Transocean 10-K 12-31-2004



UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
_________________

FORM 10-K
 
 
 (Mark One)
 
[X]
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
For the fiscal year ended December 31, 2004
OR 
 
[  ]
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
For the transition period from _____ to ______.
 
Commission file number 333-75899
 
_________________
TRANSOCEAN INC.
(Exact name of registrant as specified in its charter)
_________________

 Cayman Islands
 
  66-0582307
 (State or other jurisdiction of incorporation or organization)
 
 (I.R.S. Employer Identification No.)
    
 
4 Greenway Plaza 
 
 77046
Houston, Texas
 
  (Zip Code)
(Address of principal executive offices) 
   

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

Securities registered pursuant to Section 12(b) of the Act:

 Title of class
 
 Exchange on which registered
 Ordinary Shares, par value $0.01 per share 
 
 New York Stock Exchange, Inc.
 
Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes [x] No [ ]

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [ ]

Indicate by check mark whether the registrant is an accelerated filer. Yes [x] No [ ]

As of June 30, 2004, 320,819,763 ordinary shares were outstanding and the aggregate market value of such shares held by non-affiliates was approximately $9.3 billion (based on the reported closing market price of the ordinary shares on such date of $28.94 and assuming that all directors and executive officers of the Company are “affiliates,” although the Company does not acknowledge that any such person is actually an “affiliate” within the meaning of the federal securities laws). As of February 28, 2005, 324,073,235 ordinary shares were outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the registrant's definitive Proxy Statement to be filed with the Securities and Exchange Commission within 120 days of December 31, 2004, for its 2004 annual general meeting of shareholders, are incorporated by reference into Part III of this Form 10-K.
 
TRANSOCEAN INC. AND SUBSIDIARIES
INDEX TO ANNUAL REPORT ON FORM 10-K
FOR THE YEAR ENDED DECEMBER 31, 2004
 
Item   
Page
 
PART I
 
ITEM 1.
3
 
3
 
4
 
9
 
10
 
10
 
10
 
10
 
11
 
11
 
12
ITEM 2.
12
ITEM 3.
12
ITEM 4.
14
 
14
   
 
 
PART II
 
ITEM 5.
16
ITEM 6.
18
ITEM 7.
19
ITEM 7A.
55
ITEM 8.
56
ITEM 9.
107
ITEM 9A.
107
ITEM 9B.
107
   
 
 
PART III
 
ITEM 10.
107
ITEM 11.
107
ITEM 12.
107
ITEM 13.
107
ITEM 14.
107
   
 
 
PART IV
 
ITEM 15.
108
 
 
PART I
ITEM 1. Business 

Transocean Inc. (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 28, 2005, we owned, had partial ownership interests in or operated 93 mobile offshore and barge drilling units. As of this date, our fleet included 32 High-Specification semisubmersibles and drillships (“floaters”), 24 Other Floaters, 26 Jackup Rigs and 11 Other Rigs.

Our mobile offshore drilling fleet is considered one of the most modern and versatile fleets in the world. Our primary business is to contract these drilling rigs, related equipment and work crews primarily on a dayrate basis to drill oil and gas wells. We specialize in technically demanding sectors of the offshore drilling business with a particular focus on deepwater and harsh environment drilling services. We also provide additional services, including integrated services. Our ordinary shares are listed on the New York Stock Exchange under the symbol “RIG.”

The discussion of our business excludes TODCO (together with its subsidiaries and predecessors, unless the context requires otherwise, “TODCO”), a publicly traded company and a former wholly-owned subsidiary in which we now have a 22 percent interest and account for under the equity method of accounting. See “—Background of Transocean.” TODCO’s results of operations are included in our consolidated financial statements until December 17, 2004, when TODCO was deconsolidated. Any discussion of our consolidated financial results through December 16, 2004 includes TODCO.

Transocean Inc. is a Cayman Islands exempted company with principal executive offices in the U.S. located at 4 Greenway Plaza, Houston, Texas 77046. Our telephone number at that address is (713) 232-7500.

Background of Transocean

In June 1993, the Company then known as “Sonat Offshore Drilling Inc.,” completed an initial public offering of approximately 60 percent of the outstanding shares of its common stock as part of its separation from Sonat Inc., and in July 1995 Sonat Inc. sold its remaining 40 percent interest in the Company through a secondary public offering. In September 1996, the Company acquired Transocean ASA, a Norwegian offshore drilling company, and changed its name to “Transocean Offshore Inc.” On May 14, 1999, we completed a corporate reorganization by which we changed our place of incorporation from Delaware to the Cayman Islands.

In December 1999, we completed our merger with Sedco Forex Holdings Limited (“Sedco Forex”), the former offshore contract drilling business of Schlumberger Limited (“Schlumberger”). Effective upon the merger, we changed our name to “Transocean Sedco Forex Inc.” On January 31, 2001, we completed our merger transaction (the “R&B Falcon merger”) with R&B Falcon Corporation (“R&B Falcon”). At the time of the merger, R&B Falcon operated a diverse global drilling rig fleet, consisting of drillships, semisubmersibles, jackup rigs and other units in addition to the Gulf of Mexico Shallow and Inland Water segment fleet. R&B Falcon and the Gulf of Mexico Shallow and Inland Water segment later became known as TODCO and the TODCO segment, respectively. In preparation for the initial public offering discussed below, we transferred all assets and businesses out of R&B Falcon that were unrelated to the Gulf of Mexico Shallow and Inland Water business. In May 2002, we changed our name to “Transocean Inc.”

In February 2004, we completed an initial public offering (the “TODCO IPO”) of common stock of TODCO in which we sold 13.8 million shares of TODCO class A common stock, representing 23 percent of TODCO’s total outstanding shares. In September 2004 and December 2004, respectively, we completed additional public offerings of TODCO common stock (respectively referred to as the “September TODCO Offering” and “December TODCO Offering” and, together with the TODCO IPO, the “TODCO Offerings”). We sold 17.9 million shares of TODCO class A common stock (30 percent of TODCO’s total outstanding shares) in the September TODCO Offering and 15.0 million shares of TODCO class A common stock (25 percent of TODCO’s total outstanding shares) in the December TODCO Offering. Prior to the December TODCO Offering, we held TODCO class B common stock, which was entitled to five votes per share (compared to one vote per share of TODCO class A common stock) and converted automatically into class A common stock upon any sale by us to a third party. In conjunction with the December TODCO Offering, we converted all of our remaining TODCO class B common stock not sold in the TODCO Offerings into shares of class A common stock. After the TODCO Offerings, we hold a 22 percent ownership and voting interest in TODCO, represented by 13.3 million shares of class A common stock.

 
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 sheets. As a result of the conversion of the TODCO class B common stock into class A common stock, we no longer have a majority voting interest in TODCO and no longer consolidate TODCO in our financial statements but account for our remaining investment under the equity method of accounting.

Beginning December 17, 2004, we recorded our 22 percent interest in TODCO’s net income as equity in earnings in our consolidated statement of operations. Our current intention is to dispose of our remaining interest in TODCO, which could be achieved through a number of possible transactions including additional public offerings, open market sales, sales to one or more third parties, a spin-off to our shareholders, split-off offerings to our shareholders that would allow for the opportunity to exchange our ordinary shares for shares of TODCO class A common stock or a combination of these transactions.

For information about the revenues, operating income, assets and other information relating to our business segments and the geographic areas in which we operate, see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Note 21 to our consolidated financial statements included in Item 8 of this report. For information about the risks and uncertainties relating to our business, see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Risk Factors.”

Drilling Fleet

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

Also included in our fleet are barge drilling rigs, tenders, a mobile offshore production unit and a platform drilling rig.

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.

As of February 28, 2005, our fleet of 93 rigs included:
 
 
·
32 High-Specification Floaters, which are comprised of:
-
13 Fifth-Generation Deepwater Floaters;
-
15 Other Deepwater Floaters; and
-
four Other High-Specification Floaters;
 
·
24 Other Floaters;
 
·
26 Jackups; and
 
·
11 Other Rigs, which are comprised of:
-
four barge drilling rigs;
-
four tenders;
-
one platform drilling rig;
-
one mobile offshore production unit; and
-
one coring drillship.

As of February 28, 2005, our fleet was located in the U.S. Gulf of Mexico (13 units), Trinidad (one unit), Canada (one unit), Brazil (nine units), North Europe (17 units), the Mediterranean and Middle East (eight units), the Caspian Sea (one unit), Africa (14 units), India (11 units) and Asia and Australia (18 units).

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

We categorize our fleet as follows: (i) “High-Specification Floaters” consisting of our “Fifth-Generation Deepwater Floaters,” “Other Deepwater Floaters” and “Other High-Specification Floaters,” (ii) “Other Floaters”, (iii) “Jackups,” and (iv) “Other Rigs.” Within our High-Specification Floaters category, we consider our Fifth-Generation Deepwater Floaters to be the semisubmersibles Deepwater Horizon, Cajun Express, Deepwater Nautilus, Sedco Energy and Sedco Express and the drillships Deepwater Discovery, Deepwater Expedition, Deepwater Frontier, Deepwater Millennium, Deepwater Pathfinder, Discoverer Deep Seas, Discoverer Enterprise, and Discoverer Spirit. These rigs were built in the last construction cycle (approximately 1996 - 2001) and have high-pressure mud pumps and a water depth capability of 7,500 feet or greater. The Other Deepwater Floaters are generally those other semisubmersible rigs and drillships that have a water depth capacity of at least 4,500 feet. The Other High-Specification Floaters, built as fourth-generation rigs in the mid to late 1980’s, are capable of drilling in harsh environments and have greater displacement than previously constructed rigs resulting in larger variable load capacity, more useable deck space and better motion characteristics. The Other Floaters category is generally comprised of those non-high-specification floaters with a water depth capacity of less than 4,500 feet. The Jackups category consists of our jackup fleet, and the Other Rigs category consists of other rigs that are of a different type or use. These categories reflect how we view, and how we believe our investors and the industry generally view, our fleet, and reflect our strategic focus on the ownership and operation of premium high-specification floating rigs and jackups.

Drillships are generally self-propelled, shaped like conventional ships and are the most mobile of the major rig types. All of our drillships are dynamically positioned, which allows them to maintain position without anchors through the use of their onboard propulsion and station-keeping systems. Some of our drillships can also be operated in a moored configuration. 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 Enterprise-class drillships are equipped for dual-activity drilling, which is a well-construction technology we developed and patented that allows for drilling tasks associated with a single well to be accomplished in a parallel rather than sequential manner by utilizing two complete drilling systems under a single derrick. The dual-activity well-construction process is designed to reduce critical path activity and improve efficiency in both exploration and development drilling.

Semisubmersibles are floating vessels that can be submerged by means of a water ballast system such that the lower hulls are below the water surface during drilling operations. These rigs 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 for operations in rough water conditions than drillships. Our three Express-class semisubmersibles are equipped with the unique tri-act derrick, which was designed to reduce overall well construction costs and effectively integrate new 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 300 feet or less.

Rigs described in the following tables as “operating” are under contract, including rigs being mobilized under contract. Rigs described as “warm stacked” are not under contract and may require the hiring of additional crew, but are generally ready for service with little or no capital expenditures and are being actively marketed. Rigs described as “cold stacked” are not being actively marketed on short or near term contracts, generally cannot be reactivated upon short notice and normally require the hiring of most of the crew, a maintenance review and possibly significant refurbishment before they can be reactivated. Our cold stacked rigs and some of our warm stacked rigs would require additional costs to return to service. The actual cost, which could fluctuate over time, is dependent upon various factors, including the availability and cost of shipyard facilities, cost of equipment and materials and the extent of repairs and maintenance that may ultimately be required. For some of these rigs, the cost could be significant. We would take these factors into consideration together with market conditions, length of contract and dayrate and other contract terms in deciding whether to return a particular idle rig to service. We may consider marketing some of our cold stacked rigs for alternative uses, including as accommodation units, from time to time until drilling activity increases and we obtain drilling contracts for these units.
 
-5-

 
High-Specification Floaters (32)

The following tables provide certain information regarding our High-Specification fleet as of February 28, 2005:

   
Year
Water
Drilling
     
   
Entered
Depth
Depth
     
   
Service/
Capacity
Capacity
   
Estimated
Name
Type
Upgraded(a)
(in feet)
(in feet)
Location
Customer
Expiration (b)
Fifth-Generation Deepwater Floaters (13)
             
Deepwater Discovery (c)
HSD
2000
10,000
30,000
Ivory Coast
Vanco
March 2005
Deepwater Expedition (c)
HSD
1999
10,000
30,000
Brazil
Petrobras
October 2005
Deepwater Frontier (c)
HSD
1999
10,000
30,000
Brazil
Petrobras
March 2006
Deepwater Millennium (c)
HSD
1999
10,000
30,000
U.S. Gulf
Anadarko
June 2005
         
U.S. Gulf
Anadarko
December 2005
Deepwater Pathfinder (c)
HSD
1998
10,000
30,000
Nigeria
Devon
April 2006
Discoverer Deep Seas (c) (f)
HSD
2001
10,000
35,000
U.S. Gulf
ChevronTexaco
January 2006
         
U.S. Gulf
ChevronTexaco
January 2007
Discoverer Enterprise (c) (f)
HSD
1999
10,000
35,000
U.S. Gulf
BP
December 2007
Discoverer Spirit (c) (f)
HSD
2000
10,000
35,000
U.S. Gulf
Unocal
September 2005
         
U.S. Gulf
Shell
March 2007
Deepwater Horizon (c)
HSS
2001
10,000
30,000
U.S. Gulf
BP
September 2005
Cajun Express (c) (g)
HSS
2001
8,500
35,000
U.S. Gulf
Dominion
May 2005
         
U.S. Gulf
ChevronTexaco
June 2007
Deepwater Nautilus (d)
HSS
2000
8,000
30,000
U.S. Gulf
Shell
September 2005
         
U.S. Gulf
Shell
September 2006
Sedco Energy (c) (g)
HSS
2001
7,500
25,000
Nigeria
ChevronTexaco
March 2005
Sedco Express (c) (g)
HSS
2001
7,500
25,000
Brazil
-
Shipyard
         
Angola
BP
May 2008
Other Deepwater Floaters (15)
             
Deepwater Navigator (c)
HSD
2000
7,200
25,000
Brazil
Petrobras
March 2005
Discoverer 534 (c)
HSD
1975/1991
7,000
25,000
India
Reliance
March 2005
Discoverer Seven Seas (c)
HSD
1976/1997
7,000
25,000
India
ONGC
February 2007
Transocean Marianas
HSS
1979/1998
7,000
25,000
U.S. Gulf
Murphy
April 2005
         
U.S. Gulf
BP
November 2005
Sedco 707 (c)
HSS
1976/1997
6,500
25,000
Brazil
Petrobras
November 2005
Jack Bates
HSS
1986/1997
5,400
30,000
Australia
Woodside
September 2005
Peregrine I (c)
HSD
1982/1996
5,200
25,000
Brazil
Cold stacked
-
Sedco 709 (c)
HSS
1977/1999
5,000
25,000
Ivory Coast
CNR
April 2005
M. G. Hulme, Jr. (e)
HSS
1983/1996
5,000
25,000
Nigeria
Warm stacked
-
Transocean Richardson
HSS
1988
5,000
25,000
Ivory Coast
CNR
December 2005
Jim Cunningham
HSS
1982/1995
4,600
25,000
Egypt
BG
August 2005
Transocean Leader
HSS
1987/1997
4,500
25,000
Norway
Statoil
February 2006
Transocean Rather
HSS
1988
4,500
25,000
U.K. North Sea
BP
October 2005
         
U.K. North Sea
BP
December 2005
         
U.K. North Sea
BP
February 2006
Sovereign Explorer
HSS
1984
4,500
25,000
Venezuela
Statoil
March 2005
         
Trinidad
BG
August 2005
Sedco 710 (c)
HSS
1983/2001
4,500
25,000
Brazil
Petrobras
October 2006
             
Other High-Specification Floaters (4)
           
Henry Goodrich
HSS
1985
2,000
30,000
Canada
Terra Nova
August 2005
Paul B. Loyd, Jr.
HSS
1990
2,000
25,000
U.K. North Sea
BP
March 2005
         
U.K. North Sea
BP
March 2007
Transocean Arctic
HSS
1986
1,650
25,000
Norwegian N. Sea
Statoil
March 2006
Polar Pioneer
HSS
1985
1,500
25,000
Norwegian N. Sea
Statoil
July 2006
 
    
_______________________________________
“HSD” means high-specification drillship.
“HSS” means high-specification semisubmersible.

(a)
Dates shown are the original service date and the date of the most recent upgrade, if any.
(b)
Expiration dates represent our current estimate of the earliest date the contract for each rig is likely to expire. Some rigs have two or more contracts in continuation, so the last line shows the last expected termination date. Some contracts may permit the client to extend the contract.
(c)
Dynamically positioned.
(d)
The Deepwater Nautilus is leased from its owner, an unrelated third party, pursuant to a fully defeased lease arrangement.
(e)
The M. G. Hulme, Jr. is leased from its owner, an unrelated third party, under an operating lease as a result of a sale/leaseback transaction in November 1995. We have exercised the purchase option to reacquire the rig in the fourth quarter of 2005 (see “―Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations―Acquisitions and Dispositions”).
(f)
Enterprise-class rig.
(g)
Express-class rig.

Other Floaters (24)

The following table provides certain information regarding our Other Floater drilling rigs as of February 28, 2005:

   
Year
Water
Drilling
     
   
Entered
Depth
Depth
     
   
Service/
Capacity
Capacity
   
Estimated
Name
Type
Upgraded(a)
(in feet)
(in feet)
Location
Customer
Expiration (b)
Peregrine III (c)
OD
1976
4,200
25,000
U.S. Gulf
Cold stacked
-
Sedco 700
OS
1973/1997
3,600
25,000
Equatorial Guinea
Amerada Hess
January 2006
Transocean Amirante
OS
1978/1997
3,500
25,000
U.S. Gulf
ENI
August 2005
         
U.S. Gulf
Remington
February 2006
Transocean Legend
OS
1983
3,500
25,000
Enroute to Singapore
Warm stacked
-
C. Kirk Rhein, Jr.
OS
1976/1997
3,300
25,000
U.S. Gulf
Cold stacked
-
Transocean Driller
OS
1991
3,000
25,000
Brazil
Petrobras
July 2006
Falcon 100
OS
1974/1999
2,400
25,000
U.S. Gulf
LLOG
July 2005
         
U.S. Gulf
LLOG
January 2006
Sedco 703
OS
1973/1995
2,000
25,000
Australia
ENI
March 2005
         
Australia
OMV
May 2005
Sedco 711
OS
1982
1,800
25,000
U.K. North Sea
Shell
December 2005
Transocean John Shaw
OS
1982
1,800
25,000
U.K. North Sea
Nexen
May 2005
         
U.K. North Sea
KerrMcGee
August 2005
Sedco 714
OS
1983/1997
1,600
25,000
U.K. North Sea
BG
March 2005
         
U.K. North Sea
BG
April 2005
         
U.K. North Sea
BG
May 2005
         
U.K. North Sea
ADTI
August 2005
Sedco 712
OS
1983
1,600
25,000
U.K. North Sea
Oilexco
March 2006
Actinia
OS
1982
1,500
25,000
India
Reliance
August 2005
Sedco 601
OS
1983
1,500
25,000
Indonesia
Santos
March 2005
         
Indonesia
Santos
April 2005
         
Indonesia
Santos
June 2005
         
Indonesia
Santos
July 2005
Sedco 702
OS
1973/1992
1,500
25,000
Australia
Cold stacked
-
Sedneth 701
OS
1972/1993
1,500
25,000
Angola
ChevronTexaco
March 2005
Transocean Prospect
OS
1983/1992
1,500
25,000
U.K. North Sea
Cold stacked
-
Transocean Searcher
OS
1983/1988
1,500
25,000
Norwegian N. Sea
Statoil
May 2005
Transocean Winner
OS
1983
1,500
25,000
Norwegian N. Sea
Cold stacked
-
Transocean Wildcat
OS
1977/1985
1,300
25,000
U.K. North Sea
Cold stacked
-
Transocean Explorer
OS
1976
1,250
25,000
U.K. North Sea
Cold stacked
-
J. W. McLean
OS
1974/1996
1,250
25,000
U.K. North Sea
ConocoPhillips
August 2005
Sedco 704
OS
1974/1993
1,000
25,000
U.K. North Sea
Venture
March 2005
         
U.K. North Sea
Venture
June 2006
Sedco 706
OS
1976/1994
1,000
25,000
U.K. North Sea
Total
September 2005
 
 
_______________________________________
“OD” means other drillship.
“OS” means other semisubmersible.

(a)
Dates shown are the original service date and the date of the most recent upgrade, if any.
(b)
Expiration dates represent our current estimate of the earliest date the contract for each rig is likely to expire. Some rigs have two or more contracts in continuation, so the last line shows the last expected termination date. Some contracts may permit the client to extend the contract.
(c)
Dynamically positioned.

Jackup Rigs (26)

The following table provides certain information regarding our Jackup Rig fleet as of February 28, 2005:

 
Year Entered
Water
Depth
Drilling
Depth
     
 
Service/
Capacity
Capacity
   
Estimated
Name
Upgraded(a)
(in feet)
(in feet)
Location
Customer
Expiration (b)
Trident IX
1982
400
21,000
Vietnam
JVPC
September 2005
       
Vietnam
JVPC
September 2006
Trident 17
1983
355
25,000
Vietnam
Petronas Carigali
April 2006
Trident 20
2000
350
25,000
Caspian Sea
Petronas Carigali
July 2005
Harvey H. Ward
1981
300
25,000
Malaysia
Talisman
July 2005
J. T. Angel
1982
300
25,000
Indonesia
BP
October 2005
Roger W. Mowell
1982
300
25,000
Malaysia
Talisman
November 2005
Ron Tappmeyer
1978
300
25,000
India
ONGC
November 2006
D. R. Stewart
1980
300
25,000
Italy
ENI
March 2005
       
Italy
ENI
March 2006
Randolph Yost
1979
300
25,000
India
ONGC
November 2006
C. E. Thornton
1974
300
25,000
India
ONGC
October 2007
F. G. McClintock
1975
300
25,000
India
ONGC
December 2007
Shelf Explorer
1982
300
25,000
Indonesia
Kodeco
July 2005
Transocean III
1978/1993
300
20,000
Egypt
Zeitco
July 2005
Transocean Nordic
1984
300
25,000
India
Reliance
March 2005
       
India
ONGC
April 2007
Trident II
1977/1985
300
25,000
India
ONGC
May 2006
Trident IV-A
1980/1999
300
25,000
Egypt
IEOC
March 2005
       
Italy
ENI
July 2005
Trident VIII
1981
300
21,000
Nigeria
Conoil
August 2005
       
Nigeria
Conoil
January 2008
Trident XII
1982/1992
300
25,000
India
ONGC
November 2006
Trident XIV
1982/1994
300
20,000
Angola
ChevronTexaco
April 2005
Trident 15
1982
300
25,000
Thailand
Unocal
February 2006
Trident 16
1982
300
25,000
Thailand
ChevronTexaco
April 2005
George H. Galloway
1984
300
25,000
Italy
ENI
July 2005
Transocean Comet
1980
250
20,000
Egypt
GUPCO
October 2005
Transocean Mercury
1969/1998
250
20,000
Egypt
Geisum
May 2005
Trident VI
1981
220
21,000
India
Reliance
March 2005
       
Vietnam
VSP
March 2006
Transocean Jupiter
1981/1997
170
16,000
United Arab Emirates
Cold stacked
-
 
 
______________________________
 
(a)
Dates shown are the original service date and the date of the most recent upgrade, if any.
 
(b)
Expiration dates represent our current estimate of the earliest date the contract for each rig is likely to expire. Some rigs have two or more contracts in continuation, so the last line shows the last expected termination date. Some contracts may permit the client to extend the contract.

Other Rigs

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

Markets

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

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

The deepwater and mid-water market sectors are serviced by our semisubmersibles and drillships. While the use of the term “deepwater” as used in the drilling industry to denote a particular 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 10,000 feet. We view the mid-water market sector as that which covers water depths of about 300 feet to approximately 4,500 feet.

The global shallow water market sector begins at the outer limit of the transition zone and extends to water depths of about 300 feet. We service this sector with our jackups and drilling tenders. 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, shallow bay and coastal water areas. We operate in this sector using our drilling barges located in West Africa and Southeast Asia.
 
 
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,
 
   
2004
 
2003
 
2002
 
Operating Revenues
             
United States
 
$
856
 
$
753
 
$
753
 
Brazil
   
278
   
317
   
283
 
India
   
271
   
120
   
101
 
United Kingdom
   
209
   
212
   
346
 
Other Countries (a)
   
1,000
   
1,032
   
1,191
 
Total Operating Revenues
 
$
2,614
 
$
2,434
 
$
2,674
 

   
As of December 31,
 
   
2004
 
2003
 
Long-Lived Assets
         
United States
 
$
2,397
 
$
3,209
 
Brazil
   
865
   
1,277
 
Nigeria
   
811
   
439
 
Other Countries (a)
   
2,932
   
3,085
 
Total Long-Lived Assets
 
$
7,005
 
$
8,010
 
______________________
(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.

Integrated Services

From time to time, we provide well services in addition to our normal drilling services through third party contractors. We refer to these other services as integrated services. The work generally consists of individual contractual agreements to meet specific client needs and may be provided on either a dayrate or fixed price basis depending on the daily activity. As of March 1, 2005, we were performing such services in the North Sea and India. These integrated service revenues did not represent a material portion of our revenues for any period presented.

Drilling Contracts

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

A dayrate drilling contract generally extends over a period of time covering either the drilling of a single well or group of wells or covering a stated term. These contracts typically can be terminated by the client under various circumstances such as the loss or destruction of the drilling unit or the suspension of drilling operations for a specified period of time as a result of a breakdown of major equipment. The contract term in some instances may be extended by the client exercising options for the drilling of additional wells or for an additional term, or by exercising a right of first refusal. In reaction to depressed market conditions, our clients may seek renegotiation of firm drilling contracts to reduce their obligations or may seek to suspend or terminate their contracts. Some drilling contracts permit the customer to terminate the contract at the customer's option without paying a termination fee. Suspension of drilling contracts results in the reduction in or loss of dayrate for the period of the suspension. If our customers cancel some of our significant contracts and we are unable to secure new contracts on substantially similar terms, or if contracts are suspended for an extended period of time, it could adversely affect our results of operations.

Significant Clients

During the past five years, we have engaged in offshore drilling for most of the leading international oil companies (or their affiliates), as well as for many government-controlled and independent oil companies. Major clients included BP, Shell, Petrobras, ChevronTexaco and ONGC. Our largest unaffiliated clients in 2004 were BP, Petrobras and ChevronTexaco, with each accounting for approximately 10 percent of our 2004 operating revenues. No other unaffiliated client accounted for 10 percent or more of our 2004 operating revenues. The loss of any of these significant clients could, at least in the short term, have a material adverse effect on our results of operations.

 
Regulation

Our operations are affected from time to time in varying degrees by governmental laws and regulations. The drilling industry is dependent on demand for services from the oil and gas exploration industry and, accordingly, is affected by changing tax and other laws generally relating to the energy business.

International contract drilling operations are subject to various laws and regulations in countries in which we operate, including laws and regulations relating to the equipping and operation of drilling units, currency conversions and repatriation, oil and gas exploration and development, taxation of offshore earnings and earnings of expatriate personnel and use of local employees and suppliers by foreign contractors. Governments in some foreign countries are active in regulating and controlling the ownership of concessions and companies holding concessions, the exportation of oil and gas and other aspects of the oil and gas industries in their countries. In addition, government action, including initiatives by the Organization of Petroleum Exporting Countries (“OPEC”), may continue to cause oil price volatility. In some areas of the world, this governmental activity has adversely affected the amount of exploration and development work done by major oil companies and may continue to do so.

In the U.S., regulations applicable to our operations include certain regulations controlling the discharge of materials into the environment and requiring the removal and cleanup of materials that may harm the environment or otherwise relating to the protection of the environment.

The U.S. Oil Pollution Act of 1990 (“OPA”) and related regulations impose a variety of requirements on “responsible parties” related to the prevention of oil spills and liability for damages resulting from such spills. Few defenses exist to the liability imposed by OPA, and such liability could be substantial. Failure to comply with ongoing requirements or inadequate cooperation in a spill event could subject a responsible party to civil or criminal enforcement action.

The U.S. Outer Continental Shelf Lands Act authorizes regulations relating to safety and environmental protection applicable to lessees and permittees operating on the outer continental shelf. Included among these are regulations that require the preparation of spill contingency plans and establish air quality standards for certain pollutants, including particulate matter, volatile organic compounds, sulfur dioxide, carbon monoxide and nitrogen oxides. Specific design and operational standards may apply to outer continental shelf vessels, rigs, platforms, vehicles and structures. Violations of environmental related lease conditions or regulations issued pursuant to the U.S. Outer Continental Shelf Lands Act can result in substantial civil and criminal penalties, as well as potential court injunctions curtailing operations and canceling leases. Such enforcement liabilities can result from either governmental or citizen prosecution.

The U.S. Comprehensive Environmental Response Compensation and Liability Act (“CERCLA”), also known as the “Superfund” law, imposes liability without regard to fault or the legality of the original conduct on some classes of persons that are considered to have contributed to the release of a “hazardous substance” into the environment. These persons include the owner or operator of a facility where a release occurred and companies that disposed or arranged for the disposal of the hazardous substances found at a particular site. Persons who are or were responsible for releases of hazardous substances under CERCLA may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources. It is not uncommon for third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.

Certain of the other countries in whose waters we are presently operating or may operate in the future have regulations covering the discharge of oil and other contaminants in connection with drilling operations.

Although significant capital expenditures may be required to comply with these governmental laws and regulations, such compliance to date has not materially adversely affected our earnings or competitive position.

Employees

We require highly skilled personnel to operate our drilling units. As a result, we conduct extensive personnel recruiting, training and safety programs. At January 31, 2005, we had approximately 8,600 employees and we also utilized approximately 2,200 persons through contract labor providers. As of such date, approximately 15 percent of our employees and contract labor worldwide worked under collective bargaining agreements, most of whom worked in Norway, U.K. and Nigeria. Of these represented individuals, 100 percent are working under agreements that are subject to salary negotiation in 2005. These negotiations could result in higher personnel expenses, other increased costs or increased operating restrictions.

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

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

·   Corporate Governance Guidelines;
 
·   Audit Committee Charter;
 
·   Corporate Governance Committee Charter;
 
·   Executive Compensation Committee Charter;
 
·   Finance and Benefits Committee Charter; and
 
·   Code of Ethics.
 
We intend to satisfy the requirement under Item 5.05 of Form 8-K to disclose any amendments to our Code of Ethics and any waiver from a provision of our Code of Ethics by posting such information in the Corporate Governance section of our website at www.deepwater.com.

ITEM 2. Properties 

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

We maintain offices, land bases and other facilities worldwide, including our principal executive offices in Houston, Texas and regional operational offices in the U.S., France and Singapore. Our remaining offices and bases are located in various countries in North America, South America, the Caribbean, Europe, Africa, the Middle East, India and Asia. We lease most of these facilities.

ITEM 3. Legal Proceedings 

Several of our subsidiaries have been named, along with other defendants, in several complaints that have been filed in the Circuit Courts of the State of Mississippi involving over 700 persons that allege 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 name as defendants certain of TODCO's subsidiaries to whom we may owe indemnity and other unaffiliated defendant companies, including companies that allegedly manufactured drilling related products containing asbestos that are the subject of the complaints. The number of unaffiliated defendant companies involved in each complaint ranges from approximately 20 to 70. The complaints allege that the defendant drilling contractors used those asbestos-containing products in offshore drilling operations, land based drilling operations and in drilling structures, drilling rigs, vessels and other equipment and assert claims based on, among other things, negligence and strict liability, and claims authorized under the Jones Act. The plaintiffs seek, among other things, awards of unspecified compensatory and punitive damages. Based on a recent decision of the Mississippi Supreme Court, we anticipate that the trial courts may grant motions requiring each plaintiff to name the specific defendant or defendants against whom such plaintiff makes a claim and the time period and location of asbestos exposure so that the cases may be properly severed. We have not yet had an opportunity to conduct any discovery nor have we been able to determine the number of plaintiffs, if any, that were employed by our subsidiaries or otherwise have any connection with our drilling operations. We intend to defend ourselves vigorously and, based on the limited information available to us at this time, we do not expect the liability, if any, resulting from these actions to have a material adverse effect on our current consolidated financial position, results of operations and cash flows.

In 1990 and 1991, two of our subsidiaries were served with various assessments collectively valued at approximately $6.8 million from the municipality of Rio de Janeiro, Brazil to collect a municipal tax on services. We believe that neither subsidiary is liable for the taxes and have contested the assessments in the Brazilian administrative and court systems. We have received several adverse rulings by various courts with respect to a June 1991 assessment, which is valued at approximately $5.9 million. We are continuing to challenge the assessment, however, and have an action to stay execution of a related tax foreclosure proceeding. We have received a favorable ruling in connection with a disputed August 1990 assessment but the government has appealed that ruling. We also are awaiting a ruling from the Taxpayer's Council in connection with an October 1990 assessment. If our defenses are ultimately unsuccessful, we believe that the Brazilian government-controlled oil company, Petrobras, has a contractual obligation to reimburse us for municipal tax payments required to be paid by them. We do not expect the liability, if any, resulting from these assessments to have a material adverse effect on our current consolidated financial position, results of operations and cash flows.

  
The Indian Customs Department, Mumbai, filed a "show cause notice" against one of our subsidiaries and various third parties in July 1999. The show cause notice alleged that the initial entry into India in 1988 and other subsequent movements of the Trident II jackup rig operated by the subsidiary constituted imports and exports for which proper customs procedures were not followed and sought payment of customs duties of approximately $31 million based on an alleged 1998 rig value of $49 million, plus interest and penalties, and confiscation of the rig. In January 2000, the Customs Department issued its order, which found that we had imported the rig improperly and intentionally concealed the import from the authorities, and directed us to pay a redemption fee of approximately $3 million for the rig in lieu of confiscation and to pay penalties of approximately $1 million in addition to the amount of customs duties owed. In February 2000, we filed an appeal with the Customs, Excise and Gold (Control) Appellate Tribunal ("CEGAT") together with an application to have the confiscation of the rig stayed pending the outcome of the appeal. In March 2000, the CEGAT ruled on the stay application, directing that the confiscation be stayed pending the appeal. The CEGAT issued its order on our appeal on February 2, 2001, and while it found that the rig was imported in 1988 without proper documentation or payment of duties, the redemption fee and penalties were reduced to less than $0.1 million in view of the ambiguity surrounding the import practice at the time and the lack of intentional concealment by us. The CEGAT further sustained our position regarding the value of the rig at the time of import as $13 million and ruled that subsequent movements of the rig were not liable to import documentation or duties in view of the prevailing practice of the Customs Department, thus limiting our exposure as to custom duties to approximately $6 million. Although CEGAT did not grant us the benefit of a customs duty exemption due to the absence of required documentation, CEGAT left it open for our subsidiary to seek such documentation from the Ministry of Petroleum. Following the CEGAT order, we tendered payment of redemption, penalty and duty in the amount specified by the order by offset against a $0.6 million deposit and $10.7 million guarantee previously made by us. The Customs Department attempted to draw the entire guarantee, alleging the actual duty payable is approximately $22 million based on an interpretation of the CEGAT order that we believe is incorrect. This action was stopped by an interim ruling of the High Court, Mumbai on writ petition filed by us. We and the Customs Department both filed appeals with the Supreme Court of India against the order of the CEGAT, and both appeals were admitted. The Supreme Court has recently dismissed the Customs Department appeal and affirmed the CEGAT order but the Customs Department has not agreed with our interpretation of that order. We and our customer agreed to pursue and obtained the issuance of the required documentation from the Ministry of Petroleum that, if accepted by the Customs Department, would reduce the duty to nil. The Customs Department did not accept the documentation or agree to refund the duties already paid. We are pursuing our remedies against the Customs Department and our customer. We do not expect the liability, if any, resulting from this matter to have a material adverse effect on our current consolidated financial position, results of operations and cash flows.

In October 2001, TODCO was notified by the U.S. Environmental Protection Agency ("EPA") that the EPA had identified a subsidiary as a potentially responsible party in connection with the Palmer Barge Line superfund site located in Port Arthur, Texas. Based upon the information provided by the EPA and a review of TODCO's internal records to date, TODCO disputes its designation as a potentially responsible party. Pursuant to the master separation agreement with TODCO, we are responsible and will indemnify TODCO for any losses TODCO incurs in connection with this action. We do not expect the liability, if any, resulting from this matter to have a material adverse effect on our current consolidated financial position, results of operations and cash flows.

In August 2003, a judgment of approximately $9.5 million was entered by the Labor Division of the Provincial Court of Luanda, Angola, against us and one of our labor contractors, Hull Blyth, in favor of certain former workers on several of our drilling rigs. The workers were employed by Hull Blyth to work on several drilling rigs while the rigs were located in Angola. When the drilling contracts concluded and the rigs left Angola, the workers' employment ended. The workers brought suit claiming that they were not properly compensated when their employment ended. In addition to the monetary judgment, the Labor Division ordered the workers to be hired by us. We believe that this judgment is without sufficient legal foundation and have appealed the matter to the Angola Supreme Court. We further believe that Hull Blyth has an obligation to protect us from any judgment. We do not expect the liability, if any, resulting from this matter to have a material adverse effect on our current consolidated financial position, results of operations and cash flows.

One of our subsidiaries is involved in an action with respect to customs penalties relating to the semisubmersible drilling rig Sedco 710. Prior to the Sedco Forex merger, 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 was moved to an entity that would become one 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 import permit and sought a penalty and assessment against the Schlumberger entity. 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 to our entity but has not ruled that the temporary admission could be extended without the payment of a financial penalty. During the first quarter of 2004, the customs office renewed its efforts to collect a penalty and issued a second assessment for this penalty but has now done so against our subsidiary. The assessment is for approximately $61 million. We believe that the amount of the assessment, even if it were appropriate, should only be approximately $6 million and should in any event be assessed against the Schlumberger entity. We and Schlumberger are contesting our respective assessments. We have put Schlumberger on notice that we consider any assessment to be the responsibility of Schlumberger. We do not expect the liability, if any, resulting from this matter to have a material adverse effect on our current consolidated financial position, results of operations and 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."  We are also involved in a number of other lawsuits, all of which have arisen in the ordinary course of our business. We do not expect the liability, if any, resulting from these other lawsuits to have a material adverse effect on our current consolidated financial position, results of operations and 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.

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

The Company did not submit any matter to a vote of its security holders during the fourth quarter of 2004.

Executive Officers of the Registrant

   
Age as of
Officer
Office
March 1, 2005
Robert L. Long
President and Chief Executive Officer
59
Jean P. Cahuzac
Executive Vice President and Chief Operating Officer
51
Eric B. Brown
Senior Vice President, General Counsel and Corporate Secretary
53
Gregory L. Cauthen
Senior Vice President and Chief Financial Officer
47
Steven L. Newman
Senior Vice President, Human Resources, Information Process Solutions and Treasury
40
David A. Tonnel
Vice President and Controller
35

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

Jean P. Cahuzac is Executive Vice President and Chief Operating Officer of the Company. Mr. Cahuzac served as Executive Vice President, Operations of the Company from February 2001 until October 2002, at which time he assumed his current position. Mr. Cahuzac served as President of Sedco Forex from January 1999 until the time of the Sedco Forex merger, at which time he assumed the positions of Executive Vice President and President, Europe, Middle East and Africa with the Company. Mr. Cahuzac served as Vice President-Operations Manager of Sedco Forex from May 1998 to January 1999, Region Manager-Europe, Africa and CIS of Sedco Forex from September 1994 to May 1998 and Vice President/General Manager-North Sea Region of Sedco Forex from February 1994 to September 1994. He had been employed by Schlumberger since 1979.

Eric B. Brown is Senior Vice President, General Counsel and Corporate Secretary of the Company. Mr. Brown served as Vice President and General Counsel of the Company since February 1995 and Corporate Secretary of the Company since September 1995. He assumed the position of Senior Vice President in February 2001. Prior to assuming his duties with the Company, Mr. Brown served as General Counsel of Coastal Gas Marketing Company.

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

Steven L. Newman is Senior Vice President of Human Resources, Information Process Solutions and Treasury. Mr. Newman served as Vice President of Performance and Technology of the Company from August 2003 until March 2005, at which time he assumed his current position. Mr. Newman served as Regional Manager, Asia Australia from May 2001 until August 2003. From December 2000 to May 2001, Mr. Newman served as Region Operations Manager of the Africa-Mediterranean Region of the Company. From April 1999 to December 2000, Mr. Newman served in various operational and marketing roles in the Africa-Mediterranean and U.K. region offices. Mr. Newman has been employed by the Company since 1994.

David A. Tonnel is Vice President and Controller of the Company. Mr. Tonnel served as Assistant Controller of the Company from May 2003 to February 2005, at which time he assumed his current position. Mr. Tonnel served as Finance Manager, Asia Australia Region from October 2000 to May 2003 and as Controller, Nigeria from April 1999 to October 2000. Mr. Tonnel joined the Company in 1996 after working for Ernst & Young in France as Senior Auditor.

 
PART II

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

Our ordinary shares are listed on the New York Stock Exchange (the “NYSE”) under the symbol “RIG.” The following table sets forth the high and low sales prices of our ordinary shares for the periods indicated as reported on the NYSE Composite Tape.

   
Price
   
High
 
Low
         
2003
First Quarter
$24.36
 
$19.87
 
Second Quarter
  25.90
 
  18.40
 
Third Quarter
  22.43
 
  18.50
 
Fourth Quarter
  24.85
 
  18.49
   
 
   
2004
First Quarter
$31.94
 
$23.10
 
Second Quarter
  29.27
 
  24.49
 
Third Quarter
  36.24
 
  25.94
 
Fourth Quarter
  43.25
 
  33.70
 
On February 28, 2005, the last reported sales price of our ordinary shares on the NYSE Composite Tape was $48.48 per share. On such date, there were 16,312 holders of record of our ordinary shares and 324,073,235 ordinary shares outstanding.

We paid quarterly cash dividends of $0.03 per ordinary share from the fourth quarter of 1993 to the second quarter of 2002. Any future declaration and payment of dividends will (i) depend on our results of operations, financial condition, cash requirements and other relevant factors, (ii) be subject to the discretion of the board of directors, (iii) be subject to restrictions contained in our revolving credit agreement and other debt covenants and (iv) be payable only out of our profits or share premium account in accordance with Cayman Islands law. As we approach our targeted debt levels, we will begin to explore alternative uses for our excess cash, which could include quarterly dividends or an extraordinary dividend, among other possibilities.

There is currently no reciprocal tax treaty between the Cayman Islands and the United States. Under current Cayman Islands law, there is no withholding tax on dividends.

We are a Cayman Islands exempted company. Our authorized share capital is $13,000,000, divided into 800,000,000 ordinary shares, par value $0.01, and 50,000,000 preference shares, par value $0.10, of which shares may be designated and created as shares of any other classes or series of shares with the respective rights and restrictions determined by action of our board of directors. On February 28, 2005, no preference shares were outstanding.

The holders of ordinary shares are entitled to one vote per share other than on the election of directors.

With respect to the election of directors, each holder of ordinary shares entitled to vote at the election has the right to vote, in person or by proxy, the number of shares held by him for as many persons as there are directors to be elected and for whose election that holder has a right to vote. The directors are divided into three classes, with only one class being up for election each year. Directors are elected by a plurality of the votes cast in the election. Cumulative voting for the election of directors is prohibited by our articles of association.

There are no limitations imposed by Cayman Islands law or our articles of association on the right of nonresident shareholders to hold or vote their ordinary shares.

The rights attached to any separate class or series of shares, unless otherwise provided by the terms of the shares of that class or series, may be varied only with the consent in writing of the holders of all of the issued shares of that class or series or by a special resolution passed at a separate general meeting of holders of the shares of that class or series. The necessary quorum for that meeting is the presence of holders of at least a majority of the shares of that class or series. Each holder of shares of the class or series present, in person or by proxy, will have one vote for each share of the class or series of which he is the holder. Outstanding shares will not be deemed to be varied by the creation or issuance of additional shares that rank in any respect prior to or equivalent with those shares.

 
Under Cayman Islands law, some matters, like altering the memorandum or articles of association, changing the name of a company, voluntarily winding up a company or resolving to be registered by way of continuation in a jurisdiction outside the Cayman Islands, require approval of shareholders by a special resolution. A special resolution is a resolution (1) passed by the holders of two-thirds of the shares voted at a general meeting or (2) approved in writing by all shareholders entitled to vote at a general meeting of the company.

The presence of shareholders, in person or by proxy, holding at least a majority of the issued shares generally entitled to vote at a meeting, is a quorum for the transaction of most business. However, different quorums are required in some cases to approve a change in our articles of association.

Our board of directors is authorized, without obtaining any vote or consent of the holders of any class or series of shares unless expressly provided by the terms of issue of that class or series, to provide from time to time for the issuance of classes or series of preference shares and to establish the characteristics of each class or series, including the number of shares, designations, relative voting rights, dividend rights, liquidation and other rights, redemption, repurchase or exchange rights and any other preferences and relative, participating, optional or other rights and limitations not inconsistent with applicable law.

Our articles of association contain provisions that could prevent or delay an acquisition of our company by means of a tender offer, proxy contest or otherwise.

The foregoing description is a summary. This summary is not complete and is subject to the complete text of our memorandum and articles of association. For more information regarding our ordinary shares and our preference shares, see our Current Report on Form 8-K dated May 14, 1999 and our memorandum and articles of association. Our memorandum and articles of association are filed as exhibits to this annual report.

Issuer Purchases of Equity Securities
                 
Period
 
(a) Total
Number
of Shares
Purchased (1)
 
(b) Average
Price
Paid Per
Share
 
(c) Total Number of
Shares Purchased as
Part of Publicly
Announced Plans or
Programs (2)
 
(d) Maximum Number (or
Approximate Dollar
Value) of Shares that May
Yet Be Purchased Under
the Plans or Programs (2)
October 2004
 
 
 
N/A
 
N/A
November 2004
 
 
 
N/A
 
N/A
December 2004
 
45
 
$42.51
 
N/A
 
N/A
Total
 
45
 
$42.51
 
N/A
 
N/A
_________________
(1)
The issuer purchase during the period covered by this report represents 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 to pay withholding taxes due upon vesting of a restricted share award.

(2)
In connection with the vesting of restricted share awards under our Long-Term Incentive Plan, we generally withhold shares to satisfy withholding taxes upon vesting.
 
 
ITEM 6. Selected Financial Data
 
The selected financial data as of December 31, 2004 and 2003 and for each of the three years in the period ended December 31, 2004 has been derived from the audited consolidated financial statements included elsewhere herein. The selected financial data as of December 31, 2002, 2001 and 2000, and for the years ended December 31, 2001 and 2000 has been derived from audited consolidated financial statements not included herein. The following data should be read in conjunction with “Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations” and the audited consolidated financial statements and the notes thereto included under “Item 8. Financial Statements and Supplementary Data.”

On January 31, 2001, we completed a merger transaction with R&B Falcon. As a result of the merger, R&B Falcon became our indirect wholly owned subsidiary. The merger was accounted for as a purchase and we were treated as the accounting acquiror. The balance sheet data as of December 31, 2001 represents the consolidated financial position of the combined company. The statement of operations and other financial data for the year ended December 31, 2001 include eleven months of operating results and cash flows for the merged company.

We consolidated TODCO’s results of operations and financial condition in our consolidated financial statements through December 16, 2004. Immediately following the closing of the December TODCO Offering and in connection with the conversion of our remaining shares of TODCO’s class B common stock to TODCO’s class A common stock, our ownership and voting interest declined to approximately 22 percent. We deconsolidated TODCO effective December 17, 2004 and subsequently accounted for our investment in TODCO under the equity method of accounting.

   
Years ended December 31,
 
   
2004
2003
2002
2001
2000
 
   
(In millions, except per share data)
 
       
Statement of Operations
                     
Operating revenues
 
$
2,614
 
$
2,434
 
$
2,674
 
$
2,820
 
$
1,230
 
Operating income (loss)
   
328
   
240
   
(2,310
)
 
550
   
133
 
Income (loss) before cumulative effect of changes
                               
in accounting principles
   
152
   
18
   
(2,368
)
 
253
   
109
 
Income (loss) before cumulative effect of changes
                               
in accounting principles per share
                               
Basic
 
$
0.47
 
$
0.06
 
$
(7.42
)
$
0.82
 
$
0.52
 
Diluted
 
$
0.47
 
$
0.06
 
$
(7.42
)
$
0.80
 
$
0.51
 
                                 
Balance Sheet Data (at end of period)
                               
Total assets
 
$
10,758
 
$
11,663
 
$
12,665
 
$
17,048
 
$
6,359
 
Total debt
   
2,481
   
3,658
   
4,678
   
5,024
   
1,453
 
Total equity
   
7,393
   
7,193
   
7,141
   
10,910
   
4,004
 
Dividends per share
 
$
 
$
 
$
0.06
 
$
0.12
 
$
0.12
 
                                 
Other Financial Data
                               
Cash provided by operating activities
 
$
604
 
$
525
 
$
939
 
$
560
 
$
196
 
Cash provided by (used in) investing activities
   
549
   
(445
)
 
(45
)
 
(26
)
 
(493
)
Cash provided by (used in) financing activities
   
(1,176
)
 
(820
)
 
(533
)
 
285
   
166
 
Capital expenditures
   
127
   
494
   
141
   
506
   
575
 
Operating margin
   
13
%
 
10
%
 
N/M
   
20
%
 
11
%
_________________________
“N/M” means not meaningful due to loss on impairments of long-lived assets.
 
 
ITEM 7. Management's Discussion and Analysis of Financial Condition and Results of Operations

The following information should be read in conjunction with the information contained in the audited consolidated financial statements and the notes thereto included under “Item 8. Financial Statements and Supplementary Data” elsewhere in this annual report.

Overview 

Transocean Inc. (together with its subsidiaries and predecessors, unless the context requires otherwise, the “Company,” “Transocean,” “we,” “us” or “our”) is a leading international provider of offshore contract drilling services for oil and gas wells. As of February 28, 2005, we owned, had partial ownership interests in or operated 93 mobile offshore and barge drilling units. As of this date, our fleet included 32 High-Specification semisubmersibles and drillships (“floaters”), 24 Other Floaters, 26 Jackup Rigs and 11 Other Rigs.

Our mobile offshore drilling fleet is considered one of the most modern and versatile fleets in the world. Our primary business is to contract these drilling rigs, related equipment and work crews primarily on a dayrate basis to drill oil and gas wells. We specialize in technically demanding segments of the offshore drilling business with a particular focus on deepwater and harsh environment drilling services. We also provide additional services, including integrated services.

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

   
Years ended December 31,
     
   
2004
 
2003
 
Change
 
   
(In millions, except dayrates and percentages)
 
Average dayrate (a)
 
$
71,300
 
$
67,200
 
$
4,100
 
Utilization (b)
   
58
%
 
57
%
 
N/A
 
Statement of Operations (c)
                   
Operating revenue
 
$
2,613.9
 
$
2,434.3
 
$
179.6
 
Operating and maintenance expense
   
1,726.3
   
1,610.4
   
115.9
 
Operating income
   
327.9
   
239.7
   
88.2
 
Net income
   
152.2
   
19.2
   
133.0
 
Balance Sheet Data (at end of period) (c)
                   
Cash
   
451.3
   
474.0
   
(22.7
)
Total Assets
   
10,758.3
   
11,662.6
   
(904.3
)
Total Debt
   
2,481.5
   
3,658.1
   
(1,176.6
)
______________________
“N/A” means not applicable.

(a)
Average dayrate 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)
Utilization is the total actual number of revenue earning days as a percentage of the total number of calendar days in the period.
(c)
We consolidated TODCO’s (together with its subsidiaries and predecessors, unless the context requires otherwise, “TODCO,” a publicly traded company and a former wholly-owned subsidiary) results of operations and financial condition in our consolidated financial statements through December 16, 2004. We deconsolidated TODCO effective December 17, 2004 and subsequently accounted for our investment in TODCO under the equity method of accounting. See “―Significant Events.”

We begin 2005 with an improving outlook for our fleet, especially among our 13 Fifth-Generation Deepwater Floaters, where capacity constraints are visible for the next 12 to 24 months. As a result, the prospect for improving utilization and dayrates among our fleet of drillships, semisubmersibles and jackups is encouraging. We expect our industry to experience higher costs in 2005 relative to levels seen in the recent past, due in part to higher personnel costs required to support the increased level of offshore drilling activity, although we anticipate revenue increases to outpace these increased costs.

Our revenue and operating and maintenance expenses for the year ended December 31, 2004 increased from the prior year due to the current year effect of including the operations of the drillships Deepwater Pathfinder and Deepwater Frontier as a result of the 2003 acquisitions of the ownership interests in the Deepwater Drilling L.L.C. (“DD LLC”) and Deepwater Drilling II L.L.C. (“DDII LLC”) joint ventures and the subsequent payoff of the synthetic lease financing arrangements in late December 2003, as well as from increased integrated services provided to our clients in 2004. In 2003, the Discoverer Enterprise riser incident, an electrical fire on the Peregrine I and a labor strike and restructuring of a benefit plan in Nigeria negatively impacted revenues and operating and maintenance expense (see “—Historical 2003 compared to 2002—Significant Events”). In 2004, the Discoverer Enterprise operating and maintenance expense was partially reduced by an insurance settlement related to the riser incident (see “—Significant Events”). Adding to the increase in operating and maintenance expense were repairs resulting from a fire on the jackup rig Trident 20 and a well control incident on the semisubmersible rig Jim Cunningham that occurred in the third quarter of 2004 (see “―Significant Events”), while a well control incident on TODCO’s inland barge Rig 62 and a fire on TODCO’s inland barge Rig 20 negatively impacted operating and maintenance expense in 2003. Revenues were negatively impacted by suspended operations due to the strike in Norway (see “―Significant Events”), the fire on the Trident 20 and the well control incident on the semisubmersible rig Jim Cunningham, all of which occurred during the third quarter of 2004. Our year ended December 31, 2004 financial results included non-cash charges pertaining to losses on retirement of debt partially offset by the recognition of a gain on the sale of a semisubmersible rig. We also recognized gains on the TODCO initial public offering (“TODCO IPO”), a TODCO offering in September 2004 (the “September TODCO Offering”) and a TODCO offering in December 2004 (the “December TODCO Offering" and, together with the TODCO IPO and the September TODCO Offering, the “TODCO Offerings”). These gains were partially offset by a tax valuation allowance adjustment and stock option expense recorded in connection with the TODCO IPO, as well as a non-cash charge related to contingent amounts due from TODCO under the tax sharing agreement between us and TODCO (see “—Significant Events”). Cash decreased during the year ended December 31, 2004 primarily as a result of the early retirements of debt instruments resulting from our continued focus on debt reduction, partially offset by proceeds received from the TODCO Offerings and cash provided by operating activities.

  
Through December 16, 2004, our operations were aggregated into two reportable segments: (i) Transocean Drilling and (ii) TODCO. The Transocean Drilling segment consists of floaters, jackups and other rigs used in support of offshore drilling activities and offshore support services. The TODCO segment consisted of our interest in TODCO, which conducts jackup, drilling barge, land rig, submersible and other operations in the U.S. Gulf of Mexico and inland waters, Mexico, Trinidad and Venezuela. As a result of the deconsolidation of TODCO (see “―Significant Events”), we now operate in one business segment, the Transocean Drilling segment. We provide services with different types of drilling equipment in several geographic regions. The location of our rigs and the allocation of resources to build or upgrade rigs is determined by the activities and needs of our customers.

We categorize our fleet as follows: (i) “High-Specification Floaters” consisting of our “Fifth-Generation Deepwater Floaters,” “Other Deepwater Floaters” and “Other High-Specification Floaters,” (ii) “Other Floaters”, (iii) “Jackups,” and (iv) “Other Rigs.” Within our High-Specification Floaters category, we consider our Fifth-Generation Deepwater Floaters to be the semisubmersibles Deepwater Horizon, Cajun Express, Deepwater Nautilus, Sedco Energy and Sedco Express and the drillships Deepwater Discovery, Deepwater Expedition, Deepwater Frontier, Deepwater Millennium, Deepwater Pathfinder, Discoverer Deep Seas, Discoverer Enterprise, and Discoverer Spirit. These rigs were built in the last construction cycle (approximately 1996 - 2001) and have high-pressure mud pumps and a water depth capability of 7,500 feet or greater. The Other Deepwater Floaters are generally those other semisubmersible rigs and drillships that have a water depth capacity of at least 4,500 feet. The Other High-Specification Floaters, built as fourth-generation rigs in the mid to late 1980’s, are capable of drilling in harsh environments and have greater displacement than previously constructed rigs resulting in larger variable load capacity, more useable deck space and better motion characteristics. The Other Floaters category is generally comprised of those non-high-specification floaters with a water depth capacity of less than 4,500 feet. The Jackups category consists of this segment’s jackup fleet, and the Other Rigs category consists of other rigs that are of a different type or use. These categories reflect how we view, and how we believe our investors and the industry generally view, our fleet, and reflect our strategic focus on the ownership and operation of premium high-specification floating rigs and jackups.

Significant Events

Transocean Drilling Segment

Operational Incidents—In May 2003, we announced that a drilling riser had separated on our deepwater drillship Discoverer Enterprise and that the rig had temporarily suspended drilling operations for our customer. The rig resumed operations in July 2003 and we resolved a disagreement with our customer regarding the incident in early 2004, which had no significant effect on our results of operations. In June 2004, we finalized discussions with our insurers relating to an insurance claim for a portion of our losses stemming from this incident and received an insurance settlement during 2004, the majority of which was received in June 2004, which had a favorable effect on pre-tax earnings of $13.4 million.

In July 2004, members of the OFS, one of three unions representing offshore workers in Norway, called a strike on our semisubmersible units operating in the country. OFS called the strike after it was unable to reach an agreement with the Norwegian Shipowners Association, which represents rig owners in Norway. The strike affected the semisubmersible rigs Polar Pioneer, Transocean Searcher and Transocean Leader. The strike ended in late October 2004 following government intervention, and the Transocean Searcher and Transocean Leader resumed operations in the Norwegian sector of the North Sea in November 2004. The Polar Pioneer commenced operations in December 2004 following the completion of planned survey and upgrade work. Operating income would have been an estimated $9.0 million higher absent the labor strike. See “—Historical 2004 Compared to 2003.”

 
In July 2004, the jackup rig Trident 20 suffered damage resulting from a fire in the rig's engine room while operating offshore Turkmenistan in the Caspian Sea. The rig, which was under a three-well contract, was out of service a majority of the third and fourth quarters and returned to work in December 2004. Total repair, crew and other costs resulted in approximately $12.5 million of additional operating and maintenance expense. Operating income would have been an estimated $26.4 million higher absent the incident. See “—Historical 2004 Compared to 2003.”

In August 2004, the semisubmersible rig Jim Cunningham experienced a well control incident that resulted in a fire while operating offshore Egypt. The rig was out of service all of the fourth quarter and returned to work in February 2005. Repair, crew and other costs totaled approximately $12.0 million of which approximately $7.0 was incurred in 2004. Operating income would have been an estimated $14.4 million higher absent the incident. See “—Historical 2004 Compared to 2003.”

Asset Dispositions—In March 2004, we entered into an agreement to sell a semisubmersible rig, the Sedco 600, for net proceeds of approximately $25.0 million. At December 31, 2004, the rig was classified as an asset held for sale and included in other current assets in our consolidated balance sheet. We completed the sale of the rig in January 2005 for net proceeds of $24.9 million and expect to recognize a gain on the sale of $18.8 million in the first quarter of 2005.

In June 2004, we completed the sale of a semisubmersible rig, the Sedco 602, for net proceeds of approximately $28.0 million and recognized a gain of $21.7 million.

TODCO Segment

Delta Towing—As a result of the adoption of the Financial Accounting Standards Board’s (“FASB”) Interpretation (“FIN”) 46 and a determination that TODCO was the primary beneficiary for accounting purposes of TODCO’s joint venture, Delta Towing Holdings, LLC (“Delta Towing”); TODCO consolidated Delta Towing at December 31, 2003. Due to the consolidation of Delta Towing, operating revenue and operating and maintenance expense increased during the twelve months ended December 31, 2004 by $29.3 million and $24.5 million, respectively.

TODCO Offerings and Deconsolidation

In February 2004, we completed the TODCO IPO in which we sold 13.8 million shares of TODCO class A common stock representing 23 percent of TODCO’s total outstanding shares, at $12.00 per share. We received net proceeds of $155.7 million from the TODCO IPO and recognized a gain of $39.4 million, which had no tax effect, in the first quarter of 2004, and represented the excess of net proceeds received over the net book value of the TODCO shares sold in the TODCO IPO. TODCO was formerly known as R&B Falcon Corporation (“R&B Falcon”). Before the closing of the TODCO IPO, TODCO transferred to us all assets and businesses unrelated to TODCO’s business. R&B Falcon’s business was previously considerably broader than TODCO’s ongoing business.

As a result of the deconsolidation of TODCO from our other U.S. subsidiaries for U.S. federal income tax purposes in conjunction with the TODCO IPO, we established an initial valuation allowance in the first quarter of 2004 of approximately $31.0 million against the estimated deferred tax assets of TODCO in excess of its deferred tax liabilities, taking into account prudent and feasible tax planning strategies as required by the FASB’s Statement of Financial Accounting Standards (“SFAS”) 109, Accounting for Income Taxes. We adjusted the initial valuation allowance during the year to reflect changes in our estimate of the ultimate amount of TODCO’s deferred tax assets.

In conjunction with the closing of the TODCO IPO, TODCO granted restricted stock and stock options to certain of its employees under its long-term incentive plan and certain of these awards vested at the time of grant. In accordance with the provisions of SFAS 123, Accounting for Stock-Based Compensation, TODCO recognized compensation expense of $5.6 million in the first quarter of 2004 as a result of the immediate vesting of certain awards. TODCO amortized $4.6 million to compensation expense subsequent to the TODCO IPO and prior to our deconsolidation of TODCO from our consolidated financial statements at December 17, 2004. In addition, certain of TODCO’s employees held options that were granted prior to the TODCO IPO to acquire our ordinary shares. In accordance with the employee matters agreement, these options were modified, which resulted in the accelerated vesting of the options and the extension of the term of the options through the original contractual life. In connection with the modification of these options, TODCO recognized $1.5 million additional compensation expense in the first quarter of 2004.

 
In September 2004, we completed the September TODCO Offering, in which we sold 17.9 million shares of TODCO’s class A common stock, representing 30 percent of TODCO’s total outstanding shares, at $15.75 per share. We received net proceeds of $269.9 million from this offering and recognized a gain of $129.4 million, which had no tax effect, in the third quarter of 2004, and represented the excess of net proceeds received over the net book value of the TODCO shares sold in this offering.

In December 2004, we completed the December TODCO Offering in which we sold 15.0 million shares of TODCO’s class A common stock, representing 25 percent of TODCO’s total outstanding shares, at $18.00 per share. We received net proceeds of $258.0 million from this offering and recognized a gain of $140.0 million, which had no tax effect, in the fourth quarter of 2004, which represented the excess of net proceeds received over the net book value of the TODCO shares sold in this offering. In connection with this offering, we converted all of our remaining TODCO class B common stock not sold in this offering into shares of class A common stock. Each share of our TODCO class B common stock had five votes per share compared to one vote per share of the class A common stock. As a result of the conversion, our voting interest in TODCO is proportionate to our ownership interest.

As of December 31, 2004, we held a 22 percent interest in TODCO, represented by 13.3 million shares of class A common stock. 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 reflected as minority interest in our consolidated statements of operations and balance sheets. We deconsolidated TODCO from our consolidated statements of operations and balance sheets effective December 17, 2004 and subsequently accounted for our investment in TODCO under the equity method of accounting. The deconsolidation was reflected in our December 31, 2004 consolidated balance sheet as a reduction to all assets, liabilities and minority interest with the exception of an increase to investments in and advances to unconsolidated subsidiaries. The following table reflects the increase (decrease) in each line item of our balance sheet at December 17, 2004 that resulted from the deconsolidation of TODCO (in millions):

Assets
         
Liabilities and Equity
       
Cash and cash equivalents (a)
 
$
(68.6
)
 
Accounts payable
 
$
(20.3
)
Accounts receivable, trade
   
(67.3
)
 
Accrued income taxes
   
(14.9
)
Materials and supplies, net
   
(4.1
)
 
Debt due within one year
   
(8.2
)
Deferred incomes taxes, net
   
(5.4
)
 
Other current liabilities
   
(38.0
)
Other current assets
   
(3.0
)
 
Total current liabilities
   
(81.4
)
Total current assets
   
(148.4
)
           
 
         
Long-term debt
   
(15.2
)
Property and equipment
   
(921.0
)
 
Deferred income taxes, net
   
(164.6
)
Less accumulated depreciation
   
(350.2
)
 
Other long-term liabilities
   
4.4
 
Property and equipment, net
   
(570.8
)
 
Total long-term liabilities
   
(175.4
)
Investment in and advances to unconsolidated subsidiaries
   
105.0
   
 
       
Other assets
   
(23.8
)
 
Minority interest
   
(381.2
)
Total assets
 
$
(638.0
)
 
Total liabilities and minority interest
 
$
(638.0
)
__________________________
(a) Included in net cash flows provided by (used in) investing activities in our consolidated statements of cash flows.

Our current intention is to dispose of our remaining interest in TODCO, which could be achieved through a number of possible transactions including additional public offerings, open market sales, sales to one or more third parties, a spin-off to our shareholders, split-off offerings to our shareholders that would allow for the opportunity to exchange our ordinary shares for shares of TODCO class A common stock or a combination of these transactions.

TODCO Tax Sharing Agreement Charge

Under the tax sharing agreement entered into between us and TODCO in connection with the TODCO IPO, we are entitled to receive from TODCO payment for most of the tax benefits generated prior to the TODCO IPO that TODCO utilizes subsequent to the TODCO IPO. As long as TODCO was our consolidated subsidiary, we followed the provisions of SFAS 109, which allowed us to evaluate the recoverability of the deferred tax assets associated with the tax sharing agreement considering the deferred tax liabilities of TODCO. We recorded a valuation allowance for the excess of these deferred tax assets over the deferred tax liabilities of TODCO, also taking into account prudent and feasible tax planning strategies as required by SFAS 109. Because we no longer own a majority voting interest in TODCO, we no longer include TODCO as a consolidated subsidiary in our financial statements and we are no longer able to apply the provisions of SFAS 109 in accounting for the utilization of these deferred tax assets. As a result, we recorded a non-cash charge of $167.1 million, which had no tax effect, in the fourth quarter of 2004 related to contingent amounts due from TODCO under the tax sharing agreement. In future years, as TODCO generates income and utilizes its pre-TODCO IPO tax assets, TODCO is required to pay us for the benefits received in accordance with the provisions of the tax sharing agreement. We will recognize those amounts as other income as those amounts are realized, which is based on when TODCO files its annual tax returns.

 
Debt Redemptions and Repurchases

In March 2004, we completed the redemption of our $289.8 million aggregate principal amount outstanding 9.5% Senior Notes due December 2008 at the make-whole premium price provided in the indenture. We redeemed these notes at 127.796 percent of face value or $370.3 million, plus accrued and unpaid interest. We recognized a loss on the redemption of debt of $28.1 million, which had no tax effect, and reflected adjustments for fair value of the debt at the date of the merger with R&B Falcon and the unamortized fair value adjustment on a previously terminated interest rate swap. We funded the redemption with existing cash balances, which included proceeds from the TODCO IPO.

In October 2004, we redeemed our $342.3 million aggregate principal amount outstanding 6.75% Senior Notes due April 2005 at the make-whole premium price provided in the indenture. We redeemed these notes at 102.127 percent of face value or $349.5 million, plus accrued and unpaid interest. We recognized a loss on the redemption of $3.3 million, which had no tax effect, and reflected adjustments for fair value of the debt at the date of the R&B Falcon merger and the unamortized fair value adjustment on a previously terminated interest rate swap. We funded the redemption with existing cash on hand, which included proceeds from the September TODCO Offering.

In December 2004, we acquired, pursuant to a tender offer, a total of $142.7 million, or 71.3 percent, aggregate principal amount of our 8% Debentures due April 2027 at 130.449 percent of face value, or $186.1 million, plus accrued and unpaid interest. We recognized a loss on the repurchase of $45.1 million, which had no tax effect. We funded the repurchase with existing cash balances.

In December 2004, the previously discussed deconsolidation of TODCO resulted in the elimination from our consolidated balance sheets of TODCO’s 6.75% Senior Notes due April 2005, 6.95% Senior Notes due April 2008, 9.5% Senior Notes due December 2008 and 7.375% Senior Notes due April 2018, which had an aggregate principal amount outstanding of $7.7 million, $2.2 million, $10.2 million and $3.5 million, respectively.

In February 2005, we called our $247.8 million aggregate principal amount outstanding 6.95% Senior Notes due April 2008 at the make-whole premium price provided in the indenture. We expect to redeem these notes at 109.92 percent of face value or $272.4 million, plus accrued and unpaid interest. The redemption is expected to be completed by March 21, 2005. We expect to recognize a loss on the redemption of approximately $10.8 million, which reflects adjustments for fair value of the debt at the date of the R&B Falcon merger and the unamortized fair value adjustment on a previously terminated interest rate swap. We plan to fund the redemption with existing cash on hand.

Outlook

Drilling Market—Oil prices have remained strong, and, although a decline from current levels could occur, we expect prices to remain relatively high in historical terms. Future price expectations have historically been a key driver for offshore drilling demand. However, the availability of quality drilling prospects, exploration success, relative production costs, the stage of reservoir development and political and regulatory environments also affect our customers’ drilling programs.

Prospects for our 32 High-Specification Floaters continue to improve, with new and expected contracts resulting in declining rig availability among this fleet during 2005. We are increasingly confident that most of the available time in 2005 will be contracted, although some intermittent idle time remains a possibility, especially for some of the Other Deepwater Floaters in this fleet. We have signed a number of new contracts or extensions for our High-Specification Floaters that reflect the increased activity in this sector. Recent awards during the last part of 2004 and early 2005 include a 12 month program for the Transocean Rather in the North Sea, with the rig relocating from West Africa, a 240 day program for the Transocean Marianas in the Gulf of Mexico as well as a number of short-term contracts on the Deepwater Millennium, Discoverer 534, Deepwater Discovery and Sedco Energy. In addition, we entered into contracts for the Discoverer Spirit and Deepwater Nautilus in February 2005 for 18 month and 12 month programs, respectively, to begin at the conclusion of their current contracts in approximately September 2005. Rates have been generally trending higher, especially for the highest specification rigs. We continue to believe that, over the long-term, deepwater exploration and development drilling opportunities in the Gulf of Mexico, West Africa, India and other market sectors represent a significant source of future deepwater rig demand, although the risk of project delays remains, especially in West Africa. We continue to see a strong customer preference for using fifth-generation equipment in these deepwater areas, which may lead to a near term shortage of these highest specification rigs.

 
The outlook for activity for the non-U.S. jackup market sector is expected to remain strong, particularly in Asia and the Middle East. We expect to remain at or near full utilization for our Jackups in the near term, and at the present time we do not anticipate any inter-regional relocations of these units.

The outlook for our Other Floaters that operate in the mid-water sector has improved substantially from the global oversupply position that existed throughout most of 2004. We expect overall North Sea industry activity to remain well above 2004 levels, with resulting improvements in utilization and dayrates in 2005. Demand in the Gulf of Mexico market sector also rose in late 2004, which has caused us to reactivate or commence active marketing efforts for some of our cold-stacked units in this fleet.

The Transocean Legend is being relocated to Singapore from Brazil for shipyard work in advance of a long-term program. Likewise, we plan to relocate the Sedco Express to Angola from Brazil upon completion of its shipyard work to commence a long-term drilling program. In addition to these mobilizations and contract preparation shipyard periods, we expect downtime during the first and second quarters of 2005 to result from planned shipyard projects for the Sedco 706, Transocean Rather, Searex 10, Trident 15, Trident 16 and Deepwater Navigator. The Jim Cunningham returned to work in February 2005 after undergoing repairs resulting from a well control incident in 2004. These rig mobilizations and shipyard projects are expected to have a negative impact on revenues and related earnings.

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

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.

As of February 28, 2005, approximately 64 percent of our fleet days were committed for the remainder of 2005 and approximately 27 percent for the year 2006.

Tax Matters—We are a Cayman Islands company registered in Barbados. We operate through our various subsidiaries in a number of countries throughout the world. Consequently, we are subject to changes in tax laws, treaties and regulations in and between the countries in which we operate, including treaties that the U.S. has with other nations. A material change in these tax laws, treaties or regulations, including those in and involving the U.S., could result in a higher effective tax rate on our worldwide earnings.

On October 22, 2004, the American Jobs Creation Act of 2004 (the “Act”) was signed into law. The Act contains provisions that apply to certain companies that undertook a transaction commonly known as an inversion after a specified date. Because our reorganization as a Cayman Islands company in May 1999 occurred prior to the effective dates specified in the Act, we do not believe there should be any adverse impact to us from the inversion provisions of the Act. Additionally, the tax treaty between the U.S. and Barbados was recently amended. We do not expect the amendment to have a material adverse effect on our financial position, results of operations or cash flows.

The Act also creates a temporary incentive for U.S. corporations to repatriate accumulated income earned abroad by providing, in some cases, an 85 percent dividends received deduction for dividends paid by certain non-U.S. subsidiaries of the U.S. corporation (“controlled foreign corporations”) to the U.S. corporation. The deduction is subject to a number of limitations and uncertainty currently remains as to how to interpret numerous provisions of the Act. Further, several requirements must be met in order to qualify for the deduction. While we are still in the process of analyzing whether any of our U.S. subsidiaries could qualify for the deduction, it is reasonably possible that under the repatriation provisions of the Act certain of our non-U.S. subsidiaries may repatriate to our U.S. subsidiaries some amount of earnings up to an estimated maximum amount of $150 million. As we have provided deferred U.S. taxes on the unremitted earnings of these controlled foreign corporations, this deduction, should we qualify, could reduce our tax expense in 2005 by an estimated maximum amount of $40 million. The ultimate amounts could be much less or even zero.

 
The Act further provides for a tax deduction for qualified production activities. Under the guidance of FASB Staff Position No. 109-1, Application of FASB Statement No. 109, “Accounting for Income Taxes,” to the Tax Deduction on Qualified Production Activities Provided by the American Jobs Creation Act of 2004, the deduction will be treated as a “special deduction” as described in SFAS 109 and not as a reduction in the tax rate. As such, the special deduction has no effect on deferred tax assets and liabilities existing on the date of enactment. Rather, the impact of this deduction will be reported in the period in which the deduction is claimed on our tax return. We are still reviewing whether any of our operations would qualify for this deduction. Further, because of losses carried forward by the applicable subsidiaries, this deduction is not expected to have any impact on our tax provision in 2005.

Our income tax returns are subject to review and examination in the various jurisdictions in which we operate. In October 2004, we received from the U.S. Internal Revenue Service (“IRS”) examination reports setting forth proposed changes to the U.S. federal income tax reported for the period 1999-2000. The maximum amount of additional tax based on the proposed changes would be approximately $195 million, exclusive of interest. While we have agreed to certain non-material adjustments, we believe our returns are materially correct as filed and intend to defend ourselves vigorously. The IRS has also notified us of its intent to audit our 2002 and 2003 tax years. No examination report has been received at this time.
 
In September 2004, the Norwegian tax authorities initiated inquiries related to a restructuring transaction undertaken in 2001 and 2002 and a dividend payment made during 2001. In February 2005, we filed a response to these inquiries. In March 2005, pursuant to court orders, the Norwegian tax authorities took action to obtain additional information regarding these transactions. Based on these inquiries, we believe the Norwegian authorities are contemplating a tax assessment on the dividend of approximately $106 million, plus penalty and interest. No assessment has been made, and, we believe such an assessment would be without merit. While we cannot predict or provide assurance as to the final outcome, we do not expect the liability, if any, resulting from the inquiry to have a material adverse effect on our current consolidated financial position, results of operations and cash flows.
   
In addition, other tax authorities have examined the amounts of income and expense subject to tax in their jurisdiction for prior periods. We are currently contesting various non-U.S. assessments that have been asserted and would expect to contest any future U.S. or non-U.S. assessments. We do not expect the liability, if any, resulting from existing or future assessments to have a material adverse effect on our current consolidated financial position, results of operations and cash flows. We cannot predict with certainty the outcome or effect of any of the tax assessments described herein.  There can be no assurance that our beliefs or expectations as to the outcome or effect of any tax assessment we are contesting will prove correct and the eventual outcome of these matters could materially differ from management's current estimates.
 
As a result of the deconsolidation of TODCO from our other U.S. subsidiaries for U.S. federal income tax purposes in conjunction with the TODCO IPO, we established an initial valuation allowance in the first quarter of 2004 of approximately $31.0 million against the estimated deferred tax assets of TODCO in excess of its deferred tax liabilities, taking into account prudent and feasible tax planning strategies as required by the FASB’s Statement of Financial Accounting Standards (“SFAS”) 109, Accounting for Income Taxes. We adjusted the initial valuation allowance during the year to reflect changes in our estimate of the ultimate amount of TODCO’s deferred tax assets. The ultimate allocation of tax benefits between TODCO and our other U.S. subsidiaries will occur in 2005 upon the filing of our 2004 U.S. consolidated federal income tax return.  This final allocation of tax benefits could impact our effective tax rate for 2005.
 
 
Performance and Other Key Indicators
 
Fleet Utilization and Dayrates—The following table shows our average dayrates and utilization for the quarterly periods ended on or prior to December 31, 2004. We consolidated TODCO’s results of operations and financial condition in our consolidated financial statements through December 16, 2004 (see “―Significant Events”). Average dayrate 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 dayrate after commencement of operations. Utilization in the table below is defined as the total actual number of revenue earning days in the period as a percentage of the total number of calendar days in the period for all drilling rigs in our fleet.

   
Three months ended
 
   
December 31, 2004
 
September 30, 2004
 
December 31, 2003
 
Average Dayrates
             
               
Transocean Drilling Segment:
             
High-Specification Floaters
             
Fifth-Generation Deepwater Floaters 
 
$
180,100
 
$
193,400
 
$
186,500
 
Other Deepwater Floaters 
 
$
119,400
 
$
103,900
 
$
101,400
 
Other High-Specification Floaters 
 
$
135,700
 
$
111,200
 
$
117,900
 
Total High-Specification Floaters 
 
$
149,000
 
$
142,200
 
$
141,800
 
Other Floaters
 
$
64,000
 
$
65,400
 
$
60,600
 
Jackups
 
$
55,800
 
$
52,500
 
$
53,700
 
Other Rigs
 
$
48,100
 
$
44,700
 
$
45,200
 
Segment Total 
 
$
93,900
 
$
91,100
 
$
87,900
 
                     
TODCO Segment (a) 
 
$
28,600
 
$
27,300
 
$
21,500
 
                     
Total Drilling Fleet  
 
$
74,200
 
$
69,800
 
$
67,400
 
     
Utilization
   
     
Transocean Drilling Segment:
   
High-Specification Floaters
   
Fifth-Generation Deepwater Floaters 
   
89
%
 
83
%
 
91
%
Other Deepwater Floaters 
   
69
%
 
78
%
 
69
%
Other High-Specification Floaters 
   
92
%
 
84
%
 
74
%
Total High-Specification Floaters 
   
80
%
 
81
%
 
78
%
Other Floaters
   
50
%
 
45
%
 
47
%
Jackups
   
81
%
 
81
%
 
81
%
Other Rigs
   
54
%
 
44
%
 
53
%
Segment Total 
   
69
%
 
67
%
 
68
%
                   
TODCO Segment (a) 
   
47
%
 
45
%
 
40
%
                     
Total Drilling Fleet 
   
61
%
 
58
%
 
56
%
_________________
(a) TODCO was deconsolidated effective December 17, 2004. Statistics for the TODCO segment are through December 16, 2004 for the three months ended December 31, 2004.

Contract Drilling Revenue—Our contract drilling revenues are based primarily on dayrates received for our drilling services and the number of operating days during the relevant periods. The level of our contract drilling revenue depends on dayrates, which in turn are primarily a function of industry supply and demand for drilling units in the market sectors in which we operate. During periods of high demand, our rigs typically achieve higher utilization and dayrates than during periods of low demand. Some of our drilling contracts also enable us to earn mobilization, contract preparation, capital upgrade, bonus and demobilization revenue. Mobilization, contract preparation and capital upgrade revenue earned on a lump sum basis is recognized on a straight-line basis over the original contract term and in relation to our drilling revenues, which are earned on a contractual fixed dayrate basis. Bonus and demobilization revenue is recognized when earned.

   
Other Revenue—Beginning with the first quarter of 2004, we began classifying our revenues into two categories: (1) contract drilling revenues and (2) other revenues, as other revenue became a more significant component of our total revenues. Our other revenue represents client reimbursable revenue, integrated services revenue and other miscellaneous revenues. From time to time, we provide well services in addition to our normal drilling services through third party contractors. We refer to these other services as integrated services.

Operating and Maintenance Costs—Our operating and maintenance costs represent all direct and indirect costs associated with the operation and maintenance of our drilling rigs. The principal elements of these costs are direct and indirect labor and benefits, repair and maintenance, insurance, boat and helicopter rentals, professional and technical fees, freight costs, communications, customs duties, tool rentals and services, fuel and water, general taxes and licenses. Labor, repair and maintenance and insurance costs represent the most significant components of our operating and maintenance costs. Insurance costs include insurance premiums, personal injury losses less than the deductible and hull and machinery losses that fall below the deductible.
 
We do not expect operating and maintenance expenses to necessarily fluctuate in proportion to changes in operating revenues. Operating revenues may fluctuate as a function of changes in dayrate. However, costs for operating a rig are generally fixed or only semi-variable regardless of the dayrate being earned. In addition, should our rigs incur idle time between contracts, we typically do not de-man those rigs because we will use the crew to prepare the rig for its next contract. During times of reduced activity, reductions in costs may not be immediate as portions of the crew may be required to prepare our rigs for stacking, after which time the crew members are assigned to active rigs or dismissed. In 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. We maintain a per occurrence insurance deductible of $10 million on our hull and machinery and our protection and indemnity policies. We also have an additional aggregate deductible of $23 million that is applied to each hull and machinery occurrence until it has been exhausted over one or more occurrences. After this $23 million aggregate deductible is fully exhausted, the hull and machinery deductible reverts to $10 million per occurrence.

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

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

Interest Expense—Interest expense consists of interest associated with our senior notes and other debt and related financing cost amortization. Interest expense is partially offset by the amortization of fair value adjustments resulting from various interest rate swaps that were terminated during 2003. We expect the amortization of these fair value adjustments to continue over the life of the related debt instruments (see “—Derivative Instruments”).

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



Financial Condition

December 31, 2004 compared to December 31, 2003

   
December 31,
         
   
2004
 
2003
 
Change
 
% Change
 
   
(In millions, except % change)
     
Total Assets
                 
Transocean Drilling  
 
$
10,758.3
 
$
10,874.0
 
$
(115.7
)
 
(1
)%
TODCO
   
   
788.6
   
(788.6
)
 
(100
)%
   
$
10,758.3
 
$
11,662.6
 
$
(904.3
)
 
(8
)%

The decrease in Transocean Drilling segment assets was primarily due to asset depreciation ($432.6 million) and decreases in cash and cash equivalents ($3 million), partially offset by increases to investments in and advances to unconsolidated subsidiaries ($104 million), property and equipment, net of retirements ($89 million) (see “―Capital Expenditures”), goodwill ($21 million), accounts receivable ($19 million) and other long-term assets ($61 million). The decrease in cash and cash equivalents resulted primarily from repayments of debt ($1,069 million), partially offset by proceeds received from the TODCO Offerings ($684 million), net proceeds received from the sale of a semisubmersible rig ($28 million) and cash from operations during the year ended December 31, 2004. The increase in investments in and advances to unconsolidated subsidiaries primarily relates to our 22 percent interest in TODCO. The increase in goodwill primarily related to changes in our estimates related to certain pre-acquisition income tax-related contingencies, and the increase in other long-term assets was primarily due to incremental deferred income tax expense related to intercompany rig sales. The decrease in TODCO segment assets resulted from the deconsolidation of TODCO (see “―Significant Events”). 

Liquidity and Capital Resources

Sources and Uses of Cash
 
   
Years ended December 31, 
     
     2004  
2003
 
Change 
 
       
(In millions)
     
Net Cash Provided by Operating Activities
              
Net income
 
$
152.2
 
$
19.2
 
$
133.0
 
Depreciation
   
524.6
   
508.2
   
16.4
 
Other non-cash items
   
(45.6
)
 
(63.6
)
 
18.0
 
Working capital
   
(27.1
)
 
61.6
   
(88.7
)
   
$
604.1
 
$
525.4
 
$
78.7
 

Net cash provided by operating activities increased $78.7 million due to an increase in cash generated from net income adjusted for non-cash activity of $167.4 million, partially offset by a decrease in cash related to working capital items of $88.7 million during the year ended December 31, 2004 as compared to the corresponding prior year period.
 
   
Years ended December 31,
     
   
2004
   2003  
Change
 
       
(In millions) 
     
Net Cash Provided by (Used in) Investing Activities
               
Capital expenditures
 
$
(127.0
)
$
(493.8
)
$
366.8
 
Proceeds from disposal of assets, net
   
50.4
   
8.4
   
42.0
 
DDII LLC’s cash acquired, net of cash paid
   
   
18.1
   
(18.1
)
DD LLC’s cash acquired
   
   
18.6
   
(18.6
)
Proceeds from TODCO Offerings
   
683.6
   
-
   
683.6
 
Reduction of cash from the deconsolidation of TODCO
   
(68.6
)
 
-
   
(68.6
)
Joint ventures and other investments, net
   
10.4
   
3.3
   
7.1
 
   
$
548.8
 
$
(445.4
)
$
994.2
 

Net cash provided by investing activities increased $994.2 million over the previous year. The increase is primarily the result of proceeds from the TODCO Offerings of $683.6 million combined with an increase in proceeds from asset sales as compared to the prior year and a reduction in current year capital expenditures primarily due to the 2003 acquisition of the Deepwater Frontier and Deepwater Pathfinder totaling $382.8 million. Partially offsetting these increases was the decrease in cash of $68.6 million resulting from the deconsolidation of TODCO compared to $36.7 million of cash acquired upon acquisition of ConocoPhillips’ interests in DD LLC and DDII LLC during 2003.
 
   
Years ended December 31,
      
   
2004
 
2003
 
 Change
 
   
(In millions)
 
Net Cash Used in Financing Activities
             
Borrowings (repayments) under revolving credit agreement
 
$
(250.0
)
$
250.0
 
$
(500.0
)
Repayments on other debt instruments
   
(957.0
)
 
(1,252.7
)
 
295.7
 
Cash received from termination of interest rate swaps
   
   
173.5
   
(173.5
)
Other, net
   
31.4
   
9.0
   
22.4
 
   
$
(1,175.6
)
$
(820.2
)
$
(355.4
)

Net cash used in financing activities increased in 2004 compared to 2003 primarily due to higher debt repayments, which included scheduled debt repayments, the early redemption of our 9.5% Senior Notes and 6.75% Senior Notes and the repurchase of approximately 71.3 percent of our 8% Debentures by means of a tender offer. We had net borrowings under our revolving credit facility in 2003 that were repaid in 2004. In addition, the termination of our interest rate swaps was a source of cash in 2003 with no comparable activity during 2004  (see “—Derivative Instruments”).

Capital Expenditures

Capital expenditures totaled $127.0 million during the year ended December 31, 2004 of which $118.2 million and $8.8 million related to the Transocean Drilling and TODCO segments, respectively.

During 2005, we expect to spend approximately $140 million on our existing fleet, corporate infrastructure and major upgrades. These amounts are dependent upon the actual level of operational and contracting activity. In addition, we expect to spend another $50 million towards those upgrades required and funded by our drilling contracts, and another $35.7 million for the purchase of the semisubmersible rig M.G. Hulme, Jr. (see “—Acquisitions and Dispositions”). We intend to fund the cash requirements relating to our capital expenditures through available cash balances, cash generated from operations and asset sales. We also have available credit under our revolving credit agreement (see “Sources of Liquidity”) and may utilize other commercial bank or capital market financings.

Acquisitions and Dispositions

From time to time, we review possible acquisitions of businesses and drilling units and may in the future make significant capital commitments for such purposes. Any such acquisition could involve the payment by us of a substantial amount of cash or the issuance of a substantial number of additional ordinary shares or other securities. We would likely fund the cash portion of any such acquisition through cash balances on hand, the incurrence of additional debt, sales of assets, issuance of ordinary shares or other securities or a combination thereof. In addition, from time to time, we review possible dispositions of drilling units.

Acquisition - In November 2004, we gave notice to Deep Sea Investors, L.L.C. (“Deep Sea Investors”) of our intent to purchase the semisubmersible M.G. Hulme, Jr. for approximately $35.7 million. See “Off-Balance Sheet Arrangement.”

Dispositions—During 2004, we completed the TODCO Offerings. See “—Significant Events.”

In March 2004, we entered into agreements to sell two semisubmersible rigs, the Sedco 600 and Sedco 602, for net proceeds of $52.7 million in connection with our efforts to dispose of certain non-strategic assets in our Transocean Drilling segment. In June 2004, we completed the sale of the Sedco 602 for net proceeds of $28.0 million and recognized a gain of $21.7 million, which had no tax effect. In January 2005, we completed the sale of the Sedco 600 for net proceeds of $24.9 million, and we expect to recognize an after-tax gain of $18.8 million in the first quarter of 2005.

During the year ended December 31, 2004, we settled insurance claims and sold marine support vessels and certain other assets for net proceeds of $22.4 million and recorded net gains of $4.2 million ($3.3 million, net of tax) in our Transocean Drilling segment and $6.0 million, which had no tax effect, in our TODCO segment.



Sources of Liquidity

Our primary sources of liquidity in 2004 were our cash flows from operations, proceeds from the TODCO Offerings, proceeds from asset sales, borrowings under our revolving credit agreement and existing cash balances. Our primary uses of cash were debt repayments and capital expenditures. At December 31, 2004, we had $451.3 million in cash and cash equivalents.

We expect to use existing cash balances, internally generated cash flows and proceeds from asset sales, including potential sales of our interest in TODCO, to fulfill anticipated obligations such as scheduled debt maturities, capital expenditures and working capital needs. From time to time, we may also use bank lines of credit to maintain liquidity for short-term cash needs.

When cash on hand, cash flows from operations, proceeds from asset sales, including potential sales of our interest in TODCO, and committed bank facility availability exceed our expected liquidity needs, we may use a portion of such cash to reduce debt prior to scheduled maturities through repurchases, redemptions or tender offers, or make repayments on any outstanding bank borrowings. As we approach our targeted debt levels of $1 to $2 billion, we will begin to explore alternative uses of our excess cash. Such possible uses could include an extraordinary dividend, share repurchases, resumption of periodic dividends and/or opportunistic asset acquisitions.

At December 31, 2004 and 2003, our total debt was $2,481.5 million and $3,658.1 million, respectively. Net debt, a non-GAAP financial measure defined as total debt less cash and cash equivalents, at such dates was $2,030.2 million and $3,184.1 million, respectively. During the year ended December 31, 2004, we reduced net debt by $1,153.9 million. The reconciliation of total debt to net debt at carrying value is as follows (in millions):

   
December 31,
 
   
2004
 
2003
 
Total Debt
 
$
2,481.5
 
$
3,658.1
 
Less: Cash and cash equivalents
   
(451.3
)
 
(474.0
)
Net Debt
 
$
2,030.2
 
$
3,184.1
 

We believe net debt provides useful information regarding the level of our indebtedness by reflecting the amount of indebtedness assuming cash and investments are used to repay debt. Net debt declined each year since 2001 because cash flows, primarily from operations and asset sales, have exceeded capital expenditures.

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

We have access to a bank line of credit under an $800 million five-year revolving credit agreement expiring in December 2008. As of March 1, 2005, $800.0 million remained available under this credit line. Because our current cash balances, expected cash flow and this revolving credit agreement provide us with adequate liquidity, we terminated our commercial paper program during the first quarter of 2004.

The bank credit line requires compliance with various covenants and provisions customary for agreements of this nature, including an earnings before interest, taxes, depreciation and amortization (“EBITDA”) to interest coverage ratio and debt to tangible capital ratio, both as defined by the credit agreement, of not less than three to one and not greater than 50 percent, respectively. Other provisions of the credit agreement include limitations on creating liens, incurring debt, transactions with affiliates, sale/leaseback transactions and mergers and sale of substantially all assets. Should we fail to comply with these covenants, we would be in default and may lose access to this facility. We are also subject to various covenants under the indentures pursuant to which our public debt was issued, including restrictions on creating liens, engaging in sale/leaseback transactions and engaging in merger, consolidation or reorganization transactions. A default under our public debt could trigger a default under our credit line and cause us to lose access to this facility.
 
In April 2001, the Securities and Exchange Commission (“SEC”) declared effective our shelf registration statement on Form S-3 for the proposed offering from time to time of up to $2.0 billion in gross proceeds of senior or subordinated debt securities, preference shares, ordinary shares and warrants to purchase debt securities, preference shares, ordinary shares or other securities. At February 28, 2005, $1.6 billion in gross proceeds of securities remained unissued under the shelf registration statement.

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

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

   
For the years ending December 31,
 
   
Total
 
 2005
 
2006-2007
 
2008-2009
 
Thereafter
 
Contractual Obligations
     
Debt
 
$
2,390.2
 
$
19.6
 
$
500.0
 
$
266.8
 
$
1,603.8
 
Operating Leases
   
68.8
   
26.6
   
19.9
   
14.8
   
7.5
 
Purchase Obligations
   
35.7
   
35.7
   
-
   
-
   
-
 
Defined Benefit Pension Plans
   
2.4
   
2.4
   
-
   
-
   
-
 
Total Obligations
 
$
2,497.1
 
$
84.3
 
$
519.9
 
$
281.6
 
$
1,611.3
 
 
Bondholders may, at their option, require us to repurchase the 1.5% Convertible Debentures due 2021, the 7.45% Notes due 2027 and the Zero Coupon Convertible Debentures due 2020 in May 2006, April 2007 and May 2008, respectively. With regard to both series of the Convertible Debentures, we have the option to pay the repurchase price in cash, ordinary shares or any combination of cash and ordinary shares. The chart above assumes that the holders of these convertible debentures and notes exercise the options at the first available date. We are also required to repurchase the convertible debentures at the option of the holders at other later dates.

We have a required obligation to make a contribution in 2005 to our funded Norway defined benefit pension plans. See “—Retirement Plans and Other Postemployment Benefits” for a discussion of expected contributions for pension funding requirements of expected benefit payments for our unfunded defined benefit pension plans.

At December 31, 2004, we had other commitments that we are contractually obligated to fulfill with cash should the obligations be called. These obligations include standby letters of credit and surety bonds that guarantee our performance as it relates to our drilling contracts, insurance, tax and other obligations in various jurisdictions. Letters of credit are issued under a number of facilities provided by several banks. The obligations that are the subject of these surety bonds 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 table below provides a list of these obligations in U.S. dollar equivalents and their time to expiration.

   
For the years ending December 31,
 
   
Total
 
2005
 
2006-2007
 
2008-2009
 
Thereafter
 
   
(In millions)
 
Other Commercial Commitments
                     
Standby Letters of Credit
 
$
182.2
 
$
151.3
 
$
24.8
 
$
6.1
 
$
-
 
Surety Bonds
   
7.6
   
7.6
   
-
   
-
   
-
 
Surety Bonds-TODCO
   
11.9
   
11.9
   
-
   
-
   
-
 
Total
 
$
201.7
 
$
170.8
 
$
24.8
 
$
6.1
 
$
-
 

As is customary in the contract drilling business, we also have various surety bonds in place that secure customs obligations relating to the importation of our rigs and certain performance and other obligations. Until April 2005, we also guarantee $11.9 million of TODCO’s surety bonds, which TODCO has collateralized.

Derivative Instruments

We have established policies and procedures for derivative instruments that have been approved by our board of directors. These policies and procedures provide for the prior approval of derivative instruments by our Chief Financial Officer. From time to time, we may enter into a variety of derivative financial instruments in connection with the management of our exposure to fluctuations in foreign exchange rates and interest rates. We do not enter into derivative transactions for speculative purposes; however, for accounting purposes, certain transactions may not meet the criteria for hedge accounting.

Gains and losses on foreign exchange derivative instruments that qualify and are designated as accounting cash flow hedges are deferred as accumulated other comprehensive income (loss) and recognized when the underlying foreign exchange exposure is realized. Gains and losses on foreign exchange derivative instruments that are not designated as cash flow hedges or no longer qualify as hedges or are terminated as such for accounting purposes are recognized currently in other, net in our consolidated statements of operations based on the change in market value of the derivative instruments. At December 31, 2004, we had no open foreign exchange derivative instruments.

 
From time to time, we may use interest rate swaps to manage the effect of interest rate changes on our future interest rate expense. Interest rate swaps that we enter into are designated as a hedge of future interest payments on our underlying debt. The interest rate differential to be received or paid under the swaps is recognized over the lives of the swaps as an adjustment to interest expense. If an interest rate swap is terminated or no longer qualifies for hedge accounting, the gain or loss is amortized over the remaining life of the underlying debt. We do not enter into interest rate swaps for speculative purposes.

In June 2001, we entered into $700 million aggregate notional amount of interest rate swaps as a fair value hedge against our 6.625% Notes due April 2011. In February 2002, we entered into $900 million aggregate notional amount of interest rate swaps as a fair value hedge against our 6.75% Senior Notes due April 2005, 6.95% Senior Notes due April 2008 and 9.5% Senior Notes due December 2008. The swaps effectively converted the fixed interest rate on each of the four series of notes into a floating rate. The market value of the swaps was carried as an asset or a liability in our consolidated balance sheet and the carrying value of the hedged debt was adjusted accordingly.

In January 2003, we terminated swaps and associated fair value hedges with respect to our 6.75% Senior Notes due April 2005, 6.95% Senior Notes due April 2008 and 9.5% Senior Notes due December 2008. In March 2003, we terminated swaps with respect to our 6.625% Notes due April 2011. As a result of these terminations, we received cash proceeds, net of accrued interest, of $173.5 million that had been recognized in connection with the associated fair value hedges as a fair value adjustment to long-term debt in our consolidated balance sheet and is being amortized as a reduction to interest expense over the life of the underlying debt. Such reduction amounted to $22.7 million in 2004. As a result of the redemption of our 9.5% Senior Notes in March 2004 and 6.75% Senior Notes in October 2004, we recognized unamortized premium of $25.5 million from the 2003 termination of the related interest rate swap as a reduction to our loss on retirement of debt (see “—Historical 2004 compared to 2003”). Based on the unamortized premiums remaining on the terminated interest rate swaps and taking the announced March 2005 redemption of the 6.95% Senior Notes into account, we expect our interest expense to be reduced by $13.3 million in 2005.

Historical 2004 compared to 2003

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

Transocean Drilling Segment

   
Years ended
         
   
December 31,
         
   
2004
 
2003
 
Change
 
% Change
 
   
(In millions, except day amounts and percentages)
 
       
Revenue earning days (a)
   
23,427
   
23,712
   
(285
)
 
(1
)%
Utilization (b)
   
68
%
 
69
%
 
N/A
   
(1
)%
Average dayrate (c)
 
$
91,100
 
$
89,400
 
$
1,700
   
2
%
                           
Contract drilling revenues
 
$
2,134.1
 
$
2,118.7
 
$
15.4
   
1
%
Other revenues
   
146.3
   
88.0
   
58.3
   
66
%
     
2,280.4
   
2,206.7
   
73.7
   
3
%
Operating and maintenance expense
   
1,445.1
   
1,367.9
   
77.2
   
6
%
Depreciation
   
432.6
   
416.0
   
16.6
   
4
%
Impairment loss on long-lived assets
   
   
5.2
   
(5.2
)
 
N/M
 
Gain from sale of assets, net
   
(25.9
)
 
(4.9
)
 
(21.0
)
 
N/M
 
Operating income before general and administrative expense
 
$
428.6
 
$
422.5
 
$
6.1
   
1
%
_________________
“N/A” means not applicable
“N/M” means not meaningful

(a) Revenue earning day is a day for which a rig earns dayrate after commencement of operations.
(b) Utilization is defined as the total actual number of revenue earning days as a percentage of total number of calendar days in the period.
(c) Average dayrate is defined as contract drilling revenue earned per revenue earning day.

  
This segment’s contract drilling revenues increased by approximately $100.0 million as a result of revenues for the full year in 2004 from the Discoverer Enterprise, which was inactive for the latter part of the second quarter of 2003 due to a riser separation incident, and revenues from the Deepwater Frontier and the Deepwater Pathfinder resulting from the consolidation of DDII LLC and DD LLC, which occurred late in the second and fourth quarters of 2003, respectively. Additionally, a labor strike in Nigeria and the Peregrine I electrical incident during the second quarter of 2003 negatively impacted revenues during 2003 with no comparable incidents in 2004, which resulted in a positive impact of approximately $17.0 million in 2004 over the prior year. Partially offsetting these increases were decreases of approximately $38.0 million as a result of the strike in Norway and the Trident 20 and Jim Cunningham incidents in the third quarter of 2004. Contract drilling revenues were also negatively impacted by approximately $59.0 million due to a slight decline in utilization and a semisubmersible rig sold in 2004.

Other revenues for the year ended December 31, 2004 increased $58.3 million primarily due to a $68.0 million increase in integrated services revenue, partially offset by a decrease of $11.8 million from client reimbursable revenue and the absence of revenue from management fees as a result of the consolidation of DDII LLC and DD LLC late in the second and fourth quarters, respectively, of 2003.

This segment’s operating and maintenance expenses increased by approximately $83.0 million primarily from costs associated with higher personal injury claim losses, integrated services, additional expenses related to the Deepwater Pathfinder as a result of the consolidation of DD LLC late in the fourth quarter of 2003 and the Trident 20 and Jim Cunningham incidents in 2004. Expenses also increased approximately $25.0 million due to increased expenses primarily related to activity and the reactivation of rigs, a loss on retirement of rig equipment and higher provisions for local tax matters in 2004. Additional increases of $8.0 million resulted from favorable litigation and turnkey settlements during 2003 with no comparable activity during 2004. Partially offsetting these increases were decreased operating and maintenance expenses of approximately $42.0 million primarily related to the settlement of the Discoverer Enterprise May 2003 riser incident, the favorable insurance settlement related to a prior year Peregrine I riser incident, the favorable settlement of a turnkey dispute during 2004 and costs incurred in 2003 related to the restructuring of the Nigeria defined benefit plan and the Peregrine I electrical incident with no comparable activity in 2004.

The increase in this segment’s depreciation expense resulted primarily from $19.5 million of additional depreciation expense related to the Deepwater Frontier and Deepwater Pathfinder as a result of the late December 2003 payoff of the synthetic lease financing arrangements and the purchase of tensioner system equipment for the Discoverer Enterprise. An additional increase of approximately $2.0 million resulted from depreciation on other asset additions, net of retirements. These increases were partially offset by a $4.7 million decrease resulting from extending the useful lives of four rigs from 30 to 32 years, to 35 years in the fourth quarter of 2004 and $0.6 million resulting from rigs sold during and subsequent to 2003.

During 2003, we recorded non-cash impairment charges in this segment of $5.2 million associated with the removal of two rigs from drilling service and the value assigned to leases on oil and gas properties that we intended to discontinue. The determination of fair market value was based on an offer from a potential buyer, in the case of the two rigs, and management’s assessment of fair value, in the case of the leases on oil and gas properties, where third party valuations were not available.

During 2004, this segment recognized net gains of $25.9 million related to the sale of the semisubmersible rig Sedco 602 and the sale of other assets. During the year ended December 31, 2003, this segment recognized net gains of $4.9 million related to the sale of the jackup rig RBF 160, the sale of the Searex 15, the settlement of an insurance claim and the sale of other assets.


TODCO Segment

The results discussed below for the TODCO segment are through December 16, 2004 as a result of the TODCO Offerings and the deconsolidation of TODCO. See “—Significant Events.”

   
Years ended
         
   
December 31,
         
   
2004
 
2003
 
Change
 
% Change
 
   
(In millions, except day amounts and percentages)
 
       
Revenue earning days (a) (b)
   
10,476
   
10,953
   
(477
)
 
(4
)%
Utilization (a) (c)