 Enroute to India Reliance June 2002 Discoverer Seven Seas (b) . . . . . 1976/1997 7,000 25,000 Brazil Petrobras September 2004 OTHER DRILLSHIPS (1) Joides Resolution (b)(f). . . . . . 1978 27,000 30,000 Peru Texas A&M September 2003 ------------------------- (a) Dates shown are the original service date and the date of the most recent upgrade, if any. (b) Dynamically positioned. 5 (c) The Deepwater Pathfinder is leased and operated by a limited liability company in which we own a 50 percent interest. See Note 16 to our consolidated financial statements. (d) The Deepwater Frontier is leased and operated by a limited liability company in which we own a 60 percent interest. See Note 16 to our consolidated financial statements. (e) Expiration dates represent our current estimate of the earliest date the contract for each rig is likely to expire. Some contracts may permit the client to extend the contract. (f) The Joides Resolution is currently engaged in scientific geological coring activities and is owned by a joint venture in which we have a 50 percent interest. See Note 16 to our consolidated financial statements.STATES

~~YEAR~~SECURITIES ~~WATER DRILLING ENTERED DEPTH DEPTH SERVICE/ CAPACITY CAPACITY ESTIMATED TYPE~~ AND ~~NAME~~EXCHANGE UPGRADED(A) (IN FEET) (IN FEET) LOCATION CUSTOMER EXPIRATION (C) ------------------------- ----------- --------- --------- ----------------- ------------- -------------- HIGH-SPECIFICATION SEMISUBMERSIBLES (19) Deepwater Horizon . . . . 2001 10,000 30,000 U.S. Gulf BP September 2004 Cajun Express (b) . . . . 2001 8,500 35,000 U.S. Gulf - Idle Deepwater Nautilus (d). . 2000 8,000 30,000 U.S. Gulf Shell June 2005 Sedco Energy (b). . . . . 2001 7,500 25,000 Ivory Coast ChevronTexaco October 2004 Sedco Express (b) . . . . 2001 7,500 25,000 Egypt BP May 2002 Transocean Marianas . . . 1979/1998 7,000 25,000 U.S. Gulf Shell August 2003 Sedco 707 (b) . . . . . . 1976/1997 6,500 25,000 Brazil Petrobras January 2004 Jack Bates. . . . . . . . 1986/1997 6,000 30,000 U.K. North Sea BP April 2002 Sedco 709 (b) . . . . . . 1977/1999 5,000 25,000 Nigeria Shell May 2002 M. G. Hulme, Jr. (e). . . 1983/1996 5,000 25,000 Nigeria ExxonMobil June 2002 Transocean Richardson . . 1988 5,000 25,000 U.S. Gulf Anadarko September 2002 Jim Cunningham . . . . . 1982/1995 5,000 25,000 Angola ExxonMobil August 2002 Transocean Leader . . . . 1987/1997 4,500 25,000 U.K. North Sea BP March 2003 Transocean Rather . . . . 1988 4,500 25,000 U.S. Gulf BP January 2003 Sovereign Explorer. . . . 1984 4,000 25,000 Enroute to Amerada Hess March 2003 Equatorial Guinea Henry Goodrich. . . . . . 1985 2,000 30,000 Canada Terra Nova February 2003 Paul B. Loyd, Jr. . . . . 1990 2,000 25,000 U.K. North Sea BP March 2003 Transocean Arctic . . . . 1986 1,650 25,000 Norwegian N. Sea - Idle Polar Pioneer. . . . . . 1985 1,500 25,000 Norwegian N. Sea Norsk Hydro February 2003COMMISSION

YEAR WATER DRILLING ENTERED DEPTH DEPTH SERVICE/ CAPACITY CAPACITY ESTIMATED TYPE AND NAME UPGRADED(A) (IN FEET) (IN FEET) LOCATION CUSTOMER EXPIRATION (C) --------------------------- ----------- --------- --------- ----------------- ------------- -------------- OTHER SEMISUBMERSIBLES (29) Sedco 710 (b) . . . . . . . 1983 4Washington,~~000~~ ~~25,000 Brazil Petrobras October 2006 Sedco 700~~ D. . . . . . . . . 1973/1997 3,600 25,000 Equatorial Guinea Amerada Hess October 2002 Transocean Amirante . . . . 1978/1997 3,500 25,000 U.S. Gulf - Idle Transocean Legend . . . . . 1983 3,500 25,000 Brazil Petrobras March 2002 C. Kirk Rhein, Jr. . . . . 1976/1997 3,300 25,000 Trinidad - Idle Transocean Driller. . . . . 1991 3,000 25,000 Brazil Petrobras January 2003 Falcon 100. . . . . . . . . 1974/1999 2,400 25,000 U.S. Gulf Agip May 2002 Transocean 96 . . . . . . . 1975/1997 2,300 25,000 U.S. Gulf Anadarko March 2002 Sedco 711 . . . . . . . . . 1982 1,800 25,000 U.K. North Sea ExxonMobil May 2002 U.K. North Sea Conoco November 2002 Transocean John Shaw . . . 1982 1,800 25,000 U.K. North Sea TotalFinaElf December 2002 Sedco 714 . . . . . . . . . 1983/1997 1,600 25,000 U.K. North Sea BP October 2002 Sedco 712 . . . . . . . . . 1983 1,600 25,000 U.K. North Sea Shell December 2002 Actinia . . . . . . . . . . 1982 1,500 25,000 Spain Repsol March 2002 Mediterranean I.E.O.C. September 2002 J. W. McLean. . . . . . . . 1974/1996 1,500 25,000 U.K. North Sea Phillips April 2002 Sedco 600 . . . . . . . . . 1983/1994 1,500 25,000 Indonesia Conoco April 2002 Sedco 601 . . . . . . . . . 1983 1,500 25,000 Indonesia Unocal December 2002 Sedco 602 . . . . . . . . . 1983 1,500 25,000 Indonesia - Idle Sedco 702 . . . . . . . . . 1973/1992 1,500 25,000 Australia Apache March 2002 Australia Santos April 2002 Australia Agip July 2002 Sedco 703 . . . . . . . . . 1973/1995 1,500 25,000 Australia Woodside May 2002 Australia El Paso June 2002 Sedco 708 . . . . . . . . . 1976 1,500 25,000 Congo - Idle Sedneth 701 . . . . . . . . 1972/1993 1,500 25,000 Angola ChevronTexaco March 2002 Gabon Vaalco June 2002 Transocean Prospect . . . . 1983/1992 1,500 25,000 Norwegian N. Sea Statoil August 2002 Transocean Searcher . . . . 1983/1988 1,500 25,000 Norwegian N. Sea Statoil August 2002 Norwegian N. Sea Statoil February 2003 Transocean Winner . . . . . 1983 1,500 25,000 Norwegian N. Sea Shell July 2002 Transocean Wildcat. . . . . 1977/1985 1,300 25,000 U.K. North Sea - Idle Transocean Explorer . . . . 1976 1,250 25,000 U.K. North Sea - Idle Sedco 704 . . . . . . . . . 1974/1993 1,000 25,000 U.K. North Sea ChevronTexaco October 2002 Sedco 706 . . . . . . . . . 1976/1994 1,000 25,000 U.K. North Sea TotalFinaElf June 2002 Sedco I - Orca (f). . . . . 1970/1987 900 25,000 South Africa Schlumberger March 2003 --------------------------- (a) Dates shown are the original service date and the date of the most recent upgrade, if any. (b) Dynamically positioned. (c) Expiration dates represent our current estimate of the earliest date the contract for each rig is likely to expire. Some rigs have two contracts in continuation, so the second line shows the estimated earliest availability. Some contracts may permit the client to extend the contract. (d) The Deepwater Nautilus is leased from its owner, an unrelated third party, pursuant to a fully defeased lease arrangement. (e) The M. G. Hulme, Jr. is accounted for as an operating lease as a result of a sale/leaseback transaction in November 1995. (f) Operated under a management contract with the rig's owner.20549

YEAR ENTERED WATER DEPTH DRILLING DEPTH SERVICE/ CAPACITY CAPACITY TYPE AND NAME UPGRADED(A) (IN FEET) (IN FEET) LOCATION STATUS ------------------- ------------- ------------ --------------- ----------------- --------- Trident IX (b). . . 1982 400 21,000 Vietnam Operating Trident 17. . . . . 1983 355 25,000 Indonesia Operating Harvey H. Ward. . . 1981 300 25,000 Singapore Idle J. T. Angel . . . . 1982 300 25,000 India Operating Roger W. Mowell . . 1982 300 25,000 Malaysia Operating Ron Tappmeyer . . . 1978 300 25,000 Indonesia Operating D. R. Stewart . . . 1980 300 25,000 Italy Operating Randolph Yost . . . 1979 300 25,000 Equatorial Guinea Operating C. E. Thornton. . . 1974 300 25,000 India Operating F. G. McClintock. . 1975 300 25,000 India Operating Shelf Explorer. . . 1982 300 25,000 Denmark Operating Transocean III. . . 1978/1993 300 20,000 United Arab Operating Emirates Transocean Nordic . 1984 300 25,000 U.K. North Sea Idle Trident II. . . . . 1977/1985 300 25,000 India Operating Trident IV. . . . . 1980/1999 300 25,000 Angola Operating Trident VI. . . . . 1981 300 21,000 Nigeria Operating Trident VIII. . . . 1981 300 21,000 Nigeria Operating Trident XII . . . . 1982/1992 300 25,000 India Operating Trident XIV . . . . 1982/1994 300 20,000 Angola Operating Trident 15. . . . . 1982 300 25,000 Thailand Operating Trident 16. . . . . 1982 300 25,000 Malaysia Operating Trident 20 (c). . . 2000 300 25,000 Caspian Sea Operating George H. Galloway. 1985 300 25,000 U.S. Gulf Idle Transocean Comet. . 1980 250 20,000 Egypt Operating Transocean Mercury. 1969/1998 250 20,000 Egypt Operating RBF 208 . . . . . . 1980 200 20,000 Brazil Idle RBF 209 . . . . . . 1980 200 25,000 Brazil Operating RBF 192 . . . . . . 1981 250 25,000 U.S. Gulf Idle RBF 250 . . . . . . 1974 250 25,000 U.S. Gulf Idle RBF 251 . . . . . . 1978 250 25,000 U.S. Gulf Idle RBF 252 . . . . . . 1978 250 25,000 U.S. Gulf Idle RBF 253 . . . . . . 1982 250 25,000 U.S. Gulf Idle RBF 254 . . . . . . 1976 250 25,000 U.S. Gulf Idle RBF 255 . . . . . . 1976 250 25,000 U.S. Gulf Idle RBF 256 . . . . . . 1975 250 25,000 U.S. Gulf Idle RBF 190 . . . . . . 1978 200 25,000 U.S. Gulf Idle RBF 200 . . . . . . 1979 200 25,000 U.S. Gulf Operating RBF 201 . . . . . . 1981 200 25,000 U.S. Gulf Idle RBF 202 . . . . . . 1982 200 25,000 U.S. Gulf Operating RBF 203 . . . . . . 1981 200 25,000 U.S. Gulf Idle RBF 204 . . . . . . 1981 200 25,000 U.S. Gulf Operating RBF 205 . . . . . . 1979 200 25,000 U.S. Gulf Operating RBF 206 . . . . . . 1980 200 25,000 U.S. Gulf Idle RBF 207 . . . . . . 1981 200 25,000 U.S. Gulf Idle RBF 185 . . . . . . 1982 190 25,000 U.S. Gulf Idle 8 YEAR ENTERED WATER DEPTH DRILLING DEPTH SERVICE/ CAPACITY CAPACITY TYPE AND NAME UPGRADED(A) (IN FEET) (IN FEET) LOCATION STATUS ------------------- ------------- ------------ --------------- ----------------- --------- RBF 191 . . . . . . 1978 184 25,000 U.S. Gulf Idle RBF 150 . . . . . . 1979 150 20,000 U.S. Gulf Operating RBF 151 . . . . . . 1981 150 25,000 U.S. Gulf Idle RBF 152 . . . . . . 1980 150 25,000 U.S. Gulf Idle RBF 153 . . . . . . 1980 150 25,000 U.S. Gulf Idle RBF 154 . . . . . . 1979 150 20,000 U.S. Gulf Idle RBF 155 . . . . . . 1980 150 20,000 U.S. Gulf Idle RBF 156 . . . . . . 1983 150 25,000 U.S. Gulf Idle RBF 110 . . . . . . 1982 110 25,000 Trinidad Operating ---------------------------- (a) Dates shown are the original service date and the date of the most recent upgrade, if any. (b) As of March 1, 2002, the Trident IX was owned by an unrelated third party and leased by us as part of a secured rig financing. See Note 23 to our consolidated financial statements. (c) Owned by a joint venture in which we have a 75 percent interest._________________

~~YEAR ENTERED SERVICE/ DRILLING CAPACITY RIG UPGRADED(A) (IN FEET) LOCATION STATUS~~ FORM 10------------------------ ------------- ------------------ --------- --------- CONVENTIONAL BARGES (14) 1. . . . . . . . . . . . 1980 20,000 U.S. Gulf Operating 11 . . . . . . . . . . . 1982 30,000 U.S. Gulf Operating 15 . . . . . . . . . . . 1981 25,000 U.S. Gulf Idle 19 . . . . . . . . . . . 1996 14,000 U.S. Gulf Operating 20 . . . . . . . . . . . 1998 14,000 U.S. Gulf Idle 21 . . . . . . . . . . . 1982 15,000 U.S. Gulf Idle 23 . . . . . . . . . . . 1995 14,000 U.S. Gulf Idle 28 . . . . . . . . . . . 1979 30,000 U.S. Gulf Operating 29 . . . . . . . . . . . 1980 30,000 U.S. Gulf Idle 30 . . . . . . . . . . . 1981 30,000 U.S. Gulf Idle 31 . . . . . . . . . . . 1981 30,000 U.S. Gulf Operating 32 . . . . . . . . . . . 1982 30,000 U.S. Gulf Operating 74 (b) . . . . . . . . . 1981 25,000 U.S. Gulf Idle 75 (b) . . . . . . . . . 1979 30,000 U.S. Gulf IdleK

~~YEAR ENTERED SERVICE/ DRILLING CAPACITY UPGRADED~~(A)Mark ~~(IN FEET~~one) LOCATION STATUS ------------- ------------------ --------- --------- POSTED BARGES (17) 7 . . . . . . . . 1978 25,000 U.S. Gulf Idle 9 . . . . . . . . 1981 25,000 U.S. Gulf Idle 10 . . . . . . . . 1981 25,000 U.S. Gulf Idle 17 . . . . . . . . 1981 30,000 U.S. Gulf Idle 27 . . . . . . . . 1978 30,000 U.S. Gulf Idle 41 . . . . . . . . 1981 30,000 U.S. Gulf Operating 46 . . . . . . . . 1981 30,000 U.S. Gulf Idle 47 . . . . . . . . 1982 30,000 U.S. Gulf Idle 48 . . . . . . . . 1982 30,000 U.S. Gulf Idle 49 . . . . . . . . 1980 30,000 U.S. Gulf Idle 52 . . . . . . . . 1981 25,000 U.S. Gulf Operating 55 . . . . . . . . 1981 30,000 U.S. Gulf Idle 56 . . . . . . . . 1973 25,000 U.S. Gulf Idle 57 . . . . . . . . 1975 25,000 U.S. Gulf Idle 61 . . . . . . . . 1978 30,000 U.S. Gulf Idle 62 . . . . . . . . 1978 30,000 U.S. Gulf Operating 64 . . . . . . . . 1979 30,000 U.S. Gulf Idle

~~YEAR~~x ~~ENTERED~~ANNUAL ~~SERVICE/~~REPORT ~~DRILLING~~PURSUANT ~~CAPACITY~~TO ~~UPGRADED(A)~~SECTION ~~(IN~~13 ~~FEET)~~OR ~~LOCATION STATUS ------------- ------------------ --------- --------- SWAMP BARGES~~ 15(4d) ~~Searex~~OF 4THE .SECURITIES .EXCHANGE .ACT .OF 1981/1989 25,000 Nigeria Idle Searex 6 . . . . 1981/1991 25,000 Nigeria Operating Searex 12. . . . 1982/1992 25,000 Nigeria Operating Hibiscus (c) . . 1979/1993 16,000 Indonesia Operating -------------------- (a) Dates shown are the original service date and the date of the most recent upgrade, if any. (b) These rigs are leased to us. (c) The Hibiscus is owned by a joint venture in which we own more than 50 percent.1934

~~AGE~~For ASthe OFfiscal ~~OFFICER~~year ~~OFFICE~~ended ~~MARCH 1~~December 31, 2002 -------------------------- -------------------------------------------------------------- ------------- J. Michael Talbert . . . . Chief Executive Officer and Director 55 Robert L. Long . . . . . . President 56 W. Dennis Heagney. . . . . Executive Vice President and Chief Operating Officer 54 Jean P. Cahuzac. . . . . . Executive Vice President, Operations 48 Jon C. Cole. . . . . . . . Executive Vice President, Shallow Water and Inland Water Operations 49 Donald R. Ray. . . . . . . Executive Vice President, Technical Services 55 Eric B. Brown. . . . . . . Senior Vice President, General Counsel and Corporate Secretary 50 Gregory L. Cauthen . . . . Vice President, Chief Financial Officer and Treasurer 44 Barbara S. Koucouthakis. . Vice President and Chief Information Officer 43 Ricardo H. Rosa. . . . . . Vice President and Controller 45 Jurgen Sager . . . . . . . Vice President, Human Resources 43 Brian C. Voegele . . . . . Vice President, Tax 42 Michael I. Unsworth. . . . Vice President, Marketing 432008

PRICE ---------------- HIGH LOW ------- ------- 2000 First Quarter . . . . . . . . . . . . . . . . . . . . . . $53.125 $29.250 Second Quarter. . . . . . . . . . . . . . . . . . . . . . 56.188 41.250 Third Quarter . . . . . . . . . . . . . . . . . . . . . . 64.625 45.625 Fourth Quarter. . . . . . . . . . . . . . . . . . . . . . 65.500 34.375 2001 First Quarter . . . . . . . . . . . . . . . . . . . . . . $54.500 $40.600 Second Quarter. . . . . . . . . . . . . . . . . . . . . . 57.690 40.350 Third Quarter . . . . . . . . . . . . . . . . . . . . . . 37.680 23.050 Fourth Quarter. . . . . . . . . . . . . . . . . . . . . . 34.220 24.200 2002 First Quarter (through February 28) . . . . . . . . . . . $33.460 $26.510OR

~~YEARS~~o ~~ENDED~~TRANSITION ~~DECEMBER~~REPORT ~~31,~~PURSUANT ~~------------------------------------------------------~~TO ~~2001~~SECTION ~~2000~~13 ~~1999~~OR ~~1998 1997 ------- ------ ------ ------ ------~~ 15(~~IN MILLIONS, EXCEPT PER SHARE DATA~~d) ~~STATEMENT~~ OF ~~OPERATIONS~~THE ~~Operating~~SECURITIES ~~revenues.~~EXCHANGE .ACT . . . . . . . . $ 2,820 $1,230 $ 648 $1,091 $ 891 Operating income. . . . . . . . . . . 550 133 49 377 299 Income before extraordinary items . . 272 107 58 342 260 Earnings per share Basic . . . . . . . . . . . . . . $ 0.88 $ 0.51 $ 0.53 (a) $ 3.12 (a) $ 2.38 (a) Diluted . . . . . . . . . . . . . $ 0.86 $ 0.50 $ 0.53 (a) $ 3.12 (a) $ 2.38 (a) OTHER FINANCIAL DATA Cash flows from operating activities. $ 567 $ 196 $ 241 $ 473 $ 318 Capital expenditures. . . . . . . . . 506 575 537 425 187 EBITDA (b). . . . . . . . . . . . . . 1,191 401 186 508 420 BALANCE SHEET DATA (AT END OF PERIOD) Total assets. . . . . . . . . . . . . $17,020 $6,359 $6,140 $1,473 $1,051 Total debt. . . . . . . . . . . . . . 5,024 1,453 1,266 100 160 Total equity. . . . . . . . . . . . . 10,910 4,004 3,910 564 363 Dividends per share . . . . . . . . . $ 0.12 $ 0.12 - - - -------------------- (a) Unaudited pro forma earnings per share was calculated using the Transocean Sedco Forex Inc. ordinary shares issued pursuant to the Sedco Forex merger agreement and the dilutive effect of Transocean Sedco Forex Inc. stock options granted to former Sedco Forex employees at the time of the Sedco Forex merger, as applicable. (b) Earnings before interest, taxes, depreciation and amortization ("EBITDA") is presented here because it is a widely accepted financial indication of a company's ability to incur and service debt. EBITDA measures presented may not be comparable to similarly titled measures used by other companies. EBITDA is not a measurement presented in accordance with accounting principles generally accepted in the United States ("GAAP") and is not intended to be used in lieu of GAAP presentations of results of consolidated operations and cash provided by operating activities.1934

~~YEARS~~For ~~ENDED~~the ~~DECEMBER~~transition ~~31,~~period ~~------------------~~from %_____ ~~2001~~to ~~2000 CHANGE CHANGE -------- -------- -------- ------- (IN MILLIONS, EXCEPT % CHANGE) OPERATING REVENUES International and U~~_____.S. Floater Contract Drilling Services . . . . . . . . . . . . . . . . . . . $2,424.1 $1,229.5 $1,194.6 97% Gulf of Mexico Shallow and Inland Water. . . . . 396.0 - 396.0 100% -------- -------- -------- ------- $2,820.1 $1,229.5 $1,590.6 129% ======== ======== ======== =======

~~YEARS~~Commission ~~ENDED~~file ~~DECEMBER~~number ~~31,~~ 000---------------- % 2001 2000 CHANGE CHANGE -------- ------ ------- ------- (IN MILLIONS, EXCEPT % CHANGE) OPERATING AND MAINTENANCE International and U.S. Floater Contract Drilling Services . . . . . . . . . . . . . . . . . . . $1,358.6 $812.6 $ 546.0 67% Gulf of Mexico Shallow and Inland Water. . . . . 244.7 - 244.7 100% -------- ------ ------- ------- $1,603.3 $812.6 $ 790.7 97% ======== ====== ======= =======53533

YEARS ENDED DECEMBER 31, -------------- % 2001 2000 CHANGE CHANGE ------ ------ ------- ------- (IN MILLIONS, EXCEPT % CHANGE) DEPRECIATION International and U.S. Floater Contract Drilling Services . . . . . . . . . . . . . . . . . . . $379.2 $232.8 $ 146.4 63% Gulf of Mexico Shallow and Inland Water. . . . . 90.9 - 90.9 100% ------ ------ ------- ------- $470.1 $232.8 $ 237.3 102% ====== ====== ======= =======_________________

~~YEARS ENDED DECEMBER 31, ------------- % 2001 2000 CHANGE CHANGE ------ ----- ------- ------- (IN MILLIONS, EXCEPT % CHANGE) GOODWILL AMORTIZATION International and U~~TRANSOCEAN LTD.S. Floater Contract Drilling Services . . . . . . . . . . . . . . . . . . . $114.2 $26.7 $ 87.5 328% Gulf of Mexico Shallow and Inland Water. . . . . 40.7 - 40.7 100% ------ ----- ------- ------- $154.9 $26.7 $ 128.2 480% ====== ===== ======= =======

~~YEARS ENDED DECEMBER 31, ------------ % 2001 2000 CHANGE CHANGE ----- ----- ------- -------~~ (INExact ~~MILLIONS,~~name ~~EXCEPT~~of %registrant ~~CHANGE)~~as ~~GENERAL~~specified ~~AND~~in ~~ADMINISTRATIVE.~~its ~~. . . . $57.9 $42.1 $ 15.8 38% ===== ===== ======= =======~~charter)

~~YEARS ENDED DECEMBER 31~~Zug, ~~-------------~~Switzerland ~~% 2001 2000 CHANGE CHANGE~~ 98------- ---- -------- ------- (IN MILLIONS, EXCEPT % CHANGE) IMPAIRMENT LOSS ON LONG-LIVED ASSETS International and U.S. Floater Contract Drilling Services . . . . . . . . . . . . . . . . . . . $(36.3) - $ (36.3) 100% Gulf of Mexico Shallow and Inland Water. . . . . (4.1) - (4.1) 100% ------- ---- -------- ------- $(40.4) - $ (40.4) 100% ======= ==== ======== =======0599916

~~YEARS ENDED DECEMBER 31, ------------ % 2001 2000 CHANGE CHANGE ----- ----- ------- -------~~ (INState ~~MILLIONS,~~or ~~EXCEPT~~other %jurisdiction ~~CHANGE) GAIN FROM SALE OF ASSETS, NET~~ (I. R. S. ~~$56.5 $17.8 $ 38.7 217% ===== ===== ======= =======~~Employer

~~YEARS ENDED DECEMBER 31, ---------------- % 2001 2000 CHANGE CHANGE -------- ------ -------- ------- (IN MILLIONS, EXCEPT % CHANGE) OTHER INCOME (EXPENSE), NET Equity in earnings~~ of ~~joint~~incorporation ~~ventures~~or ~~. . . . $ 16.5 $ 9.4 $ 7.1 76% Interest income. . . . . . . . . . . . . . . 18.7 6.2 12.5 202% Interest expense, net of amounts capitalized (223.9~~organization) ~~(3.0)~~Identification ~~(220~~No.9) ~~7,363% Other, net . . . . . . . . . . . . . . . . . (0.8) (1.3) 0.5 38% -------- ------ -------- ------- $(189.5) $11.3 $(200.8) 1,777% ======== ====== ======== =======~~

~~YEARS~~Blandonnet ~~ENDED~~International ~~DECEMBER~~Business ~~31, ------------ % 2001 2000 CHANGE CHANGE ----- ----- ------- ------- (IN MILLIONS, EXCEPT % CHANGE) INCOME TAX EXPENSE $85.7 $36.7 $ 49.0 134% ===== ===== ======= =======~~Center

~~YEARS~~Chemin ~~ENDED~~de ~~DECEMBER~~Blandonnet 31, -------------- % 2001 2000 CHANGE CHANGE ------- ----- -------- ------- (IN MILLIONS, EXCEPT % CHANGE) GAIN (LOSS) ON EXTRAORDINARY ITEMS, NET OF TAX $(19.3) $ 1.4 $ (20.7) 1,479% ======= ===== ======== =======2

~~YEARS~~Building ~~ENDED DECEMBER 31~~F, ~~----------------~~7th ~~% 2000 1999 CHANGE CHANGE -------- ------ ------- ------- (IN MILLIONS, EXCEPT % CHANGE) OPERATING REVENUES $1,229.5 $648.2 $ 581.3 90% ======== ====== ======= =======~~Floor

~~YEARS ENDED DECEMBER 31~~Vernier, ~~--------------~~Switzerland ~~% 2000 1999 CHANGE CHANGE ------ ------ ------- ------- (IN MILLIONS, EXCEPT % CHANGE) OPERATING AND MAINTENANCE $812.6 $448.9 $ 363.7 81% ====== ====== ======= =======~~1214

~~YEARS ENDED DECEMBER 31, -------------- % 2000 1999 CHANGE CHANGE ------ ------ ------- -------~~ (INAddress ~~MILLIONS,~~of ~~EXCEPT~~principal %executive ~~CHANGE~~offices) ~~DEPRECIATION~~(Zip ~~. . . . . . . . . $232.8 $131.9 $ 100.9 76% ====== ====== ======= =======~~code)

~~YEARS~~Registrant's ~~ENDED~~telephone ~~DECEMBER 31~~number, ~~------------~~including %area ~~2000~~code: ~~1999~~+41 ~~CHANGE CHANGE ----- ----- ------- -------~~ (~~IN MILLIONS, EXCEPT % CHANGE~~22) ~~GOODWILL AMORTIZATION . . . . . . . . . $26.7 $~~ 930- ~~$ 26.7 100% ===== ===== ======= =======~~9000

~~YEARS~~Securities ~~ENDED~~registered ~~DECEMBER~~pursuant ~~31,~~to ~~------------~~Section ~~% 2000 1999 CHANGE CHANGE ----- ----- ------- -------~~ 12(~~IN MILLIONS, EXCEPT % CHANGE~~b) ~~GENERAL~~of ~~AND~~the ~~ADMINISTRATIVE . . . . . . . . . $42.1 $16.8 $ 25.3 151% ===== ===== ======= =======~~Act:

~~YEARS~~Title ~~ENDED~~of ~~DECEMBER~~class ~~31,~~Exchange ~~--------------~~on %which ~~2000 1999 CHANGE CHANGE ----- ------ ------- ------- (IN MILLIONS, EXCEPT % CHANGE) GAIN (LOSS) FROM SALE OF ASSETS, NET . . . . . . . . . $17.8 $(1.3) $ 19.1 1,469% ===== ====== ======= =======~~registered

~~YEARS ENDED DECEMBER 31~~Shares, ~~--------------~~par %value ~~2000~~CHF 1999 CHANGE CHANGE ------ ------- -------- ------- (IN MILLIONS, EXCEPT % CHANGE) OTHER INCOME (EXPENSE), NET Equity in earnings of joint ventures . . . . $ 9.4 $ 5.6 $ 3.8 68% Interest income. . . . . . . . . . . . . . . 6.2 5.4 0.8 15~~% Interest expense, net of amounts capitalized (3~~.0)00 ~~(10.3)~~per ~~7.3~~share ~~71%~~New ~~Other,~~York ~~net~~Stock ~~. . . . . . . . . . . . . . . . . (1.3) (0.7) (0.6) 86% ------ ------- -------- ------- $11.3 $ - $ 11.3 100% ====== ======= ======== =======~~Exchange

~~YEARS~~Securities ~~ENDED~~registered ~~DECEMBER~~pursuant ~~31,~~to ~~-------------~~Section ~~% 2000 1999 CHANGE CHANGE ----- ------ ------- -------~~ 12(~~IN MILLIONS, EXCEPT % CHANGE~~g) ~~INCOME~~of ~~TAX~~the ~~EXPENSE~~Act: ~~(BENEFIT) . . . . . . . . . . .$36.7 $(9.3) $ 46.0 495% ===== ====== ======= =======~~None

THREE MONTHS ENDED ----------------------------------------------- DECEMBER 31, SEPTEMBER 30, DECEMBER 31, 2001 2001 2000 (A) -------------- --------------- -------------- AVERAGE DAYRATES INTERNATIONAL AND U.S. FLOATER CONTRACT DRILLING SERVICES SEGMENT: High-Specification Floaters. . . . . . . . . . $ 145,000 $ 144,500 $ 124,300 Other Floaters . . . . . . . . . . . . . . . . 71,100 66,600 56,000 Jackups - Non-U.S. . . . . . . . . . . . . . . 52,800 49,200 37,100 Other. . . . . . . . . . . . . . . . . . . . . 41,300 42,500 41,400 -------------- --------------- -------------- Segment Total. . . . . . . . . . . . . . . . . . . 88,200 86,600 72,000 -------------- --------------- -------------- GULF OF MEXICO SHALLOW AND INLAND WATER SEGMENT: Jackups and Submersibles . . . . . . . . . . . 30,600 37,700 32,000 Inland Barges. . . . . . . . . . . . . . . . . 22,800 24,400 20,000 -------------- --------------- -------------- Segment Total. . . . . . . . . . . . . . . . . . . 25,600 30,000 26,300 -------------- --------------- -------------- Total Mobile Offshore Drilling Fleet . . . . . . . $ 74,000 $ 66,900 $ 54,200 ============== =============== ============== UTILIZATION INTERNATIONAL AND U.S. FLOATER CONTRACT DRILLING SERVICES SEGMENT: High-Specification Floaters. . . . . . . . . . 90% 87% 92% Other Floaters . . . . . . . . . . . . . . . . 89% 82% 70% Jackups - Non-U.S. . . . . . . . . . . . . . . 89% 84% 86% Other. . . . . . . . . . . . . . . . . . . . . 54% 48% 47% -------------- --------------- -------------- Segment Total. . . . . . . . . . . . . . . . . . . 86% 81% 78% -------------- --------------- -------------- GULF OF MEXICO SHALLOW AND INLAND WATER SEGMENT: Jackups and Submersibles . . . . . . . . . . . 27% 52% 70% Inland Barges. . . . . . . . . . . . . . . . . 49% 75% 65% -------------- --------------- -------------- Segment Total. . . . . . . . . . . . . . . . . . . 38% 63% 67% -------------- --------------- -------------- Total Mobile Offshore Drilling Fleet . . . . . . . 67% 73% 74% ============== =============== ============== -------------------- (a) Pro forma based on the combined fleet of Transocean Sedco Forex and R&B Falcon._________________

~~YEARS~~Indicate ~~ENDED~~by ~~DECEMBER~~check ~~31,~~mark ~~------------------------~~whether ~~2001~~the ~~2000~~registrant ~~CHANGE~~is ~~--------~~a well-~~-------------~~known ~~--------~~seasoned ~~(In~~issuer, ~~millions)~~as ~~NET~~defined ~~CASH~~in ~~PROVIDED~~Rule BY405 ~~OPERATING~~of ~~ACTIVITIES~~the ~~Net~~Securities ~~income~~Act. .Yes .x .No . . . . . . . . . . . $ 252.6 $ 108.5 $ 144.1 Depreciation and amortization . . . . . 625.0 259.5 365.5 Non-cash items. . . . . . . . . . . . . (202.6) (90.9) (111.7) Working capital . . . . . . . . . . . . (108.2) (81.2) (27.0) -------- -------------- -------- $ 566.8 $ 195.9 $ 370.9 ======== ============== ========o

~~YEARS~~Indicate ~~ENDED~~by ~~DECEMBER~~check ~~31,~~mark ~~------------------------~~if ~~2001~~the ~~2000~~registrant ~~CHANGE~~is ~~--------~~not ~~--------------~~required ~~--------~~to ~~(In~~file ~~millions)~~reports ~~NET~~pursuant ~~CASH~~to ~~USED~~Section IN13 ~~INVESTING~~or ~~ACTIVITIES~~Section ~~Capital expenditures . . . . . . . . . . . . $~~15(~~506.2~~d) ~~$ (574.7) $ 68.5 Proceeds from sale~~ of ~~coiled~~the ~~tubing~~Exchange ~~drilling services business~~Act. .Yes .o .No . . . . . . . . . - 24.9 (24.9) Proceeds from sale of securities . . . . . . 17.2 - 17.2 Proceeds from disposal of assets . . . . . . 201.7 56.3 145.4 Merger costs paid. . . . . . . . . . . . . . (24.4) (4.5) (19.9) R&B Falcon cash at acquisition . . . . . . . 264.7 - 264.7 Other, net . . . . . . . . . . . . . . . . . 20.6 5.1 15.5 -------- -------------- -------- $ (26.4) $ (492.9) $ 466.5 ======== ============== ========x

~~YEARS~~Indicate ~~ENDED~~by ~~DECEMBER~~check ~~31,~~mark ~~--------------------------~~whether ~~2001~~the ~~2000~~registrant ~~CHANGE ---------- -------------- ----------~~ (~~In millions~~1) has ~~NET~~filed ~~CASH~~all ~~PROVIDED~~reports BYrequired ~~FINANCING~~to ~~ACTIVITIES~~be ~~Net~~filed ~~borrowings~~by ~~under~~Section ~~commercial~~13 ~~paper~~or ~~program~~15(d) $of ~~326.4~~the $Securities -Exchange $Act ~~326.4 Net proceeds from issuance~~ of ~~debt.~~1934 .during .the .preceding .12 .months ~~1,693.5~~(or ~~489.1~~for ~~1,204.4~~such ~~Early~~shorter ~~repayments~~period ofthat ~~debt~~the ~~instruments.~~registrant .was .required .to .file ~~(1,495.0)~~such ~~(233.8~~reports) (1,~~261.2)~~ ~~Net~~and ~~repayments on revolving credit agreements~~ (~~180.1~~2) has ~~(56.3)~~been ~~(123.8)~~subject ~~Other,~~to ~~net.~~such .filing .requirements .for .the .past .90 days. Yes x ~~. . . . . . . . . . (66.3) (33.2) (33.1) ---------- -------------- ---------- $ 278.5 $ 165.8 $ 112.7 ========== ============== ==========~~No o

ASIndicate OFby ~~DECEMBER~~check ~~31,~~mark ~~2001~~if ~~------------------------------------------------~~disclosure ~~LESS~~of ~~THAN~~delinquent 1filers TOpursuant 3to 4Item -405 5of ~~AFTER~~Regulation ~~TOTAL 1 YEAR YEARS YEARS 5 YEARS~~ S-~~-----~~K ~~----------~~is ~~----------~~not ~~------~~contained ~~--------~~herein, ~~(IN~~and ~~MILLIONS)~~will ~~CONTRACTUAL~~not ~~OBLIGATIONS~~be ~~Debt. . . . . . . . . . $4~~contained,~~995~~ $to ~~484~~the $best ~~1,711~~of $registrant's ~~500 $ 2~~knowledge,~~300~~ ~~Operating~~in ~~Leases.~~definitive .proxy .or .information ~~127~~statements 28incorporated 66by 12reference 21in ~~------~~Part ~~----------~~III ~~----------~~of ~~------~~this Form 10-~~-------~~K ~~Total~~or ~~Obligations~~any .amendment .to ~~$5,122 $ 512 $ 1,777 $ 512 $ 2,321 ====== ========== ========== ====== ========~~this Form 10-K. x

ASIndicate OFby ~~DECEMBER~~check ~~31,~~mark ~~2001~~whether ~~----------------------------------------------~~the ~~LESS~~registrant ~~THAN~~is 1a TOlarge 3accelerated 4filer, -an 5accelerated ~~AFTER~~filer, ~~TOTAL~~a ~~1 YEAR YEARS YEARS 5 YEARS~~ non-~~-----~~accelerated ~~----------~~filer, ~~--------~~or ------ -------- (IN MILLIONS) OTHER COMMERCIAL COMMITMENTS Standby Letters of Credit . . $ 38 $ 34 $ 4 $ - $ - Surety Bonds. . . . . . . . . 190 124 66 - - Purchase Option Guarantees - Joint Ventures (a). .smaller company. .See .definitions ~~209~~of -"large ~~209~~accelerated -filer," -"accelerated ~~Other~~filer" ~~Commitments~~and ."smaller .reporting .company" .in .Rule ~~. 4 4~~ 12b-2 -of -the ~~------~~Exchange ~~---------- -------- ------ -------- Total~~ Act. ~~. . . . . . . . . . $ 441 $ 162 $ 279 $ - $ - ====== ========== ======== ====== ======== -------------------- (a) See "-Special Purpose Entities".~~

~~SCHEDULED~~Large ~~MATURITY~~accelerated ~~DATE~~filer ~~FAIR~~x Accelerated ~~VALUE~~ filer o Non-~~----------------------------------------------------------------~~accelerated ~~---------- 2002 2003 2004 2005 2006 THEREAFTER TOTAL 12/31/01 ------- ------- ------- ------- ---- ------------ --------- ---------- Total debt Fixed Rate~~filer (a) . . . . . . . . . . . . $ 58.0 $382.6 $ 61.4 $419.6 - $ 2,965.0 $3,886.6 $ 3,586.2 Average interest rate. . . . . . . 6.7% 7.1% 6.5% 7.0% - 5.5% 5.8% Variable Rate . . . . . . . . . . . . $100.0 $150.0 $150.0 - - - $ 400.0 $ 400.0 Average interest rate. . . . . . . 2.6% 2.6% 2.6% - - - 2.6% Receive Fixed/Pay Variable Swaps(b) . . . . . . . . . . . . . - - - - - $ 700.0 $ 700.0 $ 689.2 Average interest rate. . . . . . . - - - - - 2.4% 2.4% Commercial Paper. . . . . . . . . . . . $326.4 - - - - - $ 326.4 $ 326.4 Average interest rate. . . . . . . 3.2% - - - - - 3.2% -------------------- (a) Expected maturity amounts are based on the face value of debt and do not ~~reflect~~check ~~fair~~if ~~market~~a ~~value~~smaller ofreporting ~~debt. (b~~company) o Smaller ~~The~~reporting ~~6.625% Notes are considered variable as a result of the interest rate swaps. See Note 8 to our consolidated financial statements.~~company o

~~TRANSOCEAN~~Indicate ~~SEDCO~~by ~~FOREX~~check ~~INC.~~mark ~~AND~~whether ~~SUBSIDIARIES~~the ~~CONSOLIDATED~~registrant ~~STATEMENTS~~is OFa ~~OPERATIONS~~shell ~~(IN~~company MILLIONS, EXCEPT PER SHARE) YEARS ENDED DECEMBER 31, ----------------------------- 2001 2000 1999 --------- --------- ------- OPERATING REVENUES . . . . . . . . . . . . . . . . $2,820.1 $1,229.5 $648.2 --------- --------- ------- COSTS AND EXPENSES Operating and maintenance . . . . . . . . . . . 1,603.3 812.6 448.9 Depreciation. . . . . . . . . . . . . . . . . . 470.1 232.8 131.9 Goodwill amortization . . . . . . . . . . . . . 154.9 26.7 - General and administrative. . . . . . . . . . . 57.9 42.1 16.8 --------- --------- ------- 2,286.2 1,114.2 597.6 --------- --------- ------- Impairment Loss on Long-Lived Assets . . . . . . . (~~40.4)~~as -defined -by ~~Gain~~Rule ~~(Loss) from Sale of Assets, net . . . . . . . 56.5 17.8 (1.3)~~ 12b--------- --------- ------- OPERATING INCOME . . . . . . . . . . . . . . . . . 550.0 133.1 49.3 --------- --------- ------- OTHER INCOME (EXPENSE), NET Equity in earnings of joint ventures. . . . . . 16.5 9.4 5.6 Interest income . . . . . . . . . . . . . . . . 18.7 6.2 ~~5.4 Interest expense, net~~ of ~~amounts~~the ~~capitalized.~~Exchange ~~. (223.9~~Act) (3.0) ~~(10.3)~~Yes ~~Other,~~o ~~net.~~No . . . . . . . . . . . . . . . . . . (0.8) (1.3) (0.7) --------- --------- ------- (189.5) 11.3 - --------- --------- ------- INCOME BEFORE INCOME TAXES, MINORITY INTEREST AND EXTRAORDINARY ITEMS. . . . . . . . 360.5 144.4 49.3 Income Tax Expense (Benefit) . . . . . . . . . . . 85.7 36.7 (9.3) Minority Interest. . . . . . . . . . . . . . . . . 2.9 0.6 0.5 --------- --------- ------- INCOME BEFORE EXTRAORDINARY ITEMS. . . . . . . . . 271.9 107.1 58.1 Gain (Loss) on Extraordinary Items, net of tax . . (19.3) 1.4 - --------- --------- ------- NET INCOME . . . . . . . . . . . . . . . . . . . . $ 252.6 $ 108.5 $ 58.1 ========= ========= ======= BASIC EARNINGS PER SHARE (UNAUDITED PRO FORMA PRIOR TO THE EFFECTIVE DATE OF THE SEDCO FOREX MERGER) Income Before Extraordinary Items . . . . . . . $ 0.88 $ 0.51 $ 0.53 Gain (Loss) on Extraordinary Items, net of tax. (0.06) 0.01 - --------- --------- ------- Net Income . . . . . . . . . . . . . . . . . $ 0.82 $ 0.52 $ 0.53 ========= ========= ======= DILUTED EARNINGS PER SHARE (UNAUDITED PRO FORMA PRIOR TO THE EFFECTIVE DATE OF THE SEDCO FOREX MERGER) Income Before Extraordinary Items . . . . . . . $ 0.86 $ 0.50 $ 0.53 Gain (Loss) on Extraordinary Items, net of tax. (0.06) 0.01 - --------- --------- ------- Net Income . . . . . . . . . . . . . . . . . $ 0.80 $ 0.51 $ 0.53 ========= ========= ======= WEIGHTED AVERAGE SHARES OUTSTANDING (UNAUDITED PRO FORMA PRIOR TO THE EFFECTIVE DATE OF THE SEDCO FOREX MERGER) Basic . . . . . . . . . . . . . . . . . . . . . 309.2 210.4 109.6 --------- --------- ------- Diluted . . . . . . . . . . . . . . . . . . . . 314.8 211.7 109.6 --------- --------- ------- DIVIDENDS PAID PER SHARE . . . . . . . . . . . . . $ 0.12 $ 0.12 $ -x

~~TRANSOCEAN~~As ~~SEDCO~~of ~~FOREX INC. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (In millions~~June 30, ~~except share data) DECEMBER 31~~2008, -------------------- 2001 2000 ---------- -------- ASSETS Cash and Cash Equivalents . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 853.4 $ 34.5 Accounts Receivable Trade . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 602.9 268.9 Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 72.8 27.1 Materials and Supplies. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 158.8 89.5 Deferred Income Taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21.0 18.1 Other Current Assets. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27.9 10.0 ---------- -------- Total Current Assets. . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1319,~~736.8 448.1 ---------- -------- Property and Equipment. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10~~044,~~081.4~~814 ~~6,003.2~~shares ~~Less~~were ~~Accumulated~~outstanding ~~Depreciation . . . . . . . . . . . . . . . . . . . . . . . . . . 1,713.3 1,308.2 ---------- -------- Property~~ and ~~Equipment,~~the ~~net~~aggregate .market .value .of .shares .held .by ~~. . . . . . . . . . . . . . . . . . . . 8,368.1 4,695.0~~ non-~~---------~~affiliates ~~--------~~was ~~Goodwill,~~approximately net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6,466.7 1,037.9 Investments in and Advances to Joint Ventures . . . . . . . . . . . . . . . . . . 28.2 105.9 Note Receivable from Related Party. . . . . . . . . . . . . . . . . . . . . . . . 78.9 - Other Assets. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 341.1 71.9 ---------- -------- Total Assets. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $~~17,019~~48.~~8 $~~6~~,358.8~~ billion ~~==========~~(based ~~========~~on ~~LIABILITIES~~the ~~AND~~reported ~~SHAREHOLDERS'~~closing ~~EQUITY~~market ~~Accounts~~price ~~Payable.~~of .the .ordinary .shares .of Transocean Inc. .on .such .date .of ~~. . . . . . . . . . . . . . . . . . . . . . .~~ $ ~~188~~152.439 $and ~~135.6~~assuming ~~Accrued~~that ~~Income~~all ~~Taxes.~~directors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 188.2 113.1 Debt Due Within One Year. . . . . . . . . . . . . . . . . . . . . . . . . . . . . 484.4 23.1 Other Current Liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . 283.4 223.4 ---------- -------- Total Current Liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . 1,144.4 495.2 ---------- -------- Long-Term Debt. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4,539.4 1,430.3 Deferred Income Taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 317.1 359.2 Other Long-Term Liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . 108.6 70.0 ---------- -------- Total Long-Term Liabilities . . . . . . . . . . . . . . . . . . . . . . . . . 4,965.1 1,859.5 ---------- -------- Commitments and ~~Contingencies~~executive ~~Preference~~officers ~~Shares,~~of ~~$0.10~~the ~~par~~Company ~~value;~~are 50"affiliates,~~000,000~~" ~~shares~~although ~~authorized,~~the ~~none~~Company does ~~issued~~not ~~and~~acknowledge ~~outstanding~~that .any .such .person .is .actually .an ."affiliate" .within .the .meaning .of .the .federal .securities laws). .As .of ~~. . . . . . . . . . . . . . . . . - - Ordinary Shares~~February 20, ~~$0.01 par value; 800~~2009,~~000,000~~ ~~shares authorized~~319, ~~318~~660,~~816,035~~304 ~~and 210,710,363~~ shares ~~issued~~were ~~and~~ outstanding ~~at December 31, 2001 and 2000, respectively~~. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.2 2.1 Additional Paid-in Capital. . . . . . . . . . . . . . . . . . . . . . . . . . . . 10,611.7 3,918.7 Accumulated Other Comprehensive Income. . . . . . . . . . . . . . . . . . . . . . (2.3) - Retained Earnings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 297.7 83.3 ---------- -------- Total Shareholders' Equity. . . . . . . . . . . . . . . . . . . . . . . . . . 10,910.3 4,004.1 ---------- -------- Total Liabilities and Shareholders' Equity. . . . . . . . . . . . . . . . . . $17,019.8 $6,358.8 ========== ========

~~TRANSOCEAN~~DOCUMENTS ~~SEDCO~~INCORPORATED ~~FOREX~~BY INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF EQUITY (In millions, except per share data) ACCUMULATED ORDINARY SHARES ADDITIONAL OTHER ------------------ PAID-IN COMPREHENSIVE RETAINED PRE-MERGER TOTAL SHARES AMOUNT CAPITAL INCOME EARNINGS EQUITY EQUITY --------- ------- ------------ --------------- ---------- ------------ ---------- Balance at December 31, 1998 $ 564.4 $ 564.4 Net income 58.1 58.1 Advances from related parties and other 299.6 299.6 Merger with Transocean Offshore Inc.. . 210.1 $ 2.1 $ 3,908.0 $ - $ - (922.1) 2,988.0 --------- ------- ------------ --------------- ---------- ------------ ---------- Balance at December 31, 1999. . . . . . . 210.1 2.1 3,908.0 - - - 3,910.1 Net income. . . . . . . . . . . . . . . - - - - 108.5 - 108.5 Issuance of ordinary shares under stock-based compensation plans. . . . 0.6 - 16.6 - - - 16.6 Other . . . . . . . . . . . . . . . . . - - (5.9) - - - (5.9) Cash dividends ($0.12 per share). . . . - - - - (25.2) - (25.2) --------- ------- ------------ --------------- ---------- ------------ ---------- Balance at December 31, 2000. . . . . . . 210.7 2.1 3,918.7 - 83.3 - 4,004.1 Net income. . . . . . . . . . . . . . . - - - - 252.6 - 252.6 Shares issued for R&B Falcon merger. . . . . . . . . . . . . . . . 106.1 1.1 6,654.9 - - - 6,656.0 Issuance of ordinary shares under stock-based compensation plans. . . . 1.6 - 45.2 - - - 45.2 Issuance of ordinary shares upon exercise of warrants. . . . . . . . . 0.6 - 10.6 - - - 10.6 Other . . . . . . . . . . . . . . . . . (0.2) - (17.7) - - - (17.7) Cash dividends ($0.12 per share). . . . - - - - (38.2) - (38.2) Gain on terminated interest rate swaps. - - - 3.9 - - 3.9 Fair value adjustment on marketable securities held for sale. . . . . . . - - - (0.6) - - (0.6) Other comprehensive income related to joint venture. . . . . . . - - - (5.6) - - (5.6) --------- ------- ------------ --------------- ---------- ------------ ---------- Balance at December 31, 2001. . . . . . . 318.8 $ 3.2 $ 10,611.7 $ (2.3) $ 297.7 $ - $10,910.3 ========= ======= ============ =============== ========== ============ ==========REFERENCE

~~TRANSOCEAN~~ Portions ~~SEDCO~~of ~~FOREX~~the ~~INC.~~registrant's ~~AND~~definitive ~~SUBSIDIARIES~~Proxy ~~CONSOLIDATED~~Statement STATEMENTS OF CASH FLOWS (In millions) YEARS ENDED DECEMBER 31, ---------------------------- 2001 2000 1999 -------- -------- -------- CASH FLOWS FROM OPERATING ACTIVITIES Net income. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 252.6 $ 108.5 $ 58.1 Adjustments to ~~reconcile~~be ~~net~~filed ~~income~~with tothe ~~net~~Securities ~~cash provided by operating activities Depreciation~~ and ~~amortization~~Exchange .Commission .within .120 days . . . . . . . . . . . . . . . . . . . . 625.0 259.5 131.9 Deferred income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . (98.2) (30.1) (24.3) 1999 charges . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . - - 29.4 Equity in earnings of joint ventures. . . . . . . . . . . . . . . . . . . . (16.5) (9.4) (5.6) Net (gain) loss from sale of assets . . . . . . . . . . . . . . . . . . . . (52.5) (15.0) 1.3 Impairment loss on long-lived assets. . . . . . . . . . . . . . . . . . . . 40.4 - - Amortization of debt-related discounts/premiumsDecember 31, ~~fair value adjustments and issue costs~~2008, ~~net.~~for .its .2009 .annual .general .meeting . . . . . . . . . . . . . . . (4.0) 9.4 - Deferred income, net. . . . . . . . . . . . . . . . . . . . . . . . . . . . (46.5) (20.7) (26.2) Deferred expenses, net. . . . . . . . . . . . . . . . . . . . . . . . . . . (53.8) (18.6) - Extraordinary (gain) loss on debt extinguishment, net of ~~tax. . . . . . . . 19.3 (1.4) - Tax benefit from exercise of stock options. . . . . . . . . . . . . . . . . 9.6 1.9 - Other~~shareholders, ~~net.~~are .incorporated . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (0.4) (7.0) (0.1) Changes in operating assets and liabilities, net of effects from the R&B Falcon merger Accounts receivable . . . . . . . . . . . . . . . . . . . . . . . . . . . . (55.2) (5.9) 100.5 Accounts payable and other accrued liabilities. . . . . . . . . . . . . . . (95.9) (58.6) (22.5) Receivable/payable with related parties, net. . . . . . . . . . . . . . . . - - 19.5 Income taxes receivable/payable, net. . . . . . . . . . . . . . . . . . . . 48.2 1.2 (21.5) Other current assets. . . . . . . . . . . . . . . . . . . . . . . . . . . . (5.3) (17.9) 0.1 -------- -------- -------- Net Cash Provided by ~~Operating~~reference ~~Activities~~into .Part III . . . . . . . . . . . . . . . . . . . 566.8 195.9 240.6 -------- -------- -------- CASH FLOWS FROM INVESTING ACTIVITIES Capital expenditures. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (506.2) (574.7) (537.0) Proceeds from sale of ~~coiled~~this ~~tubing drilling services business. . . . . . . . .~~ Form 10- 24K.9 - Proceeds from sale of securities. . . . . . . . . . . . . . . . . . . . . . . . 17.2 - - Proceeds from sale of subsidiary. . . . . . . . . . . . . . . . . . . . . . . . 85.6 - - Other proceeds from disposal of assets, net . . . . . . . . . . . . . . . . . . 116.1 56.3 0.7 Merger costs paid . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (24.4) (4.5) - Cash acquired in merger, net of cash paid . . . . . . . . . . . . . . . . . . . 264.7 - 439.8 Joint ventures and other investments, net . . . . . . . . . . . . . . . . . . . 20.6 5.1 6.3 -------- -------- -------- Net Cash Used in Investing Activities . . . . . . . . . . . . . . . . . . . . . . (26.4) (492.9) (90.2) -------- -------- --------

TRANSOCEAN ~~SEDCO FOREX INC~~LTD. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (CONTINUED) (In millions) YEARS ENDED DECEMBER 31, ------------------------------ 2001 2000 1999 ---------- -------- -------- CASH FLOWS FROM FINANCING ACTIVITIES Net borrowings under commercial paper program. . . . . . . . . . . . . . 326.4 - - Net proceeds from issuance of debt . . . . . . . . . . . . . . . . . . . 1,693.5 489.1 - Early repayments of debt instruments . . . . . . . . . . . . . . . . . . (1,495.0) (233.8) - Net repayments on revolving credit agreements. . . . . . . . . . . . . . (180.1) (54.9) - Other repayments of debt instruments . . . . . . . . . . . . . . . . . . (56.0) (21.1) (15.3) Proceeds from issuance of ordinary shares under stock-based compensation plans. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29.6 13.7 - Proceeds from issuance of ordinary shares upon exercise of warrants. . . 10.6 - - Dividends paid . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (38.2) (25.3) - Financing costs. . . . . . . . . . . . . . . . . . . . . . . . . . . . . (15.2) (2.6) - Net repayments of debt to related parties. . . . . . . . . . . . . . . . - - (407.4) Advances and other from related parties, net . . . . . . . . . . . . . . - - 265.5 Other, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.9 0.7 (2.0) ---------- -------- -------- Net Cash Provided by (Used in) Financing Activities. . . . . . . . . . . . 278.5 165.8 (159.2) ---------- -------- -------- Net Increase (Decrease) in Cash and Cash Equivalents . . . . . . . . . . . 818.9 (131.2) (8.8) ---------- -------- -------- Cash and Cash Equivalents at Beginning of Period . . . . . . . . . . . . . 34.5 165.7 174.5 ---------- -------- -------- Cash and Cash Equivalents at End of Period . . . . . . . . . . . . . . . . $ 853.4 $ 34.5 $ 165.7 ========== ======== ========

~~YEARS~~INDEX ~~ENDED~~TO ~~DECEMBER~~ANNUAL ~~31,~~REPORT ~~----------------------~~ON ~~2001 2000 1999~~ FORM 10------- ------ ----- Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $252.6 $108.5 $58.1 Gain on terminated interest rate swaps . . . . . . . . . . . . . . . . . . . . 3.9 - - Unrealized loss on securities available for sale . . . . . . . . . . . . . . . (0.6) - - Share of unrealized loss in unconsolidated joint venture's interest rate hedge (5.6) - - ------- ------ ----- Total comprehensive income . . . . . . . . . . . . . . . . . . . . . . . . . $250.3 $108.5 $58.1 ======= ====== =====K

~~DECEMBER~~FOR ~~31,~~THE ~~2001~~YEAR ~~--------------~~ENDED ~~Gain~~DECEMBER 31, on terminated interest rate swaps . . . . . . . . . . . . . . . . . . . . $ 3.9 Unrealized loss on securities available for sale . . . . . . . . . . . . . . . (0.6) Share of unrealized loss in unconsolidated joint venture's interest rate hedge (5.6) -------------- Accumulated other comprehensive income. . . . . . . . . . . . . . . . . . . $ (2.3) ==============2008

YEARS ENDED DECEMBER 31, ------------------------ 2001 2002 ----------- ----------- Operating revenues . . . . . . . . . . . $ 2,946.0 $ 2,292.4 Operating income . . . . . . . . . . . . 549.5 129.9 Income (loss) from continuing operations 257.6 (300.6) Earnings (loss) per share: Basic and Diluted. . . . . . . . . . . $ 0.80 $ (0.95)

Item		Page

	PART I
ITEM 1.	Business	4
ITEM 1A.	Risk Factors	14
ITEM 1B.	Unresolved Staff Comments	21
ITEM 2.	Properties	21
ITEM 3.	Legal Proceedings	21
ITEM 4.	Submission of Matters to a Vote of Security Holders	25

	PART II
ITEM 5.	Market for Registrant's Common Equity, Related Shareholder Matters and Issuer Purchases of Equity Securities	27
ITEM 6.	Selected Financial Data	30
ITEM 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations	32
ITEM 7A.	Quantitative and Qualitative Disclosures About Market Risk	56
ITEM 8.	Financial Statements and Supplementary Data	57
ITEM 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	107
ITEM 9A.	Controls and Procedures	107
ITEM 9B.	Other Information	107

	PART III
ITEM 10.	Directors, Executive Officers and Corporate Governance	107
ITEM 11.	Executive Compensation	107
ITEM 12.	Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters	107
ITEM 13.	Certain Relationships and Related Transactions, and Director Independence	107
ITEM 14.	Principal Accountant Fees and Services	107

	PART IV
ITEM 15.	Exhibits and Financial Statement Schedules	108

~~Year ended December 31, 1999~~ -~~-----------------~~ ~~Operating~~2 ~~revenues . . . . . . . . . . . $ 1,579.1 Operating income . . . . . . . . . . . . 291.1 Net income . . . . . . . . . . . . . . . 237.9 Earnings per share: Basic and Diluted . . . . . . . . . . $ 1.13~~-

~~DECEMBER 31,~~ Forward-~~-----------------~~Looking ~~2001~~Information 2000 -------- -------- Commercial Paper. . . . . . . . . . . . . . . . . . . . . . . . . . $ 326.4 $ - 6.5% Senior Notes, due April 2003 . . . . . . . . . . . . . . . . . 240.5 - 9.125% Senior Notes, due December 2003. . . . . . . . . . . . . . . 92.0 - Amortizing Term Loan Agreement - Final Maturity December 2004. . . 400.0 400.0 550 million Revolving Credit Agreement, due December 2005. . . . . - 180.1 7.31% Nautilus Class A1 Amortizing Notes - Final Maturity May 2005. 142.9 - 9.41% Nautilus Class A2 Notes, due May 2005 . . . . . . . . . . . . 52.4 - 6.75% Senior Notes, due April 2005. . . . . . . . . . . . . . . . . 354.6 - Secured Rig Financing . . . . . . . . . . . . . . . . . . . . . . . 50.6 68.6 6.95% Senior Notes, due April 2008. . . . . . . . . . . . . . . . . 252.3 - 9.5% Senior Notes, due December 2008. . . . . . . . . . . . . . . . 348.1 - 6.625% Notes, due April 2011. . . . . . . . . . . . . . . . . . . . 711.7 - 7.375% Senior Notes, due April 2018 . . . . . . . . . . . . . . . . 250.5 - Zero Coupon Convertible Debentures, due May 2020. . . . . . . . . . 512.2 497.7 1.5% Convertible Debentures, due May 2021 . . . . . . . . . . . . . 400.0 - 8% Debentures, due April 2027 . . . . . . . . . . . . . . . . . . . 197.9 197.9 7.45% Notes, due April 2027 . . . . . . . . . . . . . . . . . . . . 94.4 94.1 7.5% Notes, due April 2031. . . . . . . . . . . . . . . . . . . . . 597.3 - 6.9% Notes. . . . . . . . . . . . . . . . . . . . . . . . . . . . . - 14.9 Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . - 0.1 -------- -------- Total Debt. . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5,023.8 1,453.4 Less Debt Due Within One Year . . . . . . . . . . . . . . . . . . . 484.4 23.1 -------- -------- Total Long-Term Debt. . . . . . . . . . . . . . . . . . . . . . . . $4,539.4 $1,430.3 ======== ========

~~Years~~The ~~Ended~~statements ~~December~~included ~~31,~~in ~~-------------~~this ~~2002~~annual .report .regarding .future .financial .performance .and .results .of .operations .and .other .statements .that .are $not ~~484.4~~historical ~~2003~~facts .are .forward-looking .statements .within .the .meaning .of .Section .27A .of .the .Securities .Act .of ~~532.3~~1933 ~~2004~~and .Section .21E .of .the .Securities .Exchange .Act .of 1934. ~~. . . . . 211.4 2005 . . . . . . . . . . . . . . 423.4 2006 . . . . . . . . . . . . . .~~ Forward-looking ~~Thereafter~~statements .in .this .annual .report .include, .but .are .not limited ~~. . . 3~~to,~~650.0~~ ~~-------------~~statements ~~Total.~~about .the .following ~~. . . . . . . . . $ 5,301.5 =============~~subjects:

~~Years~~• ~~ended~~the ~~December~~offshore 31drilling market, ~~-------------------------~~including ~~2001~~supply ~~2000~~and ~~1999~~demand, ~~-------~~utilization ~~-------~~rates, ~~-------~~dayrates, ~~Current~~customer ~~provision~~drilling .programs, .commodity .prices, .effects .of .new .rigs .on .the .market .and .effects .of .declines .in .commodity .prices .and .downturn .in ~~$174.2~~global $economy ~~66.5~~on $market ~~15.0~~outlook ~~Deferred~~for ~~benefit~~our .various .geographical .operating .sectors .and .classes ~~. . . . . . . . . . . . . . (98.2) (30.1) (24.3) ------- ------- ------- Income tax expense (benefit) after extraordinary items. . 76.0 36.4 (9.3) Tax effect~~ of ~~extraordinary items . . . . . . . . . . . . 9.7 0.3 - ------- ------- ------- Income Tax Expense (Benefit) before Extraordinary Items . $ 85.7 $ 36.7 $ (9.3) ======= ======= =======~~rigs,

~~DECEMBER~~• 31customer contracts, ~~----------------------~~including ~~2001~~contract ~~2000~~backlog, ~~----------~~contract ~~----------~~commencements, ~~DEFERRED~~contract ~~TAX~~terminations, ~~ASSETS-CURRENT~~contract ~~Accrued~~option ~~personnel~~exercises, ~~taxes.~~contract .revenues, .contract .awards . . . . . . . . . . . . $ 1.4 $ 1.3 Accrued workers' compensation insurance. . . . . . . . 4.4 1.7 Other accruals . . . . . . . . . . . . . . . . . . . . 17.9 11.4 Other. . . . . . . . . . . . . . . . . . . . . . . . . 3.7 5.0 ---------- ---------- Total Current Deferred Tax Assets. . . . . . . . . . 27.4 19.4 ---------- ---------- DEFERRED TAX LIABILITIES-CURRENT Insurance accruals . . . . . . . . . . . . . . . . . . (3.5) - Deferred drydock . . . . . . . . . . . . . . . . . . . (2.7) (1.3) Other accruals . . . . . . . . . . . . . . . . . . . . (0.2) - ---------- ---------- Total Current Deferred Tax Liabilities . . . . . . . (6.4) (1.3) ---------- ---------- Net Current Deferred Tax Assets. . . . . . . . . . . $ 21.0 $ 18.1 ========== ========== DEFERRED TAX ASSETS-NONCURRENT Net operating loss carryforwards . . . . . . . . . . . $ 447.0 $ 78.5 Foreign tax credit carryforwards . . . . . . . . . . . 185.6 12.4 Retirement and ~~benefit~~rig plan accruals . . . . . . . . . 0.8 3.1 Other accruals . . . . . . . . . . . . . . . . . . . . 7.9 6.6 Deferred income and other. . . . . . . . . . . . . . . 41.3 3.5 Valuation allowance for noncurrent deferred tax assets (115.4) (24.7) ---------- ---------- Total Noncurrent Deferred Tax Assets . . . . . . . . 567.2 79.4 ---------- ---------- DEFERRED TAX LIABILITIES-NONCURRENT Depreciation and amortization. . . . . . . . . . . . . (680.0) (383.2) Deferred gains . . . . . . . . . . . . . . . . . . . . (123.2) (28.4) Investment in subsidiaries . . . . . . . . . . . . . . (72.1) (22.6) Other. . . . . . . . . . . . . . . . . . . . . . . . . (9.0) (4.4) ---------- ---------- Total Noncurrent Deferred Tax Liabilities. . . . . . (884.3) (438.6) ---------- ---------- Net Noncurrent Deferred Tax Liabilities. . . . . . . $ (317.1) $ (359.2) ========== ==========mobilizations,

~~NUMBER OF SHARES WEIGHTED-AVERAGE UNDER OPTION EXERCISE PRICE ----------------- ----------------- SCHLUMBERGER OPTIONS Outstanding at December 31~~• newbuild, ~~1998. . . . . . . . . 762~~upgrade,~~920~~ $shipyard ~~45.13~~and ~~Granted~~other .capital ~~. . . . . . . . . . . . . . . . . . . . 121~~projects,~~250~~ ~~56.83~~including ~~Exercised . . . . . . . . . . . . . . . . . . . . (216~~completion,~~616)~~ ~~33.38~~delivery ~~Unvested~~and ~~options~~commencement terminated . . . . . . . . . . . (282,000) 61.23 Options retained by Schlumberger. . . . . . . . . (385,554) 48.56 ----------------- ----------------- Outstanding at December 31, 1999. . . . . . . . . - - ================= ================= TRANSOCEAN SEDCO FOREX INC. OPTIONS Options outstanding at time of ~~Sedco~~operations ~~Forex merger 2~~dates,~~747,773~~ $expected ~~25.04~~downtime ~~Options~~and ~~issued~~lost ~~under the SF Plan. . . . . . . . . 491~~revenue,~~645~~ ~~34.09 Options issued under~~ the ~~Incentive~~level ~~Plan~~of .expected .capital .expenditures .and . 20,000 33.69 ----------------- ----------------- Outstanding at December 31, 1999. . . . . . . . . 3,259,418 26.46 Granted . . . . . . . . . . . . . . . . . . . . . 1,636,918 37.30 Exercised . . . . . . . . . . . . . . . . . . . . (499,428) 23.99 Forfeited . . . . . . . . . . . . . . . . . . . . (22,500) 37.00 ----------------- ----------------- Outstanding at December 31, 2000. . . . . . . . . 4,374,408 30.74 Granted . . . . . . . . . . . . . . . . . . . . . 2,370,840 38.53 Options assumed in the ~~R&B~~timing ~~Falcon~~and ~~merger.~~cost .of .completion .of .capital 8projects,094,010 22.25 Exercised . . . . . . . . . . . . . . . . . . . . (1,286,554) 20.91 Forfeited . . . . . . . . . . . . . . . . . . . . (92,025) 42.15 ----------------- ----------------- Outstanding at December 31, 2001. . . . . . . . . 13,460,679 $ 27.99 ================= ================= Exercisable at December 31, 1999. . . . . . . . . 3,239,418 $ 26.41 Exercisable at December 31, 2000. . . . . . . . . 2,754,073 $ 26.91 Exercisable at December 31, 2001. . . . . . . . . 9,977,963 $ 24.29

~~Options~~• ~~Outstanding~~liquidity ~~Options~~and ~~Exercisable~~adequacy ~~Weighted-Average ----------------------------- ----------------------------- Remaining Number Weighted-Average Number Weighted-Average Range~~ of ~~Exercise~~cash ~~Prices~~flow ~~Contractual~~for ~~Life~~our ~~Outstanding Exercise Price Outstanding Exercise Price ------------------------ ----------------- ----------- ---------------- ----------- ---------------- $ 7.58 - $19.50 6.50 years 4~~obligations,~~072,452~~ ~~$14.88~~including ~~4,072,452~~our ~~$14.88~~ability ~~$20.12~~and -the ~~$34.63~~expected ~~6.53~~timing ~~years~~to ~~4,156,062~~access ~~$25.10~~certain ~~4,147,241~~investments ~~$25.08~~in ~~$37.00~~highly -liquid ~~$81.78 8.45 years 5~~instruments,~~232,165 $40.48 1,758,270 $44.19~~

~~YEARS~~• ~~ENDED~~our ~~DECEMBER~~results ~~31,~~of ~~----------------------------------~~operations ~~2001~~and ~~2000~~cash ~~1999~~flow ~~----------~~from ~~---------- ---------- (IN MILLIONS~~operations, ~~EXCEPT~~including ~~PER~~revenues ~~SHARE~~and DATA) Net Income As Reported . . . . . . . . . . . . . . . . . $ 252.6 $ 108.5 $ 58.1 Pro Forma . . . . . . . . . . . . . . . . . . 239.8 101.5 56.3 Basic Earnings Per Share (Unaudited pro forma prior to the effective date of the Sedco Forex merger) As Reported . . . . . . . . . . . . . . . . . $ 0.82 $ 0.52 $ 0.53 Pro Forma . . . . . . . . . . . . . . . . . . 0.78 0.48 0.51 Diluted Earnings Per Share (Unaudited pro forma prior to the effective date of the Sedco Forex merger) As Reported . . . . . . . . . . . . . . . . . $ 0.80 $ 0.51 $ 0.53 Pro Forma . . . . . . . . . . . . . . . . . . 0.76 0.48 0.51expenses,

~~2001~~• ~~2000~~uses 1999 ----------- ----------- ----------- Dividend yield. . . . . . . . . . . . . . . . . . 0.30% 0.25% 0.75% Expected price volatility range . . . . . . . . . 50-51% 46-47% 26-27% Risk-free interest rate range . . . . . . . . . . 4.13-5.25% 6.13-6.56% 4.86-5.22% Expected life of ~~options~~excess ~~(in~~cash, ~~years)~~including .debt .retirement .and .share .repurchases .under .our ~~4.00~~share ~~4.00~~repurchase ~~5.60 Weighted-average fair value of options granted. . $16.26 $15.21 $18.31~~program,

~~2001~~• ~~2000~~timing ~~--------------------~~and ~~-------------------~~proceeds ~~Dividend yield . . . . . . . . . . . . . . . . . 0.30% 0.25% Expected price volatility. . . . . . . . . . . . 51% 50% Risk-free interest rate. . . . . . . . . . . . . 1.71% 5.64% Expected life~~ of ~~options~~asset ~~. . . . . . . . . . . . Less than one year Less than one year Weighted-average fair value of options granted . $7.22 $7.67~~sales,

~~DECEMBER~~• 31tax matters, ~~----------------------~~including ~~2001~~our ~~2000~~effective ~~----------~~tax ~~----------~~rate, ~~CHANGE~~changes INin ~~BENEFIT~~tax ~~OBLIGATION~~laws, ~~Benefit~~treaties ~~obligation~~and atregulations, ~~beginning~~tax ofassessments ~~year~~and .liabilities .for .tax .issues, $including ~~133.6~~those $associated ~~133.2 Merger~~ with ~~R&B~~our ~~Falcon.~~activities .in . . . . . . . . . . . 85.7 - Service cost. . . . . . . . . . . . . . . . . . 12.0 9.5 Interest cost . . . . . . . . . . . . . . . . . 15.9 9.1 Actuarial losses. . . . . . . . . . . . . . . . 4.8 4.1 Plan settlements. . . . . . . . . . . . . . . . - (17.4) Plan amendments . . . . . . . . . . . . . . . . 0.8 - Benefits paid . . . . . . . . . . . . . . . . . (10.1) (4.9) ---------- ---------- Benefit obligation at end of year . . . . . . 242.7 133.6 ---------- ---------- CHANGE IN PLAN ASSETS Fair value of plan assets at beginning of year 117.7 134.4 Merger with R&B Falcon. . . . . . . . . . . . . 99.3 - Actual return on plan assets. . . . . . . . . . (1.3) (0.5) Company contributions . . . . . . . . . . . . . 4.8 8.8 Benefits paid . . . . . . . . . . . . . . . . . (10.1) (25.0) ---------- ---------- Fair value of plan assets at end of year. . . 210.4 117.7 ---------- ---------- FUNDED STATUS . . . . . . . . . . . . . . . . . (32.3) (15.9) Unrecognized transition obligation. . . . . . . 3.5 4.2 Unrecognized net actuarial loss . . . . . . . . 32.4 6.1 Unrecognized prior service cost . . . . . . . . 0.1 0.2 ---------- ---------- Accrued pension asset (liability) . . . . . . $ 3.7 $ (5.4) ========== ========== Comprised of: Prepaid benefit cost. . . . . . . . . . . . . . $ 34.2 $ 18.9 Accrued benefit liability . . . . . . . . . . . (30.5) (24.3) ---------- ---------- Accrued pension asset (liability) . . . . . . $ 3.7 $ (5.4) ========== ========== AS OF DECEMBER 31Brazil, ~~----------------------~~Norway ~~2001~~and ~~2000~~the ~~---------- ---------- WEIGHTED-AVERAGE ASSUMPTIONS Discount rate~~ U. S. ~~. . . . . . . . . . . . . . . 7.45% 7.36% Expected return on plan assets. . . . . . . . . 9.24% 8.69% Rate of compensation increase . . . . . . . . . 5.71% 5.83%~~,

~~DECEMBER~~• ~~31,~~legal ~~----------------------~~and ~~2001~~regulatory ~~2000~~matters, ~~----------~~including ~~----------~~results ~~CHANGE~~and INeffects ~~BENEFIT OBLIGATION Benefit obligation at beginning~~ of ~~year~~legal .proceedings .and .governmental .audits $and ~~12.0~~assessments, $outcome ~~8.8~~and ~~Merger~~effects with R&B Falcon. . . . . . . . . . . . . 16.1 - Service cost. . . . . . . . . . . . . . . . . . 0.4 0.2 Interest cost . . . . . . . . . . . . . . . . . 1.9 0.8 Actuarial losses (gains). . . . . . . . . . . . (0.2) 2.4 Participant's contributions . . . . . . . . . . 0.2 - Plan amendments . . . . . . . . . . . . . . . . - 0.4 Benefits paid . . . . . . . . . . . . . . . . . (1.2) (0.6) ---------- ---------- Benefit obligation at end of ~~year~~internal .and .governmental . . . . 29.2 12.0 ---------- ---------- CHANGE IN PLAN ASSETS Fair value of plan assets at beginning of year. 0.6 0.6 Actual return on plan assets. . . . . . . . . . 0.1 0.2 Company contributions . . . . . . . . . . . . . 0.8 0.4 Participant's contributions . . . . . . . . . . 0.2 - Benefits paid . . . . . . . . . . . . . . . . . (1.2) (0.6) ---------- ---------- Fair value of plan assets at end of year. . . 0.5 0.6 ---------- ---------- FUNDED STATUS . . . . . . . . . . . . . . . . . (28.7) (11.4) Unrecognized net actuarial gain . . . . . . . . 0.9 1.0 Unrecognized prior service cost . . . . . . . . 0.3 0.4 ---------- ---------- Postretirement benefit liability. . . . . . . $ (27.5) $ (10.0) ========== ========== AS OF DECEMBER 31investigations, ~~----------------------~~customs ~~2001~~and ~~2000~~environmental ~~---------- ---------- WEIGHTED-AVERAGE ASSUMPTIONS Discount rate 7.00% 7.25% Expected return on plan assets 7.00% 7.00% Rate of compensation increase 5.50% 5.50%~~matters,

~~YEARS~~• ~~ENDED~~insurance ~~DECEMBER 31~~matters, ~~-----------------------------~~including ~~2001~~adequacy ~~2000~~of ~~1999~~insurance, ~~---------~~insurance ~~--------~~proceeds ~~--------~~and ~~COMPONENTS~~cash OFinvestments ~~NET PERIODIC BENEFIT COST Service cost. . . . . . . . . . . . . . $ 0.4 $ 0.2 $ 0.2 Interest cost . . . . . . . . . . . . . 1.9 0.8 0.3 Amortization~~ of ~~prior~~our ~~service cost. . .~~ wholly-owned ~~0.1~~captive -insurance ~~Recognized net actuarial gain . . . . . (0.1) - - --------- -------- -------- Benefit Cost. . . . . . . . . . . . . $ 2.2 $ 1.1 $ 0.5 ========= ======== ========~~company,

~~One-~~• ~~One-~~the ~~Percentage~~possible ~~Percentage~~benefits, ~~Point~~effects ~~Point~~or ~~Increase~~results ~~Decrease --------- ---------- Effect on total service and interest cost components in 2001 . . . . . . $ 0.2 $ (0.2) Effect on postretirement benefit obligations as~~ of ~~December~~the ~~31,~~redomestication ~~2001 . . $ 2.9 $ (2.7)~~transaction,

~~Years~~• ~~ended~~debt ~~December 31~~levels, ~~----------------------------~~including ~~2001~~impacts ~~2000 1999 --------- --------- ------ Operating Revenues International and U.S. Floater Contract Drilling Services . $2,430.3 $1,229.5 $648.2 Gulf~~ of ~~Mexico~~the ~~Shallow~~financial and ~~Inland~~credit ~~Water . . . . . . . . . . 396.0 - - Elimination of intersegment revenues. . . . . . . . . . . . (6.2) - - --------- --------- ------ Total Operating Revenues. . . . . . . . . . . . . . . . . $2~~crisis,820.1 $1,229.5 $648.2 ========= ========= ====== Income Before Income Taxes, Minority Interest and Extraordinary Items International and U.S. Floater Contract Drilling Services . $ 625.2 $ 144.4 $ 49.3 Gulf of Mexico Shallow and Inland Water . . . . . . . . . . (17.3) - - --------- --------- ------ 607.9 144.4 49.3 Unallocated general and administrative expense . . . . . . . (57.9) - - Unallocated other expense, net . . . . . . . . . . . . . . . (189.5) - - --------- --------- ------ Total Income Before Income Taxes, Minority Interest and Extraordinary Items . . . . . . . . . . . . . . . . $ 360.5 $ 144.4 $ 49.3 ========= ========= ======

~~December~~• ~~31,~~effects ~~-------------------~~of ~~2001~~accounting ~~2000~~changes ~~--------- -------- International~~ and ~~U.S.~~adoption ~~Floater Contract Drilling Services . . $14,290.0 $6,358.8 Gulf~~ of ~~Mexico~~accounting ~~Shallow and Inland Water . . . . . . . . . . . 2~~policies,~~671.6~~ ~~- Unallocated Corporate . . . . . . . . . . . . . . . . . . . . 58.2 - --------- -------- Total Assets . . . . . . . . . . . . . . . . . . . . . . . $17,019.8 $6,358.8 ========= ========~~and

~~Years~~• ~~ended~~investments ~~December~~in 31recruitment, ~~---------------------------~~retention ~~2001~~and ~~2000~~personnel ~~1999~~development --------- -------- ------ Operating Revenues United States. . . . . . . $ 979.5 $ 265.0 $ 2.0 Brazil . . . . . . . . . . 355.8 153.6 60.6 United Kingdom . . . . . . 354.6 158.9 124.9 Norway . . . . . . . . . . 227.8 248.5 - Nigeria. . . . . . . . . . 166.2 76.2 69.3 Indonesia. . . . . . . . . 70.2 54.7 88.2 Rest of the World. . . . . 666.0 272.6 303.2 --------- -------- ------ Total Operating Revenues. $ 2initiatives,~~820.1~~ ~~$1,229.5~~pension ~~$648.2~~plan ~~=========~~and ~~========~~other ~~======~~postretirement Asbenefit ofplan ~~December 31~~contributions, ~~-------------------~~the ~~2001~~timing 2002 --------- -------- Long-Lived Assets United States. . . . . . . $ 3,853.5 $2,038.9 Brazil . . . . . . . . . . 1,036.2 383.8 United Kingdom . . . . . . 851.7 504.8 Norway . . . . . . . . . . 626.7 657.3 Spain. . . . . . . . . . . - 777.6 Goodwill (a) . . . . . . . 6,466.7 1,037.9 Rest of ~~the~~severance ~~World.~~payments ~~. . . . 2,448.2 510.4 --------- -------- Total Long-Lived Assets . $15,283.0 $5,910.7 ========= ======== -------------------- (a) Goodwill resulting from the Sedco Forex~~ and ~~R&B~~benefit ~~Falcon mergers has not been allocated to individual countries~~payments.

~~Years ended December 31,~~ Forward-~~------------------------~~looking ~~2001~~statements ~~2000~~in ~~1999~~this ~~-------~~annual ~~------~~report ~~-------~~are ~~Income~~identifiable ~~Before~~by ~~Extraordinary~~use ~~Items . . . . . . . . . . . . . . . . . . . . . $271.9 $107.1 $ 58.1 Gain (Loss) on Extraordinary Items, net~~ of tax. . . . . . . . . . . . . . . (19.3) 1.4 - ------- ------ ------- Net Income. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $252.6 $108.5 $ 58.1 ======= ====== ======= Weighted Average Shares Outstanding (Unaudited pro forma prior to the ~~effective~~following ~~date~~words ~~of the Sedco Forex merger) Shares for basic earnings per share . . . . . . . . . . . . . . . . . . . . 309.2 210.4 109.6 Effect of dilutive securities: Employee stock options~~ and ~~unvested~~other ~~stock~~similar ~~grants~~expressions .among . . . . . . . . . . . 3.4 1.3 - Warrants to purchase ordinary shares . . . . . . . . . . . . . . . . . . 2.2 - - ------- ------ ------ Adjusted weighted-average shares and assumed conversions for diluted earnings per share . . . . . . . . . . . . . . . 314.8 211.7 109.6 ======= ====== ====== Basic Earnings Per Share (Unaudited pro forma prior to the effective date of the Sedco Forex merger) Income Before Extraordinary Items. . . . . . . . . . . . . . . . . . . . $ 0.88 $ 0.51 $ 0.53 Gain (Loss) on Extraordinary Items, net of tax . . . . . . . . . . . . . (0.06) 0.01 - ------- ------ ------ Net Income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 0.82 $ 0.52 $ 0.53 ======= ====== ====== Diluted Earnings Per Share (Unaudited pro forma prior to the effective date of the Sedco Forex merger) Income Before Extraordinary Items. . . . . . . . . . . . . . . . . . . . $ 0.86 $ 0.50 $ 0.53 Gain (Loss) on Extraordinary Items, net of tax . . . . . . . . . . . . . (0.06) 0.01 - ------- ------ ------ Net Income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 0.80 $ 0.51 $ 0.53 ======= ====== ======others:

~~Quarter~~•"anticipates” ~~First~~•“may” ~~Second~~•“believes” ~~Third~~•“might” ~~Fourth~~•“budgets” ~~-------------------~~•“plans” ~~--------~~•“could” ~~--------~~•“predicts” ~~-------~~•“estimates” ~~-------~~•“projects” ~~2001~~•“expects” ~~(a)~~•“scheduled” ~~Operating~~•“forecasts” ~~Revenues~~•“should” $550.1 $752.2 $770.2 $747.6 Operating Income. . . . . . . . . . . . . . 74.5 178.2 179.8 117.5 Income Before Extraordinary Items . . . . 30.5 85.8 97.6 58.0 Net Income (b). . . . . . . . . . . . . . . 30.5 68.5 97.6 56.0 Basic Earnings Per Share Income Before Extraordinary Items . . . . $ 0.11 $ 0.27 $0.31 $ 0.19 Diluted Earnings Per Share Income Before Extraordinary Items . . . . $ 0.11 $ 0.26 $0.30 $ 0.19 Weighted Average Shares Outstanding (c) Shares for basic earnings per share . . . 280.6 318.2 318.7 318.7 Shares for diluted earnings per share . . 285.5 325.0 322.7 322.7 2000 (e) Operating Revenues. . . . . . . . . . . . . $300.8 $299.2 $314.5 $314.9 Operating Income (Loss) (d) . . . . . . . . 37.6 43.2 60.0 (7.7) Income (Loss) Before Extraordinary Items. 32.5 35.9 47.9 (9.2) Net Income (Loss) . . . . . . . . . . . . . 32.5 35.9 49.3 (9.2) Basic Earnings (Loss) Per Share Income (Loss) Before Extraordinary Items. $ 0.15 $ 0.17 $ 0.22 $(0.04) Diluted Earnings (Loss) Per Share Income (Loss) Before Extraordinary Items. $ 0.15 $ 0.17 $ 0.22 $(0.04) Weighted Average Shares Outstanding Shares for basic earnings per share . . . 210.2 210.4 210.5 210.6 Shares for diluted earnings per share . . 211.0 211.7 212.0 210.6 -------------------- (a) First quarter 2001 included two months of operating results for R&B Falcon and the second, third and fourth quarters of 2001 included three months of operating results of R&B Falcon, respectively. Fourth quarter 2001 included impairment charges (see Note 7) and gain on sale of RBF FPSO L.P. (see Note 6). (b) Second and fourth quarter 2001 included extraordinary losses of $17.3 million and $2.0 million, net of income taxes, respectively, relating to the early extinguishment of debt. (c) First quarter 2001 included approximately 106 million ordinary shares issued on January 31, 2001 in exchange for each R&B Falcon share. (d) First and second quarter 2000 included certain reclassifications for minority interest and gain (loss) from sale of assets to conform with the current presentation. (e) Third quarter 2000 included an extraordinary gain of $1.4 million, net of income taxes, relating to the early termination of debt. Fourth quarter 2000 included charges totaling $37.2 million related to the settlement of an arbitration proceeding with Global Marine and a $6.7 million ($4.8 million after taxes) increase in provisions for legal claims.•“intends”

~~Transocean~~Such ~~Sedco~~statements ~~Forex~~are ~~Inc.~~subject ~~and Subsidiaries Schedule II - Valuation and Qualifying Accounts (In millions) Additions -------------------- Charged Charged Balance at~~ to ~~Costs~~numerous ~~to Other Balance at Beginning and Accounts- Deductions- End of of Period Expenses Describe Describe Period ---------- --------- ---------- ------------ -------- Year Ended December 31~~risks, ~~1999~~uncertainties ~~Reserves~~ and allowances deducted from asset accounts: Allowance for doubtful accounts receivable . . . . . . . . . . . . . . $ 0.8 $13.8 $12.6 (1) $ 0.1 (3) $27.1 Allowance for obsolete materials and supplies . . . . . . . . . . . . . . . 10.2 1.8 12.5 (2) 1.4 (4) 23.1 Year Ended December 31assumptions, 2000 Reserves and allowances deducted from asset accounts: Allowance for doubtful accounts receivable . . . . . . . . . . . . . . 27.1 20.0 0.2 (3) 23.0 (3) 24.3 Allowance for obsolete materials and supplies . . . . . . . . . . . . . . . 23.1 0.3 (0.2)(5) (0.1)(4) 23.3 (6) Year Ended December 31including, ~~2001~~but ~~Reserves~~not ~~and~~limited allowances deducted from asset accounts: Allowance for doubtful accounts receivable . . . . . . . . . . . . . . 24.3 12.0 14.9 (7) 27.0 (3) 24.2 (9) Allowance for obsolete materials and supplies . . . . . . . . . . . . . . . $23.3 $ - $ 9.2 (8) $ 8.4 (4) $24.1 (10) _____________________________ (1) Amount includes $10.5 relating to the allowance for doubtful accounts receivable assumed in the Sedco Forex merger and $2.1 in receivable reserves reclassifications. (2) Amount includes $12.5 relating to the allowance for obsolete materials and supplies assumed in the Sedco Forex merger. (3) Uncollectible accounts receivable written off, net of recoveries. (4) Obsolete materials and supplies written off, net of scrap. (5) Amount includes $0.4 related to a write-off to assets held for sale. (6) Amount includes $0.7 related to reversals of prior year write-offs. (7) Amount includes $15.0 relating to the allowance for doubtful accounts receivable assumed in the RBF merger. (8) Amount includes $8.7 relating to the obsolete materials and supplies inventory assumed in the RBF merger. (9) Amount includes $4.9 related to adjustments to the provision. (10) Amount includes $2.7 related to sale of rigs.:

• those described under "Item 1A. Risk Factors,"

• the adequacy of sources of liquidity,

• our inability to obtain contracts for our rigs that do not have contracts,

• the cancellation of contracts currently included in our reported contract backlog,

• the effect and results of litigation, tax audits and contingencies, and

• other factors discussed in this annual report and in our other filings with the U.S. Securities and Exchange Commission ("SEC"), which are available free of charge on the SEC's website at www.sec.gov.

Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual results may vary materially from those indicated.

All subsequent written and oral forward-looking statements attributable to us or to persons acting on our behalf are expressly qualified in their entirety by reference to these risks and uncertainties. You should not place undue reliance on forward-looking statements. Each forward-looking statement speaks only as of the date of the particular statement, and we undertake no obligation to publicly update or revise any forward-looking statements, except as required by law.

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PART I

ITEM 1.

Business

Transocean Ltd. (together with its subsidiaries and predecessors, unless the context requires otherwise, "Transocean," the "Company," "we," "us" or "our") is a leading international provider of offshore contract drilling services for oil and gas wells. As of February 3, 2009, we owned, had partial ownership interests in or operated 136 mobile offshore drilling units. As of this date, our fleet consisted of 39 High-Specification Floaters (Ultra-Deepwater, Deepwater and Harsh Environment semisubmersibles and drillships), 28 Midwater Floaters, 10 High-Specification Jackups, 55 Standard Jackups and four Other Rigs. In addition, we had 10 Ultra-Deepwater Floaters under construction or contracted for construction.

We believe our mobile offshore drilling fleet is one of the most modern and versatile fleets in the world. Our primary business is to contract our drilling rigs, related equipment and work crews primarily on a dayrate basis to drill oil and gas wells. We specialize in technically demanding segments of the offshore drilling business with a particular focus on deepwater and harsh environment drilling services. We also provide oil and gas drilling management services on either a dayrate basis or a completed-project, fixed-price (or "turnkey") basis, as well as drilling engineering and drilling project management services, and we participate in oil and gas exploration and production activities. Our shares are listed on the New York Stock Exchange ("NYSE") under the symbol "RIG."

Transocean Ltd. is a Swiss corporation with principal executive offices located at Blandonnet International Business Center, Chemin de Blandonnet 2, Building F, 7^th Floor, 1214 Vernier, Switzerland. Our telephone number at that address is +41 (22) 930-9000.

For information about the revenues, operating income, assets and other information relating to our business, our segments and the geographic areas in which we operate, see "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" and Notes to Consolidated Financial Statements—Note 23—Segments, Geographical Analysis and Major Customers.

In this Annual Report, we sometimes refer to Transocean Inc., a Cayman Islands company and our wholly-owned subsidiary, as "Transocean-Cayman."

Background of Transocean

In November 2007, we completed our merger transaction (the "Merger") with GlobalSantaFe Corporation ("GlobalSantaFe"). Immediately prior to the effective time of the Merger, each of Transocean-Cayman's outstanding ordinary shares was reclassified by way of a scheme of arrangement under Cayman Islands law into (1) 0.6996 Transocean-Cayman ordinary shares and (2) $33.03 in cash (the "Reclassification" and together with the Merger, the "GSF Transactions"). At the effective time of the Merger, each outstanding ordinary share of GlobalSantaFe (the "GlobalSantaFe Ordinary Shares") was exchanged for (1) 0.4757 Transocean-Cayman ordinary shares (after giving effect to the Reclassification) and (2) $22.46 in cash. Transocean-Cayman issued approximately 107,752,000 of its ordinary shares in connection with the Merger and distributed $14.9 billion in cash in connection with the GSF Transactions. Transocean-Cayman funded the payment of the cash consideration for the GSF Transactions with $15.0 billion of borrowings under a $15.0 billion, one-year senior unsecured bridge loan facility (the "Bridge Loan Facility") and has since refinanced or repaid those borrowings and terminated the Bridge Loan Facility. We included the financial results of GlobalSantaFe in our consolidated financial statements beginning November 27, 2007, the date the GlobalSantaFe Ordinary Shares were exchanged for Transocean-Cayman ordinary shares.

In December 2008, Transocean Ltd. completed a transaction pursuant to an Agreement and Plan of Merger among Transocean Ltd., Transocean Inc., which was our former parent holding company, and Transocean Cayman Ltd., a company organized under the laws of the Cayman Islands that was a wholly-owned subsidiary of Transocean Ltd., pursuant to which Transocean Inc. merged by way of schemes of arrangement under Cayman Islands law with Transocean Cayman Ltd., with Transocean Inc. as the surviving company and, as a result, a wholly-owned subsidiary of Transocean Ltd. (the "Redomestication Transaction"). In the Redomestication Transaction, Transocean Ltd. issued one of its shares in exchange for each ordinary share of Transocean Inc. In addition, Transocean Ltd. issued 16 million of its shares to Transocean Inc. for future use to satisfy Transocean Ltd.'s obligations to deliver shares in connection with awards granted under our incentive plans, warrants or other rights to acquire shares of Transocean Ltd. The Redomestication Transaction effectively changed the place of incorporation of our parent holding company from the Cayman Islands to Switzerland. As a result of the Redomestication Transaction, Transocean Inc. became a direct, wholly-owned subsidiary of Transocean Ltd. In connection with the Redomestication Transaction, we relocated our principal executive offices to Vernier, Switzerland. We refer to the Redomestication Transaction and the relocation of our principal executive offices together as the "Redomestication."

Drilling Fleet

We principally operate three types of drilling rigs:

• drillships;

• semisubmersibles; and

• jackups.

Also included in our fleet are barge drilling rigs, a mobile offshore production unit and a coring drillship.

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

We categorize our fleet as follows: (1) "High-Specification Floaters," consisting of our "Ultra-Deepwater Floaters," "Deepwater Floaters" and "Harsh Environment Floaters," (2) "Midwater Floaters," (3) "High-Specification Jackups," (4) "Standard Jackups" and (5) "Other Rigs." As of February 3, 2009, our fleet of 136 rigs, which excludes assets that are classified as held for sale and are not currently operating under a contract and rigs contracted for or under construction, included:

• 39 High-Specification Floaters, which are comprised of:

• 18 Ultra-Deepwater Floaters;

• 16 Deepwater Floaters; and

• five Harsh Environment Floaters;

• 28 Midwater Floaters;

• 10 High-Specification Jackups;

• 55 Standard Jackups; and

• four Other Rigs, which are comprised of:

• two barge drilling rigs;

• one mobile offshore production unit; and

• one coring drillship.

As of February 3, 2009, our fleet was located in the Far East (22 units), U.K. North Sea (17 units), Middle East (18 units), U.S. Gulf of Mexico (13 units), Nigeria (nine units), India (12 units), Angola (11 units), Brazil (11 units), Norway (five units), other West African countries (nine units), the Caspian Sea (three units), Trinidad (two units), Australia (one unit), the Mediterranean (two units) and Canada (one unit).

High-Specification Floaters are specialized offshore drilling units that we categorize into three sub-classifications based on their capabilities. Ultra-Deepwater Floaters have high-pressure mud pumps and a water depth capability of 7,500 feet or greater. Deepwater Floaters are generally those other semisubmersible rigs and drillships that have a water depth capacity between 7,500 and 4,500 feet. Harsh Environment Floaters have a water depth capacity between 4,500 and 1,500 feet, are capable of drilling in harsh environments and have greater displacement, resulting in larger variable load capacity, more useable deck space and better motion characteristics. Midwater Floaters are generally comprised of those non-high-specification semisubmersibles with a water depth capacity of less than 4,500 feet. High-Specification Jackups consist of our harsh environment and high-performance jackups, and Standard Jackups consist of our remaining jackup fleet. Other Rigs consist of rigs that are of a different type or use than those mentioned above.

Drillships are generally self-propelled, shaped like conventional ships and are the most mobile of the major rig types. All of our High-Specification drillships are dynamically positioned, which allows them to maintain position without anchors through the use of their onboard propulsion and station-keeping systems. Drillships typically have greater load capacity than early generation semisubmersible rigs. This enables them to carry more supplies on board, which often makes them better suited for drilling in remote locations where resupply is more difficult. However, drillships are typically limited to calmer water conditions than those in which semisubmersibles can operate. Our three existing Enterprise-class drillships are, and five of our ten additional newbuild drillships contracted for or under construction will be, equipped with our patented dual-activity technology. Dual-activity technology includes structures, equipment and techniques for using two drilling stations within a single derrick to perform drilling tasks. Dual-activity technology allows our rigs to perform simultaneous drilling tasks in a parallel rather than sequential manner. Dual-activity technology reduces critical path activity and improves efficiency in both exploration and development drilling.

Semisubmersibles are floating vessels that can be submerged by means of a water ballast system such that the lower hulls are below the water surface during drilling operations. These rigs are capable of maintaining their position over the well through the use of an anchoring system or a computer controlled dynamic positioning thruster system. Some semisubmersible rigs are self-propelled and move between locations under their own power when afloat on pontoons although most are relocated with the assistance of tugs. Typically, semisubmersibles are better suited than drillships for operations in rougher water conditions. Our three Express-class semisubmersibles are designed for mild environments and are equipped with the unique tri-act derrick, which was designed to reduce overall well construction costs. The tri-act derrick allows offline tubular and riser handling operations to occur at two sides of the derrick while the center portion of the derrick is being used for normal drilling operations through the rotary table. Our two operating Development Driller-class semisubmersibles are, and one that is under construction will be, equipped with our patented dual-activity technology.

Jackup rigs are mobile self-elevating drilling platforms equipped with legs that can be lowered to the ocean floor until a foundation is established to support the drilling platform. Once a foundation is established, the drilling platform is then jacked further up the legs so that the platform is above the highest expected waves. These rigs are generally suited for water depths of 400 feet or less.

We classify certain of our jackup rigs as High-Specification Jackups. These rigs have greater operational capabilities than Standard Jackups and are able to operate in harsh environments, have higher capacity derricks, drawworks, mud systems and storage, and are typically capable of drilling to deeper depths. Typically, these jackups also have deeper water depth capacity than Standard Jackups.

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Depending on market conditions, we may "warm stack" or "cold stack" non-contracted rigs. "Warm stacked" rigs are not under contract and may require the hiring of additional crew, but are generally ready for service with little or no capital expenditures and are being actively marketed. "Cold stacked" rigs are not actively marketed, generally cannot be reactivated upon short notice and normally require the hiring of most of the crew, a maintenance review and possibly significant refurbishment before they can be reactivated. Cold stacked rigs and some warm stacked rigs would require additional costs to return to service. The actual cost, which could fluctuate over time, is dependent upon various factors, including the availability and cost of shipyard facilities, cost of equipment and materials and the extent of repairs and maintenance that may ultimately be required. In certain circumstances, the cost could be significant. We would take these factors into consideration together with market conditions, length of contract and dayrate and other contract terms in deciding whether to return a particular idle rig to service. We may consider marketing cold stacked rigs for alternative uses, including as accommodation units, from time to time until drilling activity increases and we obtain drilling contracts for these units.

We own all of the drilling rigs in our fleet noted in the tables below except for the following: (1) those specifically described as being owned wholly or in part by unaffiliated parties, (2) Petrobras 10000, which will be subject to a capital lease with a 20-year term, (3) GSF Explorer, which is subject to a capital lease with a remaining term of 18 years, and (4) GSF Jack Ryan, which is subject to a fully defeased capital lease with a remaining term of 12 years.

In the tables presented below, the location of each rig indicates the current drilling location for operating rigs or the next operating location for rigs in shipyards with a follow-on contract, unless otherwise noted.

Rigs Under Construction (10)

The following table provides certain information regarding our Ultra-Deepwater Floaters contracted for or under construction as of February 3, 2009:

			Water	Drilling
			depth	depth
		Expected	capacity	capacity	Contracted
Name	Type	completion	(in feet)	(in feet)	location
Ultra-Deepwater Floaters (a) (10)
Discoverer Americas (b)	HSD	Mid 2009	12,000	40,000	U.S. Gulf
Discoverer Clear Leader (b)	HSD	2Q 2009	12,000	40,000	U.S. Gulf
Discoverer Inspiration (b)	HSD	1Q 2010	12,000	40,000	U.S. Gulf
Deepwater Champion (b)	HSD	4Q 2010	12,000	40,000	U.S. Gulf
Dhirubhai Deepwater KG1 (c)	HSD	2Q 2009	12,000	35,000	India
Dhirubhai Deepwater KG2 (c)	HSD	1Q 2010	10,000	35,000	India
Discoverer India (b)	HSD	4Q 2010	10,000	40,000	India
Petrobras 10000 (b)	HSD	3Q 2009	10,000	37,500	Angola
Discoverer Luanda (b)(d)	HSD	3Q 2010	7,500	40,000	Angola
Development Driller III (b)	HSS	Mid 2009	7,500	30,000	U.S. Gulf

________________________________

"HSD" means high-specification drillship.

"HSS" means high-specification semisubmersible.

(a)	Dynamically positioned.

(b)	Dual-activity.

(c)	Owned through our 50 percent interest in Transocean Pacific Drilling Inc.

(d)	Owned through our 65 percent interest in Angola Deepwater Drilling Company Limited.

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High-Specification Floaters (39)

The following table provides certain information regarding our High-Specification Floaters as of February 3, 2009:

		Year	Water	Drilling
		entered	depth	depth
		service/	capacity	capacity
Name	Type	upgraded (a)	(in feet)	(in feet)	Location
Ultra-Deepwater Floaters (b) (18)
Deepwater Discovery	HSD	2000	10,000	30,000	Brazil
Deepwater Expedition	HSD	1999	10,000	30,000	India
Deepwater Frontier	HSD	1999	10,000	30,000	India
Deepwater Horizon	HSS	2001	10,000	30,000	U.S. Gulf
Deepwater Millennium	HSD	1999	10,000	30,000	Brazil
Deepwater Pathfinder	HSD	1998	10,000	30,000	Nigeria
Discoverer Deep Seas (c) (d)	HSD	2001	10,000	35,000	U.S. Gulf
Discoverer Enterprise (c) (d)	HSD	1999	10,000	35,000	U.S. Gulf
Discoverer Spirit (c) (d)	HSD	2000	10,000	35,000	U.S. Gulf
GSF C.R. Luigs	HSD	2000	10,000	35,000	U.S. Gulf
GSF Jack Ryan	HSD	2000	10,000	30,000	Nigeria
Cajun Express (e)	HSS	2001	8,500	35,000	U.S. Gulf
Deepwater Nautilus	HSS	2000	8,000	30,000	U.S. Gulf
GSF Explorer	HSD	1972/1998	7,800	30,000	Angola
GSF Development Driller I (d)	HSS	2004	7,500	37,500	U.S. Gulf
GSF Development Driller II (d)	HSS	2004	7,500	37,500	U.S. Gulf
Sedco Energy (e)	HSS	2001	7,500	30,000	Nigeria
Sedco Express (e)	HSS	2001	7,500	30,000	Angola
Deepwater Floaters (16)
Deepwater Navigator (b)	HSD	2000	7,200	25,000	Brazil
Discoverer 534 (b)	HSD	1975/1991	7,000	25,000	India
Discoverer Seven Seas (b)	HSD	1976/1997	7,000	25,000	India
Transocean Marianas	HSS	1979/1998	7,000	25,000	U.S. Gulf
Sedco 702 (b)	HSS	1973/2007	6,500	25,000	Nigeria
Sedco 706 (b) (f)	HSS	1976/(f)	6,500	25,000	Singapore
Sedco 707 (b)	HSS	1976/1997	6,500	25,000	Brazil
GSF Celtic Sea	HSS	1982/1998	5,750	25,000	Brazil
Jack Bates	HSS	1986/1997	5,400	30,000	Indonesia
M.G. Hulme, Jr.	HSS	1983/1996	5,000	25,000	Nigeria
Sedco 709 (b)	HSS	1977/1999	5,000	25,000	Nigeria
Transocean Richardson	HSS	1988	5,000	25,000	Angola
Jim Cunningham	HSS	1982/1995	4,600	25,000	Angola
Sedco 710 (b)	HSS	1983/2001	4,500	25,000	Brazil
Sovereign Explorer	HSS	1984	4,500	25,000	Brazil
Transocean Rather	HSS	1988	4,500	25,000	U.K. N. Sea
Harsh Environment Floaters (5)
Transocean Leader	HSS	1987/1997	4,500	25,000	Norwegian N. Sea
Henry Goodrich	HSS	1985	5,000	30,000	U.S. Gulf
Paul B. Loyd, Jr.	HSS	1990	2,000	25,000	U.K. N. Sea
Transocean Arctic	HSS	1986	1,650	25,000	Norwegian N. Sea
Polar Pioneer	HSS	1985	1,500	25,000	Norwegian N. Sea

________________________________

"HSD" means high-specification drillship.

"HSS" means high-specification semisubmersible.

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

(b)	Dynamically positioned.

(c)	Enterprise-class rig.

(d)	Dual-activity.

(e)	Express-class rig.

(f)	Sedco 706 completed the upgrade from a Midwater Floater to a Deepwater Floater during the first quarter of 2009. As of February 20, 2009, the rig was in mobilization to Brazil for customer acceptance.

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Midwater Floaters (28)

The following table provides certain information regarding our Midwater Floaters as of February 3, 2009:

		Year	Water	Drilling
		entered	depth	depth
		service/	capacity	capacity
Name	Type	upgraded (a)	(in feet)	(in feet)	Location
Sedco 700	OS	1973/1997	3,600	25,000	Congo
Transocean Amirante	OS	1978/1997	3,500	25,000	U.S. Gulf
Transocean Legend	OS	1983	3,500	25,000	Singapore
GSF Arctic I	OS	1983/1996	3,400	25,000	Brazil
C. Kirk Rhein, Jr.	OS	1976/1997	3,300	25,000	Mozambique
Transocean Driller	OS	1991	3,000	25,000	Brazil
GSF Rig 135	OS	1983	2,800	25,000	Congo
Falcon 100	OS	1974/1999	2,400	25,000	Brazil
GSF Rig 140	OS	1983	2,400	25,000	Angola
GSF Aleutian Key	OS	1976/2001	2,300	25,000	Angola
Istiglal (b)	OS	1995/1998	2,300	20,000	Caspian Sea
Sedco 703	OS	1973/1995	2,000	25,000	Australia
GSF Arctic III	OS	1984	1,800	25,000	Libya
Sedco 711	OS	1982	1,800	25,000	U.K. N. Sea
Transocean John Shaw	OS	1982	1,800	25,000	U.K. N. Sea
Sedco 712	OS	1983	1,600	25,000	Warm Stacked (c)
Sedco 714	OS	1983/1997	1,600	25,000	U.K. N. Sea
Actinia	OS	1982	1,500	25,000	India
Dada Gorgud (b)	OS	1978/1998	1,500	25,000	Caspian Sea
GSF Arctic IV (d)	OS	1983/1999	1,500	25,000	U.K. N. Sea
GSF Grand Banks	OS	1984	1,500	25,000	East Canada
Sedco 601	OS	1983	1,500	25,000	Malaysia
Sedneth 701	OS	1972/1993	1,500	25,000	Angola
Transocean Prospect	OS	1983/1992	1,500	25,000	U.K. N. Sea
Transocean Searcher	OS	1983/1988	1,500	25,000	Norwegian N. Sea
Transocean Winner	OS	1983	1,500	25,000	Norwegian N. Sea
J. W. McLean	OS	1974/1996	1,250	25,000	U.K. N. Sea
Sedco 704	OS	1974/1993	1,000	25,000	U.K. N. Sea

________________________________

"OS" means other semisubmersible.

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

(b)	Owned by the State Oil Company of the Azerbaijan Republic ("SOCAR") and operated under long-term bareboat charters between Caspian Drilling Company Limited, a joint venture in which we own a 45 percent ownership interest, and SOCAR.

(c)	As of February 20, 2009, Sedco 712 was warm stacked.

(d)

In connection with our previously announced undertakings to the Office of Fair Trading in the U.K. (the "OFT") made in connection with the Merger, GSF Arctic II and GSF Arctic IV are classified as held for sale. In July 2008, we entered into a definitive agreement to sell GSF Arctic II and GSF Arctic IV; however, the acquisition of the rigs was contingent upon the buyers' ability to obtain lender consents. The buyers have reported that they have been unable to obtain the consent of their lenders on terms acceptable to them and have publicly announced their termination of the agreement to purchase the vessels. We continue to market both rigs for sale. At February 3, 2009, GSF Arctic IV is included in the table above as it continued to operate under contract, and GSF Arctic II is excluded from the table above as it was warm stacked in anticipation of its sale, having completed its contracted operations.

High-Specification Jackups (10)

The following table provides certain information regarding our High-Specification Jackups as of February 3, 2009:

	Year	Water	Drilling
	entered	depth	depth
	service/	capacity	capacity
Name	upgraded (a)	(in feet)	(in feet)	Location
GSF Constellation I	2003	400	30,000	Trinidad
GSF Constellation II	2004	400	30,000	Egypt
GSF Galaxy I	1991/2001	400	30,000	U.K. N. Sea
GSF Galaxy II	1998	400	30,000	U.K. N. Sea
GSF Galaxy III	1999	400	30,000	U.K. N. Sea
GSF Baltic	1983	375	25,000	Nigeria
GSF Magellan	1992	350	30,000	U.K. N. Sea
GSF Monarch	1986	350	30,000	U.K. N. Sea
GSF Monitor	1989	350	30,000	Trinidad
Trident 20	2000	350	25,000	Caspian Sea

________________________________

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

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Standard Jackups (55)

The following table provides certain information regarding our Standard Jackups as of February 3, 2009:

	Year	Water	Drilling
	entered	depth	depth
	service/	capacity	capacity
Name	upgraded (a)	(in feet)	(in feet)	Location
Trident IX	1982	400	20,000	Vietnam
Trident 17	1983	355	25,000	Malaysia
GSF Adriatic II	1981	350	25,000	Angola
GSF Adriatic IX	1981	350	25,000	Gabon
GSF Adriatic X	1982	350	30,000	Egypt
GSF Key Manhattan	1980	350	25,000	Egypt
GSF Key Singapore	1982	350	25,000	Egypt
GSF Adriatic VI	1981	328	25,000	Gabon
GSF Adriatic VIII	1983	328	25,000	Nigeria
C. E. Thornton	1974	300	25,000	India
D. R. Stewart	1980	300	25,000	Italy
F. G. McClintock	1975	300	25,000	India
George H. Galloway	1984	300	25,000	Italy
GSF Adriatic I	1981	300	25,000	Angola
GSF Adriatic V	1979	300	25,000	Angola
GSF Adriatic XI	1983	300	25,000	Indonesia
GSF Compact Driller	1992	300	25,000	Thailand
GSF Galveston Key	1978	300	25,000	Vietnam
GSF Key Gibraltar	1976/1996	300	25,000	Warm Stacked (b)
GSF Key Hawaii	1982	300	25,000	Qatar
GSF Labrador	1983	300	25,000	U.K. N. Sea
GSF Main Pass I	1982	300	25,000	Arabian Gulf
GSF Main Pass IV	1982	300	25,000	Arabian Gulf
GSF Parameswara	1983	300	20,000	Indonesia
GSF Rig 134	1982	300	20,000	Malaysia
GSF Rig 136	1982	300	25,000	Malaysia
Harvey H. Ward	1981	300	25,000	Malaysia
J. T. Angel	1982	300	25,000	India
Randolph Yost	1979	300	25,000	India
Roger W. Mowell	1982	300	25,000	Malaysia
Ron Tappmeyer	1978	300	25,000	India
Shelf Explorer	1982	300	20,000	Malaysia
Interocean III	1978/1993	300	25,000	Egypt
Transocean Nordic	1983	300	25,000	Warm Stacked (b)
Trident II	1977/1985	300	25,000	India
Trident IV	1980/1999	300	25,000	Warm Stacked (c)
Trident VIII	1981	300	21,000	Eq.Guin. (c)
Trident XII	1982/1992	300	25,000	India
Trident XIV	1982/1994	300	20,000	Angola
Trident 15	1982	300	25,000	Thailand
Trident 16	1982	300	25,000	Vietnam
GSF High Island II	1979	270	20,000	Arabian Gulf
GSF High Island IV	1980/2001	270	20,000	Arabian Gulf
GSF High Island V	1981	270	20,000	Congo
GSF High Island VII	1982	250	20,000	Cameroon
GSF High Island IX	1983	250	20,000	Nigeria
GSF Rig 103	1974	250	20,000	Egypt
GSF Rig 105	1975	250	20,000	Egypt
GSF Rig 124	1980	250	20,000	Egypt
GSF Rig 127	1981	250	20,000	Qatar
GSF Rig 141	1982	250	20,000	Egypt
Transocean Comet	1980	250	20,000	Egypt
Transocean Mercury	1969/1998	250	20,000	Egypt
GSF Britannia	1968	230	20,000	U.K. N. Sea
Trident VI	1981	220	21,000	Vietnam

________________________________

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

(b)	As of February 20, 2009, GSF Key Gibraltar and Transocean Nordic were cold stacked.

(c)	As of February 20, 2009, Trident IV and Trident VIII were warm stacked.

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Other Rigs

In addition to our floaters and jackups, we also own or operate several other types of rigs as follows: two drilling barges, a mobile offshore production unit and a coring drillship.

Rigs Held for Sale and Stacked

In connection with our previously announced undertakings to the OFT made in connection with the Merger, GSF Arctic II and GSF Arctic IV are classified as held for sale. In July 2008, we entered into a definitive agreement to sell GSF Arctic II and GSF Arctic IV; however, the acquisition of the rigs was contingent upon the buyers' ability to obtain lender consents. The buyers have reported that they have been unable to obtain the consent of their lenders on terms acceptable to them and have publicly announced their termination of the agreement to purchase the vessels. We continue to market both rigs for sale. At February 3, 2009, GSF Arctic IV is included in the tables above as it continued to operate under contract, and GSF Arctic II is excluded from the table above as it was warm stacked in anticipation of its sale, having completed its contracted operations.

Markets

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

In recent years, there has been increased emphasis by oil companies on exploring for hydrocarbons in deeper waters. This deepwater focus is due, in part, to technological developments that have made such exploration more feasible and cost-effective. Therefore, water-depth capability is a key component in determining rig suitability for a particular drilling project. Another distinguishing feature in some drilling market sectors is a rig's ability to operate in harsh environments, including extreme marine and climatic conditions and temperatures.

The deepwater and midwater market sectors are serviced by our semisubmersibles and drillships. Although the term "deepwater" as used in the drilling industry to denote a particular sector of the market can vary 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 and extends to the maximum water depths in which rigs are capable of drilling, which is currently approximately 12,000 feet. We view the midwater market sector as that which covers water depths of about 300 feet to approximately 4,500 feet.

The global jackup market sector begins at the outer limit of the transition zone and extends to water depths of about 400 feet. This sector has been developed to a significantly greater degree than the deepwater market sector because the shallower water depths have made it much more accessible than the deeper water market sectors.

The "transition zone" market sector is characterized by marshes, rivers, lakes, and shallow bay and coastal water areas. We operate in this sector using our two barge drilling rigs located in Southeast Asia.

Contract Backlog

We were successful in building contract backlog in 2008 within all of our asset classes. Our contract backlog at December 31, 2008 was approximately $40 billion, representing a 25 percent and 100 percent increase compared to our contract backlog of $32 billion and $20 billion at December 31, 2007 and 2006, respectively. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Outlook–Drilling Market" and "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Performance and Other Key Indicators."

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Operating Revenues and Long-Lived Assets by Country

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

	Years ended December 31,
	2008		2007		2006
Operating revenues
U.S.	$	2,578	$	1,259	$	806
U.K.		2,012		848		439
Nigeria		1,096		587		447
India		890		761		291
Other countries (a)		6,098		2,922		1,899
Total operating revenues	$	12,674	$	6,377	$	3,882

	As of December 31,
	2008		2007
Long-lived assets
U.S.	$	8,155	$	5,856
U.K.		1,534		2,301
Other countries (a)		11,138		12,773
Total long-lived assets	$	20,827	$	20,930

_______________________________

(a)	Other countries represents countries in which we operate that individually had operating revenues or long-lived assets representing less than 10 percent of total operating revenues earned or total long-lived assets for any of the periods presented.

Contract Drilling Services

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

A dayrate drilling contract generally extends over a period of time covering either the drilling of a single well or group of wells or covering a stated term. Certain of our contracts with customers may be cancelable at the option of the customer upon payment of an early termination payment. Such payments may not, however, fully compensate us for the loss of the contract. Contracts also customarily provide for either automatic termination or termination at the option of the customer typically without the payment of any termination fee, under various circumstances such as non-performance, in the event of downtime or impaired performance caused by equipment or operational issues, or sustained periods of downtime due to force majeure events. Many of these events are beyond our control. The contract term in some instances may be extended by the client exercising options for the drilling of additional wells or for an additional term. Our contracts also typically include a provision that allows the client to extend the contract to finish drilling a well-in-progress. During periods of depressed market conditions, our clients may seek to renegotiate firm drilling contracts to reduce their obligations or may seek to repudiate their contracts. Suspension of drilling contracts will result in the reduction in or loss of dayrate for the period of the suspension. If our customers cancel some of our contracts and we are unable to secure new contracts on a timely basis and on substantially similar terms, or if contracts are suspended for an extended period of time or if a number of our contracts are renegotiated, it could adversely affect our consolidated statement of financial position, results of operations or cash flows. See "Item 1A. Risk Factors—Our drilling contracts may be terminated due to a number of events."

Drilling Management Services

We provide drilling management services primarily on a turnkey basis through Applied Drilling Technology Inc., our wholly owned subsidiary, which primarily operates in the U.S. Gulf of Mexico, and through ADT International, a division of one of our U.K. subsidiaries, which primarily operates in the North Sea (together, "ADTI"). As part of our turnkey drilling services, we provide planning, engineering and management services beyond the scope of our traditional contract drilling business and thereby assume greater risk. Under turnkey arrangements, we typically assume responsibility for the design and execution of a well and deliver a logged or cased hole to an agreed depth for a guaranteed price for which payment is contingent upon successful completion of the well program.

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In addition to turnkey drilling services, we participate in project management operations that include providing certain planning, management and engineering services, purchasing equipment and providing personnel and other logistical services to customers. Our project management services differ from turnkey drilling services in that the customer assumes control of the drilling operations and thereby retains the risks associated with the project. These drilling management services revenues represented less than six percent of our consolidated revenues for the year ended December 31, 2008.

In the course of providing drilling management services, ADTI may use a drilling rig in our fleet or contract for a rig owned by a third party.

Integrated Services

From time to time, we provide well and logistics services in addition to our normal drilling services through third party contractors and our employees. We refer to these other services as integrated services, which are generally subject to individual contractual agreements executed to meet specific client needs and may be provided on either a dayrate, cost plus or fixed-price basis, depending on the daily activity. As of February 3, 2009, we were performing such services in India. These integrated services revenues represented less than two percent of our consolidated revenues for the year ended December 31, 2008.

Oil and Gas Properties

We conduct oil and gas exploration, development and production activities through our oil and gas subsidiaries. We acquire interests in oil and gas properties principally in order to facilitate the awarding of turnkey contracts for our drilling management services operations. Our oil and gas activities are conducted through Challenger Minerals Inc. and Challenger Minerals (North Sea) Limited (together, "CMI"), which holds property interests primarily in the U.S. offshore Louisiana and Texas and in the U.K. sector of the North Sea. The oil and gas properties revenues represented less than one percent of our consolidated revenues for the year ended December 31, 2008.

Joint Venture, Agency and Sponsorship Relationships and Other Investments

In some areas of the world, local customs and practice or governmental requirements necessitate the formation of joint ventures with local participation, which we may or may not control. We are an active participant in several joint venture drilling companies, principally in Azerbaijan, Indonesia, Malaysia, Angola, Libya and Nigeria.

We hold a 50 percent interest in Overseas Drilling Limited ("ODL"), an unconsolidated Liberian joint venture company, which owns the drillship Joides Resolution. The drillship is contracted to perform drilling and coring operations in deep waters worldwide for the purpose of scientific research. We manage and operate the vessel on behalf of ODL.

We hold a 50 percent equity interest in Transocean Pacific Drilling Inc. ("TPDI"), a British Virgin Islands joint venture company formed by us and Pacific Drilling Limited ("Pacific Drilling"), a Liberian company, to own two ultra-deepwater drillships to be named Dhirubhai Deepwater KG1 and Dhirubhai Deepwater KG2, which are currently under construction. Under a management services agreement with TPDI, we provide construction management services and have agreed to provide operating management services once the drillships begin operations. Beginning on October 18, 2010, Pacific Drilling will have the right to exchange its interest in the joint venture for our shares or cash at a purchase price based on an appraisal of the fair value of the drillships, subject to various adjustments.

In September 2008, we acquired a 65 percent interest in Angola Deepwater Drilling Company Limited ("ADDCL"), a Cayman Islands joint venture company formed to construct, own and operate an ultra-deepwater drillship to be named Discoverer Luanda. Angco Cayman Limited, a Cayman Islands company, acquired the remaining 35 percent interest in ADDCL. Under a management services agreement with ADDCL, we provide construction management services and have agreed to provide operating management services once the drillship begins operations. Beginning on the fifth anniversary of the first well commencement date, Angco Cayman Limited will have the right to exchange its interest in the joint venture for cash at a purchase price based on an appraisal of the fair value of the drillship, subject to various adjustments.

In Azerbaijan, Caspian Drilling Company Limited ("CDC"), a joint venture in which we hold a 45 percent ownership interest operates the semisubmersibles Istiglal and Dada Gorgud under bareboat charters running until October 2011 from the owner of both rigs, SOCAR, our sole equity partner in CDC.

A joint venture in which we hold a noncontrolling minority interest operates primarily in Libya and, to a limited extent, in Syria. The joint venture, Arab Drilling & Workover Company ("ADWOC"), is a Libyan joint venture company, of which we own a 40 percent interest, with the remaining 60 percent being owned by parties unrelated to us. One of these parties is Arab Petroleum Investments Corporation, a Saudi Arabian company ("APIC"), whose shareholders are the ten member states of the Organization of Arab Petroleum Exporting Countries ("OAPEC"), including Syria (three percent interest). APIC owns a 20 percent interest in ADWOC. The other party is Arab Petroleum Services Company, a Libyan company ("APSCO"), whose shareholders are the member states of OAPEC. APSCO owns a 40 percent interest in ADWOC. The Establishment Agreement and Statutes of the joint venture provide us with the right to appoint two of the five members of the board of directors of ADWOC. While the Libyan Sanctions Regulations of the U.S. Treasury Department's Office of Foreign Assets Control ("OFAC") were in effect, our two representatives on the board generally attended but did not otherwise participate in meetings of the board of directors. Since the Libyan Sanctions Regulations were lifted by executive order, our representatives have voted on some matters at meetings of the board of directors of ADWOC.

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Syria is identified by the U.S. State Department as a state sponsor of terrorism. In addition, Syria is subject to a number of economic regulations, including sanctions administered by OFAC, and comprehensive restrictions on the export and re-export of U.S.-origin items to Syria. We believe our noncontrolling minority investment has been maintained in accordance with all applicable OFAC regulations. However, potential investors could view our minority interest in our Libyan joint venture and any potential violations of OFAC regulations negatively, which could adversely affect our reputation and the market for our shares. Various state and municipal governments, universities and other investors have proposed or adopted divestment and other initiatives regarding investments (including, with respect to state governments, by state retirement systems) in companies that do business with countries that have been designated as state sponsors of terrorism by the U.S. State Department. As a result, certain investors may be subject to reporting requirements with respect to investments in companies such as ours or may be subject to limits or prohibitions with respect to those investments. See "Item 1A. Risk Factors—Our non-U.S. operations involve additional risks not associated with our U.S. operations."

Local laws or customs in some areas of the world also effectively mandate establishment of a relationship with a local agent or sponsor. When appropriate in these areas, we enter into agency or sponsorship agreements.

Significant Clients

We engage in offshore drilling for most of the leading international oil companies (or their affiliates), as well as for many government-controlled and independent oil companies. Our most significant client in 2008 was BP, accounting for 11 percent of our 2008 operating revenues. No other client accounted for 10 percent or more of our 2008 operating revenues. The loss of this significant client could, at least in the short term, have a material adverse effect on our results of operations.

Environmental Regulation

For a discussion of the effects of environmental regulation, see "Item 1A. Risk Factors—Compliance with or breach of environmental laws can be costly and could limit our operations." We have made and will continue to make the required expenditures to comply with environmental requirements. We continue to make expenditures to further our commitment to continuous improvement and the setting of a global environmental standard. Continually assessing our aspects and impacts, specifically in the areas of greenhouse gas emissions and climate change, while monitoring legislation, will ensure continued risk reduction in our future operations and sound environmental management. To date, we have not expended material amounts in order to comply, and we do not believe that our compliance with such requirements will have a material adverse effect upon our results of operations or competitive position or materially increase our capital expenditures.

Employees

We require highly skilled personnel to operate our drilling units. As a result, we conduct extensive personnel recruiting, training and safety programs. At December 31, 2008, we had approximately 21,600 employees and we also utilized approximately 4,700 persons through contract labor providers. Some of our employees, most of whom work in Nigeria, the U.K., Egypt and Norway, are represented by collective bargaining agreements. In addition, some of our contracted labor work under collective bargaining agreements. Many of these represented individuals are working under agreements that are subject to ongoing salary negotiation in 2009. These negotiations could result in higher personnel expenses, other increased costs or increased operation restrictions. Additionally, the unions in the U.K. have sought an interpretation of the application of the Working Time Regulations to the offshore sector. The Employment Appeal Tribunal (the "Tribunal") has issued its decision in favor of the unions and held, in part, that offshore workers are entitled to another 14 days of annual leave. We have appealed in the first instance to the Tribunal. Oral arguments on the appeal have been held but no decision has been issued. The application of the Working Time Regulations to the offshore sector could result in higher labor costs and could undermine our ability to obtain a sufficient number of skilled workers in the U.K.

Available Information

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

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

• Audit Committee Charter;

• Corporate Governance Committee Charter;

• Executive Compensation Committee Charter;

• Finance/Benefits Committee Charter;

• Mission Statement;

• Code of Business Conduct and Ethics, including our anti-corruption policy; and

• Corporate Governance Guidelines.

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We intend to satisfy the requirement under Item 5.05 of Form 8-K to disclose any amendments to our Code of Business Conduct and Ethics and any waiver from a provision of our Code of Business Conduct and Ethics by posting such information in the Corporate Governance section of our website at www.deepwater.com.

ITEM 1A.

Risk Factors

The recent worldwide financial and credit crisis and worldwide economic downturn could have a material adverse effect on our revenue, profitability and financial position.

The recent worldwide financial and credit crisis has reduced the availability of liquidity and credit to fund the continuation and expansion of industrial business operations worldwide. The shortage of liquidity and credit combined with recent substantial losses in worldwide equity markets could lead to an extended worldwide economic recession. A slowdown in economic activity caused by a recession could reduce worldwide demand for energy and result in an extended period of lower oil and natural gas prices. Crude oil prices have declined from record levels in July 2008 of approximately $145 per barrel to approximately $40 per barrel as of February 20, 2009 and natural gas prices have also experienced sharp declines. This decline in commodity prices, along with difficult conditions in the credit markets, has had a negative impact on our business, and this impact could continue or worsen. Demand for our services depends on oil and natural gas industry activity and expenditure levels that are directly affected by trends in oil and, to a lesser extent, natural gas prices. Demand for our services is particularly sensitive to the level of exploration, development, and production activity of, and the corresponding capital spending by, oil and natural gas companies, including national oil companies. Any prolonged reduction in oil and natural gas prices could depress the immediate levels of exploration, development, and production activity. Perceptions of longer-term lower oil and natural gas prices by oil and gas companies could similarly reduce or defer major expenditures given the long-term nature of many large-scale development projects. Lower levels of activity result in a corresponding decline in the demand for our services, which could have a material adverse effect on our revenue and profitability. Additionally, these factors may adversely impact our statement of financial position if they are determined to cause a further impairment of our goodwill or intangible assets or of our long-lived assets or our assets held for sale. The financial crisis may also adversely affect the ability of shipyards to meet scheduled deliveries of our newbuild and other shipyard projects.

The global financial and credit crisis may negatively impact our business and financial condition.

The continued credit crisis and related instability in the global financial system has had, and may continue to have, an impact on our business and our financial condition. We may face significant challenges if conditions in the financial markets do not improve. Our ability to access the capital markets may be severely restricted at a time when we would like, or need, to access such markets, which could have an impact on our flexibility to react to changing economic and business conditions. The credit crisis has impacted lenders participating in our credit facilities and our customers, and further negative impacts may cause them to fail to meet their obligations to us.

Our business depends on the level of activity in the offshore oil and gas industry, which is significantly affected by volatile oil and gas prices and other factors.

Our business depends on the level of activity in oil and gas exploration, development and production in offshore areas worldwide. Oil and gas prices and market expectations of potential changes in these prices significantly affect this level of activity. However, higher commodity prices do not necessarily translate into increased drilling activity since customers' expectations of future commodity prices typically drive demand for our rigs. Also, increased competition for customers' drilling budgets could come from, among other areas, land-based energy markets in Africa, Russia, Western Asian countries, the Middle East, the U.S. and elsewhere. The availability of quality drilling prospects, exploration success, relative production costs, the stage of reservoir development and political and regulatory environments also affect customers' drilling campaigns. Worldwide military, political and economic events have contributed to oil and gas price volatility and are likely to do so in the future.

Oil and gas prices are extremely volatile and are affected by numerous factors, including the following:

• worldwide demand for oil and gas including economic activity in the U.S. and other energy-consuming markets;

• the ability of the Organization of the Petroleum Exporting Countries ("OPEC") to set and maintain production levels and pricing;

• the level of production in non-OPEC countries;

• the policies of various governments regarding exploration and development of their oil and gas reserves;

• advances in exploration and development technology; and

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

Our industry is highly competitive and cyclical, with intense price competition.

The offshore contract drilling industry is highly competitive with numerous industry participants, none of which has a dominant market share. Drilling contracts are traditionally awarded on a competitive bid basis. Intense price competition is often the primary factor in determining which qualified contractor is awarded a job, although rig availability and the quality and technical capability of service and equipment may also be considered.

Our industry has historically been cyclical and is impacted by oil and gas price levels and volatility. There have been periods of high demand, short rig supply and high dayrates, followed by periods of low demand, excess rig supply and low dayrates. Changes in commodity prices can have a dramatic effect on rig demand, and periods of excess rig supply intensify the competition in the industry and often result in rigs being idle for long periods of time. Since the onset of the worldwide financial and credit crisis and economic downturn, we have experienced weakness in our Midwater Floater and Jackup markets. We may be required to idle rigs or enter into lower dayrate contracts in response to market conditions.

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During prior periods of high utilization and dayrates, industry participants have increased the supply of rigs by ordering the construction of new units. This has typically resulted in an oversupply of drilling units and has caused a subsequent decline in utilization and dayrates, sometimes for extended periods of time. There are numerous high-specification rigs and jackups under contract for construction and several mid-water semisubmersibles are being upgraded to enhance their operating capability. The entry into service of these new and upgraded units will increase supply and could curtail a strengthening, or trigger a reduction, in dayrates as rigs are absorbed into the active fleet. Any further increase in construction of new drilling units would likely exacerbate the negative impact on utilization and dayrates. Lower utilization and dayrates could adversely affect our revenues and profitability. Prolonged periods of low utilization and dayrates could also result in the recognition of impairment charges on certain classes of our drilling rigs or our goodwill balance if future cash flow estimates, based upon information available to management at the time, indicate that the carrying values of these rigs, goodwill or other intangible assets may not be recoverable.

Our shipyard projects and operations are subject to delays and cost overruns.

We have committed to a total of ten deepwater newbuild rig projects and the Sedco 706 rig upgrade. We also have a variety of other more limited shipyard projects at any given time. These shipyard projects are subject to the risks of delay or cost overruns inherent in any such construction project resulting from numerous factors, including the following:

• shipyard availability;

• shortages of equipment, materials or skilled labor;

• unscheduled delays in the delivery of ordered materials and equipment;

• engineering problems, including those relating to the commissioning of newly designed equipment;

• work stoppages;

• client acceptance delays;

• weather interference or storm damage;

• unanticipated cost increases; and

• difficulty in obtaining necessary permits or approvals.

These factors may contribute to cost variations and delays in the delivery of our upgraded and newbuild units and other rigs undergoing shipyard projects. Delays in the delivery of these units would result in delay in contract commencement, resulting in a loss of revenue to us, and may also cause customers to terminate or shorten the term of the drilling contract for the rig pursuant to applicable late delivery clauses. In the event of termination of one of these contracts, we may not be able to secure a replacement contract on as favorable terms, if at all.

Our operations also rely on a significant supply of capital and consumable spare parts and equipment to maintain and repair our fleet. We also rely on the supply of ancillary services, including supply boats and helicopters. We have experienced increased delivery times from vendors due to increased drilling activity worldwide and the increase in construction and upgrade projects and have also experienced a tightening in the availability of ancillary services. Shortages in materials, delays in the delivery of necessary spare parts, equipment or other materials, or the unavailability of ancillary services could negatively impact our future operations and result in increases in rig downtime, and delays in the repair and maintenance of our fleet.

Our drilling contracts may be terminated due to a number of events.

Certain of our contracts with customers may be cancelable at the option of the customer upon payment of an early termination payment. Such payments may not, however, fully compensate us for the loss of the contract. Contracts also customarily provide for either automatic termination or termination at the option of the customer typically without the payment of any termination fee, under various circumstances such as non-performance, as a result of downtime or impaired performance caused by equipment or operational issues, or sustained periods of downtime due to force majeure events. Many of these events are beyond our control. During periods of depressed market conditions, we may be subject to an increased risk of our clients seeking to repudiate their contracts, including through claims of non-performance. Our customers' ability to perform their obligations under their drilling contracts with us may also be negatively impacted by the credit crisis and the economic downturn. If our customers cancel some of our contracts, and we are unable to secure new contracts on a timely basis and on substantially similar terms, or if contracts are suspended for an extended period of time or if a number of our contracts are renegotiated, it could adversely affect our consolidated statement of financial position, results of operations or cash flows.

The anticipated benefits of moving our principal executive offices to Switzerland may not be realized, and difficulties in connection with moving our principal executive offices could have an adverse effect on us.

We are in the process of relocating our principal executive offices from the Cayman Islands and Houston, Texas to Vernier, Switzerland. Initially we expect that 14 of our officers, including our Chief Executive Officer, will be located at our new principal executive offices, along with related support staff. We may face significant challenges in relocating our executive offices to a different country, including difficulties in retaining and attracting officers, key personnel and other employees and challenges in maintaining principal executive offices in a country different from the country where other employees, including corporate support staff, are located. Employees may be uncertain about their future roles within our organization following the completion of the Redomestication Transaction. Management may also be required to devote substantial time to the Redomestication Transaction and related matters, which could otherwise be devoted to focusing on ongoing business operations and other initiatives and opportunities. In addition, we may not realize the benefits we anticipate from the Redomestication Transaction. Any such difficulties could have an adverse effect on our business, results of operations or financial condition.

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Our non-U.S. operations involve additional risks not associated with our U.S. operations.

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

• terrorist acts, war, piracy and civil disturbances;

• expropriation or nationalization of equipment; and

• the inability to repatriate income or capital.

We are protected to some extent against loss of capital assets, but generally not loss of revenue, from most of these risks through indemnity provisions in our drilling contracts. Our assets are generally not insured against risk of loss due to perils such as terrorist acts, civil unrest, expropriation, nationalization and acts of war.

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

Our non-U.S. contract drilling operations are subject to various laws and regulations in certain countries in which we operate, including laws and regulations relating to the equipment and operation of drilling units, currency conversions and repatriation, oil and gas exploration and development and taxation of offshore earnings and earnings of expatriate personnel. We are also subject to OFAC and other U.S. laws and regulations governing our international operations. In addition, various state and municipal governments, universities and other investors have proposed or adopted divestment and other initiatives regarding investments (including, with respect to state governments, by state retirement systems) in companies that do business with countries that have been designated as state sponsors of terrorism by the U.S. State Department. We have a minority interest in a Libyan joint venture that operates to a limited extent in Syria, which has been designated as a state sponsor of terrorism by the U.S. State Department. Our internal compliance program has identified a potential OFAC compliance issue involving the shipment of goods by a freight forwarder through Iran, another country that has been designated as a state sponsor of terrorism by the U.S. State Department. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Outlook–Regulatory Matters." Failure to comply with applicable laws and regulations, including those relating to sanctions and export restrictions, may subject us to criminal sanctions or civil remedies, including fines, denial of export privileges, injunctions or seizures of assets. Potential investors could view our minority interest in our Libyan joint venture and any potential violations of OFAC regulations negatively, which could adversely affect our reputation and the market for our shares.

Governments in some foreign countries have become increasingly active in regulating and controlling the ownership of concessions and companies holding concessions, the exploration for oil and gas and other aspects of the oil and gas industries in their countries. In addition, government action, including initiatives by OPEC, may continue to cause oil or gas price volatility. In some areas of the world, this governmental activity has adversely affected the amount of exploration and development work done by major oil companies and may continue to do so.

A substantial portion of our drilling contracts are partially payable in local currency. Those amounts may exceed our local currency needs, leading to the accumulation of excess local currency, which, in certain instances, may be subject to either temporary blocking or other difficulties converting to U.S. dollars. Excess amounts of local currency may be exposed to the risk of currency exchange losses.

A change in tax laws, treaties or regulations, or their interpretation, of any country in which we operate could result in a higher tax rate on our worldwide earnings, which could result in a significant negative impact on our earnings and cash flows from operations.

A change in applicable tax laws, treaties or regulations could result in a higher effective tax rate on our worldwide earnings and such change could be significant to our financial results. One of the income tax treaties that we rely upon is currently in the process of being renegotiated. This renegotiation will likely result in a change in the terms of the treaty that is adverse to our tax structure, which in turn would increase our effective tax rate, and such increase could be material. We expect to take certain steps to mitigate any such potential negative impact. We may not be able to fully, or partially, mitigate any negative impact of this treaty renegotiation or any other future changes in treaties that we rely upon.

Tax legislative proposals intending to eliminate some perceived tax advantages of companies that have legal domiciles outside the U.S. but have certain U.S. connections have repeatedly been introduced in the U.S. Congress. Recent examples include, but are not limited to, legislative proposals that would broaden the circumstances in which a non-U.S. company would be considered a U.S. resident and proposals that could override certain tax treaties and limit treaty benefits on certain payments by U.S. subsidiaries to non-U.S. affiliates.

Failure to comply with the U.S. Foreign Corrupt Practices Act could result in fines, criminal penalties, drilling contract terminations and an adverse effect on our business.

In June 2007, GlobalSantaFe's management retained outside counsel to conduct an internal investigation of its Nigerian and West African operations, focusing on brokers who handled customs matters for its affiliates operating in those jurisdictions and whether those brokers have fully complied with the U.S. Foreign Corrupt Practices Act ("FCPA") and local laws. GlobalSantaFe commenced its investigation following announcements by other oilfield service companies that they were independently investigating the FCPA implications of certain actions taken by third parties in respect of customs matters in connection with their operations in Nigeria, as well as another company's announced settlement implicating a third party handling customs matters in Nigeria. In each case, the customs broker

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was reported to be Panalpina Inc., which GlobalSantaFe used to obtain temporary import permits for its rigs operating offshore Nigeria. GlobalSantaFe voluntarily disclosed its internal investigation to the U.S. Department of Justice (the "DOJ") and the SEC and, at their request, expanded its investigation to include the activities of its customs brokers in other West African countries and the activities of Panalpina Inc. worldwide. The investigation is focusing on whether the brokers have fully complied with the requirements of their contracts, local laws and the FCPA. In late November 2007, GlobalSantaFe received a subpoena from the SEC for documents related to its investigation. In this connection, the SEC advised GlobalSantaFe that it had issued a formal order of investigation. After the completion of the Merger, outside counsel began formally reporting directly to the audit committee of our board of directors. Our legal representatives are keeping the DOJ and SEC apprised of the scope and details of their investigation and producing relevant information in response to their requests.

We cannot predict the ultimate outcome of these investigations, the total costs to be incurred in completing the investigations, the potential impact on personnel, the effect of implementing any further measures that may be necessary to ensure full compliance with applicable laws or to what extent, if at all, we could be subject to fines, sanctions or other penalties. Our investigation includes a review of amounts paid to and by customs brokers in connection with the obtaining of permits for the temporary importation of vessels and the clearance of goods and materials. These permits and clearances are necessary in order for us to operate our vessels in certain jurisdictions. There is a risk that we may not be able to obtain import permits or renew temporary importation permits in West African countries, including Nigeria, in a manner that complies with the FCPA. As a result, we may not have the means to renew temporary importation permits for rigs located in the relevant jurisdictions as they expire or to send goods and equipment into those jurisdictions, in which event we may be forced to terminate the pending drilling contracts and relocate the rigs or leave the rigs in these countries and risk permanent importation issues, either of which could have an adverse effect on our financial results. In addition, termination of drilling contracts could result in damage claims by customers.

Our labor costs and the operating restrictions under which we operate could increase as a result of collective bargaining negotiations and changes in labor laws and regulations.

Some of our employees, most of whom work in Nigeria, the U.K., Egypt and Norway, are represented by collective bargaining agreements. In addition, some of our contracted labor work under collective bargaining agreements. Many of these represented individuals are working under agreements that are subject to ongoing salary negotiation in 2009. These negotiations could result in higher personnel expenses, other increased costs or increased operating restrictions. Additionally, the unions in the U.K. have sought an interpretation of the application of the Working Time Regulations to the offshore sector. The Employment Appeal Tribunal (the "Tribunal") has issued its decision in favor of the unions and held, in part, that offshore workers are entitled to another 14 days of annual leave. We have appealed in the first instance to the Tribunal. Oral arguments on the appeal have been held but no decision has been issued. The application of the Working Time Regulations to the offshore sector could result in higher labor costs and could undermine our ability to obtain a sufficient number of skilled workers in the U.K.

Our business involves numerous operating hazards.

Our operations are subject to the usual hazards inherent in the drilling of oil and gas wells, such as blowouts, reservoir damage, loss of production, loss of well control, punch-throughs, craterings, fires and natural disasters such as hurricanes and tropical storms. In particular, the Gulf of Mexico area is subject to hurricanes and other extreme weather conditions on a relatively frequent basis, and our drilling rigs in the region may be exposed to damage or total loss by these storms (some of which may not be covered by insurance). The occurrence of these events could result in the suspension of drilling operations, damage to or destruction of the equipment involved and injury to or death of rig personnel. We are also subject to personal injury and other claims by rig personnel as a result of our drilling operations. Operations also may be suspended because of machinery breakdowns, abnormal drilling conditions, failure of subcontractors to perform or supply goods or services, or personnel shortages. In addition, offshore drilling operations are subject to perils peculiar to marine operations, including capsizing, grounding, collision and loss or damage from severe weather. Damage to the environment could also result from our operations, particularly through oil spillage or extensive uncontrolled fires. We may also be subject to property, environmental and other damage claims by oil and gas companies. Our insurance policies and contractual rights to indemnity may not adequately cover losses, and we do not have insurance coverage or rights to indemnity for all risks. Consistent with standard industry practice, our clients generally assume, and indemnify us against, well control and subsurface risks under dayrate contracts. These are risks associated with the loss of control of a well, such as blowout or cratering, the cost to regain control of or redrill the well and associated pollution. However, there can be no assurance that these clients will be financially able to indemnify us against all these risks.

We maintain insurance coverage for property damage, occupational injury and illness, and general and marine third-party liabilities. We generally have no coverage for named storms in the U.S. Gulf of Mexico and war perils worldwide. Also, pollution and environmental risks generally are not totally insurable.

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We maintain large self-insured deductibles for damage to our offshore drilling equipment and third-party liabilities. With respect to hull and machinery we generally maintain a $125 million deductible per occurrence, subject to a $250 million annual aggregate deductible. In the event that the $250 million annual aggregate deductible has been exceeded, the hull and machinery deductible becomes $10 million per occurrence. However, in the event of a total loss or a constructive total loss of a drilling unit, then such loss is fully covered by our insurance with no deductible. For general and marine third-party liabilities we generally maintain a $10 million per occurrence deductible on personal injury liability for crew claims ($5 million for non-crew claims) and a $5 million per occurrence deductible on third-party property damage. We also self-insure the primary $50 million of liability limits in excess of the $5 million and $10 million per occurrence deductibles described in the prior sentence. Generally, our turnkey drilling contracts include provisions that limit ADTI's liability associated with well blowouts to $50 million. We self-insure coverage for expenses to ADTI and CMI related to well control and redrill liability for well blowouts.

If a significant accident or other event occurs and is not fully covered by insurance or an enforceable or recoverable indemnity from a client, it could adversely affect our consolidated statement of financial position, results of operations or cash flows. The amount of our insurance may be less than the related impact on enterprise value after a loss. Our insurance coverage will not in all situations provide sufficient funds to protect us from all liabilities that could result from our drilling operations. Our coverage includes annual aggregate policy limits. As a result, we retain the risk through self-insurance for any losses in excess of these limits. We do not carry insurance for loss of revenue, and certain other claims may also not be reimbursed by insurance carriers. Any such lack of reimbursement may cause us to incur substantial costs. In addition, we could decide to retain substantially more risk through self-insurance in the future. Moreover, no assurance can be made that we will be able to maintain adequate insurance in the future at rates we consider reasonable or be able to obtain insurance against certain risks. As of February 3, 2009, all of the rigs that we owned or operated were covered by existing insurance policies.

A loss of a major tax dispute or a successful tax challenge to our operating structure, intercompany pricing policies or the taxable presence of our key subsidiaries in certain countries could result in a higher tax rate on our worldwide earnings, which could result in a significant negative impact on our earnings and cash flows from operations.

We are a Swiss corporation that operates through our various subsidiaries in a number of countries throughout the world. Consequently, we are subject to tax laws, treaties and regulations in and between the countries in which we operate. Our income taxes are based upon the applicable tax laws and tax rates in effect in the countries in which we operate and earn income as well as upon our operating structures in these countries.

Our income tax returns are subject to review and examination. We do not recognize the benefit of income tax positions we believe are more likely than not to be disallowed upon challenge by a tax authority. If any tax authority successfully challenges our operational structure, intercompany pricing policies or the taxable presence of our key subsidiaries in certain countries; or if the terms of certain income tax treaties are interpreted in a manner that is adverse to our structure; or if we lose a material tax dispute in any country, particularly in the U.S., Norway or Brazil, our effective tax rate on our worldwide earnings could increase substantially and our earnings and cash flows from operations could be materially adversely affected. For example, there is considerable uncertainty as to the activities that constitute being engaged in a trade or business within the U.S. (or maintaining a permanent establishment under an applicable treaty), so we cannot be certain that the Internal Revenue Service ("IRS") will not contend successfully that we or any of our key subsidiaries were or are engaged in a trade or business in the U.S. (or, when applicable, maintained or maintains a permanent establishment in the U.S.). If we or any of our key subsidiaries were considered to have been engaged in a trade or business in the U.S. (when applicable, through a permanent establishment), we could be subject to U.S. corporate income and additional branch profits taxes on the portion of our earnings effectively connected to such U.S. business during the period in which this was considered to have occurred, in which case our effective tax rate on worldwide earnings for that period could increase substantially, and our earnings and cash flows from operations for that period could be adversely affected. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Outlook–Tax Matters."

Failure to retain key personnel could hurt our operations.

We require highly skilled personnel to operate and provide technical services and support for our business worldwide. Over the last few years, competition for the labor required for drilling operations, including for turnkey drilling and drilling management services businesses and construction projects, intensified as the number of rigs activated, added to worldwide fleets or under construction increased, leading to shortages of qualified personnel in the industry and creating upward pressure on wages and higher turnover. We may experience a reduction in the experience level of our personnel as a result of any increased turnover, which could lead to higher downtime and more operating incidents, which in turn could decrease revenues and increase costs. In response to these historical labor market conditions, we increased efforts in our recruitment, training, development and retention programs as required to meet our anticipated personnel needs. Although we expect market conditions to slow employee turnover, if increased competition for labor were to intensify in the future we may experience further increases in costs or limits on operations.

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We have a substantial amount of debt, and we may lose the ability to obtain future financing and suffer competitive disadvantages.

Our overall debt level was $14 billion and $17 billion at December 31, 2008 and December 31, 2007, respectively. This substantial level of debt and other obligations could have significant adverse consequences on our business and future prospects, including the following:

• we may not be able to obtain financing in the future for working capital, capital expenditures, acquisitions, debt service requirements or other purposes;

• we may not be able to use operating cash flow in other areas of our business because we must dedicate a substantial portion of these funds to service the debt;

• we could become more vulnerable to general adverse economic and industry conditions, including increases in interest rates, particularly given our substantial indebtedness, some of which bears interest at variable rates;

• we may not be able to meet financial ratios included in our bank credit agreements due to market conditions or other events beyond our control, which could result in a default under these agreements and trigger cross default provisions in our other debt instruments;

• less levered competitors could have a competitive advantage because they have lower debt service requirements; and

• we may be less able to take advantage of significant business opportunities and to react to changes in market or industry conditions than our competitors.

Our overall debt level and/or market conditions could lead the credit rating agencies to lower our corporate credit ratings below currently expected levels and possibly below investment grade.

Our high leverage level and/or market conditions could lead the credit rating agencies to downgrade our credit ratings below currently expected levels and possibly to non-investment grade levels. Such ratings levels could limit our ability to refinance our existing debt, cause us to issue debt with unfavorable terms and conditions and increase certain fees we pay under our credit facilities. In addition, such ratings levels could negatively impact current and prospective customers' willingness to transact business with us. Suppliers may lower or eliminate the level of credit provided through payment terms when dealing with us thereby increasing the need for higher levels of cash on hand, which would decrease our ability to repay debt balances. Our credit ratings are currently BBB+ and Baa2 by Standard & Poor's and Moody's, respectively.

We may be limited in our use of net operating losses.

Our ability to benefit from our deferred tax assets depends on us having sufficient future earnings to utilize our net operating loss ("NOL") carryforwards before they expire. We have established a valuation allowance against the future tax benefit for a number of our foreign NOL carryforwards, and we could be required to record an additional valuation allowance against our foreign or U.S. deferred tax assets if market conditions change materially and, as a result, our future earnings are, or are projected to be, significantly less than we currently estimate. Our NOL carryforwards are subject to review and potential disallowance upon audit by the tax authorities of the jurisdictions where the NOLs are incurred.

Our operating and maintenance costs will not necessarily fluctuate in proportion to changes in operating revenues.

Our operating and maintenance costs will not necessarily fluctuate in proportion to changes in operating revenues. Operating revenues may fluctuate as a function of changes in dayrate. However, costs for operating a rig are generally fixed or only semi-variable regardless of the dayrate being earned. In addition, should our rigs incur idle time between contracts, we typically will not reduce the staff on those rigs because we will use the crew to prepare the rig for its next contract. During times of reduced activity, reductions in costs may not be immediate as portions of the crew may be required to prepare rigs for stacking, after which time the crew members are assigned to active rigs or dismissed. In addition, as our rigs are mobilized from one geographic location to another, the labor and other operating and maintenance costs can vary significantly. In general, labor costs increase primarily due to higher salary levels and inflation. Equipment maintenance expenses fluctuate depending upon the type of activity the unit is performing and the age and condition of the equipment. Contract preparation expenses vary based on the scope and length of contract preparation required and the duration of the firm contractual period over which such expenditures are amortized.

We are subject to litigation that, if not resolved in our favor and not sufficiently insured against, could have a material adverse effect on us.

We are subject to a variety of litigation and may be sued in additional cases. Certain of our subsidiaries are named as defendants in numerous lawsuits alleging personal injury as a result of exposure to asbestos or toxic fumes or resulting from other occupational diseases, such as silicosis, and various other medical issues that can remain undiscovered for a considerable amount of time. Some of these subsidiaries that have been put on notice of potential liabilities have no assets. Other subsidiaries are subject to litigation relating to environmental damage. We cannot predict the outcome of these cases involving those subsidiaries or the potential costs to resolve them. Insurance may not be applicable or sufficient in all cases, insurers may not remain solvent, and policies may not be located. Suits against non-asset-owning subsidiaries have and may in the future give rise to alter ego or successor-in-interest claims against us and our asset-owning subsidiaries to the extent a subsidiary is unable to pay a claim or insurance is not available or sufficient to cover the claims. To the extent that one or more pending or future litigation matters are not resolved in our favor and are not covered by insurance, a material adverse effect on our financial results and condition could result.

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Public health threats could have a material adverse effect on our operations and our financial results.

Public health threats, such as the bird flu, Severe Acute Respiratory Syndrome, and other highly communicable diseases, outbreaks of which have already occurred in various parts of the world in which we operate, could adversely impact our operations, the operations of our clients and the global economy, including the worldwide demand for oil and natural gas and the level of demand for our services. Any quarantine of personnel or inability to access our offices or rigs could adversely affect our operations. Travel restrictions or operational problems in any part of the world in which we operate, or any reduction in the demand for drilling services caused by public health threats in the future, may materially impact operations and adversely affect our financial results.

Compliance with or breach of environmental laws can be costly and could limit our operations.

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

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

Our ability to operate our rigs in the U.S. Gulf of Mexico could be restricted by governmental regulation.

Hurricanes Ivan, Katrina and Rita in 2005 and Hurricanes Gustav and Ike in 2008 caused damage to a number of rigs in the U.S. Gulf of Mexico fleet. Rigs that were moved off location by the storms damaged platforms, pipelines, wellheads and other drilling rigs. In 2006, the Minerals Management Service of the U.S. Department of the Interior ("MMS") issued interim guidelines requiring that semisubmersibles operating in the U.S. Gulf of Mexico assess their mooring systems against stricter criteria. In 2007 additional guidelines were issued which impose stricter criteria, requiring rigs to meet 25-year storm conditions. Although all of our semisubmersibles currently operating in the U.S. Gulf of Mexico meet the 2007 requirements, these guidelines may negatively impact our ability to operate other semisubmersibles in the U.S. Gulf of Mexico in the future. Moreover, the MMS may issue additional regulations that could increase the cost of operations or reduce the area of operations for our rigs in the future, thus reducing their marketability. Implementation of additional MMS regulations may subject us to increased costs or limit the operational capabilities of our rigs and could materially and adversely affect our operations in the U.S. Gulf of Mexico.

Acts of terrorism and social unrest could affect the markets for drilling services.

Acts of terrorism and social unrest, brought about by world political events or otherwise, have caused instability in the world's financial and insurance markets in the past and may occur in the future. Such acts could be directed against companies such as ours. In addition, acts of terrorism and social unrest could lead to increased volatility in prices for crude oil and natural gas and could affect the markets for drilling services. Insurance premiums could increase and coverages may be unavailable in the future. U.S. government regulations may effectively preclude us from actively engaging in business activities in certain countries. These regulations could be amended to cover countries where we currently operate or where we may wish to operate in the future.

Our status as a Swiss corporation may limit our flexibility with respect to certain aspects of capital management and may cause us to be unable to make distributions or repurchase shares without subjecting our shareholders to Swiss withholding tax.

Swiss law allows our shareholders to authorize share capital that can be issued by the board of directors without shareholder approval, but this authorization is limited to 50 percent of the existing registered share capital and must be renewed by the shareholders every two years. Additionally, subject to specified exceptions, Swiss law grants preemptive rights to existing shareholders to subscribe for new issuances of shares. Swiss law also does not provide as much flexibility in the various terms that can attach to different classes of shares as the laws of some other jurisdictions. In the event we need to raise common equity capital at a time when the trading price of our shares is below the 15 Swiss franc (equivalent to U.S. $12.64, based on a foreign exchange rate of 1.1864 Swiss francs to $1.00 on February 20, 2009) par value of the shares, we will need to obtain approval of shareholders to decrease the par value of our shares or issue another class of shares with a lower par value. Any reduction in par value would decrease our par value available for future repayment of share capital not subject to Swiss withholding tax. Swiss law also reserves for approval by shareholders many corporate actions over which a board of directors would have authority in some other jurisdictions. For example, dividends must be approved by shareholders. These Swiss law requirements relating to our capital management may limit our flexibility, and situations may arise where greater flexibility would have provided substantial benefits to our shareholders.

If we are not successful in our efforts to make distributions, if any, through a reduction of par value or, after January 1, 2011, pay dividends, if any, out of qualifying additional paid-in capital as shown on Transocean Ltd.'s standalone Swiss statutory financial statements,

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then any dividends paid by us will generally be subject to a Swiss federal withholding tax at a rate of 35 percent. Payment of a capital distribution in the form of a par value reduction is not subject to Swiss withholding tax. However, our shareholders may not approve a reduction in par value, or we may not be able to meet the other legal requirements for a reduction in par value. The Swiss withholding rules could also be changed in the future. In addition, over the long term, the amount of par value available for us to use for par value reductions will be limited. If we are unable to make a distribution through a reduction in par value or, after January 1, 2011, pay a dividend out of qualifying additional paid-in capital as shown on Transocean Ltd.'s standalone Swiss statutory financial statements, we may not be able to make distributions without subjecting our shareholders to Swiss withholding taxes.

Under present Swiss tax law, repurchases of shares for the purposes of capital reduction are treated as a partial liquidation subject to a 35 percent Swiss withholding tax on the difference between the par value and the repurchase price. We may follow a share repurchase process for future share repurchases, if any, similar to a "second trading line" on the SIX Swiss Exchange in which Swiss institutional investors sell shares to us and are generally able to receive a refund of the Swiss withholding tax. However, if we are unable to use this process successfully, we may not be able to repurchase shares for the purposes of capital reduction without subjecting the selling shareholders to Swiss withholding taxes.

We are subject to anti-takeover provisions.

Our articles of association and Swiss law contain provisions that could prevent or delay an acquisition of the company by means of a tender offer, a proxy contest or otherwise. These provisions may also adversely affect prevailing market prices for our shares. These provisions, among other things:

• classify our board into three classes of directors, each of which serve for staggered three-year periods;

• provide that the board of directors is authorized, at any time during a maximum two-year period, to issue a number of shares of up to 50 percent of the share capital registered in the commercial register and to limit or withdraw the preemptive rights of existing shareholders in various circumstances, including (1) following a shareholder or group of shareholders acting in concert having acquired in excess of 15 percent of the share capital registered in the commercial register without having submitted a takeover proposal to shareholders that is recommended by the board of directors or (2) for purposes of the defense of an actual, threatened or potential unsolicited takeover bid, in relation to which the board of directors has, upon consultation with an independent financial adviser retained by the board of directors, not recommended acceptance to the shareholders;

• provide that any shareholder who wishes to propose any business or to nominate a person or persons for election as director at any annual meeting may only do so if advance notice is given to the Secretary of Transocean;

• provide that directors can be removed from office only by the affirmative vote of the holders of at least 66 2/3 percent of the shares outstanding and entitled to vote;

• provide that a merger or demerger transaction requires the affirmative vote of the holders of at least 66 2/3 percent of the shares represented at the meeting and provide for the possibility of a so-called "cashout" or "squeezeout" merger if the acquirer controls 90 percent of the outstanding shares entitled to vote at the meeting;

• provide that any action required or permitted to be taken by the holders of shares must be taken at a duly called annual or extraordinary general meeting of shareholders;

• limit the ability of our shareholders to amend or repeal some provisions of our articles of association; and

• limit transactions between us and an "interested shareholder," which is generally defined as a shareholder that, together with its affiliates and associates, beneficially, directly or indirectly, owns 15 percent or more of our shares entitled to vote at a general meeting.

Our board of directors is comprised of six persons who were designated by Transocean and six persons who were designated by GlobalSantaFe prior to completing the Merger. Under our organizational regulations, at each annual general meeting held during the two years following the completion of the Merger, each such director whose term expires during such period will be nominated for re-election (or another person selected by the applicable group of directors will be nominated for election) to our board of directors.

ITEM 1B.

Unresolved Staff Comments

None.

ITEM 2.

Properties

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

We maintain offices, land bases and other facilities worldwide, including our principal executive offices in Vernier, Switzerland, our corporate offices in Zug, Switzerland; Houston, Texas; Cayman Islands and Barbados and our regional operational offices in the U.S., France and Singapore. Our remaining offices and bases are located in various countries in North America, South America, the Caribbean, Europe, Africa, Russia, the Middle East, India, the Far East and Australia. We lease most of these facilities.

ITEM 3.

Legal Proceedings

In 2004, several of our subsidiaries were named, along with numerous unaffiliated defendants, in 21 complaints that were filed in the Circuit Courts of the State of Mississippi involving approximately 750 plaintiffs that alleged personal injury arising out of asbestos exposure in the course of their employment by some of these defendants between 1965 and 1986. The complaints also named as defendants certain subsidiaries of TODCO and certain subsidiaries of Sedco, Inc. to whom we may owe indemnity. Further, the

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complaints named other unaffiliated defendant companies, including companies that allegedly manufactured drilling related products containing asbestos. The complaints alleged that the defendants used asbestos-containing products in connection with drilling operations and included allegations of negligence, strict liability, and claims allowed under the Jones Act and general maritime law. The plaintiffs generally sought awards of unspecified compensatory and punitive damages. The Special Master who was appointed to oversee these cases required that each plaintiff file a separate amended complaint for each such individual plaintiff and then he dismissed the original 21 complaints. We believe that we may have a direct or indirect interest in 44 of the resulting complaints. We have not been provided with sufficient information in all claims to determine the period of the claimants' exposure to asbestos, their medical condition or, in some cases, the vessels potentially involved in the claims. We historically have maintained broad liability insurance, but we are not certain whether our insurance will cover all liabilities arising out of the 44 claims. We intend to defend these lawsuits vigorously, but there can be no assurance as to their ultimate outcome.

One of our subsidiaries is involved in an action with respect to a customs matter relating to the Sedco 710 semisubmersible drilling rig. Prior to our merger with Sedco Forex, this drilling rig, which was working for Petrobras in Brazil at the time, had been admitted into the country on a temporary basis under authority granted to a Schlumberger entity. Prior to the Sedco Forex merger, the drilling contract with Petrobras was transferred from the Schlumberger entity to an entity that would become one of our subsidiaries, but Schlumberger did not transfer the temporary import permit to any of our subsidiaries. In early 2000, the drilling contract was extended for another year. On January 10, 2000, the temporary import permit granted to the Schlumberger entity expired, and renewal filings were not made until later that January. In April 2000, the Brazilian customs authorities cancelled the temporary import permit. The Schlumberger entity filed an action in the Brazilian federal court of Campos for the purpose of extending the temporary admission. Other proceedings were also initiated in order to secure the transfer of the temporary admission to our subsidiary. Ultimately, the court permitted the transfer of the temporary admission from Schlumberger to our subsidiary but did not rule on whether the temporary admission could be extended without the payment of a financial penalty. During the first quarter of 2004, the Brazilian customs authorities issued an assessment totaling approximately $114 million against our subsidiary.

The first level Brazilian court ruled in April 2007 that the temporary admission granted to our subsidiary had expired which allowed the Brazilian customs authorities to execute on their assessment. Following this ruling, the Brazilian customs authorities issued a revised assessment against our subsidiary. As of December 31, 2008, the U.S. dollar equivalent of this assessment was approximately $184 million in aggregate. We are not certain as to the basis for the increase in the amount of the assessment, and in September 2007, we received a temporary ruling in our favor from a Brazilian federal court that the valuation method used by the Brazilian customs authorities was incorrect. This temporary ruling was confirmed in January 2008 by a local court, but it is still subject to review at the appellate levels in Brazil. We intend to continue to aggressively contest this matter. We have appealed the first level Brazilian court's ruling to a higher level court in Brazil where we have also filed for a renewed stay, which was initially denied, but later granted through a separate proceeding. The original ruling to deny the stay is being reviewed by the Superior Court of Justice and we expect that either the stay that was ultimately granted or any order from the Superior Court of Justice in our favor will prevent enforcement of the whole amount in dispute. A ruling from the Superior Court of Justice is not subject to further appeal. There may be further judicial or administrative proceedings that result from this matter. While the court has granted us the right to continue our appeal without the posting of a bond, it is possible that we may be required to post a bond for up to the full amount of the assessment in connection with these proceedings. We have also put Schlumberger on notice that we consider any assessment to be solely the responsibility of Schlumberger, not our subsidiary, and we initiated proceedings in the State of New York, which were subsequently transferred to the State of Texas, against Schlumberger seeking a declaratory judgment in this respect. Nevertheless, we expect that the Brazilian customs authorities will continue to seek to recover the assessment solely from our subsidiary, not Schlumberger. Schlumberger has denied any responsibility for this matter, but remains a party to the proceedings. We do not expect the liability, if any, resulting from this matter to have a material adverse effect on our consolidated statement of financial position, results of operations or cash flows.

In the third quarter of 2006, we received tax assessments of approximately $112 million from the state tax authorities of Rio de Janeiro in Brazil against one of our Brazilian subsidiaries for customs taxes on equipment imported into the state in connection with our operations. The assessments resulted from a preliminary finding by these authorities that our subsidiary's record keeping practices were deficient. We currently believe that the substantial majority of these assessments are without merit. We filed an initial response with the Rio de Janeiro tax authorities on September 9, 2006 refuting these additional tax assessments. In September 2007, we received confirmation from the state tax authorities that they believe the additional tax assessments are valid, and as a result, we filed an appeal on September 27, 2007 to the state Taxpayer's Council contesting these assessments. While we cannot predict or provide assurance as to the final outcome of these proceedings, we do not expect it to have a material adverse effect on our consolidated statement of financial position, results of operations or cash flows.

One of our subsidiaries is involved in lawsuits arising out of the subsidiary's involvement in the design, construction and refurbishment of major industrial complexes. The operating assets of the subsidiary were sold and its operations discontinued in 1989, and the subsidiary has no remaining assets other than the insurance policies involved in its litigation, fundings from settlements with the primary insurers and funds received from the cancellation of certain insurance policies. The subsidiary has been named as a defendant, along with numerous other companies, in lawsuits alleging personal injury as a result of exposure to asbestos. As of December 31, 2008, the subsidiary was a defendant in approximately 1,008 lawsuits. Some of these lawsuits include multiple plaintiffs and we estimate that there are approximately 2,973 plaintiffs in these lawsuits. For many of these lawsuits, we have not been provided with sufficient information from the plaintiffs to determine whether all or some of the plaintiffs have claims against the subsidiary, the basis of any such claims, or the nature of their alleged injuries. The first of the asbestos-related lawsuits was filed against this subsidiary in 1990. Through

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December 31, 2008, the amounts expended to resolve claims (including both attorneys' fees and expenses, and settlement costs) have not been material, and all deductibles with respect to the primary insurance have been satisfied. The subsidiary continues to be named as a defendant in additional lawsuits and we cannot predict the number of additional cases in which it may be named a defendant nor can we predict the potential costs to resolve such additional cases or to resolve the pending cases. However, the subsidiary has in excess of $1 billion in insurance limits. Although not all of the policies may be fully available due to the insolvency of certain insurers, we believe that the subsidiary will have sufficient insurance and funds from the settlements of litigation with insurance carriers available to respond to these claims. While we cannot predict or provide assurance as to the final outcome of these matters, we do not believe that the current value of the claims where we have been identified will have a material impact on our consolidated statement of financial position, results of operations or cash flows.

We are involved in various tax matters as described in "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Outlook–Tax Matters" and various regulatory matters as described in "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Outlook–Regulatory Matters." We are involved in lawsuits relating to damage claims arising out of hurricanes Katrina and Rita, all of which are insured and which are not material to us. We are also involved in a number of other lawsuits, including a dispute for municipal tax payments in Brazil and a dispute involving customs procedures in India, neither of which is material to us, and all of which have arisen in the ordinary course of our business. We do not expect the liability, if any, resulting from these other matters to have a material adverse effect on our consolidated statement of financial position, results of operations or cash flows. We cannot predict with certainty the outcome or effect of any of the litigation matters specifically described above or of any such other pending or threatened litigation. There can be no assurance that our beliefs or expectations as to the outcome or effect of any lawsuit or other litigation matter will prove correct and the eventual outcome of these matters could materially differ from management's current estimates.

Environmental Matters

We have certain potential liabilities under the Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA") and similar state acts regulating cleanup of various hazardous waste disposal sites, including those described below. CERCLA is intended to expedite the remediation of hazardous substances without regard to fault. Potentially responsible parties ("PRPs") for each site include present and former owners and operators of, transporters to and generators of the substances at the site. Liability is strict and can be joint and several.

We have been named as a PRP in connection with a site located in Santa Fe Springs, California, known as the Waste Disposal, Inc. site. We and other PRPs have agreed with the U.S. Environmental Protection Agency ("EPA") and the DOJ to settle our potential liabilities for this site by agreeing to perform the remaining remediation required by the EPA. The form of the agreement is a consent decree, which has been entered by the court. The parties to the settlement have entered into a participation agreement, which makes us liable for approximately eight percent of the remediation and related costs. The remediation is complete, and we believe our share of the future operation and maintenance costs of the site is not material. There are additional potential liabilities related to the site, but these cannot be quantified, and we have no reason at this time to believe that they will be material.

We have also been named as a PRP in connection with a site in California known as the Casmalia Resources Site. We and other PRPs have entered into an agreement with the EPA and the DOJ to resolve potential liabilities. Under the settlement, we are not likely to owe any substantial additional amounts for this site beyond what we have already paid. There are additional potential liabilities related to this site, but these cannot be quantified at this time, and we have no reason at this time to believe that they will be material.

We have been named as one of many PRPs in connection with a site located in Carson, California, formerly maintained by Cal Compact Landfill. On February 15, 2002, we were served with a required 90-day notification that eight California cities, on behalf of themselves and other PRPs, intend to commence an action against us under the Resource Conservation and Recovery Act ("RCRA"). On April 1, 2002, a complaint was filed by the cities against us and others alleging that we have liabilities in connection with the site. However, the complaint has not been served. The site was closed in or around 1965, and we do not have sufficient information to enable us to assess our potential liability, if any, for this site.

One of our subsidiaries has recently been ordered by the California Regional Water Quality Control Board to develop a testing plan for a site known as Campus 1000 Fremont in Alhambra, California. This site was formerly owned and operated by certain of our subsidiaries. It is presently owned by an unrelated party, which has received an order to test the property, the cost of which is expected to be in the range of $200,000. We have also been advised that one or more of our subsidiaries is likely to be named by the EPA as a PRP for the San Gabriel Valley, Area 3, Superfund site, which includes this property. We have no knowledge at this time of the potential cost of any remediation, who else will be named as PRPs and whether in fact any of our subsidiaries is a responsible party. The subsidiaries in question do not own any operating assets and have limited ability to respond to any liabilities.

Resolutions of other claims by the EPA, the involved state agency or PRPs are at various stages of investigation. These investigations involve determinations of:

• the actual responsibility attributed to us and the other PRPs at the site;

• appropriate investigatory and/or remedial actions; and

• allocation of the costs of such activities among the PRPs and other site users.

Our ultimate financial responsibility in connection with those sites may depend on many factors, including:

• the volume and nature of material, if any, contributed to the site for which we are responsible;

• the numbers of other PRPs and their financial viability; and

• the remediation methods and technology to be used.

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It is difficult to quantify with certainty the potential cost of these environmental matters, particularly in respect of remediation obligations. Nevertheless, based upon the information currently available, we believe that our ultimate liability arising from all environmental matters, including the liability for all other related pending legal proceedings, asserted legal claims and known potential legal claims which are likely to be asserted, is adequately accrued and should not have a material effect on our financial position or ongoing results of operations. Estimated costs of future expenditures for environmental remediation obligations are not discounted to their present value.

Contamination litigation—On July 11, 2005, one of our subsidiaries was served with a lawsuit filed on behalf of three landowners in Louisiana in the 12th Judicial District Court for the Parish of Avoyelles, State of Louisiana. The lawsuit named 19 other defendants, all of which were alleged to have contaminated the plaintiffs' property with naturally occurring radioactive material, produced water, drilling fluids, chlorides, hydrocarbons, heavy metals and other contaminants as a result of oil and gas exploration activities. Experts retained by the plaintiffs issued a report suggesting significant contamination in the area operated by the subsidiary and another codefendant, and claimed that over $300 million would be required to properly remediate the contamination. The experts retained by the defendants conducted their own investigation and concluded that the remediation costs would amount to no more than $2.5 million.

The plaintiffs and the codefendant threatened to add GlobalSantaFe as a defendant in the lawsuit under the "single business enterprise" doctrine contained in Louisiana law. The single business enterprise doctrine is similar to corporate veil piercing doctrines. On August 16, 2006, our subsidiary and its immediate parent company, each of which is an entity that no longer conducts operations or holds assets, filed voluntary petitions for relief under Chapter 11 of the U.S. Bankruptcy Code in the U.S. Bankruptcy Court for the District of Delaware. Later that day, the plaintiffs dismissed our subsidiary from the lawsuit. Subsequently, the codefendant filed various motions in the lawsuit and in the Delaware bankruptcies attempting to assert alter ego and single business enterprise claims against GlobalSantaFe and two other subsidiaries in the lawsuit. The efforts to assert alter ego and single business enterprise theory claims against GlobalSantaFe were rejected by the Court in Avoyelles Parish and the lawsuit against the other defendant went to trial on February 19, 2007. This lawsuit was resolved at trial with a settlement by the codefendant that included a $20 million payment and certain cleanup activities to be conducted by the codefendant.

The codefendant sought to dismiss the bankruptcies. In addition, the codefendant filed proofs of claim against both our subsidiary and its parent with regard to its claims arising out of the settlement of the lawsuit. On February 15, 2008, the Bankruptcy Court denied the codefendant's request to dismiss the bankruptcy case but modified the automatic stay to allow the codefendant to proceed on its claims against the debtors, our subsidiary and its parent, and their insurance companies. The codefendant subsequently filed suit against the debtors and certain of its insurers in the Court of Avoyelles Parish to determine their liability for the settlement.

The codefendant filed a Notice of Appeal of the rulings of the Bankruptcy Court. GlobalSantaFe and its two subsidiaries also filed Notices of Appeal to the U. S. District Court for the District of Delaware. On January 27, 2009, the codefendant's appeal was granted by the District Court and the bankruptcy case was remanded to the Bankruptcy Court with instructions to have the case dismissed. On February 10, 2009, the Bankruptcy Court entered an order dismissing the bankruptcy case. The debtors, GlobalSantaFe and the two subsidiaries have filed Notices of Appeal of the District Court's ruling with the U. S. Court of Appeals for the Third Circuit. On February 18, 2009, the District Court stayed its ruling which instructed the Bankruptcy Court to dismiss the case.

We believe that these legal theories should not be applied against GlobalSantaFe or these other two subsidiaries, and that in any event the manner in which the parent and its subsidiaries conducted their businesses does not meet the requirements of these theories for imposition of liability. Our subsidiary, its parent and GlobalSantaFe intend to continue to vigorously defend against any action taken in an attempt to impose liability against them under the theories discussed above or otherwise and believe they have good and valid defenses thereto. We are unable to determine the value of these claims as of the date of the Merger. We do not believe that these claims will have a material impact on our consolidated statement of financial position, results of operations or cash flows.

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ITEM 4.

Submission of Matters to a Vote of Security Holders

At a meeting of shareholders of Transocean Inc. held on December 8, 2008, 227,574,603 shares were present in person or by proxy out of 319,188,240 shares outstanding and entitled to vote as of the record date. With respect to the proposal to approve the schemes of arrangement to effect the Redomestication Transaction, submitted to a vote of shareholders, as set forth in our proxy statement relating to the meeting, the following number of votes were cast:

For		Against		Abstain
219,697,933		6,316,671		1,559,999

Of the 2,437 holders of Transocean-Cayman ordinary shares present in person or by proxy at the meeting, 2,098 cast votes for the proposal.

Executive Officers of the Registrant

		Age as of
Officer	Office	February 27, 2009
Robert L. Long	Chief Executive Officer	63
Steven L. Newman	President and Chief Operating Officer	44
Arnaud A.Y. Bobillier	Executive Vice President, Assets	53
Robert J. Saltiel	Executive Vice President, Performance	46
Eric B. Brown	Senior Vice President, General Counsel and Assistant Corporate Secretary	57
Gregory L. Cauthen	Senior Vice President and Chief Financial Officer	51
Cheryl D. Richard	Senior Vice President, Human Resources and I.T.	52
John H. Briscoe	Vice President and Controller	51

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

Robert L. Long is Chief Executive Officer and a member of the board of directors of the Company. Mr. Long has served as Chief Executive Officer of the Company and a member of the board of directors since October 2002. Mr. Long served as President of the Company from December 2001 to October 2006. Mr. Long served as Chief Financial Officer of the Company from August 1996 until December 2001. Mr. Long served as Senior Vice President of the Company from May 1990 until the time of the Sedco Forex merger, at which time he assumed the position of Executive Vice President. Mr. Long also served as Treasurer of the Company from September 1997 until March 2001. Mr. Long has been employed by the Company since 1976 and was elected Vice President in 1987.

Steven L. Newman is President and Chief Operating Officer of the Company. Before being named to his current position in May 2008, Mr. Newman served since November 2007 as Executive Vice President, Performance, leading the Company's three business units and focusing on client service delivery and performance improvement across the company's worldwide fleet. He previously served in senior management roles, including Executive Vice President and Chief Operating Officer (from October 2006 to November 2007), Senior Vice President of Human Resources and Information Process Solutions (from May 2006 to October 2006), Senior Vice President of Human Resources, Information Process Solutions and Treasury (from March 2005 until May 2006), and Vice President of Performance and Technology (from August 2003 until March 2005). He also has served as Regional Manager for the Asia and Australia Region and in international field and operations management positions, including Project Engineer, Rig Manager, Division Manager, Region Marketing Manager and Region Operations Manager. Mr. Newman joined the Company in 1994 in the Corporate Planning Department.

Arnaud A.Y. Bobillier is Executive Vice President, Assets of the Company. Before being named to his current position in March 2008, Mr. Bobillier served as Senior Vice President of the Company's Europe and Africa Unit, which covers offshore drilling operations in 15 countries, from January 2008 to March 2008. Previously, Mr. Bobillier served as Vice President of the Company's Europe and Africa unit from May 2005 to January 2008. He also served as Regional Manager for the Europe and Africa Region from January 2004 to May 2005. From September 2001 to January 2004, Mr. Bobillier served as Regional Manager for the Company's West Africa Region. He began his career with a predecessor company in 1980 and has served in various management positions in several countries, including the U.S., France, Saudi Arabia, Indonesia, Congo, Brazil, South Africa and China.

Robert J. Saltiel is Executive Vice President, Performance of the Company. Prior to being named to his current position in May 2008, Mr. Saltiel served as Senior Vice President of the Company's North and South America Unit, which covers the U.S. Gulf of Mexico, Canada, Trinidad and Brazil, from October 2006 to May 2008. Previously, Mr. Saltiel served as the Company's Senior Vice President of Marketing and Planning from February 2006 to October 2006 and Vice President of Marketing and Corporate Planning from December 2004 to February 2006. Mr. Saltiel joined Transocean in 2003 and served as Vice President of Marketing from July 2003 to December 2004.

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Eric B. Brown is Senior Vice President, General Counsel and Assistant Corporate Secretary of the Company. Mr. Brown has served as General Counsel of the Company since February 1995 and served as Corporate Secretary of the Company from September 1995 until October 2007. He held the position of Vice President from February 1995 to February 2001, when he assumed the position of Senior Vice President. Prior to assuming his duties with the Company, Mr. Brown served as General Counsel of Coastal Gas Marketing Company.

Gregory L. Cauthen is Senior Vice President and Chief Financial Officer of the Company. Mr. Cauthen has served as Chief Financial Officer since December 2001. He held the position of Vice President from March 2001 to July 2002, when he assumed the position of Senior Vice President. He was also Treasurer of the Company from March 2001 until July 2003. Mr. Cauthen served as Vice President, Finance from March 2001 to December 2001. Prior to joining the Company in March 2001, he served as President and Chief Executive Officer of WebCaskets.com, Inc., a provider of death care services, from June 2000 until February 2001. Prior to June 2000, he was employed at Service Corporation International, a provider of death care services, where he served as Senior Vice President, Financial Services from July 1998 to August 1999, Vice President, Treasurer from July 1995 to July 1998, was assigned to various special projects from August 1999 to May 2000 and had been employed in various other positions since February 1991.

Cheryl D. Richard is Senior Vice President, Human Resources and I.T. of the Company. Ms. Richard served as Senior Vice President, Human Resources of GlobalSantaFe from June 2003 until the Merger in November 2007, when she assumed her current position. Ms. Richard was Vice President, Human Resources, with Chevron Phillips Chemical Company from 2000 to June 2003, prior to which she served in a variety of positions with Phillips Petroleum Company (now ConocoPhillips), including operational, commercial and international positions.

John H. Briscoe is Vice President and Controller of the Company. Before being named to his current position in October 2007, Mr. Briscoe served as Vice President, Audit and Advisory Services from June 2007 to October 2007 and Director of Investor Relations and Communications from January 2007 to June 2007. From June 2005 to January 2007, Mr. Briscoe served as Finance Director for the Company's North and South America Unit. Prior to joining the Company in June 2005, Mr. Briscoe served as Vice President of Accounting for Ferrellgas Inc. from July 2003 to June 2005, Vice President of Administration from June 2002 to July 2003 and Division Controller from June 1997 to June 2002. Prior to working for Ferrellgas, Mr. Briscoe served as Controller for Latin America for Dresser Industries Inc., which has subsequently been acquired by Halliburton, Inc. Mr. Briscoe started his career with seven years in public accounting beginning with the firm of KPMG and ending with Ernst & Young as an Audit Manager.

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PART II

ITEM 5.

Market for Registrant's Common Equity, Related Shareholder Matters and Issuer Purchases of Equity Securities

Our shares are listed on the NYSE under the symbol "RIG." The following table sets forth the high and low sales prices of our shares for the periods indicated as reported on the NYSE Composite Tape, including trading of the shares of Transocean-Cayman through December 18, 2008 and trading of the shares of Transocean Ltd. after such date.

	Price
	High		Low
2007
First quarter (a)	$	83.20	$	72.47
Second quarter (a)		109.20		80.50
Third quarter (a)		120.88		92.61
Fourth quarter		149.62		107.37

2008
First quarter	$	147.25	$	111.34
Second quarter		163.00		132.46
Third quarter		154.50		105.16
Fourth quarter		109.16		41.95

________________________________

(a)	The stock prices presented reflect the historical market prices and have not been restated to reflect the effects of the GSF Transactions.

On February 20, 2009, the last reported sales price of our shares on the NYSE Composite Tape was $59.52 per share. On such date, there were 6,398 holders of record of our shares and 319,660,304 shares outstanding.

On November 27, 2007, each of Transocean-Cayman's ordinary shares outstanding at the time of the Reclassification was reclassified by way of a scheme of arrangement under Cayman Islands law into 0.6996 Transocean-Cayman ordinary shares and $33.03 in cash. The closing price of Transocean-Cayman's ordinary shares on November 26, 2007, the last trading day before the completion of the GSF Transactions, was $129.39. The opening price of Transocean-Cayman's ordinary shares on November 27, 2007, after the completion of the GSF Transactions, was $133.38.

Although our shareholders received cash in the Reclassification, we did not declare or pay a cash dividend in either of the two most recent fiscal years. Any future declaration and payment of any cash dividends will (1) depend on our results of operations, financial condition, cash requirements and other relevant factors, (2) be subject to shareholder approval, (3) be subject to restrictions contained in our credit facilities and other debt covenants and (4) be subject to restrictions imposed by Swiss law, including the requirement that sufficient distributable profits from the previous year or freely distributable reserves must exist.

In December 2008, Transocean Ltd. completed the Redomestication Transaction. In the Redomestication Transaction, Transocean Ltd. issued one of its shares in exchange for each ordinary share of Transocean Inc. In addition, Transocean Ltd. issued 16 million of its shares to Transocean Inc. for future use to satisfy Transocean Ltd.'s obligations to deliver shares in connection with awards granted under our incentive plans, warrants or other rights to acquire shares of Transocean Ltd. The Redomestication Transaction effectively changed the place of incorporation of our parent holding company from the Cayman Islands to Switzerland. As a result of the Redomestication Transaction, Transocean Inc. became a direct, wholly-owned subsidiary of Transocean Ltd. In connection with the Redomestication Transaction, we relocated our principal executive offices to Vernier, Switzerland.

Swiss Tax Consequences to Shareholders of Transocean

The tax consequences discussed below are not a complete analysis or listing of all the possible tax consequences that may be relevant to shareholders of Transocean. Shareholders should consult their own tax advisors in respect of the tax consequences related to receipt, ownership, purchase or sale or other disposition of our shares and the procedures for claiming a refund of withholding tax.

Swiss Income Tax on Dividends and Similar Distributions

A non-Swiss holder will not be subject to Swiss income taxes on dividend income and similar distributions in respect of our shares, unless the shares are attributable to a permanent establishment or a fixed place of business maintained in Switzerland by such non-Swiss holder. However, dividends and similar distributions are subject to Swiss withholding tax. See "—Swiss Withholding Tax–Distributions to Shareholders."

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Swiss Wealth Tax

A non-Swiss holder will not be subject to Swiss wealth taxes unless the holder's shares are attributable to a permanent establishment or a fixed place of business maintained in Switzerland by such non-Swiss holder.

Swiss Capital Gains Tax upon Disposal of Shares

A non-Swiss holder will not be subject to Swiss income taxes for capital gains unless the holder's shares are attributable to a permanent establishment or a fixed place of business maintained in Switzerland by such non-Swiss holder. In such case, the non-Swiss holder is required to recognize capital gains or losses on the sale of such shares, which will be subject to cantonal, communal and federal income tax.

Swiss Withholding Tax—Distributions to Shareholders

A Swiss withholding tax of 35 percent is due on dividends and similar distributions to our shareholders from us, regardless of the place of residency of the shareholder (subject to the exceptions discussed under "—Exemption from Swiss Withholding Tax–Distributions to Shareholders" below). We will be required to withhold at such rate and remit on a net basis any payments made to a holder of our shares and pay such withheld amounts to the Swiss federal tax authorities. Please see "—Refund of Swiss Withholding Tax on Dividends and Other Distributions."

Exemption from Swiss Withholding Tax—Distributions to Shareholders

Under present Swiss tax law, distributions to shareholders in relation to a reduction of par value are exempt from Swiss withholding tax. Beginning on January 1, 2011, distributions to shareholders out of qualifying additional paid-in capital for Swiss statutory purposes are as a matter of principle exempt from the Swiss withholding tax. The particulars of this general principle are, however, subject to regulations still to be promulgated by the competent Swiss authorities; it will further require that the current draft corporate law bill, which proposes an overhaul of certain aspects of Swiss corporate law, be modified in the upcoming legislative process to reflect the recent change in the tax law. On December 18, 2008, the aggregate amount of par value and qualifying additional paid-in capital of our outstanding shares was $4.7 billion and $10.6 billion, respectively. Consequently, we expect that a substantial amount of any potential future distributions may be exempt from Swiss withholding tax.

Repurchases of Shares

Under present Swiss tax law, repurchases of shares for the purposes of capital reduction are treated as a partial liquidation subject to the 35 percent Swiss withholding tax. However, for shares repurchased for capital reduction, the portion of the repurchase price attributable to the par value of the shares repurchased will not be subject to the Swiss withholding tax. Beginning on January 1, 2011, subject to the adoption of implementing regulations and amendments to Swiss corporate law, the portion of the repurchase price attributable to the qualifying additional paid-in capital for Swiss statutory reporting purposes of the shares repurchased will also not be subject to the Swiss withholding tax. We would be required to withhold at such rate the tax from the difference between the repurchase price and the related amount of par value and, beginning on January 1, 2011, subject to the adoption of implementing regulations and amendments to Swiss corporate law, the related amount of qualifying additional paid-in capital. We would be required to remit on a net basis the purchase price with the Swiss withholding tax deducted to a holder of our shares and pay the withholding tax to the Swiss federal tax authorities.

With respect to the refund of Swiss withholding tax from the repurchase of shares, see "—Refund of Swiss Withholding Tax on Dividends and Other Distributions" below.

In most instances, Swiss companies listed on the SIX Swiss Exchange, or SIX, carry out share repurchase programs through a "second trading line" on the SIX. Swiss institutional investors typically purchase shares from shareholders on the open market and then sell the shares on the second trading line back to the company. The Swiss institutional investors are generally able to receive a full refund of the withholding tax. Due to, among other things, the time delay between the sale to the company and the institutional investors' receipt of the refund, the price companies pay to repurchase their shares has historically been slightly higher (but less than one percent) than the price of such companies' shares in ordinary trading on the SIX first trading line.

We do not expect to be able to use the SIX second trading line process to repurchase our shares because we do not intend to list our shares on the SIX. We do, however, intend to follow an alternative process whereby we expect to be able to repurchase our shares in a manner that should allow Swiss institutional market participants selling the shares to us to receive a refund of the Swiss withholding tax and, therefore, accomplish the same purpose as share repurchases on the second trading line at substantially the same cost to us and such market participants as share repurchases on a second trading line.

The repurchase of shares for purposes other than capital reduction, such as to retain as treasury shares for use in connection with stock incentive plans, convertible debt or other instruments within certain periods, will generally not be subject to Swiss withholding tax.

Our board of directors has recommended to shareholders for approval at the 2009 annual meeting a release of qualifying additional paid-in-capital (for Swiss statutory purposes) to other reserves (for Swiss statutory purposes) that is necessary for the possible repurchase of shares for cancellation.

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Refund of Swiss Withholding Tax on Dividends and Other Distributions

Swiss holders–A Swiss tax resident, corporate or individual, can recover the withholding tax in full if such resident is the beneficial owner of our shares at the time the dividend or other distribution becomes due and provided that such resident reports the gross distribution received on such resident's income tax return, or in the case of an entity, includes the taxable income in such resident's income statement.

Non-Swiss holders–If the shareholder that receives a distribution from us is not a Swiss tax resident, does not hold our shares in connection with a permanent establishment or a fixed place of business maintained in Switzerland, and resides in a country that has concluded a treaty for the avoidance of double taxation with Switzerland for which the conditions for the application and protection of and by the treaty are met, then the shareholder may be entitled to a full or partial refund of the withholding tax described above. The procedures for claiming treaty refunds (and the time frame required for obtaining a refund) may differ from country to country.

Switzerland has entered into bilateral treaties for the avoidance of double taxation with respect to income taxes with numerous countries, including the U.S., whereby under certain circumstances all or part of the withholding tax may be refunded.

U.S. residents–The Swiss-U.S. tax treaty provides that U.S. residents eligible for benefits under the treaty can seek a refund of the Swiss withholding tax on dividends for the portion exceeding 15 percent (leading to a refund of 20 percent) or a 100 percent refund in the case of qualified pension funds.

As a general rule, the refund will be granted under the treaty if the U.S. resident can show evidence of:

•

beneficial ownership,

•

U.S. residency, and

•

meeting the U.S.-Swiss tax treaty's limitation on benefits requirements.

The claim for refund must be filed with the Swiss federal tax authorities (Eigerstrasse 65, 3003 Berne, Switzerland), not later than December 31 of the third year following the year in which the dividend payments became due. The relevant Swiss tax form is Form 82C for companies, 82E for other entities and 82I for individuals. These forms can be obtained from any Swiss Consulate General in the U.S. or from the Swiss federal tax authorities at the address mentioned above. Each form needs to be filled out in triplicate, with each copy duly completed and signed before a notary public in the U.S. Evidence that the withholding tax was withheld at the source must also be included.

Stamp duties in relation to the transfer of shares–The purchase or sale of our shares may be subject to Swiss federal stamp taxes on the transfer of securities irrespective of the place of residency of the purchaser or seller if the transaction takes place through or with a Swiss bank or other Swiss securities dealer, as those terms are defined in the Swiss Federal Stamp Tax Act and no exemption applies in the specific case. If a purchase or sale is not entered into through or with a Swiss bank or other Swiss securities dealer, then no stamp tax will be due. The applicable stamp tax rate is 0.075 percent for each of the two parties to a transaction and is calculated based on the purchase price or sale proceeds. If the transaction does not involve cash consideration, the transfer stamp duty is computed on the basis of the market value of the consideration.

Issuer Purchases of Equity Securities

Period	Total Number of Shares Purchased (1)		Average Price Paid Per Share	Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs (2)		Maximum Number (or Approximate Dollar Value) of Shares that May Yet Be Purchased Under the Plans or Programs (2) (in millions)
October 2008	596	$	96.69	—	$	600
November 2008	700		76.67	—		600
December 2008	404		57.61	—		600
Total	1,700	$	79.16	—	$	600

________________________________

(1)	Total number of shares purchased in the fourth quarter of 2008 consists of shares withheld by us in satisfaction of withholding taxes due upon the vesting of restricted shares granted to our employees under our Long-Term Incentive Plan.

(2)

In May 2006, Transocean-Cayman's board of directors authorized an increase in the amount of ordinary shares which could be repurchased pursuant to our share repurchase program to $4.0 billion from $2.0 billion, which was previously authorized and announced in October 2005. The shares could be repurchased from time to time in open market or private transactions. The repurchase program did not have an established expiration date and could be suspended or discontinued at any time. Under the program, repurchased shares were retired and returned to unissued status. From the inception of this program through December 18, 2008, Transocean-Cayman repurchased a total of 46.9 million of its shares at a total cost of $3.4 billion. As a result of the Redomestication Transaction, the Transocean-Cayman share repurchase program has been terminated. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources–Sources and Uses of Liquidity–Share Repurchase Program Recommendation" for a discussion of the share repurchase program that our board of directors recommends shareholders approve.

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ITEM 6.

Selected Financial Data

The selected financial data as of December 31, 2008 and 2007 and for each of the three years in the period ended December 31, 2008 has been derived from the audited consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data." The selected financial data as of December 31, 2006, 2005 and 2004, and for the years ended December 31, 2005 and 2004 has been derived from audited consolidated financial statements not included herein. The following data should be read in conjunction with "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" and the audited consolidated financial statements and the notes thereto included under "Item 8. Financial Statements and Supplementary Data."

In January 2001, we completed our merger transaction with R&B Falcon Corporation ("R&B Falcon"). At the time of the R&B Falcon merger, R&B Falcon operated a diverse global drilling rig fleet, consisting of drillships, semisubmersibles, jackups and other units in addition to the Gulf of Mexico Shallow and Inland Water segment fleet. R&B Falcon and the Gulf of Mexico Shallow and Inland Water segment later became known as TODCO (together with its subsidiaries and predecessors, unless the context requires otherwise, "TODCO"). In preparation for the initial public offering of TODCO, we transferred all assets and subsidiaries out of TODCO that were unrelated to the Gulf of Mexico Shallow and Inland Water business.

In February 2004, we completed an initial public offering (the "TODCO IPO") of approximately 23 percent of the outstanding shares of TODCO's common stock. In September 2004, December 2004 and May 2005, respectively, we completed additional public offerings of TODCO common stock. In June 2005, we completed the sale of our remaining TODCO common stock pursuant to Rule 144 under the Securities Act of 1933, as amended.

We consolidated TODCO in our financial statements as a business segment through December 16, 2004 and that portion of TODCO that we did not own was reported as minority interest in our consolidated statements of operations and balance sheet. Our ownership and voting interest in TODCO declined to approximately 22 percent on that date, and we no longer consolidated TODCO in our financial statements but accounted for our remaining investment using the equity method of accounting.

In May 2005 and June 2005, respectively, we completed a public offering and a sale of TODCO common stock pursuant to Rule 144 under the Securities Act of 1933, as amended (respectively referred to as the "May Offering" and the "June Sale"). After the May Offering, we accounted for our remaining investment using the cost method of accounting. As a result of the June Sale, we no longer own any shares of TODCO's common stock.

In November 2007, Transocean-Cayman reclassified each of its outstanding ordinary shares by way of a scheme of arrangement under Cayman Islands law immediately followed by its merger with GlobalSantaFe. We accounted for the reclassification as a reverse stock split and a dividend, which requires restatement of historical weighted-average shares outstanding and historical earnings per share for prior periods. Per share amounts for all periods have been adjusted for the reclassification. We applied the purchase accounting method for the GlobalSantaFe merger and identified Transocean-Cayman as the acquirer in the business combination. The balance sheet data as of December 31, 2007 represents the consolidated statement of financial position of the combined company. The statement of operations and other financial data for the year ended December 31, 2007 include approximately one month of operating results and cash flows for the combined company. Transocean-Cayman financed payments made in connection with the reclassification and merger with borrowings under a $15 billion bridge loan facility.

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	Years ended December 31,
	2008			2007			2006			2005			2004

	(In millions, except per share data)
Statement of operations data
Operating revenues	$	12,674		$	6,377		$	3,882		$	2,892		$	2,614
Operating income		5,357			3,239			1,641			720			328
Net income		4,202			3,131			1,385			716			152

Earnings per share
Basic	$	13.20		$	14.65		$	6.32		$	3.13		$	0.68
Diluted	$	13.09		$	14.14		$	6.10		$	3.03		$	0.67

Balance sheet data (at end of period)
Total assets	$	35,171		$	34,364		$	11,476		$	10,457		$	10,758
Debt due within one year		664			6,172			95			400			19
Long-term debt		13,522			11,085			3,203			1,197			2,462
Total shareholders' equity		16,524			12,566			6,836			7,982			7,393

Other financial data
Cash provided by operating activities	$	4,959		$	3,073		$	1,237		$	864		$	600
Cash provided by (used in) investing activities		(2,196	)		(5,677	)		(415	)		169			551
Cash provided by (used in) financing activities		(3,041	)		3,378			(800	)		(1,039	)		(1,174	)
Capital expenditures		2,208			1,380			876			182			127
Operating margin		42	%		51	%		42	%		25	%		13	%

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ITEM 7.

Management's Discussion and Analysis of Financial Condition and Results of Operations

The following information should be read in conjunction with the information contained in "Item 1. Business," "Item 1A. Risk Factors" and the audited consolidated financial statements and the notes thereto included under "Item 8. Financial Statements and Supplementary Data" elsewhere in this annual report.

Overview

We believe our mobile offshore drilling fleet is one of the most modern and versatile fleets in the world. Our primary business is to contract these drilling rigs, related equipment and work crews primarily on a dayrate basis to drill oil and gas wells. We specialize in technically demanding segments of the offshore drilling business with a particular focus on deepwater and harsh environment drilling services. We also provide oil and gas drilling management services on either a dayrate basis or a completed-project, fixed-price (or "turnkey") basis, as well as drilling engineering and drilling project management services, and we participate in oil and gas exploration and production activities.

In November 2007, we completed our merger transaction (the "Merger") with GlobalSantaFe Corporation ("GlobalSantaFe"). The Merger was accounted for as a purchase, with the Company as the acquirer for accounting purposes. At the time of the Merger, GlobalSantaFe owned, had partial ownership interests in, operated, had under construction or contracted for construction, 61 mobile offshore drilling units and other units utilized in the support of offshore drilling activities. The balance sheet data as of December 31, 2007 represents the consolidated statement of financial position of the combined company. The statement of operations and other financial data for the year ended December 31, 2007 include approximately one month of operating results and cash flows for the combined company.

In December 2008, Transocean Ltd. completed a transaction pursuant to an Agreement and Plan of Merger among Transocean Ltd., Transocean Inc., which was our former parent holding company, and Transocean Cayman Ltd., a company organized under the laws of the Cayman Islands that was a wholly-owned subsidiary of Transocean Ltd., pursuant to which Transocean Inc. merged by way of schemes of arrangement under Cayman Islands law with Transocean Cayman Ltd., with Transocean Inc. as the surviving company (the "Redomestication Transaction"). In the Redomestication Transaction, Transocean Ltd. issued one of its shares in exchange for each ordinary share of Transocean Inc. In addition, Transocean Ltd. issued 16 million of its shares to Transocean Inc. for future use to satisfy Transocean Ltd.'s obligations to deliver shares in connection with awards granted under our incentive plans, warrants or other rights to acquire shares of Transocean Ltd. The Redomestication Transaction effectively changed the place of incorporation of our parent holding company from the Cayman Islands to Switzerland. As a result of the Redomestication Transaction, Transocean Inc. became a direct, wholly-owned subsidiary of Transocean Ltd. In connection with the Redomestication Transaction, we relocated our principal executive offices to Vernier, Switzerland. We refer to the Redomestication Transaction and the relocation of our principal executive offices together as the "Redomestication."

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

	Years ended December 31,
	2008			2007			Change
	(In millions, except average daily revenue and percentages)
Average daily revenue (a)(b)	$	240,300		$	211,900		$	28,400
Utilization (b)(c)		90	%		90	%		n/a
Statement of operations data
Operating revenues	$	12,674		$	6,377		$	6,297
Operating and maintenance expenses		5,355			2,781			2,574
Operating income		5,357			3,239			2,118
Net income		4,202			3,131			1,071
Balance sheet data (at end of period)
Cash and cash equivalents		963			1,241			(278	)
Total assets		35,171			34,364			807
Total debt		14,186			17,257			(3,071	)

________________________________

"n/a" means not applicable.

(a)	Average daily revenue is defined as contract drilling revenue earned per revenue earning day. A revenue earning day is defined as a day for which a rig earns dayrate after commencement of operations.

(b)	Excludes a drillship engaged in scientific geological coring activities, the Joides Resolution, that is owned by a joint venture in which we have a 50 percent interest and is accounted for under the equity method of accounting.

(c)	Utilization is the total actual number of revenue earning days as a percentage of the total number of calendar days in the period.

We are currently experiencing high utilization and historically high dayrates across our fleet. Customers continue to express interest in multi-year contracts for our high-specification units. Recently, we have experienced weakness in our Midwater Floater fleet and in our Jackup fleet, as near-term customer demand has declined. We currently have two Midwater Floaters, including one that is held for sale, and four Jackups that are idle, and we expect to idle more rigs as they come off contracts. We expect the decline in commodity prices and the downturn in the global economy to continue to have a negative effect on dayrates and the level of contract activity in these markets, and that effect could be substantial. See "Item 1A. Risk Factors" for a discussion of some of the risks associated with a continued decline in commodity prices and an extended worldwide economic downturn.

Over the last few years, a shortage of qualified personnel in our industry drove up compensation costs and suppliers increased prices as their backlogs grow. We expect increasing unemployment, a stronger U.S. dollar and a continued decline in commodity prices to slow the rate of escalation in these costs or cause these costs to decrease over time.

Our revenues for the year ended December 31, 2008 increased from the prior year period primarily as a result of the addition of GlobalSantaFe's operations for a full year and higher dayrates. Our operating and maintenance expenses for the year increased primarily as a result of higher labor and rig maintenance costs in connection with such increased activity as well as inflationary cost increases and the addition of GlobalSantaFe's operations (see "—Outlook"). Total debt decreased as a result of repayments of borrowings under the Bridge Loan Facility during 2008. See "—Liquidity and Capital Resources–Sources and Uses of Liquidity."

We have established two reportable segments: (1) contract drilling services and (2) other operations. The contract drilling segment consists of floaters, jackups and other rigs used in support of offshore drilling activities and offshore support services on a worldwide basis. Our fleet operates in a single, global market for the provision of contract drilling services. The location of our rigs and the allocation of resources to build or upgrade rigs are determined by the activities and needs of our customers. The other operations segment includes drilling management services and oil and gas properties. We provide drilling management services through Applied Drilling Technology Inc., our wholly owned subsidiary, and through ADT International, a division of one of our U.K. subsidiaries (together, "ADTI"). Drilling management services are provided primarily on a turnkey basis at a fixed bid amount. Oil and gas properties consist of exploration, development and production activities carried out through our oil and gas subsidiaries, Challenger Minerals Inc. and Challenger Minerals (North Sea) Limited (together, "CMI").

Significant Events

Redomestication—In December 2008, we completed the Redomestication Transaction. See "—Overview."

In December 2008, in connection with the Redomestication Transaction, we assumed Transocean-Cayman's obligations under the warrants that were previously exercisable for ordinary shares of Transocean-Cayman.

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Also in December 2008, we guaranteed the obligations of Transocean-Cayman under the indenture relating to Transocean-Cayman's 1.625% Series A Convertible Senior Notes due 2037, 1.50% Series B Convertible Senior Notes due 2037 and 1.50% Series C Convertible Senior Notes due 2037 (together, the "Convertible Senior Notes") and 5.25% Senior Notes due 2013, 6.00% Senior Notes due 2018 and 6.80% Senior Notes due 2038. In addition, we assumed the obligation to deliver our shares, if any, upon conversion of the Convertible Senior Notes, in lieu of Transocean-Cayman ordinary shares. We also guaranteed the obligations of Transocean-Cayman under the indenture relating to Transocean-Cayman's 6.625% Notes due 2011, 5% Notes due 2013, 7.375% Senior Notes due 2018, 8% Debentures due 2027, 7.45% Notes due 2027, 7% Senior Notes due 2028 and 7.5% Notes due 2031.

Furthermore, in December 2008, we guaranteed the payment of the principal and the accrued and unpaid interest on commercial paper notes issued or to be issued under Transocean-Cayman's commercial paper program.

Impairment loss—During the year ended December 31, 2008, we recorded impairment losses of $320 million, of which $223 million was related to the goodwill and other intangible assets associated with our drilling management services reporting unit. Additionally, we recognized an impairment loss of $97 million associated with GSF Arctic II and GSF Arctic IV after having determined that the rigs were subject to impairment indicators resulting from the credit crisis and the rapid decline in commodity prices. We estimate the fair market value of the assets held for sale, goodwill and other intangibles based on our estimates and projections considering current market conditions and other factors.

Asset dispositions—During 2008, we completed the sale of three of our Standard Jackups (GSF Adriatic III, GSF High Island I and GSF High Island VIII). See "—Liquidity and Capital Resources–Fleet Expansion and Dispositions."

Bank credit agreements—In March 2008, Transocean-Cayman entered into a term credit facility under the Term Credit Agreement dated March 13, 2008 (the "Term Loan") and borrowed $1.925 billion under the facility. In April 2008, Transocean-Cayman borrowed an additional $75 million under the Term Loan. In June 2008, Transocean-Cayman repaid the then outstanding balance under the Bridge Loan Facility and terminated the facility. See "—Liquidity and Capital Resources–Sources and Uses of Liquidity."

In November 2008, Transocean-Cayman entered into a new credit agreement for a 364-day, $1.08 billion revolving credit facility (the "364-Day Revolving Credit Facility") to replace its expiring $1.5 billion revolving credit agreement entered into in December 2007 ("Former 364-Day Revolving Credit Facility") and terminated the expiring agreement. Transocean-Cayman also amended its existing $2.0 billion revolving credit facility (the "Five-Year Revolving Credit Facility") and the Term Loan (together with the 364-Day Revolving Credit Facility and the Five-Year Revolving Credit Facility, the "Credit Facilities") in connection with the Redomestication Transaction. Upon completion of the Redomestication Transaction, Transocean-Cayman became our wholly-owned subsidiary, and we guaranteed Transocean-Cayman's obligations under the Credit Facilities.

Fleet expansion—In April 2008, we were awarded a drilling contract for Discoverer India. The Ultra-Deepwater Floater is expected to commence operations under a multi-year drilling contract during the fourth quarter of 2010. See "—Liquidity and Capital Resources–Fleet Expansion and Dispositions."

In June 2008, we reached an agreement with subsidiaries of Petrobras and Mitsui to acquire a newbuild Ultra-Deepwater Floater, Petrobras 10000, under a capital lease contract. In conjunction with the capital lease contract, we entered into a 10-year drilling contract with subsidiaries of Petrobras covering worldwide operations of the drillship with an option for Petrobras to extend the term of the drilling contract by up to an additional 10 years. See "—Liquidity and Capital Resources–Fleet Expansion and Dispositions."

Floating rate notes—In September 2006, Transocean-Cayman issued $1.0 billion aggregate principal amount of floating rate notes, due September 2008 ("Floating Rate Notes"). In September 2008, Transocean-Cayman repaid the Floating Rate Notes at maturity.

Angola Deepwater Drilling Company—In September 2008, we acquired a 65 percent interest in Angola Deepwater Drilling Company Limited ("ADDCL"), a Cayman Islands joint venture company.

Outlook

Drilling market—We were successful in building contract backlog in 2008 within all of our asset classes. Our contract backlog at February 3, 2009 was approximately $38.7 billion. A summary of our rigs that, as of February 3, 2009, had available uncommitted time in 2009 and 2010 is set forth below:

Uncommitted rigs	2009	2010
High-Specification Floaters	1	9
Midwater Floaters	10	6
High-Specification Jackups	5	5
Standard Jackups	26	18

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We have been successful in building contract backlog within our High-Specification Floaters fleet with 39 of our 49 current and future High-Specification Floaters, including all of our newbuilds, contracted into or beyond 2011 as of February 3, 2009. These 39 units also include 25 of our 28 current and future Ultra-Deepwater Floaters. Our total contract backlog of approximately $38.7 billion as of February 3, 2009 includes an estimated $29.2 billion of backlog represented by our High-Specification Floaters. The deepwater market benefits from the limited supply of deepwater capable rigs available for contract. We believe the continued exploration successes in the deepwater offshore provinces of Brazil, Angola, India and U.S. Gulf of Mexico will continue to drive significant demand for the Ultra-Deepwater Floaters and support our long-term positive outlook for our High-Specification Floater fleet. With the expected demand for deepwater programs, we believe that the long-term outlook for deepwater capable rigs continues to be very favorable. We have a limited number of High-Specification Floaters coming available in 2009, which may result in limited or no new contracts in the near term. Additionally, the decline in commodity prices and the downturn in the global economy may have a near-term negative effect on dayrates in the High-Specification Floater fleet.

Our Midwater Floaters fleet, which includes 28 semisubmersible rigs, is 64 percent committed to contracts that extend into 2010. However, near-term customer demand has declined, resulting in a lack of tendering opportunities and the warm stacking of one of our midwater floaters and one midwater floater that is classified as held for sale. Weakness in the U.K. floater market, coupled with subletting of the existing rigs in this market and cancellations and delays in customer programs in other Midwater Floater markets, is expected to result in reduced dayrates and the stacking of additional rigs in this fleet in the near term.

We are also experiencing weakness in the jackup market. As of February 20, 2009, we had warm stacked two jackups and cold stacked two jackups. Considering the number of jackups that are under construction without customer contracts and the lack of customer demand, we expect dayrates and utilization to decrease in our jackup fleet. We believe the delivery of the uncontracted units will further adversely impact the market for jackups through 2009, and potentially beyond, and is expected to result in the stacking of additional rigs in the near term. With 31 of our 65 jackups completing their current contracts in 2009, our exposure to market weakness is significant.

The decline in commodity prices, together with the difficult conditions in the credit markets, has had a negative impact on our business. One of our clients has been placed into administration (a form of bankruptcy proceeding in the U.K.), and another has been unable to post the required escrow leading us to terminate the contract. Continued low commodity prices may lead to further decreases in demand across all rig classes and, as a result, lower dayrates and utilization for our rigs or further idling rigs in our fleet.

As of February 3, 2009, the percentage of contract days in our uncommitted fleet for 2009, 2010, 2011 and 2012 is as follows:

Uncommitted fleet percentage	2009		2010		2011		2012
High-Specification Floaters	2	%	10	%	31	%	47	%
Midwater Floaters	20	%	41	%	77	%	87	%
High-Specification Jackups	29	%	74	%	93	%	100	%
Standard Jackups	29	%	69	%	85	%	98	%

We expect our total revenues to be lower in 2009 than in 2008. Although the commencement of new contracts with higher dayrates and the commencement of operations of five of our newbuilds and the Sedco 706 are expected to increase contract drilling revenues, both contract drilling intangible revenues and other revenues are expected to decline by a greater amount. These lower revenues are expected as a result of the reduction of non-drilling activity, the sale of three jackups in 2008, the anticipated sale of GSF Arctic II and GSF Arctic IV in 2009 and lost revenue associated with an expected increase in idle rigs.

We expect our total operating and maintenance costs in 2009 to decrease compared to 2008 due to lower operating costs associated with a number of jackups and midwater floaters that may be cold stacked during 2009, exchange rate changes, the anticipated sale of GSF Arctic II and GSF Arctic IV in 2009 and the sale of three jackups during 2008. In addition, we expect a reduction of support costs due to various overhead cost-reduction initiatives and an expected decrease in non-drilling activity. These decreases are expected to be partially offset in 2009 by an increase in operating and maintenance costs as a result of the commencement of operations of five of our deepwater newbuilds and the Sedco 706. Our actual operating and maintenance costs for 2009 remain uncertain given current economic and market conditions and could be significantly impacted by the actual level of activity and other factors.

We have nine existing contracts with fixed-price or capped options, and we expect that a number of these fixed price options will not be exercised by our customers in 2009 in light of the current market environment. Well-in-progress or similar provisions in our existing contracts may delay the start of higher dayrates in subsequent contracts, and some of the delays have been and could be significant.

Our operations are geographically dispersed in oil and gas exploration and development areas throughout the world. Rigs can be moved from one region to another, but the cost of moving a rig and the availability of rig-moving vessels may cause the supply and demand balance to vary somewhat between regions. However, significant variations between regions do not tend to persist long-term because of rig mobility. Consequently, we operate in a single, global offshore drilling market.

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Insurance matters—We periodically evaluate our hull and machinery and third-party liability insurance limits and self-insured retentions. Effective May 1, 2008, we renewed our hull and machinery and third-party liability insurance coverages. Subject to large self-insured retentions, we carry hull and machinery insurance covering physical damage to the rigs for operational risks worldwide, and we carry liability insurance covering damage to third parties. However, we do not generally have commercial market insurance coverage for physical damage losses to our rigs due to hurricanes in the U.S. Gulf of Mexico and war perils worldwide. Additionally, we do not carry insurance for loss of revenue. Also, for our subsidiaries ADTI and CMI, we generally self-insure operators' extra expense coverage. This coverage provides protection against expenses related to well control and redrill liability associated with blowouts. Generally, ADTI's clients assume, and indemnify ADTI for, liability associated with blowouts in excess of $50 million. In the opinion of management, adequate accruals have been made based on known and estimated losses related to such exposures.

Tax matters—We are a Swiss corporation and we operate through our various subsidiaries in a number of countries throughout the world. Our tax provision is based upon the tax laws, regulations and treaties in effect in and between the countries in which our operations are conducted and income is earned. Our effective tax rate for financial reporting purposes will fluctuate from year to year, as our operations are conducted in different taxing jurisdictions. We are subject to changes in tax laws, treaties and regulations in and between the countries in which we operate and earn income. A change in the tax laws, treaties or regulations in any of the countries in which we operate could result in a higher or lower effective tax rate on our worldwide earnings and, as a result, could have a material effect on our financial results.

Our income tax return filings in the major jurisdictions in which we operate worldwide are generally subject to examination for periods ranging from three to six years. We have agreed to extensions beyond the statute of limitations in two jurisdictions for up to 12 years. Tax authorities in certain jurisdictions are examining our tax returns and in some cases have issued assessments. We are defending our tax positions in those jurisdictions. While we cannot predict or provide assurance as to the final outcome of these proceedings, we do not expect the ultimate liability to have a material adverse effect on our consolidated statement of financial position or results of operations although it may have a material adverse effect on our consolidated cash flows.

With respect to our 2004 and 2005 U.S. federal income tax returns, U.S. taxing authorities previously proposed certain adjustments that, if sustained, would have resulted in a cash tax liability of approximately $413 million, exclusive of interest. The tax authorities have now withdrawn one of these proposed adjustments, which will significantly reduce the proposed assessment. The authorities continue to contend that one of our key subsidiaries maintains a permanent establishment in the U.S. and is, therefore, subject to U.S. taxation on certain earnings effectively connected to such U.S. business. Such tax treatment would not be expected to result in a material adverse effect on our consolidated statement of financial position, results of operations or cash flows with respect to 2004 and 2005 activities. With respect to years following 2005, U.S. taxing authorities may continue to pursue the argument that one of our key subsidiaries maintains a permanent establishment in the U.S. and is therefore subject to U.S. taxation on certain earnings effectively connected to such U.S. business. Since there is considerable uncertainty as to the activities that constitute being engaged in a trade or business within the U.S. (or maintaining a permanent establishment under an applicable treaty), we cannot be certain that the tax authorities will not be successful in their claim that we or any of our key subsidiaries is/are engaged in a trade or business in the U.S. (or, when applicable, maintains a permanent establishment in the U.S.). If we were or any of our key subsidiaries were considered to be engaged in a trade or business in the U.S. (when applicable, through a permanent establishment), we could be subject to U.S. corporate income and additional branch profits taxes on the portion of its earnings effectively connected to such U.S. business, in which case our effective tax rate on worldwide earnings with respect to years following 2005 could increase substantially, and our earnings and cash flows from operations could be materially and adversely affected. We believe our returns are materially correct as filed, and we will continue to vigorously defend against all such claims.

Certain of our Brazilian income tax returns for the years 2000 through 2004 are currently under examination. The Brazil tax authorities have issued tax assessments totaling $84 million, plus a 75 percent penalty and $63 million of interest through December 31, 2008. The U.S. dollar amount of the assessments decreased during 2008 due to foreign currency exchange rate fluctuations. We believe our returns are materially correct as filed, and we are vigorously contesting these assessments. We filed a protest letter with the Brazilian tax authorities on January 25, 2008, and we are currently engaged in the appeals process.

Norwegian civil tax and criminal authorities are investigating various transactions undertaken by our subsidiaries in 2001 and 2002. The authorities have issued a tax assessment of approximately $59 million, plus interest, related to a 2001 dividend payment. We plan to appeal this tax assessment. We may be required to provide some form of financial security, in an amount up to $122 million, for these assessed amounts as this dispute is appealed and addressed by the Norwegian courts. Furthermore, the authorities have also issued notifications of their intent to issue tax assessments of approximately $225 million, plus interest, related to certain restructuring transactions, approximately $6 million, plus interest, related to certain foreign exchange deductions, and approximately $144 million, plus interest, related to the migration of a subsidiary that was previously subject to tax in Norway. The authorities have indicated that they plan to seek penalties of 60 percent on all matters. We have and will continue to respond to all information requests from the Norwegian authorities. We plan to vigorously contest any assertions by the Norwegian authorities in connection with the various transactions being investigated.

During the year ended December 31, 2008, our long-term liability for unrecognized tax benefits related to these Norwegian tax issues decreased by $22 million to $146 million due to exchange rate fluctuations partially offset by the accrual of interest. While we cannot predict or provide assurance as to the final outcome of these proceedings, we do not expect the ultimate resolution of these matters to have a material adverse effect on our consolidated statement of financial position or results of operations although it may have a material adverse effect on our consolidated cash flows. See Notes to Consolidated Financial Statements—Note 5—Income Taxes.

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Regulatory matters—In June 2007, GlobalSantaFe's management retained outside counsel to conduct an internal investigation of its Nigerian and West African operations, focusing on brokers who handled customs matters with respect to its affiliates operating in those jurisdictions and whether those brokers have fully complied with the U.S. Foreign Corrupt Practices Act ("FCPA") and local laws. GlobalSantaFe commenced its investigation following announcements by other oilfield service companies that they were independently investigating the FCPA implications of certain actions taken by third parties in respect of customs matters in connection with their operations in Nigeria, as well as another company's announced settlement implicating a third party handling customs matters in Nigeria. In each case, the customs broker was reported to be Panalpina Inc., which GlobalSantaFe used to obtain temporary import permits for its rigs operating offshore Nigeria. GlobalSantaFe voluntarily disclosed its internal investigation to the U.S. Department of Justice (the "DOJ") and the Securities and Exchange Commission ("SEC") and, at their request, expanded its investigation to include the activities of its customs brokers in other West African countries and the activities of Panalpina Inc. worldwide. The investigation is focusing on whether the brokers have fully complied with the requirements of their contracts, local laws and the FCPA. In late November 2007, GlobalSantaFe received a subpoena from the SEC for documents related to its investigation. In this connection, the SEC advised GlobalSantaFe that it had issued a formal order of investigation. After the completion of the Merger, outside counsel began formally reporting directly to the audit committee of our board of directors. Our legal representatives are keeping the DOJ and SEC apprised of the scope and details of their investigation and producing relevant information in response to their requests.

On July 25, 2007, our legal representatives met with the DOJ in response to a notice we received requesting such a meeting regarding our engagement of Panalpina Inc. for freight forwarding and other services in the U.S. and abroad. The DOJ informed us that it is conducting an investigation of alleged FCPA violations by oil service companies who used Panalpina Inc. and other brokers in Nigeria and other parts of the world. We developed an investigative plan which has continued to be amended and which would allow us to review and produce relevant and responsive information requested by the DOJ and SEC. The investigation was expanded to include one of our agents for Nigeria. This investigation and the legacy GlobalSantaFe investigation are being conducted by outside counsel who reports directly to the audit committee of our board of directors. The investigation has focused on whether the agent and the customs brokers have fully complied with the terms of their respective agreements, the FCPA and local laws. Our outside counsel has coordinated their efforts with the DOJ and the SEC with respect to the implementation of our investigative plan, including keeping the DOJ and SEC apprised of the scope and details of the investigation and producing relevant information in response to their requests. We cannot predict the ultimate outcome of these investigations, the total costs to be incurred in completing the investigations, the potential impact on personnel, the effect of implementing any further measures that may be necessary to ensure full compliance with applicable laws or to what extent, if at all, we could be subject to fines, sanctions or other penalties.

Our internal compliance program has detected a potential violation of U.S. sanctions regulations in connection with the shipment of goods to our operations in Turkmenistan. Goods bound for our rig in Turkmenistan were shipped through Iran by a freight forwarder. Iran is subject to a number of economic regulations, including sanctions administered by the U.S. Treasury Department's Office of Foreign Assets Control ("OFAC"), and comprehensive restrictions on the export and re-export of U.S.-origin items to Iran. Iran has been designated as a state sponsor of terrorism by the U.S. State Department. Failure to comply with applicable laws and regulations relating to sanctions and export restrictions may subject us to criminal sanctions and civil remedies, including fines, denial of export privileges, injunctions or seizures of our assets. See "Item 1A. Risk Factors—Our non-U.S. operations involve additional risks not associated with our U.S. operations." We have self-reported the potential violation to OFAC and retained outside counsel who is conducting an investigation of the matter.

Performance and Other Key Indicators

Contract backlog—The following table presents our contract backlog, including firm commitments only, for our Contract Drilling segment as of December 31, 2008 and 2007. Firm commitments are represented by signed drilling contracts or, in some cases, by other definitive agreements awaiting contract execution. Our contract backlog is calculated by multiplying the full contractual operating dayrate by the number of days remaining in the firm contract period, excluding revenues for mobilization, demobilization and contract preparation or other incentive provisions, which are not expected to be significant to our contract drilling revenues.

	December 31, 2008		December 31, 2007
	(In millions)
Contract backlog
High-Specification Floaters	$	29,770	$	20,708
Midwater Floaters		5,801		5,728
High-Specification Jackups		507		768
Standard Jackups		3,568		4,445
Other Rigs		107		158
Total	$	39,753	$	31,807

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The firm commitments that comprise the contract backlog for our Contract Drilling segment as of December 31, 2008 are presented in the following table along with the associated average contractual dayrates. The amount of actual revenue earned and the actual periods during which revenues are earned will be different than the amounts and periods shown in the tables below due to various factors, including shipyard and maintenance projects, unplanned downtime and other factors that result in lower applicable dayrates than the full contractual operating dayrate, as well as the ability of our customers to terminate contracts under certain circumstances. The contract backlog average dayrate is defined as the contracted operating dayrate to be earned per revenue earning day in the period. A revenue earning day is defined as a day for which a rig earns a dayrate during the firm contract period after commencement of operations.

	For the years ending December 31,
	Total		2009		2010		2011		2012		Thereafter
	(In millions, except average dayrates)
Contract backlog
High-Specification Floaters	$	29,770	$	5,607	$	5,912	$	5,722	$	4,369	$	8,160
Midwater Floaters		5,801		2,616		1,743		707		334		401
High-Specification Jackups		507		417		90		—		—		—
Standard Jackups		3,568		2,207		990		362		9		—
Other Rigs		107		37		27		25		18		—
Total contract backlog	$	39,753	$	10,884	$	8,762	$	6,816	$	4,730	$	8,561

Average Dayrates	Total		2009		2010		2011		2012		Thereafter
High-Specification Floaters	$	448,000	$	398,000	$	439,000	$	471,000	$	479,000	$	462,000
Midwater Floaters		326,000		327,000		335,000		346,000		306,000		266,000
High-Specification Jackups		163,000		166,000		150,000		—		—		—
Standard Jackups		154,000		157,000		153,000		146,000		100,000		—
Other Rigs		63,000		51,000		72,000		72,000		72,000		—
Total fleet average	$	353,000	$	276,000	$	336,000	$	400,000	$	448,000	$	446,000

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Fleet average daily revenue and utilization—The following table presents the average daily revenue and utilization for our Contract Drilling segment for each of the quarters ended December 31, 2008, September 30, 2008 and December 31, 2007. Average daily revenue is defined as contract drilling revenue earned per revenue earning day in the period. A revenue earning day is defined as a day for which a rig earns a dayrate after commencement of operations. Utilization is defined as the total actual number of revenue earning days in the period as a percentage of the total number of calendar days in the period for all drilling rigs in our fleet.

	Three months ended
	December 31, 2008			September 30, 2008			December 31, 2007
Average daily revenue
High-Specification Floaters
Ultra-Deepwater Floaters	$	423,600		$	401,300		$	346,100
Deepwater Floaters	$	299,000		$	322,700		$	265,300
Harsh Environment Floaters	$	358,900		$	363,500		$	326,300
Total High-Specification Floaters	$	370,500		$	369,300		$	311,600
Midwater Floaters	$	329,200		$	292,900		$	274,600
High-Specification Jackups	$	169,100		$	178,500		$	173,400
Standard Jackups	$	156,100		$	158,700		$	130,800
Other Rigs	$	37,800		$	48,900		$	48,600
Total fleet average daily revenue	$	251,500		$	242,200		$	224,000


Utilization
High-Specification Floaters
Ultra-Deepwater Floaters		96	%		93	%		97	%
Deepwater Floaters		75	%		68	%		75	%
Harsh Environment Floaters		100	%		98	%		80	%
Total High-Specification Floaters		88	%		83	%		85	%
Midwater Floaters		92	%		88	%		95	%
High-Specification Jackups		94	%		87	%		100	%
Standard Jackups		90	%		93	%		91	%
Other Rigs		99	%		100	%		97	%
Total fleet average utilization		90	%		89	%		90	%

Liquidity and Capital Resources

Sources and Uses of Cash

Our primary sources of cash in 2008 were our cash flows from operations, proceeds from asset sales, proceeds from the issuance of commercial paper, borrowings under the Term Loan, financing obtained through our joint ventures, borrowings under our other credit facilities and proceeds from the issuance of shares upon the exercise of stock options. Our primary uses of cash were capital expenditures (including for newbuild construction), repayments of borrowings under our credit facilities and the repayment of the Floating Rate Notes at maturity. At December 31, 2008, we had $963 million in cash and cash equivalents.

We include investments in highly liquid debt instruments with an original maturity of three months or less in cash and cash equivalents. As of September 30, 2008, we had $74 million invested in The Reserve Primary Fund and $334 million invested in The Reserve International Liquidity Fund Ltd. In September 2008, The Reserve announced that certain funds had lost the ability to maintain a net asset value of $1.00 per share due to losses in connection with the bankruptcy of Lehman Brothers Holdings, Inc. ("Lehman Holdings"). According to public disclosures by The Reserve, The Reserve stopped processing redemption requests in order to develop an orderly plan of liquidation that would protect all of the funds' shareholders. Based on statements made by the funds, in September 2008 we reclassified $408 million from cash and cash equivalents to short-term investments and recorded an impairment charge in the third quarter of 2008 in the amount of $16 million associated with our proportional interest in the debt instruments of Lehman Holdings held by the funds until such time as we receive our liquidated portion of the assets. Our statement of cash flows presents a use of cash in the amount of this reclassification. As of December 31, 2008, we had received $59 million invested in The Reserve Primary Fund. Following December 31, 2008, we received $216 million invested in The Reserve International Fund and another $5 million invested in the Reserve Primary Fund. At February 20, 2009, the carrying values of our investments in The Reserve Primary Fund and The Reserve International Liquidity Fund were $10 million and $102 million, respectively. The timing of our ability to access the remaining funds is uncertain but is expected to be during 2009. Potential rulings or decisions by courts or regulators may impact further distributions by the funds.

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	Years ended December 31,
	2008			2007			Change
	(In millions)
Net cash from operating activities
Net income	$	4,202		$	3,131		$	1,071
Amortization of drilling contract intangibles		(690	)		(88	)		(602	)
Depreciation, depletion and amortization		1,436			499			937
Impairment loss		320			—			320
Other non-cash items		12			(297	)		309
Changes in operating assets and liabilities, net		(321	)		(172	)		(149	)
	$	4,959		$	3,073		$	1,886

Net cash provided by operating activities in 2008 increased due to more cash generated from net income, partially offset by changes in operating assets and liabilities.

	Years ended December 31,
	2008			2007			Change
	(In millions)
Net cash from investing activities
Capital expenditures	$	(2,208	)	$	(1,380	)	$	(828	)
Business combination		—			(5,129	)		5,129
Cash balances acquired in business combination		—			695			(695	)
Proceeds from disposal of assets, net		348			379			(31	)
Short-term investments		(408	)		—			(408	)
Proceeds from maturities of short-term investments		59			—			59
Joint ventures and other investments, net		13			(242	)		255
	$	(2,196	)	$	(5,677	)	$	3,481

Net cash used in investing activities in 2008 decreased primarily due to cash paid out in connection with the Merger during 2007. Partially offsetting the decrease were capital expenditures, consisting primarily of expenditures for the construction of nine of our ten Ultra-Deepwater Floaters, the two Sedco 700-series deepwater upgrades and other equipment replaced and upgraded on our existing rigs. Additionally, in 2008, we received proceeds from the maturities of certain investments that were reclassified from cash and cash equivalents to short-term investments due to the illiquidity of those funds.

	Years ended December 31,
	2008			2007			Change
	(In millions)
Net cash from financing activities
Change in short-term borrowings, net	$	(837	)	$	1,500		$	(2,337	)
Proceeds from debt		2,661			24,095			(21,434	)
Repayments of debt		(4,893	)		(12,033	)		7,140
Financing costs		(24	)		(106	)		82
Repurchase of shares		—			(400	)		400
Payment to shareholders for Reclassification		(1	)		(9,859	)		9,858
Proceeds from (payments for) exercises of warrants, net		(7	)		40			(47	)
Proceeds from share-based compensation plans, net		51			72			(21	)
Excess tax benefit from share-based compensation plans		10			70			(60	)
Other, net		(1	)		(1	)		—
	$	(3,041	)	$	3,378		$	(6,419	)

Net cash used in financing activities decreased primarily due to repayments under the Bridge Loan Facility and the Former 364-Day Revolving Credit Facility and the repayment of the Floating Rate Notes at maturity. Partially offsetting these decreases were borrowings under the Term Loan, Transocean Pacific Drilling Inc. ("TPDI") credit facilities, ADDCL loan facilities, net borrowings under the Five-Year Revolving Credit Facility and our commercial paper program. Additionally, we did not repurchase any shares during 2008 compared to $400 million of repurchases in 2007.

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Fleet Expansion and Dispositions

Fleet expansion—We could, from time to time, review possible acquisitions of businesses and drilling rigs and may make significant future capital commitments for such purposes. We may also consider investments related to major rig upgrades or new rig construction. Any such acquisition, upgrade or new rig construction could involve the payment by us of a substantial amount of cash or the issuance of a substantial number of additional shares or other securities.

Capital expenditures—Capital expenditures, including capitalized interest of $114 million, totaled $2.2 billion during the year ended December 31, 2008, substantially all of which related to the Contract Drilling segment. The following table summarizes actual capital expenditures including capitalized interest, for our major construction and conversion projects incurred through December 31, 2008 and expected in future years (in millions):

	Total costs through December 31, 2008		Expected costs for the year ending December 31, 2009		Estimated costs thereafter		Total estimated costs at completion
Sedco 700-series upgrades	$	520	$	75	$	—	$	595
Discoverer Clear Leader		516		119		—		635
Discoverer Americas		478		147		—		625
Development Driller III (a)		483		170		—		653
Discoverer Inspiration		443		227		—		670
Dhirubhai Deepwater KG1(b)		384		311		—		695
Discoverer Luanda (c)		315		220		115		650
Dhirubhai Deepwater KG2(b)		270		177		243		690
Deepwater Champion (a)		264		280		196		740
Discoverer India		250		300		180		730
Petrobras 10000 (d)		—		—		750		750
Capitalized Interest		206		149		60		415
Total	$	4,129	$	2,175	$	1,544	$	7,848

________________________________

(a)

Total costs include our initial investments in Development Driller III and Deepwater Champion of $356 million and $109 million, respectively, representing the estimated fair values of the rigs at the time of the Merger.

(b)

The costs for Dhirubhai Deepwater KG1 and Dhirubhai Deepwater KG2 represent 100 percent of expenditures incurred ($277 million and $178 million, respectively) prior to our investment in TPDI, and 100 percent of expenditures incurred since our investment in the joint venture. However, our joint venture partner, Pacific Drilling Limited ("Pacific Drilling"), shares 50 percent of these costs.

(c)	The costs for Discoverer Luanda represent 100 percent of expenditures incurred since inception. However, Angco Cayman Limited shares 35 percent of these costs beginning on the date of its investment in ADDCL.

(d)

In June 2008, we reached an agreement with subsidiaries of Petrobras and Mitsui to acquire Petrobras 10000,under a capital lease contract. The capital lease contract, which is expected to commence in the third quarter of 2009, has a 20-year term, after which we will have the right and obligation to acquire the drillship for one dollar. Total capital costs to be incurred by Petrobras and Mitsui for the construction of the drillship are estimated to be $750 million, including $65 million of capitalized interest. Upon delivery of the rig, we will record a liability for the capital lease obligation and a corresponding addition to property and equipment based on the fair value at that date. We are offering assistance and advisory services for the construction of Petrobras 10000 and have agreed to provide operating management services once the drillship begins operations.

During 2009, we expect capital expenditures to be approximately $4.0 billion, including approximately $2.3 billion for our major construction and conversion projects and $750 million in non-cash capital cost related to the Petrobras 10000 capital lease. The level of our capital expenditures is partly dependent upon financial market conditions, the actual level of operational and contracting activity and the level of capital expenditures for which our customers agree to reimburse us. Our expected capital expenditures during 2009 do not include amounts that would be incurred as a result of other possible newbuild opportunities.

As with any major shipyard project that takes place over an extended period of time, the actual costs, the timing of expenditures and the project completion date may vary from estimates based on numerous factors, including actual contract terms, weather, exchange rates, shipyard labor conditions and the market demand for components and resources required for drilling unit construction. See "Item 1A. Risk Factors—Our shipyard projects are subject to delays and cost overruns."

We intend to fund the cash requirements relating to our capital expenditures through available cash balances, cash generated from operations and asset sales. We also have available credit under the Five-Year Revolving Credit Facility and the 364-Day Revolving Credit Facility (see "—Sources and Uses of Liquidity") and may utilize other commercial bank or capital market financings. We intend to fund the cash requirements of our joint ventures for capital expenditures in connection with newbuild construction through their respective credit facilities. The continued credit crisis and related instability in the global financial system could impact the availability of these sources of funding. See "Item 1A. Risk Factors—The recent worldwide financial and credit crisis and worldwide economic downturn could have a material adverse effect on our revenue, profitability and financial position" and "Item 1A. Risk Factors—The global financial crisis may impact our business and financial condition in ways that we currently cannot predict."

Dispositions—From time to time, we may also review possible dispositions of drilling units. During 2008, we completed the sale of three of our Standard Jackups (GSF Adriatic III, GSF High Island I and GSF High Island VIII). We received cash proceeds of $320 million associated with the sale, which had no effect on earnings.

In May 2008, we entered into a definitive agreement to sell our Standard Jackup Transocean Nordic for cash proceeds of $169 million. In December 2008, the buyer failed to perform under the agreement. Under the terms of the agreement, the buyer forfeited an escrow deposit in the amount of $17 million, which we recognized as a gain, recorded in other income, net on our consolidated statements of operations. As a result, we classified the rig as an asset held and used, recorded in property and equipment on our consolidated balance sheet.

In July 2008, we entered into a definitive agreement to sell two Midwater Floaters (GSF Arctic II and GSF Arctic IV) in connection with our previously announced undertakings to the Office of Fair Trading in the U.K. ("OFT"). The acquisition of the rigs was contingent upon the buyers' ability to obtain lender consents. The buyers have reported that they have been unable to obtain the consent of their lenders on terms acceptable to them and have publicly announced their termination of the agreement to purchase the vessels. At December 31, 2008, both GSF Arctic II and GSF Arctic IV continue to be marketed for sale and are classified as assets held for sale in the aggregate amount of $464 million on our consolidated balance sheet. The market for Midwater Floaters appears to have deteriorated subsequent to December 31, 2008, and we have a limited amount of time to sell the rigs. Consequently, we can make no assurances as to whether we are able to sell the rigs, the timing of the sale or any terms of the sale, including price. Any sale at a price below our valuation would result in an additional write down of the asset carrying value. See Notes to Consolidated Financial Statements—Note 4—Impairment Loss.

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Sources and Uses of Liquidity

We expect to use existing cash balances, internally generated cash flows and proceeds from asset sales to fulfill anticipated obligations such as scheduled debt maturities, repayment of short-term debt, capital expenditures and working capital needs. We may also use a portion of such sources of cash to reduce debt (including convertible debt) prior to scheduled maturity through repurchases (in the open market or in privately negotiated transactions), redemptions or tender offers, or to make repayments on bank borrowings or to repurchase our shares, subject in each case to then existing market conditions and to our then expected liquidity needs. Our board of directors has recommended that our shareholders approve a share repurchase program. If approved, we may use our cash flow from other than debt to fund this program. See "—Share repurchase program recommendation." From time to time, we may also use bank lines of credit and commercial paper borrowing to maintain liquidity for short-term cash needs. Although commercial paper markets have improved considerably, our access to the commercial paper markets was impacted by the credit crisis in the third quarter of 2008. If the markets experience further instability, we may be required to rely more heavily on our bank lines of credit.

Our access to debt and equity markets may be reduced or closed to us due to a variety of events, including among others, credit rating agency downgrades of our debt, industry conditions, general economic conditions, market conditions and market perceptions of us and our industry. The continued credit crisis and related instability in the global financial system has had, and may continue to have, an impact on our business and our financial condition. We may face significant challenges if conditions in the financial markets do not improve. Our ability to access the capital markets may be severely restricted at a time when we would like, or need, to access such markets, which could have an impact on our flexibility to react to changing economic and business conditions. The credit crisis could have an impact on the lenders participating in our credit facilities or on our customers, causing them to fail to meet their obligations to us.

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

Bank credit agreements—In November 2008, Transocean-Cayman entered into the new $1.08 billion 364-Day Revolving Credit Facility to replace its expiring $1.5 billion revolving credit agreement and terminated the expiring agreement. Transocean-Cayman also amended its existing $2.0 billion Five-Year Revolving Credit Facility, which will expire on November 27, 2012, and its $2.0 billion Term Loan, which will expire on March 13, 2010. Upon completion of the Redomestication Transaction, Transocean-Cayman became a wholly-owned subsidiary of ours, and we guaranteed Transocean-Cayman's obligations under the Credit Facilities.

Under the 364-Day Revolving Credit Facility, Transocean-Cayman may borrow at either (1) the adjusted London Interbank Offered Rate ("LIBOR") plus a margin determined by reference to the mid-point credit default swap spread for its senior unsecured debt with a maturity of one year, subject to a ceiling varying from 1.75 percent to 3.75 percent per annum and a floor of 0.75 percent to 1.75 percent per annum, in each case depending on Transocean-Cayman's non-credit enhanced senior unsecured long-term debt rating (the "Debt Rating") (such margin, the "364-Day Revolving Credit Facility Margin"), or (2) a base rate, determined as the greater of (A) a prime rate, (B) the federal funds effective rate plus 1/2 of one percent, or (C) the adjusted LIBOR for a one-month interest period plus one percent per annum (the "Base Rate"), plus the 364-Day Revolving Credit Facility Margin, less one percent per annum. At February 20, 2009, no amounts were outstanding under the 364-Day Revolving Credit Facility.

In March 2008, Transocean-Cayman entered into the Term Loan and borrowed $1.925 billion under the facility. In April 2008, Transocean-Cayman borrowed an additional $75 million, increasing the borrowings under this facility to $2.0 billion, the maximum allowed under the Term Loan. In January 2009 and in connection with the Redomestication, Transocean-Cayman amended the bank credit agreement governing the Term Loan. Upon completion of the Redomestication Transaction, we guaranteed Transocean-Cayman's obligations under the Term Loan.

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Transocean-Cayman may borrow under the Term Loan at either (1) the adjusted LIBOR plus a margin (the "Term Loan Margin") based on Transocean-Cayman's Debt Rating (based on its current Debt Rating, a margin of 1.25 percent), or (2) the Base Rate plus the Term Loan Margin, less one percent per annum. At February 20, 2009, Transocean-Cayman had $1.8 billion outstanding under the Term Loan at a weighted-average interest rate of 1.7 percent.

In November 2007, Transocean-Cayman entered into the Five-Year Revolving Credit Facility. In November 2008, in connection with the Redomestication Transaction, Transocean-Cayman amended the Five-Year Revolving Credit Facility. Upon completion of the Redomestication Transaction, we guaranteed Transocean-Cayman's obligations under the Five-Year Revolving Credit Facility.

Transocean-Cayman may borrow under the Five-Year Revolving Credit Facility at either (1) the adjusted LIBOR plus a margin (the "Five-Year Revolving Credit Facility Margin") based on Transocean-Cayman's Debt Rating (based on its current Debt Rating, a margin of 1.1 percent) or (2) the Base Rate plus the Five-Year Revolving Credit Facility Margin, less one percent per annum. Additionally, a facility fee is incurred on the daily amount of the underlying commitment, whether used or unused, throughout the term of the Five-Year Revolving Credit Facility. The amount of such facility fee depends on Transocean-Cayman's Debt Rating (based on its current Debt Rating, a facility fee of 0.15 percent) and varies from 0.10 percent to 0.30 percent. At February 20, 2009, Transocean-Cayman had no amounts outstanding under the Five-Year Revolving Credit Facility.

The Credit Facilities include limitations on creating liens, incurring subsidiary debt, transactions with affiliates, sale/leaseback transactions, mergers and the sale of substantially all assets. The Credit Facilities also include covenants imposing a maximum leverage ratio, which may not exceed 3.0 to 1.0 for any period through the third quarter of 2009. Additionally, the Five-Year Revolving Credit Facility and the Term Loan each include a covenant imposing a maximum debt to capitalization ratio of 0.6 to 1.0 commencing with the fourth quarter of 2009. Borrowings under the Credit Facilities are subject to acceleration upon the occurrence of events of default. Transocean-Cayman is also subject to various covenants under the indentures pursuant to which its public debt was issued, including restrictions on creating liens, engaging in sale/leaseback transactions and engaging in certain merger, consolidation or reorganization transactions. A default under Transocean-Cayman's public debt could trigger a default under the Credit Facilities and, if not waived by the lenders, could cause Transocean-Cayman to lose access to the Credit Facilities.

Each of the Credit Facilities may be prepaid in whole or in part without premium or penalty.

In December 2007, Transocean-Cayman entered into a commercial paper program (the "Program"). The Five-Year Revolving Credit Facility and the 364-Day Revolving Credit Facility provide liquidity for the Program. In December 2008, we and Transocean-Cayman entered into amendments to the Program to provide for the guarantee by us of Transocean-Cayman's obligations under the Program after the completion of the Redomestication Transaction. At February 20, 2009, $404 million was outstanding under the Program at a weighted-average interest rate of 3.26 percent.

In September 2007, Transocean-Cayman entered into a $15.0 billion, one-year senior unsecured bridge loan facility ("Bridge Loan Facility"). In June 2008, Transocean-Cayman repaid the then outstanding balance under the Bridge Loan Facility and terminated the facility.

In September 2006, Transocean-Cayman issued the Floating Rate Notes. In September 2008, Transocean-Cayman repaid the Floating Rate Notes at maturity.

ADDCL Primary Loan Facility—In September 2008, ADDCL completed final documentation for a senior credit agreement that provides a credit facility comprised of Tranche A, Tranche B and Tranche C for $215 million, $270 million and $399 million, respectively (collectively, the "ADDCL Primary Loan Facility"). Tranche A and Tranche B are provided by external lenders. One of our subsidiaries is the lender for Tranche C and has agreed to provide financial security for borrowings under Tranche A and Tranche B until customer acceptance of Discoverer Luanda, the newbuild for which the facility was established. Tranche A requires quarterly payments beginning on the rig's first well commencement date, currently scheduled for third quarter 2010, and matures in December 2017. Tranche B matures upon customer acceptance of Discoverer Luanda, and is expected to be repaid with borrowings under Tranche C. Tranche C is subordinate to Tranche A and Tranche B and due after Tranche A is fully repaid or, if earlier, by February 2015. When Tranche C is funded, it will be eliminated in consolidation. The ADDCL Primary Loan Facility will be secured by the rig upon completion of its construction and may be prepaid in whole or in part without premium or penalty. ADDCL is required to maintain certain cash balances, as defined in the loan agreement, to service the debt. The ADDCL Primary Loan Facility also limits the ability of ADDCL to incur additional indebtedness, make distributions and other payments and acquire assets.

Borrowings under Tranche A and Tranche B bear interest at LIBOR plus the applicable margin of 0.425 percent until the first well commencement date, following which the loans outstanding under Tranche A will bear interest at LIBOR plus the applicable margin of 0.725 percent. ADDCL is required to enter into fixed-for-floating interest rate swaps with one of our subsidiaries for the loans outstanding under Tranche A. Borrowings under Tranche C will bear interest at a fixed rate of 3.066 percent by a fixed-to-floating interest rate swap plus an applicable margin of 2 percent. At February 20, 2009, the borrowings under Tranche A and Tranche B were $138 million and $169 million, respectively, at a weighted-average interest rate of 3.34 percent. At February 20, 2009, there were no borrowings outstanding under Tranche C.

ADDCL Secondary Loan Facility—In September 2008, ADDCL completed final documentation for a secondary loan agreement for a $90 million credit facility (the "ADDCL Secondary Loan Facility"), for which one of our subsidiaries provides 65 percent of the total commitment and an external lender provides the remaining 35 percent. The facility bears interest at LIBOR plus the applicable margin, ranging from 3.125 percent to 5.125 percent, depending on certain milestones, as defined by the loan agreement. The facility is payable in full the earlier of 90 days after the fifth anniversary of the first well commencement or December 2015 and may be prepaid in whole or in part without premium or penalty. At February 20, 2009, the weighted-average interest rate was 4.7 percent on the $71 million outstanding balance, of which $46 million was provided by one of our subsidiaries and has been eliminated in consolidation. There have been no further borrowings on the facility.

TPDI Credit Facilities—In October 2008, TPDI entered into a credit agreement for a $1.265 billion secured credit facility (the "TPDI Term Loan Facility"), comprised of a $1.0 billion senior tranche, a $190 million junior tranche and a $75 million revolving credit facility (the "TPDI Revolving Credit Facility", and together with the TPDI Term Loan Facility, the "TPDI Credit Facilities"). The TPDI Credit Facilities will finance the construction of Dhirubhai Deepwater KG1 and Dhirubhai Deepwater KG2. One of our subsidiaries participates in the senior and junior tranches with a 50 percent commitment totaling $595 million in the aggregate. The TPDI Credit Facilities will bear interest at LIBOR plus the applicable margin of 1.60 percent until acceptance of Dhirubhai Deepwater KG2. Subsequently, the TPDI Credit Facilities will bear interest at a rate of 1.45 percent for the senior tranche and the revolving credit facility and 2.25 percent for the junior tranche. The senior tranche requires quarterly payments with a final payment on the earlier of (1) June 2015 and (2) the fifth anniversary of the acceptance date of the second rig. The junior tranche is due in full on the earlier of (1) June 2015 and (2) the fifth anniversary of the acceptance date of the second rig. The TPDI Credit Facilities have covenants that require TPDI to maintain minimum liquidity requirements, a minimum debt service ratio and a maximum leverage ratio. The TPDI Credit Facilities may be prepaid in whole or in part without premium or penalty. At February 20, 2009, $576 million was outstanding under the senior tranche, of which $288 million was due to one of our subsidiaries and was eliminated in consolidation. The weighted-average interest rate of the senior tranche on February 20, 2009 was 2.51 percent. At February 20, 2009, $1 million was outstanding under the TPDI Revolving Credit Facility at a weighted-average interest rate of 2.51 percent.

TPDI Notes—In October 2008, using proceeds from the TPDI Credit Facilities, TPDI prepaid $440 million of the outstanding promissory notes, $220 million of which was due to one of our subsidiaries. As of February 20, 2009, $220 million in promissory notes remained outstanding, $110 million of which is due to one of our subsidiaries and has been eliminated in consolidation, bearing interest at a weighted-average interest rate of 3.92 percent.

Convertible Notes—In December 2007, Transocean-Cayman issued $6.6 billion aggregate principal amount of Convertible Notes. In connection with the Redomestication Transaction, we guaranteed Transocean-Cayman's obligations under the Convertible Notes and assumed the obligation to deliver shares, if any, upon conversion of the Convertible Notes. The Convertible Notes may be converted at a rate of 5.9310 shares per $1,000 note. The conversion rate is subject to adjustment upon the occurrence of certain corporate events but not for accrued interest. Upon conversion, we will deliver, in lieu of shares, cash up to the aggregate principal amount of notes to be converted and shares in respect of the remainder, if any, of our conversion obligation in excess of the aggregate principal amount of the notes being converted. If certain fundamental changes occur on or before specified dates, we will in some cases increase the conversion rate for a holder electing to convert notes in connection with such fundamental change; provided, that in no event will the total number of shares issuable upon conversion of a note exceed 7.8585 per $1,000 principal amount of notes (subject to adjustment in the same manner as the conversion rate). Although there was no change to the conversion rate as a result of the Redomestication, it triggered the right of holders to convert the Convertible Notes at any time beginning on December 3, 2008, which was the date 15 days prior to the effective time of the Redomestication (the "Effective Time") of December 18, 2008, and ending on February 3, 2009, which was the 30^th scheduled trading day following the Effective Time. Prior to the expiration of this period, we received conversion notices with respect to $490,000 principal amount of Convertible Notes and expect to pay an aggregate amount of $150,000 to the holders upon settlement.

Share repurchase program recommendation—In February 2009, our board of directors recommended that our shareholders approve and authorize the repurchase of an amount of our shares with an aggregate purchase price of up to 3.50 billion Swiss francs (which is equivalent to approximately U.S.$2.95 billion at an exchange rate as of the close of trading on February 20, 2009 of U.S.$1.00 to 1.1864 Swiss francs).

Shareholder approval is being sought in order to provide the company with the flexibility to repurchase shares at any time after the May 2009 annual general meeting. If the share repurchase program is approved by the shareholders, there can be no assurance that any shares will actually be repurchased in the near term after the meeting, or at all. The board of directors would be permitted to delegate its share repurchase authority to company management to repurchase shares under the share repurchase program.

The board of directors or company management, as applicable, may decide, based upon the company's ongoing capital requirements, the price of the company's shares, regulatory considerations, cash flow generation, the relationship between the company's contractual backlog and debt, general market conditions and other factors, that the company should retain cash, reduce debt, make capital investments or otherwise use cash for general corporate purposes, and consequently repurchase fewer shares or not repurchase any shares. Decisions regarding the amount, if any, and timing of any share repurchases would be made from time to time based upon the factors set forth above. The company plans to fund any share repurchases from the company's current and future cash balances and will not use debt to fund any repurchases. The board of directors has decided to recommend that the shareholders at their May 2009 annual general meeting approve the release of Swiss statutory reserves, which is necessary for this authorization of a share repurchase program for the repurchase of shares for cancellation.

Any shares repurchased under this program are expected to be purchased from time to time from market participants that have acquired those shares on the open market and that can fully recover Swiss withholding tax resulting from the share repurchase. Repurchases could also be made by tender offer, in privately negotiated transactions or by any other share repurchase method. Any repurchased shares would be held by the company for cancellation by the shareholders at a future annual general meeting. The share repurchase program would not have an established expiration date and could be suspended or discontinued by the company's Board of Directors or company management, as applicable, at any time.

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Contractual obligations—Our contractual obligations included in the table below are at face value.

	For the years ending December 31,
	Total		2009		2010-2011		2012-2013		Thereafter
	(In millions)
Contractual obligations
Debt	$	14,161	$	663	$	6,630	$	3,005	$	3,863
Interest on debt		5,133		497		770		570		3,296
Operating leases		129		34		49		21		25
Capital leases		1,548		40		155		155		1,198
Stock warrant consideration		31		31		—		—		—
Purchase obligations		4,244		2,799		1,445		—		—
Defined benefit pension plans		65		65		—		—		—
Total	$	25,311	$	4,129	$	9,049	$	3,751	$	8,382

Bondholders may, at their option, require Transocean-Cayman to repurchase the Series A Notes and the Series B Notes in December 2010 and 2011, respectively. In addition, holders of any series of the Convertible Notes may, at their option, require Transocean-Cayman to repurchase their notes in December 2012, 2017, 2022, 2027 and 2032. The chart above assumes that the holders of the notes exercise the options at the first available date.

Capital leases includes our estimated future obligations associated with our newbuild Petrobras 10000, which will be held under capital lease.

Due to market conditions, the minimum funding requirements for defined benefit pension plans in future periods cannot be reasonably estimated. Additionally, we are awaiting guidance related to the enactment of the Pension Protection Act, which is expected to have an effect on the amounts associated with our minimum funding requirements.

As of December 31, 2008, the total unrecognized tax benefit related to uncertain tax positions, net of prepayments was $521 million. Due to the high degree of uncertainty regarding the timing of future cash outflows associated with the liabilities recognized in this balance, we are unable to make reasonably reliable estimates of the period of cash settlement with the respective taxing authorities.

Other commercial commitments—At December 31, 2008, 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, customs, 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 and letters of credit are geographically concentrated in Nigeria and India. These letters of credit and surety bond obligations are not normally called as we typically comply with the underlying performance requirement.

The following table provides a list of these obligations in U.S. dollar equivalents and their time to expiration.

	For the years ending December 31,
	Total		2009		2010-2011		2012-2013		Thereafter
	(In millions)
Other commercial commitments
Standby letters of credit	$	751	$	611	$	116	$	24	$	—
Surety bonds		37		37		—		—		—
Total	$	788	$	648	$	116	$	24	$	—

We have established a wholly-owned captive insurance company which insures various risks of our operating subsidiaries. Access to the cash investments of the captive insurance company may be limited due to local regulatory restrictions. These cash investments totaled $123 million at December 31, 2008 and are expected to rise to approximately $150 million by the end of 2009. Our estimate is dependent on the level of claims that will be incurred in 2009 and assumes the actual level of premiums paid to the captive insurance company continues to increase.

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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. At December 31, 2008, we had no outstanding foreign exchange or interest rate derivative instruments.

In January 2009, TPDI entered into interest rate swaps with an aggregate notional value of $446.4 million, which are designated as cash flow hedge of the variable rate borrowings under the TPDI Credit Facilities, to reduce the variability of its cash interest payments. Under the interest rate swaps, TPDI will receive interest at three-month LIBOR and pay interest at a fixed rate of 2.24 percent over the expected term of the TPDI Credit Facilities.

In February 2009, Transocean-Cayman entered into interest rate swaps with an aggregate notional value of $1 billion, which are designated as a cash flow hedge of a portion of Transocean-Cayman's borrowings under the Term Loan to reduce the variability of its cash interest payments. Under the interest rate swaps, Transocean-Cayman will receive interest at one-month LIBOR and pay interest at a fixed rate of 0.768 percent over the six-month period ending August 6, 2009.

These hedges are expected to be highly effective. Any gain or loss associated with the effective portion of the hedge, therefore, will be reported initially as a component of other comprehensive income and subsequently, recognized in interest expense upon settlement coinciding with the forecasted transaction. Any gain or loss associated with the ineffective portion will be recognized in interest expense in the period in which it is realized.

Results of Operations

Historical 2008 compared to 2007

Following is an analysis of our operating results. See "—Overview" for a definition of revenue earning days, utilization and average daily revenue.


	Years ended December 31,
	2008			2007			Change			% Change
	(In millions, except day amounts and percentages)

Revenue earning days		44,761			28,074			16,687		59	%
Utilization		90	%		90	%		n/a		n/m
Average daily revenue	$	240,300		$	211,900		$	28,400		13	%

Contract drilling revenues	$	10,756		$	5,948		$	4,808		81	%
Contract drilling intangible revenues		690			88			602		n/m
Other revenues		1,228			341			887		n/m
		12,674			6,377			6,297		99	%
Operating and maintenance expense		(5,355	)		(2,781	)		(2,574	)	93	%
Depreciation, depletion and amortization		(1,436	)		(499	)		(937	)	n/m
General and administrative expense		(199	)		(142	)		(57	)	40	%
Impairment loss		(320	)		—			(320	)	n/m
Gain (loss) from disposal of assets, net		(7	)		284

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