x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

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 o

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. x

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller company. See definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.

Large accelerated filer x Accelerated filer o Non-accelerated filer (do not check if a smaller reporting company) o Smaller reporting company o

As of June 30, 2008, 319,044,814 shares were outstanding and the aggregate market value of shares held by non-affiliates was approximately $48.6 billion (based on the reported closing market price of the ordinary shares of Transocean Inc. on such date of $152.39 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 20, 2009, 319,660,304 shares were outstanding.

Portions of the registrant's definitive Proxy Statement to be filed with the Securities and Exchange Commission within 120 days of December 31, 2008, for its 2009 annual general meeting of shareholders, are incorporated by reference into Part III of this Form 10-K.

The statements included in this annual report regarding future financial performance and results of operations and other statements that are not historical facts are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Forward-looking statements in this annual report include, but are not limited to, statements about the following subjects:

• the offshore drilling market, including supply and demand, utilization rates, dayrates, customer drilling programs, commodity prices, effects of new rigs on the market and effects of declines in commodity prices and downturn in global economy on market outlook for our various geographical operating sectors and classes of rigs,

• customer contracts, including contract backlog, contract commencements, contract terminations, contract option exercises, contract revenues, contract awards and rig mobilizations,

• newbuild, upgrade, shipyard and other capital projects, including completion, delivery and commencement of operations dates, expected downtime and lost revenue, the level of expected capital expenditures and the timing and cost of completion of capital projects,

• liquidity and adequacy of cash flow for our obligations, including our ability and the expected timing to access certain investments in highly liquid instruments,

• our results of operations and cash flow from operations, including revenues and expenses,

• uses of excess cash, including debt retirement and share repurchases under our share repurchase program,

• tax matters, including our effective tax rate, changes in tax laws, treaties and regulations, tax assessments and liabilities for tax issues, including those associated with our activities in Brazil, Norway and the U.S.,

• legal and regulatory matters, including results and effects of legal proceedings and governmental audits and assessments, outcome and effects of internal and governmental investigations, customs and environmental matters,

• insurance matters, including adequacy of insurance, insurance proceeds and cash investments of our wholly-owned captive insurance company,

• the possible benefits, effects or results of the redomestication transaction,

• investments in recruitment, retention and personnel development initiatives, pension plan and other postretirement benefit plan contributions, the timing of severance payments and benefit payments.

Forward-looking statements in this annual report are identifiable by use of the following words and other similar expressions among others:

Such statements are subject to numerous risks, uncertainties and assumptions, including, but not limited to:

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

	Years ended December 31,
	2008			2007			2006			2005			2004

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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


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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Other commercial commitments—At December 31, 2008, we had other commitments that we are contractually obligated to fulfill with cash should the obligations be called. These obligations include standby letters of credit and surety bonds that guarantee our performance as it relates to our drilling contracts, insurance, customs, tax and other obligations in various jurisdictions. Letters of credit are issued under a number of facilities provided by several banks. The obligations that are the subject of these surety bonds and letters of credit are geographically concentrated in Nigeria and India. These letters of credit and surety bond obligations are not normally called as we typically comply with the underlying performance requirement.

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

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

We have established policies and procedures for derivative instruments that have been approved by our board of directors. These policies and procedures provide for the prior approval of derivative instruments by our Chief Financial Officer. From time to time, we may enter into a variety of derivative financial instruments in connection with the management of our exposure to fluctuations in foreign exchange rates and interest rates. We do not enter into derivative transactions for speculative purposes; however, for accounting purposes, certain transactions may not meet the criteria for hedge accounting. At December 31, 2008, we had no outstanding foreign exchange or interest rate derivative instruments.

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

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

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

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


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

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

Contract drilling revenues	$	10,756		$	5,948		$	4,808		81	%
Contract drilling intangible revenues		690			88			602		n/m
Other revenues		1,228			341			887		n/m
		12,674			6,377			6,297		99	%
Operating and maintenance expense		(5,355	)		(2,781	)		(2,574	)	93	%
Depreciation, depletion and amortization		(1,436	)		(499	)		(937	)	n/m
General and administrative expense		(199	)		(142	)		(57	)	40	%
Impairment loss		(320	)		—			(320	)	n/m
Gain (loss) from disposal of assets, net		(7	)		284			(291	)	n/m
Operating income		5,357			3,239			2,118		65	%
Other income (expense), net
Interest income		32			30			2		7	%
Interest expense, net of amounts capitalized		(469	)		(172	)		(297	)	n/m
Loss on retirement of debt		(3	)		(8	)		5		63	%
Other, net		26			295			(269	)	(91)	%
Income tax expense		(743	)		(253	)		(490	)	n/m
Minority interest		2			—			2		n/m
Net income	$	4,202		$	3,131		$	1,071		34	%

Contract drilling revenues increased primarily as a result of the inclusion of an additional $3,575 million in contract drilling revenues from GlobalSantaFe's operations and higher average daily revenue across the fleet. Partially offsetting these increases were lower revenues of $405 million on 27 rigs that were out of service for a portion of 2008 for shipyard, mobilization or maintenance and repair projects and lower revenues of $40 million from two rigs sold during 2007.

Contract drilling intangible revenues of $690 million were recognized in 2008, as a result of the amortization of the fair market valuation of GlobalSantaFe's drilling contracts in effect at the time of the Merger, compared to $88 million recognized in 2007.

Other revenues for the year ended December 31, 2008 increased primarily due to a $795 million increase in combined drilling management services revenue and oil and gas revenue as a result of the inclusion of GlobalSantaFe's operations, a $76 million increase in client reimbursable revenue and a $16 million increase in integrated services and other revenue.

Operating and maintenance expenses increased primarily due to the inclusion of GlobalSantaFe's operations. Other contributing factors included estimated expenses of $51 million related to dropped riser, higher labor costs due to scheduled pay increases, vendor price increases that resulted in higher rig maintenance costs and higher costs associated with the number of rigs out of service for shipyard or maintenance projects during the period.

Depreciation, depletion and amortization increased primarily due to the inclusion of GlobalSantaFe's operations and included $826 million of depreciation of property and equipment acquired in the Merger, $39 million of depletion of intangible costs from our oil and gas properties and $13 million of amortization of intangible assets from our drilling management services.

The increase in general and administrative expenses was due primarily to $28 million related to the inclusion of GlobalSantaFe's operations and a $31 million increase in general operating costs partially offset by $2 million related to personnel expenses.

In 2008, we recorded a $320 million impairment loss. The loss includes charges in the amount of $176 million, $97 million and $47 million to goodwill, assets held for sale and other intangible assets, respectively. There was no comparable activity in 2007.

During 2008, we recognized a net loss of $7 million related to rig sales and the disposal of other assets. During 2007, we recognized net gains of $284 million related to rig sales and disposal of other assets.

The increase in interest income was primarily due to higher average cash balances in 2008 compared to 2007.

The increase in interest expense was primarily attributable to $274 million of interest expense on additional borrowings under our credit facilities and $104 million of interest expense resulting from the issuance of new debt during 2008. In addition, $32 million of the increase was from debt assumed in the Merger, including $15 million from debt due to affiliates. Partially offsetting this increase were reductions of $72 million due to debt repaid during 2008 and $38 million related to increased capitalized interest during 2008.

During 2008, we recognized a $3 million loss related to the early termination of the Bridge Loan Facility. During 2007, we recognized an $8 million loss related to the early termination of $12.8 billion aggregate principal amount of our debt.

The decrease in other, net was primarily due to a $259 million decrease of income related to the TODCO tax sharing agreement, including the final settlement received in 2008, and a $23 million decrease related to royalty payments. We also recognized a loss on short-term investments of $16 million associated with our proportional interest in the debt instruments of Lehman Holdings held by The Reserve. Partially offsetting the decrease in other, net were proceeds of $17 million related to the termination of the sale agreement for Transocean Nordic. In addition, we had a $5 million increase in equity in earnings of unconsolidated affiliates and a $7 million decrease in foreign exchange loss compared to 2007.

We operate internationally and provide for income taxes based on the tax laws and rates in the countries in which we operate and earn income. There is no expected relationship between the provision for income taxes and income before income taxes. The annual effective tax rate for 2008 and 2007 was 14.0 percent and 12.5 percent, respectively, based on 2008 and 2007 income before income taxes and minority interest after adjusting for certain items such as a portion of net gains on sales of assets, impairment losses, losses on retirement of debt and merger-related costs. The tax effect, if any, of the excluded items as well as settlements of prior year tax liabilities and changes in prior year tax estimates are all treated as discrete period tax expenses or benefits. The tax impact of the various discrete items was a net tax benefit of $5 million in 2008, resulting in an effective tax rate of 15.0 percent on earnings before income taxes and minority interest. The discrete items in 2008 included an expense of $24 million primarily resulting from changes in prior year estimates, offset by a benefit of $17 million related to impairment losses, $6 million of bad debt write offs, $3 million related to inventory obsolescence, $2 million of losses on our investments in the Reserve Funds and $1 million from merger-related costs. The discrete items in 2007 included a benefit of $43 million resulting from changes in prior year estimates, $58 million for the reduction of a valuation allowance related to U.S. foreign tax credits and $15 million from merger-related costs.

The purchase price allocation for the merger with GlobalSantaFe included, at estimated fair value, current assets of $2.1 billion, drilling and other property and equipment of $12.3 billion, intangible assets of $368 million, other assets of $170 million and the assumption of current liabilities of $636 million, long-term debt of $576 million and other long-term liabilities of $2.3 billion. The excess of the purchase price over the estimated fair value of net assets acquired was $6.1 billion, which has been accounted for as goodwill.

Our historical financial operating results for 2007 include approximately one month of operating results for the combined company. Although the Merger did not materially impact 2007 results, it had a significant impact on our 2008 results and is expected to have a significant impact on our future results of operations and financial condition. See Notes to Consolidated Financial Statements—Note 3—Business Combinations.

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


	Years ended December 31,
	2007			2006			Change			% Change
	(In millions, except day amounts and percentages)

Revenue earning days		28,074			26,361			1,713		6	%
Utilization		90	%		84	%		n/a		6	%
Average daily revenue	$	211,900		$	142,100		$	69,800		49	%

Contract drilling revenues	$	5,948		$	3,745		$	2,203		59	%
Contract intangible revenues		88			—			88		n/m
Other revenues		341			137			204		n/m
		6,377			3,882			2,495		64	%
Operating and maintenance expense		(2,781	)		(2,155	)		(626	)	29	%
Depreciation, depletion and amortization		(499	)		(401	)		(98	)	24	%
General and administrative expense		(142	)		(90	)		(52	)	58	%
Gain from disposal of assets, net		284			405			(121	)	(30)	%
Operating income		3,239			1,641			1,598		97	%
Other income (expense), net
Interest income		30			21			9		43	%
Interest expense, net of amounts capitalized		(172	)		(115	)		(57	)	50	%
Loss on retirement of debt		(8	)		—			(8	)	n/m
Other, net		295			60			235		n/m
Income tax expense		(253	)		(222	)		(31	)	14	%
Net income	$	3,131		$	1,385		$	1,746		n/m

Contract drilling revenues increased primarily due to higher average daily revenue across the fleet and as a result of the inclusion of approximately one month of GlobalSantaFe's operations. Revenues from 14 rigs that were out of service for a portion of 2006 contributed $648 million, higher revenues attributable to the Merger contributed $344 million and reactivation of three rigs during 2006 contributed to higher utilization and increased revenue by $245 million. Partially offsetting these increases were lower revenues of $113 million on eight rigs that were out of service for a portion of 2007 for shipyard, mobilization or maintenance projects and lower revenues of $19 million from three rigs sold in 2007.

Contract drilling intangible revenues of $88 million were recognized as a result of the fair market valuation of GlobalSantaFe drilling contracts in effect at the time of the Merger with no corresponding revenue in the prior year.

Other revenues for the year ended December 31, 2007 increased $204 million primarily due to an increase of $143 million in integrated services revenue, a $49 million increase in non-drilling revenue primarily as a result of the inclusion of approximately one month of GlobalSantaFe's operations and a $11 million increase in client reimbursable revenue.

Operating and maintenance expenses increased by $626 million primarily from expenses related to higher labor costs, vendor price increases, increased integrated service costs of $127 million, higher reimbursable expenses in line with the higher level of reimbursable revenues, $151 million as a result of the inclusion of approximately one month of GlobalSantaFe's operations and $59 million of accelerated share-based compensation and incremental bonus expense incurred as a result of the Merger. These increases were partially offset by the costs incurred in 2006 of $81 million for the reactivation of three of our rigs with no corresponding expense in 2007 and $19 million of costs incurred to repair damage sustained during hurricanes Katrina and Rita in 2006 with no corresponding expense in 2007.

Depreciation, depletion and amortization increased primarily due to the inclusion of approximately one month of GlobalSantaFe's operations and included $81 million of depreciation of property and equipment, $7 million of amortization of intangible assets from our drilling management services and $4 million of depletion of intangible costs from our oil and gas properties.

The increase in general and administrative expenses was due primarily to $45 million higher personnel related expenses, which included $14 million of accelerated share-based compensation expense and $6 million of incremental bonus expense incurred as a result of the Merger, and $4 million from the inclusion of approximately one month of GlobalSantaFe's operations. In addition, there was a $6 million increase in general operating costs, which included rent, utilities, advertising and public relations expenses.

During 2007, we recognized net gains of $284 million related to rig sales and disposal of other assets. During 2006, we recognized net gains of $405 million related to rig sales and disposal of other assets.

The increase in interest income was primarily due to higher average cash balances in 2007 compared to 2006.

The increase in interest expense was primarily attributable to $63 million of interest expense resulting from the issuance of new debt, of which $43 million was from borrowings under the Bridge Loan Facility executed in conjunction with the Merger. In addition, $3 million was debt assumed in connection with the Merger and $47 million was from higher borrowings under our other credit facilities in 2007, compared to 2006. Partially offsetting this increase was $59 million related to increased capitalized interest in 2007 compared to 2006.

During 2007, we recognized an $8 million loss related to the early termination of $12.8 billion aggregate principal amount of our debt, with no comparable activity in 2006.

The increase in other, net was primarily due to $277 million in income recognized in 2007 in connection with the TODCO Tax Sharing Agreement compared to $51 million recognized in 2006.

We operate internationally and provide for income taxes based on the tax laws and rates in the countries in which we operate and earn income. There is no expected relationship between the provision for income taxes and income before income taxes. The annual effective tax rate for 2007 and 2006 was 12.5 percent and 18.5 percent, respectively, based on 2007 and 2006 income before income taxes and minority interest after adjusting for certain items such as a portion of net gains on sales of assets, losses on retirement of debt and merger-related costs. The tax effect, if any, of the excluded items as well as settlements of prior year tax liabilities and changes in prior year tax estimates are all treated as discrete period tax expenses or benefits. The tax impact of the various discrete items was a net benefit of $113 million in 2007, resulting in an effective tax rate of 7.5 percent on earnings before income taxes and minority interest. The discrete items in 2007 included a benefit of $43 million resulting from changes in prior year estimates, $58 million for the reduction of a valuation allowance related to U.S. foreign tax credits and $15 million from merger-related costs. For the year ended December 31, 2006, the tax impact of the various discrete period tax items, which related to the net gains on rig sales and changes in prior year tax estimates, was a net expense of $10 million, resulting in an effective tax rate of 13.8 percent on earnings before income taxes and minority interest.

Our discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements. This discussion should be read in conjunction with disclosures included in the notes to our consolidated financial statements related to estimates, contingencies and new accounting pronouncements. Significant accounting policies are discussed in our Notes to Consolidated Financial Statements—Note 2—Summary of Significant Accounting Policies.

The preparation of our financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues, expenses and related disclosure of contingent assets and liabilities. On an ongoing basis, we evaluate our estimates, including those related to bad debts, materials and supplies obsolescence, investments, property and equipment, intangible assets and goodwill, income taxes, workers insurance, share-based compensation, pensions and other post-retirement and employment benefits and contingent liabilities. We base our estimates on historical experience and on various other assumptions that we believe are reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates under different assumptions or conditions.

We consider the following to be our most critical accounting policies. We have discussed each of these critical accounting policies and estimates with the audit committee of our board of directors.

Income taxes—We are a Swiss corporation that operates through our various subsidiaries in a number of countries throughout the world. We have provided for income taxes based upon the tax laws and rates in the countries in which operations are conducted and income is earned. The countries in which we operate have taxation regimes with varying nominal rates, deductions, credits and other tax attributes. There is no expected relationship between the provision for or benefit from income taxes and income or loss before income taxes because the countries have taxation regimes that vary not only with respect to the nominal tax rate, but also in terms of the availability of deductions, credits and other benefits. Variations also arise when income earned and taxed in a particular country or countries fluctuates from year to year.

Our annual tax provision is based on expected taxable income, statutory rates and tax planning opportunities available to us in the various jurisdictions in which we operate. The determination and evaluation of our annual tax provision and tax positions involves the interpretation of the tax laws in the various jurisdictions in which we operate and requires significant judgment and the use of estimates and

assumptions regarding significant future events such as the amount, timing and character of income, deductions and tax credits. Changes in tax laws, regulations, agreements, and treaties, foreign currency exchange restrictions or our level of operations or profitability in each jurisdiction would impact our tax liability in any given year. We also operate in many jurisdictions where the tax laws relating to the offshore drilling industry are not well developed. While our annual tax provision is based on the best information available at the time, a number of years may elapse before the ultimate tax liabilities in the various jurisdictions are determined.

We maintain liabilities for estimated tax exposures in jurisdictions of operation. Our annual tax provision includes the impact of income tax provisions and benefits for changes to liabilities that we consider appropriate, as well as related interest. Tax exposure items primarily include potential challenges to permanent establishment positions, intercompany pricing, disposition transactions and the applicability or rate of various withholding taxes. These exposures are resolved primarily through the settlement of audits within these tax jurisdictions or by judicial means, but can also be affected by changes in applicable tax law or other factors, which could cause us to conclude a revision of past estimates is appropriate. We are currently undergoing examinations in a number of taxing jurisdictions for various fiscal years. We believe that an appropriate liability has been established for estimated exposures. However, actual results may differ materially from these estimates. We review these liabilities quarterly and to the extent the audits or other events result in an adjustment to the liability accrued for a prior year, the effect will be recognized in the period of the event.

We do not believe it is possible to reasonably estimate the potential impact of changes to the assumptions and estimates identified because the resulting change to our tax liability, if any, is dependent on numerous factors which cannot be reasonably estimated. These include, among others, the amount and nature of additional taxes potentially asserted by local tax authorities; the willingness of local tax authorities to negotiate a fair settlement through an administrative process; the impartiality of the local courts; and the potential for changes in the tax paid to one country to either produce, or fail to produce, an offsetting tax change in other countries.

Judgment, assumptions and estimates are required in determining whether deferred tax assets will be realized in full or in part. When it is estimated to be more likely than not that all or some portion of specific deferred tax assets, such as foreign tax credit carryovers or net operating loss carryforwards, will not be realized, a valuation allowance must be established for the amount of the deferred tax assets that are considered at the time to be unrealizable. Resulting from a change of circumstances in 2007, we believe that we will realize the benefits of our foreign tax credits in the U.S. As such, we released the entire associated valuation allowance against U.S. foreign tax credits of approximately $58 million. There were no significant changes to our valuation allowance against deferred tax assets in 2008. See "Results of Operations—Historical 2008 compared to 2007" and "Results of Operations—Historical 2007 compared to 2006." We continually evaluate strategies that could allow for the future utilization of our deferred tax assets.

We have not provided for deferred taxes on the unremitted earnings of certain subsidiaries that are permanently reinvested. Should we make a distribution from the unremitted earnings of these subsidiaries, we may be required to record additional taxes. Because we cannot predict when, if at all, we will make a distribution of these unremitted earnings, we are unable to make a determination of the amount of unrecognized deferred tax liability.

We have not provided for deferred taxes in circumstances where we expect that, due to the structure of operations and applicable law, the operations in that jurisdiction will not give rise to future tax consequences. Should our expectations change regarding the expected future tax consequences, we may be required to record additional deferred taxes that could have a material effect on our consolidated statement of financial position, results of operations or cash flows.

Goodwill—We had approximately $8.1 billion of goodwill recorded on our consolidated balance sheet as of December 31, 2008. We conduct impairment testing for our goodwill annually as of October 1 and more frequently when an event occurs or circumstances change that may indicate a reduction in the fair value of a reporting unit below its carrying value. We test goodwill at the reporting unit level, which is defined as an operating segment or a component of an operating segment that constitutes a business for which financial information is available and is regularly reviewed by management. We have determined that our reporting units for this purpose are (1) contract drilling services, (2) drilling management services and (3) oil and gas properties.

To determine the fair value of each reporting unit, we use a combination of generally accepted valuation methodologies, including both income and market approaches. For our contract drilling services reporting unit, we estimate the fair market value using discounted cash flows and publicly traded company multiples. We discount projected cash flows using a long-term weighted-average cost of capital, which is based on our estimate of the investment returns that market participants would require for each of our reporting units. To develop the projected cash flows associated with our contract drilling services reporting unit, which are based on estimated future utilization and dayrates, we consider key factors that include assumptions regarding future commodity prices, credit market uncertainties and the effect these factors may have on our contract drilling operations and the capital expenditure budgets of our customers. We derive publicly traded company multiples for companies with operations similar to our reporting units using information on shares traded on stock exchanges and, when they are available, from analyses of recent acquisitions in the marketplace. For our drilling management services reporting unit, we estimate fair market value using estimated discounted cash flows based on assumptions for future commodity prices, projected demand for our services, rig availability and dayrates. In determining the fair value of our oil and gas properties reporting unit, we use a reserves analysis, which is a form of the market approach that considers the changes in the commodity prices.

Because our business is cyclical in nature, the results of our impairment testing is expected to vary significantly depending on the timing of the performance of the assessment in relation to the business cycle. Altering either the timing of or the assumptions used in the calculations could result in estimating a reporting unit fair value that is significantly below the carrying value, which may give rise to an impairment of goodwill.

In calculating the fair values of our reporting units for our annual and interim impairment tests performed in the fourth quarter of 2008, we applied discount rates of nine percent and 13 percent and terminal growth rates of three percent and zero percent to our contract drilling services reporting unit and drilling management services reporting unit, respectively. As a result of our tests, we recorded an impairment of goodwill associated with our drilling management services reporting unit. Furthermore, we performed sensitivity analyses of our valuations assuming a hypothetical three percent increase in the discount rate and a hypothetical 10 percent decrease in our projected cash flows. Applying these hypothetical assumptions to the impairment testing performed during the fourth quarter of 2008 would not have resulted in an impairment of goodwill associated with our contract drilling services reporting unit.

Property and equipment—Property and equipment represents approximately 59 percent of our total assets. We determine the carrying value of these assets based on our property and equipment accounting policies, which incorporate our estimates, assumptions, and judgments relative to capitalized costs, useful lives and salvage values of our rigs.

Our policies are designed to appropriately and consistently capitalize costs incurred to enhance, improve and extend the useful lives of our assets and expense those costs incurred to repair and maintain the existing condition of our rigs. Capitalized costs increase the carrying values and depreciation expense of the related assets, which would also impact our results of operations.

We depreciate our assets over their estimated useful lives, which we determine by applying assumptions and judgments that reflect both historical experience and expectations regarding future operations, utilization and asset performance. The use of different estimates, assumptions and judgments in establishing the useful lives of our rigs would likely result in materially different net book values of our assets and results of operations.

Useful lives of rigs are difficult to estimate due to a variety of factors, including technological advances that impact the methods or cost of oil and gas exploration and development, changes in market or economic conditions, and changes in laws or regulations affecting the drilling industry. We evaluate the remaining useful lives of our rigs when certain events occur that directly impact our assessment of the remaining useful lives of the rig and include changes in operating condition, functional capability and market and economic factors. We also consider major capital upgrades required to perform certain contracts and the long-term impact of those upgrades on the future marketability when assessing the useful lives of individual rigs. A one-year increase in the useful lives of all of our rigs would cause a decrease in our annual depreciation expense of approximately $162 million while a one-year decrease would cause an increase in our annual depreciation expense of approximately $182 million.

We review our property and equipment for impairment when events or changes in circumstances indicate that the carrying value of such assets or asset groups may be impaired or when reclassifications are made between property and equipment and assets held for sale as prescribed by Statement of Financial Accounting Standards ("SFAS") No. 144, Accounting for Impairment or Disposal of Long-Lived Assets. Some of the potential indicators include rapid declines in commodity prices and related market conditions, actual or expected declines in utilization or increases in idle time, cancellations of contracts or credit concerns of multiple clients.

Supply and demand are the key drivers of rig utilization and our ability to contract our rigs at economical rates. During periods of an oversupply, it is not uncommon for us to have rigs idled for extended periods of time, which could indicate that an asset group may be impaired. Our rigs are mobile units, equipped to operate in geographic regions throughout the world and, consequently, we may move rigs from an oversupplied market sector to one that is more lucrative and undersupplied when it is economical to do so. As such, our rigs are considered to be interchangeable within classes or asset groups and accordingly, we perform our impairment evaluation by asset group. We consider our asset groups to be Ultra-Deepwater Floaters, Deepwater Floaters, Harsh Environment Floaters, Midwater Floaters, High-Specification Jackups, Standard Jackups and Other Rigs.

We assess asset impairment using estimated undiscounted cash flows for the assets being evaluated by applying assumptions regarding future operations, market conditions, dayrates, utilization and idle time. An impairment loss is recorded in the period in which it is determined that the aggregate carrying amount of assets within an asset group is not recoverable. The evaluation requires us to make judgments regarding long-term forecasts of future revenues and costs. In turn, these forecasts are uncertain in that they require assumptions about demand for our services, future market conditions and technological developments. Significant and unanticipated changes to these assumptions could require a provision for impairment in a future period. Given the nature of these evaluations and their application to specific asset groups and specific times, it is not possible to reasonably quantify the impact of changes in these assumptions.

Fair value of assets acquired—We accounted for the Merger using the purchase method of accounting as defined under SFAS No. 141, Business Combinations, and the cost in excess of fair value of the net assets acquired is capitalized as goodwill. We estimated the fair values of the assets acquired and liabilities assumed as of the date of the Merger, and these estimates were subject to adjustment based on our final assessments of the fair values of property and equipment, intangible assets, liabilities and our evaluation of tax positions and contingencies. These assessments were completed within one year of the date of the Merger. See Notes to Consolidated Financial Statements—Note 3—Business Combination.

Our estimates of fair value of property and equipment were subjective based on the age and condition of rigs acquired and the determination of the remaining useful lives of the rigs. We estimated the fair values of rigs acquired based on input from a third-party broker, and values were appraised based on perceptions of potential buyers and sellers in the market, which generally renders a low trading volume of rigs in the secondary market. The valuation of a rig and our estimate of the remaining useful life can also vary based on the rig design, condition and particular equipment configuration. It can be difficult to determine the fair value based on the cyclicality of our business, demand for offshore drilling rigs in different markets and changes in economic conditions.

In connection with the Merger, we acquired drilling contracts for future contract drilling services at fixed dayrates that may have been above or below market dayrates for similar contracts as of the date of the Merger. We adjusted these drilling contracts to fair value based on the discounted cash flow associated with each contract and the estimated market expectations for dayrates that could be charged over the same contractual terms. The market for drilling contracts is limited, identifying comparable contract rates in the market and determining the fair value is subjective, and the assumptions used to estimate market value and the discounted cash flow associated with the contract can affect the assigned value. These assumptions include differences in capabilities of rigs, cost differentials between locations for similar rigs, cost escalations or tax reimbursements that may or may not be included in the dayrate and assumptions about rig efficiency. Differences in estimated market values of the contracts could have a material impact on the amortization of the contract intangible recognized in contract intangible revenues on our consolidated statement of operations.

Pension and other postretirement benefits—Our defined benefit pension and other postretirement benefit (retiree life insurance and medical benefits) obligations and the related benefit costs are accounted for in accordance with SFAS No. 158, Employers' Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106 and 132(R) ("SFAS 158"), SFAS No. 87, Employers' Accounting for Pensions ("SFAS 87") and SFAS No. 106, Employers' Accounting for Postretirement Benefits Other than Pensions. Pension and postretirement costs and obligations are actuarially determined and are affected by assumptions including expected return on plan assets, discount rates, compensation increases, employee turnover rates and health care cost trend rates. We evaluate our assumptions periodically and make adjustments to these assumptions and the recorded liabilities as necessary.

Two of the most critical assumptions are the expected long-term rate of return on plan assets and the assumed discount rate. We periodically evaluate our assumptions regarding the estimated long-term rate of return on plan assets based on historical experience and future expectations on investment returns, which are calculated by our third-party investment advisor utilizing the asset allocation classes held by the plans' portfolios. As of January 1, 2009, based on market conditions and investment strategies, we did not change our expected long-term rate of return for our U.S. plans of 8.5 percent. For determining the discount rate for our U.S. plans, we utilize a yield curve approach based on Aa corporate bonds and the expected timing of future benefit payments. Changes in these and other assumptions used in the actuarial computations could impact our projected benefit obligations, pension liabilities, pension expense and other comprehensive income. We base our determination of pension expense on a market-related valuation of assets that reduces year-to-year volatility. This market-related valuation recognizes investment gains or losses over a five-year period from the year in which they occur. Investment gains or losses for this purpose are the difference between the expected return calculated using the market-related value of assets and the actual return based on the market-related value of assets.

For each percentage point the expected long-term rate of return assumption is lowered, pension expense would increase by approximately $8 million. For each one-half percentage point the discount rate is lowered, pension expense would increase by approximately $14 million. See "—Retirement Plans and Other Postemployment Benefits."

Contingent liabilities—We establish reserves for estimated loss contingencies when we believe a loss is probable and the amount of the loss can be reasonably estimated. Our contingent liability reserves relate primarily to litigation, personal injury claims and potential tax assessments (see "—Income Taxes"). Revisions to contingent liability reserves are reflected in income in the period in which different facts or information become known or circumstances that affect our previous assumptions with respect to the likelihood or amount of loss change. Reserves for contingent liabilities are based upon our assumptions and estimates regarding the probable outcome of the matter. Should the outcome differ from our assumptions and estimates or other events result in a material adjustment to the accrued estimated reserves, revisions to the estimated reserves for contingent liabilities would be required and would be recognized in the period the new information becomes known.

The estimation of the liability for personal injury claims includes the application of a loss development factor to reserves for known claims in order to estimate our ultimate liability for claims incurred during the period. The loss development method is based on the assumption that historical patterns of loss development will continue in the future. Actual losses may vary from the estimates computed with these reserve development factors as they are dependent upon future contingent events such as court decisions and settlements.

Defined benefit pension plans—We maintain two qualified defined benefit pension plans, one of which we assumed in connection with the Merger (the "Retirement Plans"), covering substantially all U.S. employees. We also maintain two unfunded plans (the "Supplemental Benefit Plans"), one of which we assumed in connection with the Merger along with two additional unfunded benefit plans (the "Other Supplemental Benefit Plans"). One of the Other Supplemental Benefit Plans provides certain eligible employees with benefits in excess of those allowed under the Retirement Plans and the other provides benefits to eligible non-U.S. employees. We assumed three defined benefit pension plans (two funded and one unfunded) in connection with the R&B Falcon merger and one unfunded defined benefit plan in connection with the Merger (the "Frozen Plans"), all of which were frozen prior to the respective mergers and for which benefits no longer accrue but the pension obligations have not been fully distributed.. We refer to the Retirement Plans, the Supplemental Benefit Plans, the Other Supplemental Benefit Plans and the Frozen Plans, collectively, as the "U.S. Plans". Effective January 1, 2009, we merged the two Retirement Plans into a single qualified defined benefit pension plan, and we combined the two Supplemental Benefit Plans into a single supplemental benefit plan.

In connection with the Merger, we amended the Supplemental Benefit Plans to provide employees terminated under a severance plan with age, earnings and service benefits ("Severance Credits") described in the Severance Plan, as defined below, and similar severance arrangements. The Supplemental Benefit Plans provide Severance Credits for the period of time following termination during which severance is paid (the "Salary Continuation Period"). Alternatively, to provide the value of the Severance Credits to an eligible employee who receives severance in a lump sum, the Severance Credits are granted for the period of time over which the lump sum would have been paid had it been paid as salary continuation (the "Severance Continuation Period Equivalent"). The amended Supplemental Benefit Plans also provide for a lump-sum form of payment within 90 days after a participant's termination of employment and a six-month delay on benefits payable to "specified employees" under Section 409A of the Internal Revenue Code.

In connection with the Merger, we also assumed a defined benefit plan in the U.K. (the "U.K. Plan") covering certain current and former legacy GlobalSantaFe employees in the U.K.

In addition, we provide several defined benefit plans, primarily group pension schemes with life insurance companies covering our Norway operations and two unfunded plans covering certain of our employees and former employees (the "Norway Plans"). Our contributions to the Norway Plans are determined primarily by the respective life insurance companies based on the terms of the plan. For the insurance-based plans, annual premium payments are considered to represent a reasonable approximation of the service costs of benefits earned during the period. We also have unfunded defined benefit plans (the "Other Plans") that provide retirement and severance benefits for certain of our Indonesian, Nigerian and Egyptian employees. The benefits we provide under defined benefit pension plans are comprised of the U.S. Plans, the Norway Plans, the Other Plans and the U.K. Plan (collectively, the "Transocean Plans").

We account for the Transocean Plans in accordance with SFAS 87, as amended by SFAS 158. These accounting standards require us to calculate our pension expense and liabilities using assumptions based on a market-related valuation of assets, which reduces year-to-year volatility using actuarial assumptions. Changes in these assumptions can result in different expense and liability amounts, and future actual experience can differ from these assumptions.

In accordance with SFAS 87, changes in pension obligations and assets may not be immediately recognized as pension costs in the statement of operations but generally are recognized in future years over the remaining average service period of plan participants. As such, significant portions of pension costs recorded in any period may not reflect the actual level of benefit payments provided to plan participants.

Two of the most critical assumptions used in calculating our pension expense and liabilities are the expected long-term rate of return on plan assets and the assumed discount rate. Our expected long-term rate of return on plan assets for funded U.S. Plans was 8.5 percent and 9.0 percent as of December 31, 2008 and 2007, respectively. The expected long-term rate of return on plan assets was developed by reviewing each plan's target asset allocation and asset class long-term rate of return expectations. We regularly review our actual asset allocation and periodically rebalance plan assets as appropriate. For the U.S. Plans, we discounted our future pension obligations using a rate of 5.4 percent at December 31, 2008 and 6.1 percent at December 31, 2007.

We expect pension expense related to the Transocean Plans for 2009 to increase by approximately $33 million primarily due to the significant decline in the aggregate fair value of plan assets held by the trust, partly offset by a change in the demographic assumptions for future periods and plan asset growth realized in 2008.

Future changes in plan asset returns, assumed discount rates and various other factors related to the pension plans will impact our future pension expense and liabilities. We cannot predict with certainty what these factors will be in the future.

	U.S. Plans			U.K. Plan			Norway Plans			Other Plans			Total Transocean Plans
Accumulated Benefit Obligation
At December 31, 2008	$	763		$	160		$	56		$	4		$	983
At December 31, 2007		669			207			58			5			939

Projected Benefit Obligation
At December 31, 2008	$	899		$	171		$	73		$	7		$	1,150
At December 31, 2007		757			228			71			9			1,065

Fair Value of Plan Assets
At December 31, 2008	$	455		$	152		$	56		$	—		$	663
At December 31, 2007		632			247			60			—			939

Funded Status
At December 31, 2008	$	(444	)	$	(19	)	$	(17	)	$	(7	)	$	(487	)
At December 31, 2007		(125	)		19			(11	)		(9	)		(126	)

Net Periodic Benefit Cost
Year ended December 31, 2008	$	29		$	3		$	9		$	3		$	44		(	a)
Year ended December 31, 2007		16			1			8			2			27		(	a)

Change in Accumulated Other Comprehensive Income
Year ended December 31, 2008	$	338		$	36		$	6		$	(1	)	$	379
Year ended December 31, 2007		21			—			(9	)		—			12

Employer Contributions
Year ended December 31, 2008	$	60		$	7		$	7		$	—		$	74
Year ended December 31, 2007		14			1			6			1			22

Weighted-Average Assumptions – Benefit Obligations
Discount rate
At December 31, 2008		5.40	%		6.25	%		4.50	%		15.61	%		5.57	%	(	b)
At December 31, 2007		6.13	%		5.90	%		5.30	%		12.90	%		6.07	%	(	b)
Rate of compensation increase
At December 31, 2008		4.21	%		4.25	%		4.50	%		12.10	%		4.28	%	(	b)
At December 31, 2007		4.58	%		4.40	%		4.50	%		11.17	%		4.57	%	(	b)

For the funded U.S. Plans, our funding policy consists of reviewing the funded status of these plans annually and contributing an amount at least equal to the minimum contribution required under the Employee Retirement Income Security Act of 1974 ("ERISA"). Employer contributions to the funded U.S. Plans are based on actuarial computations that establish the minimum contribution required under ERISA and the maximum deductible contribution for income tax purposes. We contributed $60 million and $14 million to the funded U.S. Plans during 2008 and 2007, respectively. We contributed less than $1 million to the unfunded U.S. Plans during each of 2008 and 2007 to fund benefit payments. Our contributions to the Transocean Plans in 2008 and 2007 were funded from our cash flows from operations.

Plan assets of the funded Transocean Plans have been unfavorably impacted by a decline in world equity markets during 2008, given the allocation of approximately 59.7 percent of plan assets to equity securities. To a lesser extent, debt securities and other investments also experienced decreased values. During 2008, the market value of the investments in the Transocean Plans decreased by $276 million, or 29.4 percent, which is due to net investment losses of $196 million, primarily in the funded U.S. Plans, resulting from the unfavorable performance of equity markets in 2008, benefit plan payments of $82 million and $75 million of unfavorable foreign currency exchange rate changes. The Transocean Plans made employee contributions of $74 million and participants contributed $3 million in 2008. We expect to contribute $88 million to the Transocean Plans in 2009. These contributions are comprised of an estimated $65 million to meet minimum funding requirements for the funded U.S. Plans, $7 million to fund expected benefit payments for the unfunded U.S. Plans and Other Plans, $11 million for the funded Norway Plans and $5 million for the U.K. Plan. We expect to fund the required contributions with cash flow from operations.

The following pension benefits payments are expected to be paid by the Transocean Plans (in millions):

Postretirement benefits other than pensions—We have several unfunded contributory and noncontributory other postretirement employee benefits ("OPEB") plans, including one that we assumed in connection with the Merger, covering substantially all of our U.S. employees. Funding of benefit payments for plan participants will be made as costs are incurred. Net periodic benefit cost for these other postretirement plans and their components, including service cost, interest cost, amortization of prior service cost and recognized net actuarial losses were $3 million and less than $2 million for the years ended December 31, 2008 and 2007, respectively. The postretirement benefits payments are expected to be approximately $3 million in each of 2009, 2010 and 2011.

Pacific Drilling Limited—We hold a 50 percent equity interest in TPDI, a British Virgin Islands joint venture company formed by us and Pacific Drilling, a Liberian company, to own two ultra-deepwater drillships to be named Dhirubhai Deepwater KG1 and Dhirubhai Deepwater KG2, which are currently under construction. Beginning on October 18, 2010, Pacific Drilling will have the right to exchange its interest in the joint venture for our shares or cash at a purchase price based on an appraisal of the fair value of the drillships, subject to various adjustments.

At February 20, 2009, TPDI had outstanding promissory notes in the aggregate amount of $222 million, of which $111 million is due to Pacific Drilling and is included in long-term debt in our consolidated balance sheet.

Overseas Drilling Limited—We own a 50 percent interest in Overseas Drilling Limited ("ODL"), an unconsolidated Liberian joint venture company. ODL owns the Joides Resolution, for which we provide certain operational and management services. In 2008, we earned $2 million for those services. Siem Offshore Inc. owns the other 50 percent interest in ODL. A former director of Transocean-Cayman, Kristian Siem, is the chairman of Siem Offshore Inc. and is also a director and officer of ODL. Mr. Siem is also chairman and chief executive officer of Siem Industries, Inc., which owns an approximate 34 percent interest in Siem Offshore Inc.

In September 2006, the Financial Accounting Standards Board ("FASB") issued SFAS No. 157, Fair Value Measurements ("SFAS 157"). SFAS 157 defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles, and expands disclosures about fair value measurements. SFAS 157 does not require any new fair value measurements, but rather provides guidance for the application of fair value measurements required in other accounting pronouncements and seeks to eliminate inconsistencies in the application of such guidance among those other standards. SFAS 157 is effective for fiscal years beginning after November 15, 2007. In February 2008, the FASB issued FASB Staff Position ("FSP") No. FAS 157-2, Effective Date of FASB Statement No. 157, which delays the effective date of SFAS 157 to fiscal years beginning after November 15, 2008, for nonfinancial assets and nonfinancial liabilities except those that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually). In the first quarter 2008, we adopted those provisions of SFAS 157 that were unaffected by the delay. Such adoption did not have a material effect on our consolidated statement of financial position, results of operations or cash flows. In October 2008, the FASB issued FSP No. FAS 157-3, Determining the Fair Value of a Financial Asset When the Market for That Asset Is Not Active ("FSP 157-3"), which clarifies the application of SFAS 157 when the market is not active. We adopted FSP 157-3 as of September 30, 2008, which did not have a material effect on our consolidated statement of financial position, results of operations or cash flows.

In December 2007, the FASB issued SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements ("SFAS 160"). SFAS 160 establishes accounting and reporting standards for noncontrolling interests, also known as minority interests, in a subsidiary and for the deconsolidation of a subsidiary. It requires that a noncontrolling interest in a subsidiary be reported as equity in the consolidated financial statements and requires that consolidated net income attributable to the parent and to the noncontrolling interests be shown separately on the face of the income statement. SFAS 160 is effective for fiscal years beginning after December 15, 2008. We will be required to adopt SFAS 160 in the first quarter of 2009. We do not expect the adoption of SFAS 160 to have a material effect on our consolidated statement of financial position, results of operations or cash flows.

In December 2007, the FASB issued SFAS No. 141 (revised 2007), Business Combinations ("SFAS 141R"). SFAS 141R replaces SFAS No. 141, Business Combinations and, among other things, (1) changes previous guidance so as to require that primarily all acquired assets, liabilities, minority interest and certain contingencies be measured at fair value, (2) broadens the scope of business combinations to include all transactions in which one entity gains control over one or more other businesses and (3) requires costs incurred to effect the acquisition (acquisition-related costs) and anticipated restructuring costs of the acquired company to be recognized separately from the acquisition. SFAS 141R applies prospectively to business combinations for which the acquisition date occurs in fiscal years beginning after December 15, 2008. We will be required to adopt the principles of SFAS 141R with respect to business combinations occurring on or after January 1, 2009 and with respect to certain income tax matters related to previous business combinations. Due to the prospective application requirement, we are unable to determine the effect, if any, that the adoption of SFAS 141R will have on our consolidated statement of financial position, results of operations or cash flows.

In March 2008, the FASB issued SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activities, an amendment of FASB Statement No. 133 ("SFAS 161"). SFAS 161 changes the disclosure requirements for derivative instruments and hedging activities. Entities are required to provide enhanced disclosures about (1) how and why an entity uses derivative instruments, (2) how derivative instruments and related hedged items are accounted for under SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities ("SFAS 133"), and its related interpretations, and (3) how derivative instruments and related hedged items affect an entity's financial position, financial performance and cash flows. SFAS 161 is effective for fiscal years beginning after November 15, 2008. We will be required to adopt SFAS 161 in the first quarter of 2009. Because of our limited use of derivative instruments, we do not expect the adoption of SFAS 161 to have a significant impact on our consolidated statement of financial position, results of operations or cash flows.

In April 2008, the FASB issued FSP No. 142-3, Determination of the Useful Life of Intangible Assets ("FSP FAS 142-3"). FSP FAS 142-3 amends the factors that should be considered in developing renewal or extension assumptions used to determine the useful life of a recognized intangible asset under SFAS No. 142, Goodwill and Other Intangible Assets. FSP FAS 142-3 is effective for fiscal years beginning after December 15, 2008 and interim periods within those fiscal years, requiring prospective application to intangible assets acquired after the effective date. We will be required to adopt the principles of FSP FAS 142-3 with respect to intangible assets acquired on or after January 1, 2009. Due to the prospective application requirement, we are unable to determine the effect, if any, that the adoption of FSP FAS 142-3 will have on our consolidated statement of financial position, results of operations or cash flows.

In May 2008, the FASB issued SFAS No. 162, The Hierarchy of Generally Accepted Accounting Principles ("SFAS 162"), which identifies the sources of accounting principles and the framework for selecting the principles used in the preparation of financial statements of nongovernmental entities that are presented in conformity with accounting principles generally accepted in the U.S. SFAS 162 shall be effective 60 days following the SEC's approval of certain amendments to auditing standards proposed by the Public Company Accounting Oversight Board. We do not expect the adoption of SFAS 162 to have an effect on our consolidated statement of financial position, results of operations or cash flows.

In May 2008, the FASB also issued FSP No. APB 14-1, Accounting for Convertible Debt Instruments That May Be Settled in Cash upon Conversion (Including Partial Cash Settlement) ("FSP APB 14-1"), which requires the issuer of certain convertible debt instruments to separately account for the liability and equity components of the instrument and reflect interest expense at the entity's market rate of borrowing for non-convertible debt instruments. FSP APB 14-1 requires retrospective restatement of all periods presented with the cumulative effect of the change in accounting principle on prior periods being recognized as of the beginning of the first period presented. The adoption of FSP APB 14-1 will have an effect on the accounting, both retrospectively and prospectively, for our Convertible Notes. Aside from a reduction of debt balances and an increase to shareholders' equity on our consolidated balance sheets for each period presented, we expect the retrospective application of FSP APB 14-1 will result in a non-cash increase to our annual historical interest expense, net of amounts capitalized, of approximately $9 million and $172 million for 2007 and 2008, respectively. Additionally, we expect that the adoption will result in a non-cash increase to our projected annual interest expense, net of amounts expected to be capitalized, of approximately $176 million, $206 million and $151 million for 2009, 2010 and 2011, respectively.

In June 2008, the FASB ratified the consensus on Emerging Issues Task Force ("EITF") Issue No. 07-5, "Determining Whether an Instrument (or Embedded Feature) Is Indexed to an Entity's Own Stock" ("EITF 07-5"). An instrument or embedded feature that is both indexed to an entity's own stock and potentially settled in shares may be exempt, if certain other criteria are met, from mark-to-market accounting of derivative financial instruments. EITF 07-5 addresses instruments with contingent and other adjustment features that may change the exercise price or notional amount or otherwise alter the payoff at settlement. We have both warrants and convertible notes outstanding that are exercisable or convertible into our shares. We do not expect EITF 07-5, which is effective for fiscal years beginning after December 15, 2008, to have a material effect on our consolidated statement of financial position, results of operations or cash flows after adoption.

In June 2008, the FASB issue FSP EITF 03-6-1, Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities ("FSP EITF 03-6-1"). FSP EITF 03-6-1 clarifies that all outstanding unvested share-based payment awards that contain rights to nonforfeitable dividends participate in undistributed earnings with common shareholders. Awards of this nature are considered participating securities and the two-class method of computing basic and diluted earnings per share must be applied. FSP EITF 03-6-1 is effective for fiscal years beginning after December 15, 2008. We do not expect the adoption of FSP EITF 03-6-1 to have a material effect on our consolidated statement of financial position, results of operations or cash flows.

In December 2008, the FASB issued FSP No. FAS 140-4 and FIN 46(R)-8, Disclosures by Public Entities (Enterprises) about Transfers of Financial Assets and Interests in Variable Interest Entities ("FSP FAS 140-4 and FIN 46R-8"). FSP FAS 140-4 and FIN 46R-8 require public entities to provide additional disclosures about transfers of financial assets as an amendment to FASB Statement No. 140, Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities. Additionally, FSP FAS 140-4 and FIN 46R-8 require additional disclosures about a sponsor's involvement with variable interest entities as an amendment to FASB Interpretation No. 46 (revised December 2003), Consolidation of Variable Interest Entities. FSP FAS 140-4 and FIN 46R-8 are effective for periods ending after December 15, 2008. We have adopted the principles of FSP FAS 140-4 and FIN 46R-8 and have included such additional disclosures in the notes to our financial statements for the year ended December 31, 2008. Our adoption of these standards did not have an effect on our consolidated statement of financial position, results of operations or cash flows.

In December 2008, the FASB issued FSP No. FAS 132(R)-1, Employers' Disclosures about Postretirement Benefit Plan Assets ("FSP FAS 132R-1"), which provides additional guidance regarding required disclosures for plan assets of a defined benefit pension or other postretirement plan. FSP FAS 132R-1 is effective for fiscal years ending after December 15, 2009. We will be required to adopt the principles of FSP FAS 132R-1 in the fourth quarter of 2009 and intend to include the additional disclosures in the notes to our financial statements for the year ending December 31, 2009. We do not expect the adoption to have a material effect on our consolidated statement of financial position, results of operations or cash flows.

Our exposure to market risk for changes in interest rates relates primarily to our long-term and short-term debt. The table below presents scheduled debt maturities in U.S. dollars and related weighted-average interest rates for each of the years ended December 31 relating to debt obligations as of December 31, 2008 (in millions, except interest rate percentages):

At December 31, 2008, we had approximately $3 billion of variable rate debt at face value (24 percent of total debt at face value). This variable rate debt primarily represented issuances outstanding under the Program and borrowings under the Term Loan. At December 31, 2007, we had approximately $6 billion of variable debt outstanding represented by the Floating Rate Notes and borrowings under the Bridge Loan Facility and the Former 364-Day Revolving Credit Facility. Based upon the December 31, 2008 and 2007 variable rate debt outstanding amounts, a one percentage point change in interest rates would result in a corresponding change in interest expense of approximately $33 million and $64 million, respectively. In addition, a large part of our cash investments would earn commensurately higher rates of return if interest rates increase. Using December 31, 2008 and 2007 cash investment levels, a one percentage point change in interest rates would result in a corresponding change in interest income of approximately $4 million and $8 million per year, respectively.

The fair market value of our debt at December 31, 2008 was $12.8 billion compared to $17.9 billion at December 31, 2007. The decrease in fair value of $5.1 billion was primarily due to the repayment of debt during the year, as well as changes in the corporate bond market.

In connection with the Merger, we acquired GSF Jack Ryan, which is subject to a fully defeased financing lease arrangement with a remaining term of 12 years. As a result, we have assumed the rights and obligations under the terms of the defeasance arrangement executed by GlobalSantaFe with three financial institutions, whereby we are required to make additional payments if the defeasance deposit does not earn a rate of return of at least 8.00 percent per year, the interest rate expected at the inception of the agreement. The defeasance deposit earns interest based on the British pound three-month LIBOR, which was 2.82 percent as of December 31, 2008. If the interest rate were to remain fixed at this rate for the next five years, we would be required to make an additional payment of approximately $15 million during that period. We do not expect that, if required, any additional payments made under this defeasance arrangement would be material to our statement of financial position, results of operations or cash flows.

Our international operations expose us to foreign exchange risk. We use a variety of techniques to minimize the exposure to foreign exchange risk, including customer contract payment terms and the possible use of foreign exchange derivative instruments. Our primary foreign exchange risk management strategy involves structuring customer contracts to provide for payment in both U.S. dollars, which is our functional currency, and local currency. The payment portion denominated in local currency is based on anticipated local currency requirements over the contract term. Due to various factors, including customer acceptance, local banking laws, other statutory requirements, local currency convertibility and the impact of inflation on local costs, actual foreign exchange needs may vary from those anticipated in the customer contracts, resulting in partial exposure to foreign exchange risk. Fluctuations in foreign currencies typically have not had a material impact on our overall results. In situations where payments of local currency do not equal local currency requirements, foreign exchange derivative instruments, specifically foreign exchange forward contracts, or spot purchases, may be used to mitigate foreign currency risk. A foreign exchange forward contract obligates us to exchange predetermined amounts of specified foreign currencies at specified exchange rates on specified dates or to make an equivalent U.S. dollar payment equal to the value of such exchange. We do not enter into derivative transactions for speculative purposes. At December 31, 2008, we had no open foreign exchange derivative contracts.

Management of Transocean Ltd. (the "Company" or "our") is responsible for establishing and maintaining adequate internal control over financial reporting for the Company as defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934. The Company's internal control system was designed to provide reasonable assurance to the Company's management and Board of Directors regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with U.S. generally accepted accounting principles.

Internal control over financial reporting includes the controls themselves, monitoring (including internal auditing practices), and actions taken to correct deficiencies as identified.

There are inherent limitations to the effectiveness of internal control over financial reporting, however well designed, including the possibility of human error and the possible circumvention or overriding of controls. The design of an internal control system is also based in part upon assumptions and judgments made by management about the likelihood of future events, and there can be no assurance that an internal control will be effective under all potential future conditions. As a result, even an effective system of internal controls can provide no more than reasonable assurance with respect to the fair presentation of financial statements and the processes under which they were prepared.

Management assessed the effectiveness of the Company's internal control over financial reporting as of December 31, 2008. In making this assessment, management used the criteria for internal control over financial reporting described in Internal Control–Integrated Framework by the Committee of Sponsoring Organizations of the Treadway Commission ("COSO"). Management's assessment included an evaluation of the design of the Company's internal control over financial reporting and testing of the operating effectiveness of its internal control over financial reporting.

Management reviewed the results of its assessment with the Audit Committee of the Company's Board of Directors. Based on this assessment, management has concluded that, as of December 31, 2008, the Company's internal control over financial reporting was effective.

We have audited Transocean Ltd.'s internal control over financial reporting as of December 31, 2008, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Transocean Ltd.'s management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management's Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the company's internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the company's assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, Transocean Ltd. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2008, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Transocean Ltd. as of December 31, 2008 and 2007, and the related consolidated statements of operations, comprehensive income, equity, and cash flows for each of the three years in the period ended December 31, 2008 and our reported dated February 24, 2009 expressed an unqualified opinion thereon.

We have audited the accompanying consolidated balance sheets of Transocean Ltd. and Subsidiaries as of December 31, 2008 and 2007, and the related consolidated statements of operations, comprehensive income, equity, and cash flows for each of the three years in the period ended December 31, 2008. Our audits also included the financial statement schedule listed in the Index at Item 15(a). These financial statements and schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Transocean Ltd. and Subsidiaries at December 31, 2008 and 2007, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2008, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.

As discussed in Note 5 to the consolidated financial statements, effective January 1, 2007, the Company adopted FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement 109. Also discussed in Note 16, effective December 31, 2006, the Company adopted Statement of Financial Accounting Standards No. 158, Employers' Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106, and 132(R).

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Transocean Ltd.'s internal control over financial reporting as of December 31, 2008, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 24, 2009 expressed an unqualified opinion thereon.

	Years ended December 31,
	2008			2007			2006

Operating revenues
Contract drilling revenues	$	10,756		$	5,948		$	3,745
Contract drilling intangible revenues		690			88			—
Other revenues		1,228			341			137
		12,674			6,377			3,882
Costs and expenses
Operating and maintenance		5,355			2,781			2,155
Depreciation, depletion and amortization		1,436			499			401
General and administrative		199			142			90
		6,990			3,422			2,646
Impairment loss		(320	)		—			—
Gain (loss) from disposal of assets, net		(7	)		284			405
Operating income		5,357			3,239			1,641

Other income (expense), net
Interest income		32			30			21
Interest expense, net of amounts capitalized		(469	)		(172	)		(115	)
Loss on retirement of debt		(3	)		(8	)		—
Other, net		26			295			60
		(414	)		145			(34	)

Income before income tax expense and minority interest		4,943			3,384			1,607
Income tax expense		743			253			222
Minority interest		(2	)		—			—

Net income	$	4,202		$	3,131		$	1,385

Earnings per share
Basic	$	13.20		$	14.65		$	6.32
Diluted	$	13.09		$	14.14		$	6.10

Weighted-average shares outstanding
Basic		318			214			219
Diluted		321			222			228

	December 31,
	2008			2007
ASSETS
Cash and cash equivalents	$	963		$	1,241
Short-term investments		333			—
Accounts receivable, net
Trade		2,798			2,209
Other		66			161
Materials and supplies, net		432			333
Deferred income taxes, net		63			119
Assets held for sale		464			—
Other current assets		230			233
Total current assets		5,349			4,296

Property and equipment		25,802			24,545
Less accumulated depreciation		4,975			3,615
Property and equipment, net		20,827			20,930
Goodwill		8,128			8,219
Other assets		867			919
Total assets	$	35,171		$	34,364

LIABILITIES AND SHAREHOLDERS' EQUITY
Accounts payable	$	914		$	805
Accrued income taxes		317			99
Debt due within one year		664			6,172
Other current liabilities		806			826
Total current liabilities		2,701			7,902

Long-term debt		13,522			11,085
Deferred income taxes, net		666			681
Other long-term liabilities		1,755			2,125
Total long-term liabilities		15,943			13,891

Commitments and contingencies
Minority interest		3			5

Preference shares, none authorized, issued and outstanding at December 31, 2008; preference shares $0.10 par value, 50,000,000 shares authorized, none issued and outstanding at December 31, 2007		—			—
Shares, CHF 15.00 par value, 502,852,947 authorized, 167,617,649 contingently authorized, 335,235,298 issued and 319,262,113 outstanding at December 31, 2008; ordinary shares, $0.01 par value, 800,000,000 shares authorized, 317,222,909 shares issued and outstanding at December 31, 2007		4,444			3
Additional paid-in capital		6,492			10,799
Accumulated other comprehensive loss		(420	)		(42	)
Retained earnings		6,008			1,806
Total shareholders' equity		16,524			12,566
Total liabilities and shareholders' equity	$	35,171		$	34,364

									Accumulated			Retained
						Additional			other			earnings
			Shares			paid-in			comprehensive			(accumulated			Total
	Shares		Amount			capital			income (loss)			deficit)			equity

Balance at December 31, 2005	227		$	2		$	10,566		$	(20	)	$	(2,566	)	$	7,982
Net income	—			—			—			—			1,385			1,385
Repurchase of shares	(25	)		—			(2,600	)		—			—			(2,600	)
Issuance of shares under share-based compensation plans	3			—			70			—			—			70
Share-based compensation expense	—			—			20			—			—			20
Minimum pension liability	—			—			—			16			—			16
Adjustment to initially apply SFAS 158, net of tax	—			—			—			(26	)		—			(26	)
Other, net	—			—			(11	)		—			—			(11	)

Balance at December 31, 2006	205			2			8,045			(30	)		(1,181	)		6,836
Net income	—			—			—			—			3,131			3,131
Other comprehensive income	—			—			—			(12	)		—			(12	)
Repurchase of shares	(4	)		—			(400	)		—			—			(400	)
Issuance of shares upon conversion of convertible debentures and notes	4			—			414			—			—			414
Issuance of shares under share-based compensation plans	4			—			65			—			—			65
Share-based compensation expense	—			—			78			—			—			78
Excess tax benefit for share-based compensation plans	—			—			70			—			—			70
Exchange of shares and share-based compensation in business combination	108			1			12,385			—			—			12,386
Reclassification of ordinary shares	—			—			(9,859	)		—			—			(9,859	)
Adjustment to initially apply FIN 48, net of tax	—			—			—			—			(144	)		(144	)
Other, net	—			—			1			—			-			1

Balance at December 31, 2007	317			3			10,799			(42	)		1,806			12,566
Net income	—			—			—			—			4,202			4,202
Other comprehensive income	—			—			—			(378	)		—			(378	)
Issuance of shares under share-based compensation plans	2			—			62			—			—			62
Share-based compensation expense	—			—			64			—			—			64
Excess tax benefit for share-based compensation plans	—			—			10			—			—			10
Cancellation of ordinary shares in Redomestication Transaction	(319	)		(3	)		3			—			—			—
Issuance of shares in Redomestication Transaction	319			4,444			(4,444	)		—			—			—
Other, net	—			—			(2	)		—			—			(2	)

Balance at December 31, 2008	319		$	4,444		$	6,492		$	(420	)	$	6,008		$	16,524

	Years ended December 31,
	2008			2007			2006
Cash flows from operating activities
Net income	$	4,202		$	3,131		$	1,385
Adjustments to reconcile net income to net cash provided by operating activities:
Amortization of drilling contract intangibles		(690	)		(88	)		—
Depreciation, depletion and amortization		1,436			499			401
Share-based compensation expense		64			78			20
Excess tax benefit from share-based compensation plans		(10	)		(70	)		(7	)
(Gain) loss from disposal of assets, net		7			(284	)		(405	)
Impairment of short-term investments		16			—			—
Impairment loss		320			—			—
Deferred revenue, net		11			52			52
Deferred expenses, net		(115	)		(55	)		(109	)
Deferred income taxes		8			(40	)		(23	)
Other, net		31			22			(13	)
Changes in operating assets and liabilities		(321	)		(172	)		(64	)
Net cash provided by operating activities		4,959			3,073			1,237

Cash flows from investing activities
Capital expenditures		(2,208	)		(1,380	)		(876	)
Business combination		—			(5,129	)		—
Cash balances acquired in business combination		—			695			—
Proceeds from disposal of assets, net		348			379			461
Short-term investments		(408	)		—			—
Proceeds from maturities of short-term investments		59			—			—
Joint ventures and other investments, net		13			(242	)		—
Net cash used in investing activities		(2,196	)		(5,677	)		(415	)

Cash flows from financing activities
Change in short-term borrowings, net		(837	)		1,500			—
Proceeds from debt		2,661			24,095			2,000
Repayments of debt		(4,893	)		(12,033	)		(300	)
Financing costs		(24	)		(106	)		(5	)
Repurchase of shares		—			(400	)		(2,601	)
Payment to shareholders for Reclassification		(1	)		(9,859	)		—
Proceeds from (payments for) exercise of warrants, net		(7	)		40			—
Proceeds from share-based compensation plans, net		51			72			69
Excess tax benefit from share-based compensation plans		10			70			7
Other, net		(1	)		(1	)		30
Net cash provided by (used in) financing activities		(3,041	)		3,378			(800	)

Net increase (decrease) in cash and cash equivalents		(278	)		774			22
Cash and cash equivalents at beginning of period		1,241			467			445
Cash and cash equivalents at end of period	$	963		$	1,241		$	467

Nature of business—Transocean Ltd. (together with its subsidiaries and predecessors, unless the context requires otherwise, "Transocean," the "Company," "we," "us" or "our") is a leading international provider of offshore contract drilling services for oil and gas wells. Our mobile offshore drilling fleet is considered one of the most modern and versatile fleets in the world. Specializing in technically demanding sectors of the offshore drilling business with a particular focus on deepwater and harsh environment drilling services, we contract our drilling rigs, related equipment and work crews primarily on a dayrate basis to drill oil and gas wells. At December 31, 2008, we owned, had partial ownership interests in or operated 136 mobile offshore drilling units. As of this date, our fleet consisted of 39 High-Specification Floaters (Ultra-Deepwater, Deepwater and Harsh Environment semisubmersibles and drillships), 28 Midwater Floaters, 10 High-Specification Jackups, 55 Standard Jackups and four Other Rigs. We also have 10 Ultra-Deepwater Floaters under construction or contracted for construction (see Note 7—Drilling Fleet Expansion and Upgrades).

We also provide oil and gas drilling management services, drilling engineering and drilling project management services, and we participate in oil and gas exploration and production activities. Drilling management services are provided through Applied Drilling Technology Inc., our wholly owned subsidiary, and through ADT International, a division of one of our U.K. subsidiaries (together, "ADTI"). ADTI conducts drilling management services primarily on either a dayrate or a completed-project, fixed-price (or "turnkey") basis. Oil and gas properties consist of exploration, development and production activities performed by Challenger Minerals Inc. and Challenger Minerals (North Sea) Limited (together, "CMI"), our oil and gas subsidiaries.

On January 31, 2001, we completed a merger transaction 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 including the Gulf of Mexico Shallow and Inland Water segment fleet. R&B Falcon and the Gulf of Mexico Shallow and Inland Water segment later became known as TODCO (together with its subsidiaries and predecessors, unless the context requires otherwise, "TODCO") and the TODCO segment, respectively. In preparation for the initial public offering discussed below, we transferred all assets and subsidiaries out of TODCO that were unrelated to the TODCO segment. In February 2004, we completed an initial public offering (the "TODCO IPO") of approximately 23 percent of TODCO's outstanding shares of its common stock. In September 2004, December 2004 and May 2005, respectively, we completed additional public offerings of TODCO common stock. In June 2005, we completed a sale of our remaining TODCO common stock pursuant to Rule 144 under the Securities Act of 1933, as amended.

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

Principles of consolidation—We consolidate those investments that meet the criteria of a variable interest entity where we are deemed to be the primary beneficiary for accounting purposes and for entities in which we have a majority voting interest. Intercompany transactions and accounts are eliminated in consolidation. For investments in joint ventures and other entities that do not meet the criteria of a variable interest entity or where we are not deemed to be the primary beneficiary for accounting purposes of those entities that meet the variable interest entity criteria, we use the equity method of accounting if we have the ability to exercise significant influence over the unconsolidated affiliate. We use the cost method of accounting for investments in joint ventures and other entities if we do not have the ability to exercise significant influence over the unconsolidated affiliate.

In October 2007, we acquired a 50 percent interest in Transocean Pacific Drilling Inc. ("TPDI"), a British Virgin Islands joint venture company formed by us and Pacific Drilling Limited ("Pacific Drilling"), a Liberian company, to own and operate two ultra-deepwater drillships to be named Dhirubhai Deepwater KG1 and Dhirubhai Deepwater KG2, which are currently under construction. Since TPDI's equity at risk is insufficient to permit TPDI to carry on its activities without additional subordinated financial support, TPDI meets the criteria

for a variable interest entity, and we have determined that we are the primary beneficiary for accounting purposes. As a result, we consolidate TPDI in our consolidated financial statements, intercompany transactions are eliminated and the interest that is not owned by us is presented as minority interest on our consolidated balance sheet. We provide construction management services for the newbuilds and have agreed to provide operating management services once the drillships begin operations. Beginning on October 18, 2010, Pacific Drilling will have the right to exchange its interest in the joint venture for our shares or cash at a purchase price based on an appraisal of the fair value of the drillships, subject to various adjustments.

In September 2008, we acquired a 65 percent interest in Angola Deepwater Drilling Company Limited ("ADDCL"), a Cayman Islands joint venture company formed to commission the construction, ownership and operation of the ultra-deepwater drillship to be named Discoverer Luanda. Angco Cayman Limited acquired the remaining 35 percent interest in ADDCL. Even though we do not have a majority voting interest over the operations of ADDCL, we have determined that ADDCL is a variable interest-entity for which we are the primary beneficiary for accounting purposes because its equity at risk is insufficient to enable ADDCL to carry on its activities without additional subordinated financial support from us. Accordingly, we consolidate ADDCL in our consolidated financial statements, intercompany transactions are eliminated and the interest that is not owned by us is presented as minority interest on our consolidated balance sheet. We provide construction management services for the newbuild and have agreed to provide operating management services once the drillship begins operations. Beginning on the fifth anniversary of the first well commencement date, Angco Cayman Limited will have the right to exchange its interest in the joint venture for cash at a purchase price based on an appraisal of the fair value of the drillship, subject to various adjustments.

We recognized investments in and advances to unconsolidated affiliates of $17 million and $15 million for the years ended December 31, 2008 and 2007, respectively, and reported these amounts in other assets in our consolidated balance sheet.

We recognized equity in earnings (losses) of unconsolidated affiliates of $2 million, $(2) million and $5 million for the years ended December 31, 2008, 2007 and 2006, respectively, and reported these amounts in other, net in our consolidated statement of operations.

Accounting estimates—The preparation of financial statements in conformity with accounting principles generally accepted in the U.S. requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and disclosure of contingent assets and liabilities. On an ongoing basis, we evaluate our estimates and assumptions, including those related to bad debts, materials and supplies obsolescence, investments, goodwill and other intangible assets, and other long-lived assets, income taxes, share-based compensation, pensions and other postretirement benefits, other employment benefits and contingent liabilities. We base our estimates and assumptions on historical experience and on various other factors we believe are reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results could differ from such estimates.

Cash and cash equivalents—Cash equivalents are highly liquid debt instruments with an original maturity of three months or less and may consist of time deposits with a number of commercial banks with high credit ratings, Eurodollar time deposits, certificates of deposit and commercial paper. We may also invest excess funds in no-load, open-end, management investment trusts ("management trusts"). The management trusts invest exclusively in high quality money market instruments. Cash equivalents are stated at cost plus accrued interest, which approximates fair value. We record restricted cash in other assets in our consolidated balance sheet. At December 31, 2008 and 2007, we had $8 million and $7 million, respectively, classified as restricted cash related to collateral for surety bonds to satisfy certain Venezuelan tax requirements.

Allowance for doubtful accounts—We establish reserves for doubtful accounts on a case-by-case basis when we believe the required payment of specific amounts owed is unlikely to occur. In establishing these reserves, we consider changes in the financial position of a major customer and restrictions placed on the conversion of local currency to U.S. dollars as well as disputes with our customers regarding the application of contract provisions to our drilling operations. This allowance was $114 million and $50 million at December 31, 2008 and 2007, respectively. Uncollectible accounts receivable are written off when a settlement is reached for an amount that is less than the outstanding historical balance or the balance is determined to be uncollectible. We derive a majority of our revenue from services to international oil companies and government-owned and government-controlled oil companies, and we do not generally require collateral or other security to support client receivables.

Materials and supplies—Materials and supplies are carried at average cost less an allowance for obsolescence. Such allowance was $49 million and $22 million at December 31, 2008 and 2007, respectively.

Property and equipment—Property and equipment, consisting primarily of offshore drilling rigs and related equipment, represented approximately 59 percent of our total assets at December 31, 2008. The carrying values of these assets are based on estimates, assumptions and judgments relative to capitalized costs, useful lives and salvage values of our rigs. These estimates, assumptions and judgments reflect both historical experience and expectations regarding future industry conditions and operations. We compute depreciation using the straight-line method after allowing for salvage values. Expenditures for renewals, replacements and improvements are capitalized. Maintenance and repairs are charged to operating expense as incurred. Upon sale or other disposition, the applicable amounts of asset cost and accumulated depreciation are removed from the accounts and the net amount, less proceeds from disposal, is charged or credited to gain from disposal of assets, net.

Estimated original useful lives of our drilling units range from 18 to 35 years, reflecting maintenance history and market demand for these drilling units, buildings and improvements from 10 to 30 years and machinery and equipment from four to 12 years. From time to time, we may review the estimated remaining useful lives of our drilling units and may extend the useful life when events and circumstances indicate the drilling unit can operate beyond its original or current useful life. During the first quarter of 2006, we extended the useful life to 35 years for one rig, which previously had an estimated useful life of 30 years. During 2007, we extended the useful lives for six rigs, which previously had estimated useful lives of between 30 to 35 years, to between 35 and 45 years. During 2008, we extended the useful lives for five rigs, which previously had estimated useful lives of between 30 to 35 years, to between 34 and 50 years. We determined the years were appropriate for each of these rigs based on the then current contracts these rigs were operating under as well as the additional life-extending work, upgrades and inspections we performed on these rigs. In 2008, 2007 and 2006, the impact of the change in estimated useful life of these rigs was a reduction in depreciation expense of $6 million ($0.02 per diluted share), $25 million ($0.11 per diluted share) and $2 million ($0.01 per diluted share), respectively, which had no tax effect. During 2008, we also reduced the useful lives for four legacy GlobalSantaFe rigs, which previously had estimated useful lives of between eight and 16 years, to between three and nine years. We determined the useful lives were appropriate for each of these rigs based on the review of technical specification of the rigs and comparisons of remaining lives of comparable rigs in our fleet. In 2008, the impact of the change in estimated useful life of these rigs was an increase in depreciation expense of $46 million ($0.14 per diluted share), which had no tax effect.

Assets held for sale—Assets are classified as held for sale when we have a plan for disposal and those assets meet the held for sale criteria of Statement of Financial Accounting Standards ("SFAS") No. 144, Accounting for Impairment or Disposal of Long-Lived Assets. At December 31, 2008, we had assets held for sale in the amount $464 million that were included in current assets. At December 31, 2007, there were no assets held for sale.

Impairment of long-lived assets—We review the carrying value of long-lived assets, principally property and equipment, for potential impairment when events occur or circumstances change that indicate that the carrying value of such assets may not be recoverable. For property and equipment held and used, we determine recoverability by evaluating the undiscounted estimated future net cash flows of the related asset or asset group under review. We consider our asset groups to be Ultra-Deepwater Floaters, Deepwater Floaters, Harsh Environment Floaters, Midwater Floaters, High-Specification Jackups, Standard Jackups and Other Rigs. The estimated future net cash flows are based upon projected utilization and dayrates. For property and equipment held for sale, we record the asset at the lower of net book value or net realizable value. See Note 4—Impairment Loss.

Goodwill and other intangible assets— We conduct impairment testing for our goodwill annually as of October 1 and more frequently when an event occurs or circumstances change that may indicate a reduction in the fair value of a reporting unit below its carrying value. We test goodwill at the reporting unit level, which is defined as an operating segment or a component of an operating segment that constitutes a business for which financial information is available and is regularly reviewed by management. The impairment of goodwill is tested by comparing the reporting unit's carrying amount, including goodwill, to the fair value of the reporting unit. If the carrying amount of the reporting unit exceeds its fair value, goodwill is considered impaired and a second step is performed to measure the amount of the impairment loss, if any. Prior to the Merger, we operated in one operating segment, contract drilling services, which we considered to be our sole reporting unit. As a result of the Merger, we established two additional reporting units for this purpose: (1) drilling management services and (2) oil and gas properties. As a result of our testing in each of the years ended December 31, 2007 and 2006, we concluded that goodwill was not impaired. For the year ended December 31, 2008, we concluded that the goodwill of drilling management services was impaired. See Note 4—Impairment Loss and Note 9—Goodwill and Other Intangible Assets.

To determine the fair value of each reporting unit, we use a combination of generally accepted valuation methodologies, including both income and market approaches. For our contract drilling services reporting unit, we estimate the fair market value using estimated discounted cash flows and publicly traded company multiples. We discount projected cash flows using a long-term weighted-average cost of capital, which is based on our estimate of the investment returns that market participants would require for each of our reporting units. To develop the projected cash flows associated with our contract drilling services reporting unit, which are based on estimated future utilization and dayrates, we consider key factors that include assumptions regarding future commodity prices, credit market uncertainties and the effect these factors may have on our contract drilling operations and the capital expenditure budgets of our customers. We derive publicly traded company multiples for companies with operations similar to our reporting units using information on shares traded on stock exchanges and, when they are available, from analyses of recent acquisitions in the marketplace. For our drilling management services reporting unit, we estimate fair market value using estimated discounted cash flows based on assumptions for future commodity prices, projected demand for our services, rig availability and dayrates. In determining the fair value of our oil and gas properties reporting unit, we use a reserves analysis, which is a form of the market approach that considers the changes in the commodity prices.

For intangible assets other than goodwill, we use generally accepted valuation methodologies that are appropriate for estimating the fair values of those assets. For example, we use a relief from royalty method to value trade names and an excess earnings method to value customer relationships, both of which apply the income approach.

Operating revenues and expenses—Operating revenues are recognized as earned, based on contractual daily rates or on a fixed price basis. In connection with drilling contracts, we may receive revenues for preparation and mobilization of equipment and personnel or for capital improvements to rigs. In connection with new drilling contracts, revenues earned and incremental costs incurred directly related to contract preparation and mobilization are deferred and recognized over the primary contract term of the drilling project

using the straight-line method. Our policy to amortize the fees related to contract preparation, mobilization and capital upgrades on a straight-line basis over the estimated firm period of drilling is consistent with the general pace of activity, level of services being provided and dayrates being earned over the life of the contract. For contractual daily rate contracts, we account for loss contracts as the losses are incurred. Costs of relocating drilling units without contracts to more promising market areas are expensed as incurred. Upon completion of drilling contracts, any demobilization fees received are reported in income, as are any related expenses. Capital upgrade revenues received are deferred and recognized over the primary contract term of the drilling project. The actual cost incurred for the capital upgrade is depreciated over the estimated useful life of the asset. We incur periodic survey and drydock costs in connection with obtaining regulatory certification to operate our rigs on an ongoing basis. Costs associated with these certifications are deferred and amortized on a straight-line basis over the period until the next survey.

Contract drilling intangible revenues—In connection with the Merger, we acquired drilling contracts for future contract drilling services of GlobalSantaFe. These contracts include fixed dayrates and are at dayrates that may have been above or below dayrates as of the date of the Merger for similar contracts. We adjusted these drilling contracts to fair value as of the date of the Merger, and as a result, we recorded $67 million and $179 million in 2008 and 2007, respectively, in other assets and $593 million and $1.4 billion in 2008 and 2007, respectively, in other long-term liabilities on our consolidated balance sheet. We recognize the intangible revenues over the respective contract period, amortizing the balances using the straight-line method.

Other revenues—Our other revenues represent drilling management services revenues, integrated services revenues, oil and gas properties revenues, client reimbursable revenues and other miscellaneous revenues. For fixed-price contracts associated with our drilling management services, revenues and expenses are recognized on completion of the well and acceptance by the customer. Provisions for losses are made on contracts in progress when losses are anticipated. We refer to integrated services as those services we provide through third-party contractors and our employees under certain contracts that include well and logistics services in addition to our normal drilling services. We consider client reimbursable revenues to be billings to our client for reimbursement of certain equipment, materials and supplies, third-party services, employee bonuses and out-of-pocket expenses that we incur and recognize in operating and maintenance expense, which results in little or no effect on operating income.

Capitalized interest—We capitalize interest costs for qualifying construction and upgrade projects. We capitalized interest costs on construction work in progress of $114 million, $76 million and $16 million for the years ended December 31, 2008, 2007 and 2006, respectively.

Derivative instruments and hedging activities—We account for our derivative instruments and hedging activities in accordance with SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities. See Note 12—Interest Rate Swaps and Note 14—Financial Instruments and Risk Concentration.

Foreign currency—The majority of our revenues and expenditures are denominated in U.S. dollars to limit our exposure to foreign currency fluctuations, resulting in the use of the U.S. dollar as the functional currency for all of our operations. Foreign currency exchange gains and losses are primarily included in other income (expense) as incurred. We had net foreign currency exchange losses of $3 million, $10 million and $3 million for the years ended December 31, 2008, 2007 and 2006, respectively.

Income taxes—Income taxes have been provided based upon the tax laws and rates in effect in the countries in which operations are conducted and income is earned. There is no expected relationship between the provision for or benefit from income taxes and income or loss before income taxes because the countries in which we operate have taxation regimes that vary not only with respect to nominal rate, but also in terms of the availability of deductions, credits and other benefits. Variations also arise because income earned and taxed in any particular country or countries may fluctuate from year to year. Deferred tax assets and liabilities are recognized for the anticipated future tax effects of temporary differences between the financial statement basis and the tax basis of our assets and liabilities using the applicable jurisdictional tax rates in effect at year end. A valuation allowance for deferred tax assets is recorded when it is more likely than not that some or all of the benefit from the deferred tax asset will not be realized. See Note 5—Income Taxes.

Share-based compensation—As of January 1, 2006, we adopted SFAS No. 123 (revised 2004), Share-Based Payment ("SFAS 123R") using the modified prospective method ("Prospective Method"), and the adoption did not have a material effect on our consolidated statement of financial position, results of operations or cash flows.

Share-based compensation expense for the years ended December 31 is as follows (in millions):

For time-based awards, we recognize compensation expense on a straight-line basis through the date the employee is no longer required to provide service to earn the award ("service period"). For performance-based awards with graded vesting conditions, we recognize compensation expense on a straight-line basis over the service period for each separately vesting portion of the award as if the

award was, in substance, multiple awards. Share-based compensation expense is recognized, net of a forfeiture rate, estimated at the time of grant, based on historical experience and adjusted, if necessary, in subsequent periods based on actual forfeitures. Upon adoption of SFAS 123R, we applied the estimated forfeiture rate to all prior periods in which share-based compensation expense was recorded and recognized a cumulative effect of a change in accounting principle, which was not material to our consolidated statement of financial position, results of operations or cash flows.

To measure the fair values of restricted shares and deferred units granted or modified, we use the market price of our shares on the grant date or modification date. To measure the fair values of stock options and stock appreciation rights ("SARs") granted or modified, we use the Black-Scholes-Merton option-pricing model using assumptions for the expected life, risk-free interest rate, dividend yield and expected volatility. The expected life is based on historical information of past employee behavior regarding exercises and forfeitures of options. The risk-free interest rate is based upon the published U.S. Treasury yield curve in effect at the time of grant or modification for instruments with a similar life. The dividend yield is based on our history and expectation of dividend payouts. The expected volatility is based on a blended rate with an equal weighting of the (a) historical volatility based on historical data for an amount of time approximately equal to the expected life and (b) implied volatility derived from our at-the-money long-dated call options with a term of six months or longer.

We recognize share-based compensation expense in the same financial statement line item as cash compensation paid to the respective employees. Tax deduction benefits for awards in excess of recognized compensation costs are reported as a financing cash flow. See Note 18—Share-Based Compensation Plans.

Reclassifications—Certain reclassifications have been made to prior period amounts to conform with the current year presentation. These reclassifications did not have a material effect on our consolidated statement of financial position, results of operations or cash flows.

New accounting pronouncements—In September 2006, the Financial Accounting Standards Board ("FASB") issued SFAS No. 157, Fair Value Measurements ("SFAS 157"). SFAS 157 defines fair value, establishes a framework for measuring fair value under generally accepted accounting principles, and expands disclosures about fair value measurements. SFAS 157 does not require any new fair value measurements, but rather provides guidance for the application of fair value measurements required in other accounting pronouncements and seeks to eliminate inconsistencies in the application of such guidance among those other standards. SFAS 157 is effective for fiscal years beginning after November 15, 2007. In February 2008, the FASB issued FASB Staff Position ("FSP") No. FAS 157-2, Effective Date of FASB Statement No. 157, which delays the effective date of SFAS 157 to fiscal years beginning after November 15, 2008, for nonfinancial assets and nonfinancial liabilities except those that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually). In the first quarter 2008, we adopted those provisions of SFAS 157 that were unaffected by the delay. Such adoption did not have a material effect on our consolidated statement of financial position, results of operations or cash flows. In October 2008, the FASB issued FSP No. FAS 157-3, Determining the Fair Value of a Financial Asset When the Market for That Asset Is Not Active ("FSP 157-3"), that clarifies the application of SFAS 157 when the market is not active. We adopted FSP 157-3 as of September 30, 2008, which did not have a material effect on our consolidated statement of financial position, results of operations or cash flows.

entity's financial position, financial performance and cash flows. SFAS 161 is effective for fiscal years beginning after November 15, 2008. We will be required to adopt SFAS 161 in the first quarter of 2009. Because of our limited use of derivative instruments, we do not expect the adoption of SFAS 161 to have a significant impact on our consolidated statement of financial position, results of operations or cash flows.

In May 2008, the FASB issued SFAS No. 162, The Hierarchy of Generally Accepted Accounting Principles ("SFAS 162"), which identifies the sources of accounting principles and the framework for selecting the principles used in the preparation of financial statements of nongovernmental entities that are presented in conformity with accounting principles generally accepted in the U.S. SFAS 162 will be effective 60 days following the SEC's approval of certain amendments to auditing standards proposed by the Public Company Accounting Oversight Board. We do not expect the adoption of SFAS 162 to have an effect on our consolidated statement of financial position, results of operations or cash flows.

In May 2008, the FASB also issued FSP No. APB 14-1, Accounting for Convertible Debt Instruments That May Be Settled in Cash upon Conversion (Including Partial Cash Settlement) ("FSP APB 14-1"), which requires the issuer of certain convertible debt instruments to separately account for the liability and equity components of the instrument and reflect interest expense at the entity's market rate of borrowing for non-convertible debt instruments. FSP APB 14-1 requires retrospective restatement of all periods presented with the cumulative effect of the change in accounting principle on prior periods being recognized as of the beginning of the first period presented. The adoption of FSP APB 14-1 will have an effect on the accounting, both retrospectively and prospectively, for our convertible notes. Aside from a reduction of debt balances and an increase to shareholders' equity on our consolidated balance sheets for each period presented, we expect the retrospective application of FSP APB 14-1 will result in a non-cash increase to our annual historical interest expense, net of amounts capitalized, of approximately $9 million and $172 million for 2007 and 2008, respectively. Additionally, we expect that the adoption will result in a non-cash increase to our projected annual interest expense, net of amounts expected to be capitalized, of approximately $176 million, $206 million and $151 million for 2009, 2010 and 2011, respectively.

In June 2008, the FASB ratified the consensus on Emerging Issues Task Force ("EITF") Issue No. 07-5, Determining Whether an Instrument (or Embedded Feature) Is Indexed to an Entity's Own Stock ("EITF 07-5"). An instrument or embedded feature that is both indexed to an entity's own stock and potentially settled in shares may be exempt, if certain other criteria are met, from mark-to-market accounting of derivative financial instruments. EITF 07-5 addresses instruments with contingent and other adjustment features that may change the exercise price or notional amount or otherwise alter the payoff at settlement. We have both warrants and convertible notes outstanding that are exercisable or convertible into our shares. We do not expect EITF 07-5, which is effective for fiscal years beginning after December 15, 2008, to have a material effect on our consolidated statement of financial position, results of operations or cash flows after adoption.

In June 2008, the FASB issued FSP EITF 03-6-1, Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities ("FSP EITF 03-6-1"). FSP EITF 03-6-1 clarifies that all outstanding unvested share-based payment awards that contain rights to nonforfeitable dividends participate in undistributed earnings with common shareholders. Awards of this nature are considered participating securities and the two-class method of computing basic and diluted earnings per share must be applied. FSP EITF 03-6-1 is effective for fiscal years beginning after December 15, 2008. We do not expect the adoption of FSP EITF 03-6-1 to have a material effect on our consolidated statement of financial position, results of operations or cash flows.

statements for the year ending December 31, 2009. We do not expect the adoption to have a material effect on our consolidated statement of financial position, results of operations or cash flows.

In November 2007, we completed the Merger. We believe the Merger adds to and expands upon relationships with significant customers, expands our existing floater and jackup fleet and expands our presence in the major offshore drilling provinces. Transocean-Cayman issued approximately 107,752,000 ordinary shares and paid approximately $5 billion in cash in connection with the Merger.

We accounted for the Merger using the purchase method of accounting with Transocean treated as the accounting acquirer. As a result, the assets and liabilities of Transocean remain at historical amounts. The assets and liabilities of GlobalSantaFe were recorded at their estimated fair values at November 27, 2007, the date of completion of the GSF Transactions, with the excess of the purchase price over the sum of these fair values recorded as goodwill, and we have included the results of operations and cash flows for approximately one month of 2007 in our consolidated financial statements for the year ended December 31, 2007.

The purchase price included, at estimated fair value, current assets of $2.1 billion, drilling and other property and equipment of $12.3 billion, intangible assets of $368 million, other assets of $170 million and the assumption of current liabilities of $636 million, other long-term liabilities of $2.3 billion and long-term debt of $576 million. The excess of the purchase price over the estimated fair value of net assets acquired was $6.1 billion, which has been accounted for as goodwill.

In the fourth quarter of 2008, we completed our evaluation of the purchase price allocation. As a result, during 2008, we made adjustments to the estimated fair value of certain assets and liabilities with a corresponding net adjustment to goodwill amounting to $123 million, which are reflected in the amounts noted above. Our adjustments to the allocation of the fair value of assets acquired and liabilities assumed were primarily related to property and equipment, accrued pension liabilities, severance liabilities and income taxes, including deferred taxes, uncertain tax positions and other tax accruals. See Note 9—Goodwill and Other Intangible Assets.

Unaudited pro forma combined operating results of Transocean and GlobalSantaFe assuming the GSF Transactions were completed as of January 1, 2007 and 2006, respectively, are as follows (in millions, except per share data):

The unaudited pro forma financial information includes adjustments for additional depreciation based on the fair market value of the drilling and other property and equipment acquired, amortization of intangibles arising from the Merger, increased interest expense for debt assumed in the Merger and related adjustments for income taxes. The unaudited pro forma financial information has not been adjusted for additional charges and expenses or for other potential cost savings and operational efficiencies that may be realized as a result of the GSF Transactions. The unaudited pro forma financial information is not necessarily indicative of the result of operations had the GSF Transactions been completed on the assumed dates or the results of operations for any future periods.

In the fourth quarter 2008, we performed our annual impairment testing for intangible assets. We also identified interim indicators that resulted in testing our long-lived assets, goodwill and other intangible assets as of December 31, 2008. Based on the results of our tests, we determined that the goodwill associated with the contract drilling services reporting unit and the oil and gas properties reporting unit was not subject to impairment. We also concluded that the carrying values of our long-lived assets, excluding our assets held for sale, were not subject to impairment.

As a result of our impairment testing, we determined that the goodwill and other intangible assets associated with our drilling management services reporting unit were impaired. Accordingly, we recognized an impairment loss on full carrying amount of goodwill associated with this reporting unit in the amount of $176 million ($0.55 per share), which had no tax effect. We also impaired both the trade name and customer relationship intangible assets associated with this reporting unit and recorded impairments of $31 million ($20 million, or $0.06 per share, net of tax) and $16 million ($11 million, or $0.04 per share, net of tax), respectively.

We also performed impairment tests on our two rigs classified as assets held for sale, GSF Arctic II and GSF Arctic IV, having determined that they were subject to impairment indicators resulting from the credit crisis and rapid decline in commodity prices. Taking

consideration of liquidity concerns in the financial markets, market uncertainties and our undertakings to the Office of Fair Trading in the U.K. (the "OFT"), we estimated the fair values of the rigs and recognized an impairment loss of $97 million ($0.30 per share), which had no tax effect. See Note 8—Asset Dispositions.

Transocean Ltd., a holding company and Swiss resident, is exempt from cantonal and communal income tax in Switzerland, but is subject to Swiss federal income tax. At the federal level, qualifying net dividend income and net capital gains on the sale of qualifying investments in subsidiaries are exempt from Swiss federal income tax. Consequently, Transocean Ltd. expects dividends from its subsidiaries and capital gains from sales of investments in its subsidiaries to be exempt from Swiss federal income tax.

Our operations are conducted through our various subsidiaries in a number of countries throughout the world. We have provided for income taxes based upon the tax laws and rates in the countries in which operations are conducted and income is earned. The countries in which we operate have taxation regimes with varying nominal rates, deductions, credits and other tax attributes. Consequently, there is no expected relationship between the provision for or benefit from income taxes and income or loss before income taxes.

The components of our provision (benefit) for income taxes are as follows (in millions):

We are subject to changes in tax laws, treaties and regulations in and between the countries in which we operate. A material change in these tax laws, treaties or regulations could result in a higher or lower effective tax rate on our worldwide earnings.

We recognize deferred tax assets and liabilities for the anticipated future tax effects of temporary differences between the financial statement basis and the tax basis of our assets and liabilities at the applicable tax rates in effect. The significant components of deferred tax assets and liabilities are as follows (in millions):

We have not provided for deferred taxes in circumstances where we do not expect the operations in a jurisdiction to give rise to future tax consequences, due to the structure of operations and applicable law. Should our expectations change regarding the expected future tax consequences, we may be required to record additional deferred taxes that could have a material adverse effect on our consolidated statement of financial position, results of operations or cash flows.

The $41 million increase in our net deferred tax liability is composed primarily of $45 million related to adjustments to the net deferred tax liabilities assumed in connection with the Merger, which did not impact the statement of operations, and the deferred tax expense of $8 million. These increases were partly offset by $18 million of new tax benefits charged to equity accounts as a result of the tax effects of pension liability adjustments and deductions taken for employee option exercises.

We have not provided for deferred taxes on the unremitted earnings of certain subsidiaries that we consider to be permanently reinvested. Should we make a distribution of the unremitted earnings of these subsidiaries, we may be required to record additional taxes. Because we cannot predict when, if at all, we will make a distribution of these unremitted earnings, we are unable to make a determination of the amount of unrecognized deferred tax liability.

A valuation allowance for deferred tax assets is recorded when it is more likely than not that some or all of the benefit from the deferred tax asset will not be realized. We provide a valuation allowance to offset deferred tax assets for net operating losses ("NOL") incurred during the year in certain jurisdictions and for other deferred tax assets where, in our opinion, it is more likely than not that the financial statement benefit of these losses will not be realized. We provide a valuation allowance for foreign tax credit carryforwards to reflect the possible expiration of these benefits prior to their utilization. As of December 31, 2008, the valuation allowance for non-current deferred tax assets decreased from $29 million to $23 million. The decrease resulted primarily from reassessments of valuation allowances against deferred tax assets acquired in connection with the Merger, which did not impact the statement of operations. During the year ended December 31, 2007, our valuation allowance for non-current deferred tax assets decreased by $30 million to $29 million. The decrease resulted primarily from a $58 million release of valuation allowance against our U.S. foreign tax credits partly offset by a $28 million valuation allowance against deferred tax assets acquired in connection with the Merger.

Our U.K. NOL carryforwards do not expire. The tax effect of the U.K. NOL carryforwards was $27 million at December 31, 2008 and $49 million at December 31, 2007. We have generated additional NOL carryforwards in various worldwide tax jurisdictions. Our U.S. foreign tax credit carryforwards of $34 million, net of valuation allowances of $5 million, will expire between 2009 and 2016. Our U.S. alternative minimum tax credits of $1 million do not expire.

In addition to our recognized tax attributes, we have an unrecognized U.S. capital loss carryforward. We have not recognized a deferred tax asset for the capital loss carryforward as it is not probable that we will realize the benefit of this tax attribute. Our operations do not normally generate capital gain income, which is the only type of income that may be offset by capital losses. Certain payments from TODCO under the tax sharing agreement also serve to increase or decrease the capital loss carryforward. During 2008, we received $18 million of these payments from TODCO. Should an opportunity to utilize the remaining capital loss arise, the total potential tax benefit at December 31, 2008 was $770 million.

Our income tax returns are subject to review and examination in the various jurisdictions in which we operate. We are currently contesting various tax assessments. We accrue for income tax contingencies that we believe are more likely than not exposures in accordance with the provisions of FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes—an Interpretation of FASB Statement No. 109 ("FIN 48"), as adopted on January 1, 2007.

During the twelve months ended December 31, 2008, our total unrecognized tax benefits related to uncertain tax positions increased by $97 million to $521 million, including interest and penalties and net of foreign exchange rate fluctuations. The balance of $521 million includes $149 million of interest and penalties. If recognized, $503 million of this amount would favorably impact our effective tax rate.

A reconciliation of the unrecognized tax benefits, excluding interest and penalties, for the years ended December 31, 2008 and 2007 follows (in millions):

It is reasonably possible that our existing liabilities for unrecognized tax benefits may increase or decrease in the next twelve months primarily due to the progression of open audits or the expiration of statutes of limitation. However, we cannot reasonably estimate a range of potential changes in our existing liabilities for unrecognized tax benefits due to various uncertainties, such as the unresolved nature of various audits.

We accrue interest and penalties related to our liabilities for unrecognized tax benefits as a component of income tax expense. During the years ended December 31, 2008 and 2007, we increased the liability related to interest and penalties on our unrecognized tax benefits by $24 million and $41 million, respectively, which brought the interest and penalty component included in the December 31, 2008 liability for unrecognized tax benefits balance to $149 million. Included in the $41 million increase in interest and penalties during 2007 was a $10 million assumption of interest and penalty liabilities in connection with the Merger, which did not impact the statement of operations.

We, or one of our subsidiaries, file federal and local tax returns in several jurisdictions throughout the world. With few exceptions, we are no longer subject to examinations of our U.S. and non-U.S. tax matters for years prior to 1999. The amount of current tax benefit recognized during the years ended December 31, 2008 and December 31, 2007 from the settlement of disputes with tax authorities and the expiration of statute of limitations was insignificant.

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

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

In 2004, we entered into a tax sharing agreement (the "TSA") with TODCO in connection with the TODCO IPO. The TSA governs the parties' respective rights, responsibilities and obligations with respect to taxes and tax benefits, the filing of tax returns, the control of audits and other tax matters. Under the TSA, most U.S. federal, state, local and foreign income taxes and income tax benefits (including income taxes and income tax benefits attributable to the TODCO business) that accrued on or before the closing of the TODCO IPO will be for our account. Accordingly, we are generally liable for any income taxes that accrued on or before the closing of the TODCO IPO, but TODCO generally must pay us for the amount of any income tax benefits created on or before the closing of the TODCO IPO ("pre-closing tax benefits") that it uses or absorbs on a return with respect to a period after the closing of the TODCO IPO. Under this agreement, we are entitled to receive from TODCO payment for most of the tax benefits TODCO generated prior to the TODCO IPO that they utilize subsequent to the TODCO IPO.

In July 2007, Hercules Offshore, Inc. ("Hercules") completed the acquisition of TODCO (the "TODCO Acquisition"). The TSA required Hercules to make an accelerated change of control payment due to a deemed utilization of TODCO's pre-IPO tax benefits to us. The amount of the accelerated payment owed to us was calculated by multiplying 80 percent by the remaining pre-IPO tax benefits as of July 11, 2007. In August 2007, we received a $118 million change of control payment from Hercules. We disputed the amount of the change of control payment owed by Hercules under the TSA and, in September 2008, we recognized as other income, net $4 million associated with the final change of control payment. In addition to the final change of control payment, in 2008 we also recognized $14 million of other payments which we had previously received in connection with the TODCO TSA. The TSA also requires Hercules to make additional payments to us based on a portion of the tax benefit from the exercise of certain options to acquire our shares by TODCO's current and former employees and directors, when and if those options are exercised. We estimate that the total amount of payments related to options that remain outstanding at December 31, 2008 would be approximately $5 million, assuming a price of $47.25 per share at the time of exercise of the options (the actual price of our ordinary shares at the close of trading on December 31, 2008). However, there can be no assurance as to the amount and timing of any payment which Transocean Holdings may receive. In addition, any future reduction of the pre-IPO tax benefits by the U.S. taxing authorities upon examination of the TODCO tax returns may require us to reimburse TODCO for some of the amounts previously paid.

In 2008, 2007 and 2006, respectively, we recognized $18 million ($0.06 per diluted share), $277 million ($1.24 per diluted share) and $51 million ($0.22 per diluted share) of other income in our consolidated statement of operations related to TODCO's utilization of tax benefits and stock option deductions as a result of the filing of TODCO's 2007 tax return.

The reconciliation of the numerator and denominator used for the computation of basic and diluted earnings per share is as follows (in millions, except per share data):

	Years ended December 31,
	2008		2007		2006

Numerator for earnings per share:
Net income for basic earnings per share	$	4,202	$	3,131	$	1,385
Add back interest expense on the 1.5% convertible debentures		—		6		6
Net income for diluted earnings per share	$	4,202	$	3,137	$	1,391

Denominator for earnings per share:
Weighted-average shares outstanding for basic earnings per share		318		214		219
Effect of dilutive securities:
Stock options and other share-based awards		2		3		4
Warrants to purchase shares		1		2		2
1.5% convertible debentures		—		3		3
Weighted-average shares and assumed dilution for diluted earnings per share		321		222		228

Earnings per share
Basic	$	13.20	$	14.65	$	6.32
Diluted	$	13.09	$	14.14	$	6.10

Shares subject to issuance pursuant to the conversion features of the 1.625% Series A, 1.50% Series B and 1.50% Series C Convertible Senior Notes did not have an effect on the calculation for the years ended December 31, 2008 and 2007. Shares subject to issuance pursuant to the conversion features of the Zero Coupon Convertible Debentures and the Convertible Notes (see Note 11—Debt) are included in the calculation of adjusted weighted-average shares for the year ended December 31, 2007 and the Zero Coupon Convertible Debentures are included in the calculation of adjusted weighted-average shares for the year ended December 31, 2006; however, they did not have a material effect on the calculation for each year.

In connection with the Merger, we assumed all of GlobalSantaFe's outstanding employee stock options and stock appreciation rights. We accounted for the Reclassification as a reverse stock split and a dividend, which require restatement of historical weighted-average shares outstanding, historical earnings per share and other share-based calculations for prior periods. All references in our financial statements to number of shares and per share amounts have been retroactively restated to reflect the decreased number of shares issued and outstanding as a result of this accounting treatment unless otherwise noted.

Construction work in progress, recorded in property and equipment, was $4.5 billion and $3.1 billion at December 31, 2008 and 2007, respectively. The following table summarizes actual capital expenditures, including capitalized interest, for our major construction and conversion projects for the years ended December 31, 2008, 2007 and 2006 (in millions):

		2008	2007		2006		Total Costs

Discoverer India	$	250	$	—	$	—	$	250
Discoverer Luanda (a)		208		107		—		315
Discoverer Inspiration		205		120		118		443
Discoverer Americas		167		195		116		478
Deepwater Champion(b)		155		109		—		264
Development Driller III (b)		133		350		—		483
Sedco 700-series upgrades		124		250		146		520
Discoverer Clear Leader		107		195		214		516
Dhirubhai Deepwater KG1 (c)		105		279		—		384
Dhirubhai Deepwater KG2 (c)		91		179		—		270
Petrobras 10000 (d)		—		—		—		—
Capitalized Interest		114		76		16		206
Total	$	1,659	$	1,860	$	610	$	4,129

In April 2008, we were awarded a five-year drilling contract for a fifth enhanced Enterprise-class drillship, to be named Discoverer India, the term of which may be extended to seven or 10 years at the client's election up to one week after mobilization. The contract for this Ultra-Deepwater Floater is expected to commence during the fourth quarter of 2010, following completion of construction in South Korea, sea trials, mobilization and customer acceptance.

During 2008, we completed the sale of three of our Standard Jackups (GSF High Island VIII, GSF Adriatic III and GSF High Island I). We received cash proceeds of $320 million associated with the sales, which had no effect on earnings.

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

During 2007, we sold a Deepwater Floater (Peregrine I), a tender rig (Charley Graves) and a swamp barge (Searex VI). We received net proceeds from these sales of $344 million and recognized gains on the sales of $264 million ($261 million, or $1.16 per diluted share, net of tax).

During 2006, we sold three of our Midwater Floaters (Peregrine III, Transocean Explorer and Transocean Wildcat), three of our tender rigs (W.D. Kent, Searex IX and Searex X), a swamp barge (Searex XII) and a platform rig. We received net proceeds from these sales of $464 million and recognized gains on the sales of $411 million ($386 million, or $1.19 per diluted share, net of tax).

Goodwill—Our goodwill balance and changes in the carrying amount of goodwill are as follows (in millions):

Other intangible assets—In connection with the Merger, we acquired drilling contracts for future contract drilling services of GlobalSantaFe, the terms of some of which extend through 2016. These contracts include fixed dayrates that were above or below dayrates for similar contracts available in the market as of the date of the Merger. After determining the fair values of these drilling contracts as of the date of the Merger, we recorded the respective market adjustments on our consolidated balance sheet as intangible assets and liabilities that we amortize into contract intangible revenues using the straight-line method over the respective contract periods. During the years ended December 31, 2008 and 2007, we recognized $690 million and $88 million, respectively, in contract intangible revenues.

Additionally, we identified other intangible assets associated with customer relationships, contract backlog and the trade name of our drilling management services business.

We consider the ADTI trade name to be an indefinite-lived intangible asset, which will not be amortized and will be subject to an annual impairment test. The carrying value of the trade name is comprised of the following (in millions):

In the fourth quarter of 2008, we recorded an impairment of the trade name intangible asset. See Note 4—Impairment Loss.

The carrying value of definite-lived intangible assets and intangible liabilities are comprised of the following (in millions):

	December 31, 2008									December 31, 2007
		Gross carrying value			Accumulated amortization			Net carrying value			Gross carrying value		Accumulated amortization			Net carrying value

Drilling contract intangible assets	$	191		$	(123	)	$	68		$	191	$	(12	)	$	179
ADTI customer relationships		132	(a)		(11	)		121	(a)		148		(3	)		145
ADTI contract backlog		16			(16	)		—			16		(5	)		11
Total intangible assets	$	339		$	(150	)	$	189		$	355	$	(20	)	$	335

Drilling contract intangible liabilities	$	1,494		$	(901	)	$	593		$	1,494	$	(100	)	$	1,394

We recognize contract intangible revenues over nine years and amortize the balances using the straight-line method over the respective contract periods. The customer relationships and contract backlog have definite lifespans over which we amortize using the straight-line method. The customer relationships will be amortized over their useful lives of 15 years. The contract backlog was amortized over its useful life of three months and was fully amortized during the three months ended March 31, 2008. The estimated net future amortization expense (income) related to intangible assets and liabilities as of December 31, 2008 is as follows (in millions):

Debt, net of unamortized discounts, premiums and fair value adjustments, is as follows (in millions):

	December 31,
	2008		2007

Commercial paper program (a)	$	663	$	—
Floating Rate Notes due September 2008 (a)		—		1,000
Bridge Loan Facility due November 2008 (a)		—		3,670
Former 364-Day Revolving Credit Facility due December 2008 (a)		—		1,500
Term Loan due March 2010		2,000		—
6.625% Notes due April 2011		174		177
5% Notes due February 2013		248		246
5.25% Senior Notes due March 2013		499		499
TPDI Credit Facilities due June 2015		288		—
ADDCL Secondary Loan Facility due December 2015		25		—
TPDI Notes due October 2017		111		238
ADDCL Primary Loan Facility due December 2017		255		—
6.00% Senior Notes due March 2018		997		997
7.375% Senior Notes due April 2018		247		247
Capital lease obligation due July 2026 (b)		16		17
8% Debentures due April 2027		57		57
7.45% Notes due April 2027		96		95
7% Senior Notes due June 2028		313		314
7.5% Notes due April 2031		598		598
1.625% Series A Convertible Senior Notes due December 2037		2,200		2,200
1.50% Series B Convertible Senior Notes due December 2037		2,200		2,200
1.50% Series C Convertible Senior Notes due December 2037		2,200		2,200
6.80% Senior Notes due March 2038		999		999
ODL Loan Facility		—		3
Total debt		14,186		17,257
Less debt due within one year (a)(b)		664		6,172
Total long-term debt	$	13,522	$	11,085

The scheduled maturities of our debt assumes the bondholders exercise their options to require Transocean-Cayman to repurchase the 1.625% Series A, 1.50% Series B and 1.50% Series C Convertible Senior Notes in December 2010, 2011 and 2012, respectively. These maturities exclude maturities associated with our future indebtedness in connection with Petrobras 10000, which will be held under a capital lease upon completion. The scheduled maturities are as follows (in millions):

Parent company guarantee of subsidiary debt—Transocean-Cayman, a wholly-owned subsidiary and the principal asset of Transocean Ltd., is the issuer of certain debt securities that have been guaranteed by Transocean Ltd., as described below. Transocean Ltd. has no independent assets or operations, its guarantee of Transocean-Cayman's debt securities is full and unconditional and its only other subsidiaries are minor. There are no significant restrictions on Transocean Ltd.'s ability to obtain funds from its consolidated subsidiaries or entities accounted for under the equity method by dividends, loans or return of capital distributions.

Commercial paper program—In December 2007, Transocean-Cayman entered into a commercial paper program (the "Program") on a private placement basis under which Transocean-Cayman may issue unsecured commercial paper notes up to a maximum aggregate amount outstanding at any time of $1.5 billion. The 364-Day Revolving Credit Facility and the Five-Year Revolving Credit Facility provide liquidity for the Program. Under the Program, Transocean-Cayman may issue commercial paper from time to time, and amounts available under the Program may be reborrowed. The proceeds from the commercial paper issuance may be used for general corporate purposes. In December 2008, we and Transocean-Cayman entered into amendments to the Program to provide for the guarantee by us of Transocean-Cayman's obligations under the Program after the completion of the Redomestication Transaction. At December 31, 2008, $663 million in commercial paper was outstanding at a weighted-average interest rate of 5.79 percent.

Floating Rate Notes—In September 2006, Transocean-Cayman issued $1.0 billion aggregate principal amount of floating rate notes, due September 2008 ("Floating Rate Notes"). The per annum interest rate on the Floating Rate Notes was equal to the three-month London Interbank Offered Rate ("LIBOR"), reset on each payment date, plus 0.20 percent. In September 2008, Transocean-Cayman repaid the Floating Rate Notes at maturity.

Bridge Loan Facility—In September 2007, Transocean-Cayman entered into a $15.0 billion, one-year senior unsecured bridge loan facility ("Bridge Loan Facility"). In connection with the GSF Transactions, Transocean-Cayman borrowed $15.0 billion under the Bridge Loan Facility at LIBOR plus the applicable margin, which was based upon Transocean-Cayman's non-credit enhanced senior unsecured long-term debt rating ("Debt Rating"). In June 2008, Transocean-Cayman repaid the then outstanding balance and terminated this facility.

364-Day Revolving Credit Facility—In November 2008, Transocean-Cayman entered into a new credit agreement for a 364-day, $1.08 billion revolving credit facility (the "364-Day Revolving Credit Facility") to replace its expiring $1.5 billion revolving credit agreement entered into in December 2007 (the "Former 364-Day Revolving Credit Facility"), and terminated the expiring agreement. Upon completion of the Redomestication Transaction, we guaranteed Transocean-Cayman's obligations under the 364-Day Revolving Credit Facility.

Under the 364-Day Revolving Credit Facility, Transocean-Cayman may borrow at either (1) the adjusted LIBOR plus a margin determined by reference to the mid-point credit default swap spread for its senior unsecured debt with a maturity of one year, subject to a ceiling varying from 1.75 percent to 3.75 percent per annum and a floor of 0.75 percent to 1.75 percent per annum, in each case depending on Transocean-Cayman's Debt Rating (such margin, the "364-Day Revolving Credit Facility Margin"), or (2) a base rate, determined as the greatest of (A) a prime rate, (B) the federal funds effective rate plus 1/2 of one percent and (C) the adjusted LIBOR for a one-month interest period plus one percent per annum (the "Base Rate"), plus the 364-Day Revolving Credit Facility Margin, less one percent per annum. At December 31, 2008, no amounts were outstanding under the 364-Day Revolving Credit Facility.

The 364-Day Revolving Credit Facility includes limitations on creating liens, incurring subsidiary debt, transactions with affiliates, sale/leaseback transactions, mergers and the sale of substantially all assets. The 364-Day Revolving Credit Facility also includes covenants imposing a maximum leverage ratio, which may not exceed 3.0 to 1.0. Borrowings under the 364-Day Revolving Credit Facility are subject to acceleration upon the occurrence of events of default. The 364-Day Revolving Credit Facility may be prepaid in whole or in part without premium or penalty.

Term Loan—In March 2008, Transocean-Cayman entered into a term credit facility under the Term Credit Agreement dated March 13, 2008 (the "Term Loan") and borrowed $1.925 billion under the facility. In April 2008, Transocean-Cayman borrowed an additional $75 million, increasing the borrowings under this facility to $2.0 billion, the maximum allowed under the Term Loan. In November 2008, in connection with the Redomestication, Transocean-Cayman amended the Term Loan. Upon completion of the Redomestication Transaction, we guaranteed Transocean-Cayman's obligations under the Term Loan.

Transocean-Cayman may borrow under the Term Loan at either (1) the adjusted LIBOR plus a margin (the "Term Loan Margin") based on Transocean-Cayman's Debt Rating (based on its current Debt Rating, a margin of 1.25 percent), or (2) the Base Rate plus the Term Loan Margin, less one percent per annum. At December 31, 2008, Transocean-Cayman had $2.0 billion outstanding under the Term Loan at a weighted-average interest rate of 5.0 percent.

The Term Loan includes limitations on creating liens, incurring subsidiary debt, transactions with affiliates, sale/leaseback transactions, mergers and the sale of substantially all assets. The Term Loan also includes covenants imposing a maximum leverage ratio, which may not exceed 3.0 to 1.0. Additionally, the Term Loan includes a covenant imposing a maximum debt to capitalization ratio of 0.6 to 1.0. Borrowings under the Term Loan are subject to acceleration upon the occurrence of events of default. The Term Loan may be prepaid in whole or in part without premium or penalty.

6.625% Notes and 7.5% Notes—In April 2001, Transocean-Cayman issued $700 million aggregate principal amount of 6.625% Notes due April 2011 and $600 million aggregate principal amount of 7.5% Notes due April 2031. Upon completion of the Redomestication Transaction, we guaranteed Transocean-Cayman's obligations under the notes. The indenture pursuant to which the notes were issued contains restrictions on creating liens, engaging in sale/leaseback transactions and engaging in merger, consolidation or reorganization transactions. At December 31, 2008, $166 million and $600 million principal amount of the 6.625% Notes and 7.5% Notes, respectively, were outstanding.

Five-Year Revolving Credit Facility—In November 2007, Transocean-Cayman entered into a $2.0 billion, five-year revolving credit facility under the Five-Year Revolving Credit Facility Agreement dated November 27, 2007 ("Five-Year Revolving Credit Facility"). In November 2008, in connection with the Redomestication Transaction, Transocean-Cayman amended the Five-Year Revolving Credit Facility. Upon completion of the Redomestication Transaction, we guaranteed Transocean-Cayman's obligations under the Five-Year Revolving Credit Facility.

Transocean-Cayman may borrow under the Five-Year Revolving Credit Facility at either (1) the adjusted LIBOR plus a margin (the "Five-Year Revolving Credit Facility Margin") based on Transocean-Cayman's Debt Rating (based on its current Debt Rating, a margin of 1.1 percent) or (2) the Base Rate plus the Five-Year Revolving Credit Facility Margin, less one percent per annum. Additionally, a facility fee is incurred on the daily amount of the underlying commitment, whether used or unused, throughout the term of the Five-Year Revolving Credit Facility. The amount of such facility fee depends on Transocean-Cayman's Debt Rating (based on its current Debt Rating, a facility fee of 0.15 percent) and varies from 0.10 percent to 0.30 percent. At December 31, 2008, Transocean-Cayman had no amounts outstanding under the Five-Year Revolving Credit Facility.

The Five-Year Revolving Credit Facility includes limitations on creating liens, incurring subsidiary debt, transactions with affiliates, sale/leaseback transactions, mergers and the sale of substantially all assets. The Five-Year Revolving Credit Facility also includes covenants imposing a maximum leverage ratio, which may not exceed 3.0 to 1.0. Additionally, the Five-Year Revolving Credit Facility includes a covenant imposing a maximum debt to capitalization ratio of 0.6 to 1.0. Borrowings under the Five-Year Revolving Credit Facility are subject to acceleration upon the occurrence of events of default. The Five-Year Revolving Credit Facility may be prepaid in whole or in part without premium or penalty.

5% Notes and 7% Notes—In November 2007, Transocean Worldwide Inc. executed a supplemental indenture to assume the obligations related to the 5% Notes due 2013 (the "5% Notes") issued by GlobalSantaFe under the indenture dated as of February 1, 2003. Additionally, as a result of the Merger, we acquired Global Marine Inc., formerly a subsidiary of GlobalSantaFe and now our subsidiary, which is the obligor on the 7% Notes due 2028 (the "7% Notes"), which were issued under the indenture dated as of September 1, 1997. The 5% Notes are the obligation of Transocean Worldwide Inc. and the 7% Notes are the obligation of Global Marine Inc., and we have not guaranteed either obligation. The respective obligor may redeem the 5% Notes and the 7% Notes in whole or in part at a price equal to 100 percent of the principal amount plus accrued and unpaid interest, if any, and a make-whole premium. The indentures related to the 5% Notes and the 7% Notes contain limitations on creating liens and sale/leaseback transactions. At December 31, 2008, $250 million and $300 million aggregate principal amount of the 5% Notes and the 7% Notes, respectively, remained outstanding.

5.25%, 6.00% and 6.80% Senior Notes—In December 2007, Transocean-Cayman issued $0.5 billion aggregate principal amount of 5.25% Senior Notes due March 2013 (the "5.25% Senior Notes"), $1.0 billion aggregate principal amount of 6.00% Senior Notes due March 2018 (the "6.00% Senior Notes") and $1.0 billion aggregate principal amount of 6.80% Senior Notes due March 2038 (the "6.80% Senior Notes," and together with the 5.25% Senior Notes and the 6.00% Senior Notes, the "Senior Notes"). Transocean-Cayman

is required to pay interest on the Senior Notes on March 15 and September 15 of each year, beginning March 15, 2008. Transocean-Cayman may redeem some or all of the notes at any time, at a redemption price equal to 100 percent of the principal amount plus accrued and unpaid interest, if any, and a make-whole premium. Upon completion of the Redomestication Transaction, we guaranteed Transocean-Cayman's obligations under the notes. The indenture pursuant to which the notes were issued contains restrictions on creating liens, engaging in sale/leaseback transactions and engaging in merger, consolidation or reorganization transactions. At December 31, 2008, $500 million, $1.0 billion and $1.0 billion principal amount of the 5.25%, 6.00% and 6.80% Senior Notes, respectively, were outstanding.

TPDI Credit Facilities—In October 2008, TPDI entered into a credit agreement for a $1.265 billion secured credit facility (the "TPDI Term Loan Facility"), comprised of a $1.0 billion senior tranche, a $190 million junior tranche and a $75 million revolving credit facility (the "TPDI Revolving Credit Facility", and together with the TPDI Term Loan Facility, the "TPDI Credit Facilities"). The TPDI Credit Facilities will finance the construction of Dhirubhai Deepwater KG1 and Dhirubhai Deepwater KG2. One of our subsidiaries participates in the senior and junior tranches with a 50 percent commitment totaling $595 million in the aggregate. The TPDI Credit Facilities will bear interest at LIBOR plus the applicable margin of 1.60 percent until acceptance of Dhirubhai Deepwater KG2. Subsequently, the TPDI Credit Facilities will bear interest at a rate of 1.45 percent for the senior tranche and the revolving credit facility and 2.25 percent for the junior tranche. The senior tranche requires quarterly payments with a final payment on the earlier of (1) June 2015 and (2) the fifth anniversary of the acceptance date of the second rig. The junior tranche is due in full on the earlier of (1) June 2015 and (2) the fifth anniversary of the acceptance date of the second rig. The TPDI Credit Facilities have covenants that require TPDI to maintain minimum liquidity requirements, a minimum debt service ratio and a maximum leverage ratio. The TPDI Credit Facilities may be prepaid in whole or in part without premium or penalty. At December 31, 2008, $576 million was outstanding, of which $288 million was due to one of our subsidiaries and was eliminated in consolidation. The weighted-average interest rate on December 31, 2008 was 2.1 percent.

ADDCL Secondary Loan Facility—In September 2008, ADDCL completed final documentation for a secondary loan agreement for a $90 million credit facility (the "ADDCL Secondary Loan Facility"), for which one of our subsidiaries provides 65 percent of the total commitment and an external lender provides the remaining 35 percent. The facility bears interest at LIBOR plus the applicable margin, ranging from 3.125 percent to 5.125 percent, depending on certain milestones, as defined by the loan agreement. The facility is payable in full the earlier of 90 days after the fifth anniversary of the first well commencement or December 2015 and may be prepaid in whole or in part without premium or penalty. At December 31, 2008, the weighted-average interest rate was 4.7 percent on the $71 million outstanding balance, of which $46 million was provided by one of our subsidiaries and has been eliminated in consolidation.

TPDI Notes—In October 2008, using borrowings under the TPDI Credit Facilities, TPDI prepaid $440 million of outstanding promissory notes, $220 million of which was due to one of our subsidiaries. As of December 31, 2008, $222 million in promissory notes remained outstanding, $111 million of which was due to one of our subsidiaries and has been eliminated in consolidation. The debt bears interest at LIBOR plus an applicable spread, and the weighted-average interest rate was 5.3 percent at December 31, 2008.

Borrowings under Tranche A and Tranche B bear interest at LIBOR plus the applicable margin of 0.425 percent until the first well commencement date, following which the loans outstanding under Tranche A will bear interest at LIBOR plus the applicable margin of 0.725 percent. ADDCL is required to enter into fixed-for-floating interest rate swaps with one of our subsidiaries for the loans outstanding under Tranche A. Borrowings under Tranche C will bear interest at a fixed rate to be determined by a fixed-to-floating interest rate swap plus an applicable margin of 2 percent. At December 31, 2008, the borrowings under Tranche A and Tranche B were $115 million and $140 million, respectively, at a weighted-average interest rate of 3.8 percent. At December 31, 2008, there were no borrowings outstanding under Tranche C.

Capital lease obligation—The GSF Explorer is held under a capital lease through 2026. See Note 17—Commitments and Contingencies.

7.45% Notes and 8% Debentures—In April 1997, a predecessor of Transocean-Cayman issued $100 million aggregate principal amount of 7.45% Notes due April 2027 (the "7.45% Notes") and $200 million aggregate principal amount of 8% Debentures due April 2027 (the "8% Debentures"). The 7.45% Notes and the 8% Debentures are redeemable at any time at Transocean-Cayman's option subject to a make-whole premium. Upon completion of the Redomestication Transaction, we guaranteed Transocean-Cayman's obligations under the 7.45% Notes and the 8% Debentures. The indenture pursuant to which the 7.45% Notes and the 8% Debentures

were issued contains restrictions on creating liens, engaging in sale/leaseback transactions and engaging in merger, consolidation or reorganization transactions. At December 31, 2008, $100 million and $57 million principal amount of the 7.45% Notes and the 8% Debentures, respectively, were outstanding.

1.625% Series A, 1.50% Series B and 1.50% Series C Convertible Senior Notes—In December 2007, Transocean-Cayman issued $2.2 billion aggregate principal amount of 1.625% Series A Convertible Senior Notes due December 2037 (the "Series A Notes"), $2.2 billion aggregate principal amount of 1.50% Series B Convertible Senior Notes due December 2037 (the "Series B Notes") and $2.2 billion aggregate principal amount of 1.50% Series C Convertible Senior Notes due December 2037 (the "Series C Notes," and together with the Series A and Series B Notes, the "Convertible Notes"). Transocean-Cayman is required to pay interest on the Convertible Notes on June 15 and December 15 of each year, beginning June 15, 2008. Upon completion of the Redomestication Transaction, we guaranteed Transocean-Cayman's obligations under the notes and assumed the obligation to deliver shares, if any, upon conversion of the Convertible Notes. The Convertible Notes may be converted under the circumstances specified below at a rate of 5.9310 shares per $1,000 note. The initial conversion rate is subject to adjustments upon the occurrence of certain corporate events but not for accrued interest. Upon conversion, we will deliver, in lieu of shares, cash up to the aggregate principal amount of notes to be converted and shares in respect of the remainder, if any, of our conversion obligation in excess of the aggregate principal amount of the notes being converted. In addition, if certain fundamental changes occur on or before December 20, 2010, with respect to Series A Notes, December 20, 2011, with respect to Series B Notes or December 20, 2012, with respect to Series C Notes, we will in some cases increase the conversion rate for a holder electing to convert notes in connection with such fundamental change. Transocean-Cayman may redeem some or all of the notes at any time after December 20, 2010, in the case of the Series A Notes, December 20, 2011, in the case of the Series B Notes and December 20, 2012, in the case of the Series C Notes, in each case at a redemption price equal to 100 percent of the principal amount plus accrued and unpaid interest, if any. Holders of the Series A Notes and Series B Notes have the right to require Transocean-Cayman to repurchase their notes on December 15, 2010 and December 15, 2011, respectively. In addition, holders of any series of notes will have the right to require Transocean-Cayman to repurchase their notes on December 14, 2012, December 15, 2017, December 15, 2022, December 15, 2027 and December 15, 2032, and upon the occurrence of a fundamental change, at a repurchase price in cash equal to 100 percent of the principal amount of the notes to be repurchased plus accrued and unpaid interest, if any. At December 31, 2008, $2.2 billion principal amount of each of the Series A Notes, Series B Notes and Series C Notes were outstanding.

Holders may convert their notes only under the following circumstances: (1) during any calendar quarter after March 31, 2008 if the last reported sale price of our shares for at least 20 trading days in a period of 30 consecutive trading days ending on the last trading day of the preceding calendar quarter is more than 130 percent of the conversion price, (2) during the five business days after the average trading price per $1,000 principal amount of the notes is equal to or less than 98 percent of the average conversion value of such notes during the preceding five trading-day period as described herein, (3) during specified periods if specified distributions to holders of our shares are made or specified corporate transactions occur, (4) prior to the close of business on the business day preceding the redemption date if the notes are called for redemption or (5) on or after September 15, 2037 and prior to the close of business on the business day prior to the stated maturity of the notes. The Redomestication triggered the right of holders to convert the Convertible Notes at any time beginning on December 3, 2008, which is the date 15 days prior to the effective time of the Redomestication (the "Effective Time") of December 18, 2008, and ending on February 3, 2009, which is the 30^th scheduled trading day following the Effective Time. As of December 31, 2008, we received conversion notices with respect to approximately $384,000 principal amount of Convertible Notes and will be required to pay $114,000 in aggregate to the holders upon settlement. Except for the principal amount of the Convertible Notes for which we received conversion notices, the outstanding principal amount of the Convertible Notes, in the aggregate amount of $6.6 billion was classified in long-term debt as of December 31, 2008.

Debt redemptions, refinancing and repayments—In August 2007, Transocean-Cayman terminated its existing two-year Term Credit Facility. Prior to the termination, Transocean-Cayman repaid the then outstanding balance of $470 million. We recognized a loss on the termination of this debt of $1 million, which had no tax effect.

In November 2007, Transocean-Cayman terminated its $1.0 billion Former Revolving Credit Facility. We recognized a loss on the termination of this debt of $1 million, which had no tax effect.

In December 2007, Transocean-Cayman refinanced a total of $10.5 billion of borrowings under the Bridge Loan Facility using proceeds from borrowings under the Former 364-Day Revolving Credit Facility, the Senior Notes and the Convertible Notes. We recognized a loss on the retirement of this debt of $6 million ($0.03 per diluted share), which had no tax effect. In addition, Transocean-Cayman repaid $820 million of borrowings under the Bridge Loan Facility using internally generated cash flow.

In October 2007, Transocean-Cayman called its Zero Coupon Convertible Debentures due May 15, 2020. Between the notification and the trading day prior to the redemption date, holders retained the right to convert the debentures into Transocean-Cayman ordinary shares at a rate of 8.1566 ordinary shares per $1,000 debenture. During this period, Transocean-Cayman issued 148,244 ordinary shares upon conversion of $18 million aggregate principal amount of debentures. In November 2007, Transocean-Cayman redeemed the remaining debentures at an approximate cost of $18,000, plus accrued and unpaid interest.

In October 2007, Transocean-Cayman also called its 1.5% Convertible Debentures due May 15, 2021. Between the notification date and the fourth trading day prior to the redemption date, holders retained the right to convert the debentures into Transocean-Cayman's ordinary shares at a rate of 13.8627 ordinary shares per $1,000 debenture. During this period, Transocean-Cayman issued 5,499,613 ordinary shares upon conversion of $397 million aggregate principal amount of debentures. In November 2007, Transocean-Cayman redeemed the remaining debentures at an approximate cost of $3 million, plus accrued and unpaid interest.

Holders of Transocean-Cayman's 1.5% Convertible Debentures due May 15, 2021 had the option to require Transocean-Cayman to repurchase their debentures in May 2006; however, no holders exercised such right. In May 2006, holders of $101,000 aggregate principal amount converted their debentures into Transocean-Cayman's ordinary shares at a conversion rate of 13.8627 ordinary shares per $1,000 debenture, resulting in the issuance of 1,399 ordinary shares.

In June 2001 and February 2002, we entered into interest rate swaps with various banks related to certain notes in the aggregate notional amount of $1.6 billion. In January 2003, we terminated all our outstanding interest rate swaps, which were designated as fair value hedges, and recorded $174 million as a fair value adjustment to the underlying long-term debt in our consolidated balance sheet. We amortize this amount as a reduction to interest expense over the remaining life of the underlying debt. During the years ended December 31, 2008, 2007 and 2006 such reduction amounted to $3 million ($0.01 per diluted share) for each year. At December 31, 2008, 2007 and 2006, the remaining balance to be amortized was $8 million, $12 million and $15 million respectively, which was entirely related to the 6.625% Notes due April 2011.

At December 31, 2008, 2007 and 2006, we had no outstanding interest rate swaps. See Note 26—Subsequent Events.

The following methods and assumptions were used to estimate the fair value of each class of financial instruments for which it is practicable to estimate that value:

Cash and cash equivalents—The carrying amounts approximate fair value because of the short maturity of those instruments.

Accounts receivable-trade—The carrying amount, net of valuation allowance approximates fair value because of the short maturity of those instruments.

Short-term investments—The carrying amount represents the estimated fair value, measured pursuant to SFAS 157 using quoted prices for identical instruments in active markets and quoted prices for identical or similar instruments in markets that are not active.

Debt—The carrying value and estimated fair value are comprised of the following (in millions):

The fair value of our fixed rate debt is calculated based on market prices. The carrying value of variable rate debt approximates fair value due to the amendments to our credit facilities in November 2008, including increased credit facility fees. The fair value of the TPDI Notes and the ODL Loan Facility with an aggregate carrying value of $111 million and $241 million at December 31, 2008 and 2007, respectively, is included in the fair values stated above since there is no available market price for such related party debts (see Note 24—Related Party Transactions).

Foreign exchange risk—Our international operations expose us to foreign exchange risk. This risk is primarily associated with compensation costs denominated in currencies other than the U.S. dollar, which is our functional currency, and with purchases from foreign suppliers. We use a variety of techniques to minimize the exposure to foreign exchange risk, including customer contract payment terms and the possible use of foreign exchange derivative instruments.

Our primary foreign exchange risk management strategy involves structuring customer contracts to provide for payment in both U.S. dollars and local currency. The payment portion denominated in local currency is based on anticipated local currency requirements over the contract term. Due to various factors, including customer acceptance, local banking laws, other statutory requirements, local currency convertibility and the impact of inflation on local costs, actual foreign exchange needs may vary from those anticipated in the customer contracts, resulting in partial exposure to foreign exchange risk. Fluctuations in foreign currencies typically have not had a material impact on overall results. In situations where payments of local currency do not equal local currency requirements, foreign exchange derivative instruments, specifically foreign exchange forward contracts, or spot purchases, may be used to mitigate foreign

currency risk. A foreign exchange forward contract obligates us to exchange predetermined amounts of specified foreign currencies at specified exchange rates on specified dates or to make an equivalent U.S. dollar payment equal to the value of such exchange.

We do not enter into derivative transactions for speculative purposes. Gains and losses on foreign exchange derivative instruments, which qualify as accounting hedges, are deferred as other comprehensive income and recognized when the underlying foreign exchange exposure is realized. Gains and losses on foreign exchange derivative instruments, which do not qualify as hedges for accounting purposes, are recognized currently based on the change in market value of the derivative instruments. At December 31, 2008 and 2007, we had no outstanding foreign exchange derivative instruments.

Interest rate risk—Our use of debt directly exposes us to interest rate risk. Floating rate debt, where the interest rate can be changed every year or less over the life of the instrument, exposes us to short-term changes in market interest rates. Fixed rate debt, where the interest rate is fixed over the life of the instrument and the instrument's maturity is greater than one year, exposes us to changes in market interest rates should we refinance maturing debt with new debt.

In addition, we are exposed to interest rate risk in our cash investments, as the interest rates on these investments change with market interest rates.

From time to time, we may use interest rate swap agreements to manage the effect of interest rate changes on future income. These derivatives are used as hedges and are not used for speculative or trading purposes. Interest rate swaps are designated as a hedge of underlying future interest payments. These agreements involve the exchange of amounts based on variable interest rates and amounts based on a fixed interest rate over the life of the agreement without an exchange of the notional amount upon which the payments are based. The interest rate differential to be received or paid on the swaps is recognized over the lives of the swaps as an adjustment to interest expense. Gains and losses on terminations of interest rate swap agreements are deferred and recognized as an adjustment to interest expense over the remaining life of the underlying debt. In the event of the early retirement of a designated debt obligation, any realized or unrealized gain or loss from the swap would be recognized in income.

We had no interest rate swap transactions outstanding as of December 31, 2008 and 2007. See Note 26—Subsequent Events.

Credit risk—Financial instruments that potentially subject us to concentrations of credit risk are primarily cash and cash equivalents, short-term investments and trade receivables. It is our practice to place our cash and cash equivalents in time deposits at commercial banks with high credit ratings or mutual funds, which invest exclusively in high quality money market instruments. We limit the amount of exposure to any one institution and do not believe we are exposed to any significant credit risk.

We derive the majority of our revenue from services to international oil companies, government-owned and government-controlled oil companies. Receivables are dispersed in various countries. See Note 23—Segments, Geographical Analysis and Major Customers. We maintain an allowance for doubtful accounts receivable based upon expected collectibility and establish reserves for doubtful accounts on a case-by-case basis when we believe the required payment of specific amounts owed to us is unlikely to occur. Although we have encountered isolated credit problems with independent oil companies, we are not aware of any significant credit risks relating to our customer base and do not generally require collateral or other security to support customer receivables.

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

Note 16—Retirement Plans, Other Postemployment Benefits and Other Benefit Plans

Defined benefit pension plans—We maintain two qualified defined benefit pension plans in the U.S., one of which we assumed in connection with the Merger (the "Retirement Plans"), covering substantially all U.S. employees. We also maintain two unfunded supplemental benefit plans (the "Supplemental Benefit Plans") and two other unfunded supplemental benefit plans (the "Other Supplemental Benefit Plans"), three of which we assumed in connection with the Merger, to provide certain eligible employees with benefits in excess of those allowed under the Retirement Plans. Effective January 1, 2009, we merged the two Retirement Plans to form a single qualified defined benefit pension plan, and we combined the two Supplemental Benefit Plans to form a single unfunded supplemental benefit plan.

We assumed three defined benefit pension plans in connection with the R&B Falcon merger (two funded and one unfunded) and one unfunded defined benefit plan in connection with the Merger (collectively, the "Frozen Plans"), all of which were frozen prior to the respective mergers and for which benefits no longer accrue but the pension obligations have not been fully distributed.

We refer to the Retirement Plans, the Supplemental Benefit Plans, the Other Supplemental Benefit Plans and the Frozen Plans, collectively, as the "U.S. Plans".

Also, as a result of the Merger, we assumed a defined benefit plan in the U.K. (the "U.K. Plan") covering certain current and former legacy GlobalSantaFe employees in the U.K. In addition, we provide several defined benefit plans, primarily group pension schemes with life insurance companies covering our Norway operations and two unfunded plans covering certain of our employees and former employees (the "Norway Plans"). Our contributions to the Norway Plans are determined primarily by the respective life insurance companies based on the terms of the plan. For the insurance-based plans, annual premium payments are considered to represent a reasonable approximation of the service costs of benefits earned during the period. We also have unfunded defined benefit plans (the "Other Plans") that provide retirement and severance benefits for certain of our Indonesian, Nigerian and Egyptian employees.

We refer to the U.S. Plans, the U.K. Plan, the Norway Plans and the Other Plans, collectively, as the "Transocean Plans'. On December 31, 2006, we adopted the recognition and disclosure standards of SFAS No. 158, Employer's Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106, and 132(R) ("SFAS 158"). For all Transocean Plans, we use a January 1 measurement date for net periodic benefit cost and a December 31 measurement date for benefit obligations and plan assets.

The change in projected benefit obligation, change in plan assets, funded status and the amounts recognized in the consolidated balance sheets are shown in the table below (in millions):

	December 31,
	2008			2007
Change in projected benefit obligation
Projected benefit obligation at beginning of year	$	1,065		$	351
Projected benefit obligations for assumed pension plans		—			686
Plan amendments		(11	)		—
Actuarial (gains) losses		148			(1	)
Service cost		46			22
Interest cost		64			24
Foreign currency exchange rate changes		(85	)		—
Benefits paid		(82	)		(17	)
Participant contributions		3			—
Special termination benefits		3			—
Settlements and curtailments		(1	)		—
Projected benefit obligation at end of year	$	1,150		$	1,065

Change in plan assets
Fair value of plan assets at beginning of year	$	939		$	273
Fair value of assumed pension plans		—			655
Actual return on plan assets		(196	)		9
Foreign currency exchange rate changes		(75	)		(3	)
Employer contributions		74			22
Participant contributions		3			—
Benefits paid		(82	)		(17	)
Fair value of plan assets at end of year	$	663		$	939

Funded status	$	(487	)	$	(126	)

Amounts recognized in the consolidated balance sheets consist of:
Pension asset, non-current	$	—		$	32
Accrued pension liability, current		7			31
Accrued pension liability, non-current		480			127
Accumulated other comprehensive income (a)		(432	)		(55	)

(a) Amounts are before income tax effect of $21 million and $12 million for December 31, 2008 and 2007, respectively.

The aggregate projected benefit obligation and fair value of plan assets for plans with a projected benefit obligation in excess of plan assets are as follows (in millions):

The accumulated benefit obligation for all defined benefit pension plans was $983 million and $939 million at December 31, 2008 and 2007, respectively. The aggregate accumulated benefit obligation and fair value of plan assets for plans with an accumulated benefit obligation in excess of plan assets are as follows (in millions):

For the years ended December 31, 2008 and 2007, our components of net periodic benefit cost include $4 million and $5 million, respectively, of net actuarial losses which were recognized in other comprehensive income. There were no amounts recognized in other comprehensive income as components of net periodic benefit cost in the year ended December 31, 2006. The following table shows the amounts in accumulated other comprehensive income that have not been recognized as components of net periodic benefit costs (in millions):

The following table shows the amounts in accumulated other comprehensive income expected to be recognized as components of net periodic benefit cost during the next fiscal year (in millions):

Pension obligations are actuarially determined and are affected by assumptions including expected return on plan assets, discount rates, compensation increases and employee turnover rates. We evaluate our assumptions periodically and make adjustments to these assumptions and the recorded liabilities as necessary.

Two of the most critical assumptions used in calculating our pension expense and liabilities are the expected long-term rate of return on plan assets and the assumed discount rate. We evaluate assumptions regarding the estimated long-term rate of return on plan assets based on historical experience and future expectations on investment returns, which are calculated by an unaffiliated investment advisor utilizing the asset allocation classes held by the plan's portfolios. Beginning on December 31, 2005, we utilized a yield curve approach based on Aaa corporate bonds and the expected timing of future benefit payments as a basis for determining the discount rate for our U.S. Plans. Changes in these and other assumptions used in the actuarial computations could impact our projected benefit obligations, pension liabilities, pension expense and other comprehensive income. We base our determination of pension expense on a market-related valuation of assets that reduces year-to-year volatility. This market-related valuation recognizes investment gains or losses over a five-year period from the year in which they occur. Investment gains or losses for this purpose are the difference between the expected return calculated using the market-related value of assets and the actual return based on the market-related value of assets.

The following are the weighted-average assumptions used to determine benefit obligations:

The following are the weighted-average assumptions used to determine net periodic benefit cost:

We review our investments and policies annually. In determining our asset allocation strategy, we review models presenting many different asset allocation scenarios to assess the most appropriate target allocation to produce long-term gains without taking on undue risk. In January 2009, we modified our target allocation to 70 percent equity securities, 30 percent debt securities. Through December 2008, our target allocation was 60 percent equity securities, 30 percent debt securities and 10 percent other investments. Other investments are generally a diversified mix of funds that specialize in various equity and debt strategies that are expected to provide positive returns each year relative to U.S. Treasury Bills. These strategies included, among others, arbitrage, short-selling, and merger and acquisition investment opportunities. We review asset allocations and results quarterly to ensure that managers continue to achieve specified objectives and policies as written and agreed to by us and each manager.

The plan's investment managers have discretion in the securities in which they may invest within their asset category. Given this discretion, the managers may occasionally invest in our stock or debt, including taking either long or short positions in such securities. As these managers are required to maintain well diversified portfolios, the actual investment in our shares or debt would be immaterial relative to asset categories and the overall plan.

Our pension plan weighted-average asset allocations for funded Transocean Plans by asset category are as follows:

No plan assets are expected to be returned to us during the year ending December 31, 2009.

We contributed $74 million to our defined benefit pension plans in 2008, which were funded from our cash flows from operations. During 2008, contributions of $60 million were made to the funded U.S. Plans, $7 million each for the funded Norway Plans and U.K. Plan and less than $1 million to the Other Non-U.S. Plans.

We expect to contribute a total of $88 million to the Transocean Plans in 2009. These contributions are comprised of an estimated $65 million to meet the minimum funding requirements for the funded U.S. Plans, $7 million to fund expected benefit payments for the unfunded U.S. Plans and the Other Non-U.S. Plans, $11 million for the funded Norway Plans and $5 million for the U.K. Plan.

The following pension benefits payments are expected to be paid by the Transocean Plans (in millions):

Postretirement benefits other than pensions—We have several unfunded contributory and noncontributory other postretirement employee benefits ("OPEB") plans, including one that we assumed in connection with the Merger, covering substantially all of our U.S. employees. Funding of benefit payments for plan participants will be made as costs are incurred. The postretirement health care plans include a limit on our share of costs for recent and future retirees. For all plans, we have historically and continue to use a January 1 measurement date for net periodic benefit cost and a December 31 measurement date for benefit obligations.

Net periodic benefit cost for these post retirement plans and their components, including service cost, interest cost, amortization of prior service cost and recognized net actuarial losses were $3 million for the year ended December 31, 2008 and less than $2 million for each of the years ended December 31, 2007 and 2006.

The change in benefit obligation, change in plan assets, funded status and amounts recognized in the consolidated balance sheets are shown in the table below (in millions):

	December 31,
	2008			2007
Change in benefit obligation
Benefit obligation at beginning of year	$	55		$	36
Projected benefit obligations for assumed OPEB Plan		—			21
Service cost		1			1
Interest cost		3			2
Actuarial (gains) losses		9			(3	)
Participant contributions		1			1
Benefits paid		(5	)		(3	)
Benefit obligation at end of year	$	64		$	55

Change in plan assets
Fair value of plan assets at beginning of year	$	—		$	—
Employer contributions		4			2
Participant contributions		1			1
Benefits paid		(5	)		(3	)
Fair value of plan assets at end of year	$	—		$	—

Funded status	$	(64	)	$	(55	)

Amounts recognized in the consolidated balance sheets consist of:
Accrued postretirement benefit liability, current	$	3		$	3
Accrued postretirement benefit liability, non-current		61			52
Accumulated other comprehensive income (a)		(8)			2

There were no amounts recognized in other comprehensive income as components of net periodic benefit cost in the years ended December 31, 2008, 2007 and 2006.

The following table shows the amounts in accumulated other comprehensive income that have not been recognized as components of net periodic benefit costs (in millions):

The amounts in accumulated other comprehensive income to be recognized as components of net periodic benefit cost, including net loss and net prior service credit, are expected to be less than $1 million during the year ending December 31, 2009.

Our OPEB obligations and the related benefit costs are accounted for in accordance with SFAS No. 106, Employers' Accounting for Postretirement Benefits Other than Pensions. Postretirement costs and obligations are actuarially determined and are affected by assumptions including expected discount rates, employee turnover rates and health care cost trend rates. We evaluate our assumptions periodically and make adjustments to these assumptions and the recorded liabilities as necessary.

Two of the most critical assumptions for postretirement benefit plans are the assumed discount rate and the expected health care cost trend rates. We utilize a yield curve approach based on Aa corporate bonds and the expected timing of future benefit payments as a basis for determining the discount rate. The accumulated postretirement benefit obligation and service cost were developed using a health care trend rate of 8.55 percent for 2008 reducing on an average of approximately 0.59 percent per year to an ultimate trend rate of 5 percent per year for 2014 and later. The initial trend rate was selected with reference to recent Transocean experience and broader national statistics. The ultimate trend rate is a long-term assumption and was selected to reflect the anticipation that the portion of gross domestic product devoted to health care becomes constant. Changes in these and other assumptions used in the actuarial computations could impact our projected benefit obligations, pension liabilities and pension expense.

Weighted-average discount rates used to determine benefit obligations were 5.35 percent and 5.96 percent for the years ended December 31, 2008 and 2007, respectively.

Weighted-average assumptions used to determine net periodic benefit cost were 5.96 percent, 5.80 percent and 5.37 percent for the years ended December 31, 2008, 2007 and 2006, respectively.

The assumed health care cost trend rate could have a significant impact on the amounts reported for postretirement benefits other than pensions. A one-percentage point change in the assumed health care trend rate would result in a change of $5 million in postretirement benefit obligations as of December 31, 2008 and less than $1 million in total service and interest cost components in 2008.

The following postretirement benefits payments are expected to be paid (in millions):

Defined contribution plans—In 2008, we sponsored six defined contribution plans, including (1) two qualified defined contribution savings plans covering certain employees working in the U.S. (the "U.S. Savings Plans"), (2) one defined contribution savings plan for certain employees in working in the U.K. (the "U.K. Savings Plan"), (3) two defined contribution savings plans covering certain employees working outside the U.S. and U.K. (the "International Savings Plans"), and (4) one defined contribution pension plan that covers certain employees working outside the U.S. (the "International Pension Plan'). We assumed one of the U.S. Savings Plans, the U.K. Savings Plan and one of the International Savings Plans in connection with the Merger (the "Assumed Savings Plans").

Effective January 1, 2009, we merged the two U.S. Savings Plans to form one qualified U.S. Savings Plan. Additionally, we closed one of the International Savings Plans and the U.K. Savings Plan, both assumed in connection with the Merger, to new participants and additional contributions, and the participants of these closed savings plans were, thereafter, eligible to participate in the remaining International Savings Plan. The three surviving defined contribution plans include the U.S. Savings Plan, the remaining International Savings Plan (the "Surviving Savings Plans") and the International Pension Plan.

For the closed International Savings Plan, we made matching contributions of up to 7 percent of each covered employee's base salary, depending on the employee's contribution to the plan. For the other two Assumed Savings Plans, we made contributions of up to 6 percent of the employee's base salary, depending on the employee's contribution to the plan. For each of the Surviving Savings Plans, we make a matching contribution of up to 6.0 percent of each covered employee's base salary, based on the employee's contribution to the plan. For the International Pension Plan, we contribute between 4.5 percent and 6.5 percent of each covered employee's base salary, based on the employee's years of eligible service.

Severance plan—We established a special transition severance plan for certain employees on the U.S. payroll that were employed at the time of the Merger and involuntarily terminated during the period from November 27, 2007 through November 27, 2009 (the "Severance Plan"). The amount of the severance benefit ranges from 26 weeks to 104 weeks of the employee's weekly base pay, determined by a formula that considers the employee's annual base salary and years of service with additional amounts paid to those employees over the age of 39 years that work in the U.S. or have U.S. citizenship.

In addition to the severance benefit, affected employees are eligible to elect coverage under specified medical, retiree medical, dental and employee assistance plans until the earlier of the date the employee becomes eligible for other employer coverage and the expiration of the number of weeks that corresponds to the number of weeks used to calculate the severance benefit. Certain affected employees are also granted Severance Credits for retirement purposes and qualify for compensation and benefits offered to those employees terminated for convenience of the company pursuant to the terms of any benefit plan, award or agreement in effect on November 27, 2007, to the extent applicable.

In connection with the Merger, we established a liability of $44 million for the estimated severance-related costs associated with the involuntary termination of 218 employees pursuant to the Severance Plan. Through December 31, 2008, severance-related costs of approximately $35 million have been paid to employees whose positions were eliminated as a result of the consolidation of operations and administrative functions following the Merger.

Lease obligations(We have operating lease commitments expiring at various dates, principally for real estate, office space and office equipment. In addition to rental payments, some leases provide that we pay a pro rata share of operating costs applicable to the leased property. At December 31, 2008, the GSF Explorer drillship, recorded in property and equipment, net in the amount of $212 million, is held under a capital lease through 2026. As of December 31, 2008, future minimum rental payments related to noncancellable operating leases and the capital lease are as follows (in millions):

Rental expense for all leases, including leases with terms of less than one year, was approximately $89 million, $51 million and $32 million for the years ended December 31, 2008, 2007 and 2006, respectively.

Purchase obligations—At December 31, 2008, our purchase obligations as defined by SFAS No. 47, Disclosure of Long-Term Obligations (as amended), related to our ten newbuilds are as follows (in millions):

Legal proceedings—In 2004, several of our subsidiaries were named, along with numerous unaffiliated defendants, in 21 complaints that were filed in the Circuit Courts of the State of Mississippi involving approximately 750 plaintiffs that alleged personal injury arising out of asbestos exposure in the course of their employment by some of these defendants between 1965 and 1986. The complaints also named as defendants certain subsidiaries of TODCO and certain subsidiaries of Sedco, Inc. to whom we may owe indemnity. Further, the complaints named other unaffiliated defendant companies, including companies that allegedly manufactured drilling related products containing asbestos. The complaints alleged that the defendants used asbestos-containing products in connection with drilling operations and included allegations of negligence, strict liability, and claims allowed under the Jones Act and general maritime law. The plaintiffs generally sought awards of unspecified compensatory and punitive damages. The Special Master who was appointed to oversee these cases required that each plaintiff file a separate amended complaint for each individual plaintiff and then he dismissed the original 21 complaints. We believe that we may have a direct or indirect interest in 44 of the resulting complaints. We have not been provided with sufficient information in all claims to determine the period of the claimants' exposure to asbestos, their medical condition or, in some cases, the vessels potentially involved in the claims. We historically have maintained broad liability insurance, but we are not certain whether our insurance will cover all liabilities arising out of the 44 claims. We intend to defend these lawsuits vigorously, but there can be no assurance as to their ultimate outcome.

the subsidiary was a defendant in approximately 1,008 lawsuits. Some of these lawsuits include multiple plaintiffs and we estimate that there are approximately 2,973 plaintiffs in these lawsuits. For many of these lawsuits, we have not been provided with sufficient information from the plaintiffs to determine whether all or some of the plaintiffs have claims against the subsidiary, the basis of any such claims, or the nature of their alleged injuries. The first of the asbestos-related lawsuits was filed against this subsidiary in 1990. Through December 31, 2008, the amounts expended to resolve claims (including both attorneys' fees and expenses, and settlement costs) have not been material, and all deductibles with respect to the primary insurance have been satisfied. The subsidiary continues to be named as a defendant in additional lawsuits and we cannot predict the number of additional cases in which it may be named a defendant nor can we predict the potential costs to resolve such additional cases or to resolve the pending cases. However, the subsidiary has in excess of $1 billion in insurance limits. Although not all of the policies may be fully available due to the insolvency of certain insurers, we believe that the subsidiary will have sufficient insurance and funds from the settlements of litigation with insurance carriers available to respond to these claims. While we cannot predict or provide assurance as to the final outcome of these matters, we do not believe that the current value of the claims where we have been identified will have a material impact on our consolidated statement of financial position, results of operations or cash flows.

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

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

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

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

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

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

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

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

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

Retained risk—Our insurance program is a 12-month policy period beginning May 1, 2008. Under the program, we generally maintain a $125 million per occurrence deductible on our hull and machinery, which is subject to an aggregate deductible of $250 million. However, in the event of a total loss or a constructive total loss of a drilling unit, such loss is fully covered by our insurance with no deductible. Additionally, we maintain a $10 million per occurrence deductible on crew personal injury liability and $5 million per occurrence deductible on third-party property claims, which together are subject to an aggregate deductible of $50 million that is applied to any occurrence in excess of the per occurrence deductible until the aggregate deductible is exhausted. We also carry $950 million of third-party liability coverage exclusive of the personal injury liability deductibles, third-party property liability deductibles and retention amounts

described above. We retain the risk for any liability losses in excess of the $950 million limit. We have elected to self-insure operators extra expense coverage for our subsidiaries ADTI and CMI. This coverage provides protection against expenses related to well control and redrill liability associated with blowouts. Generally, ADTI's clients assume, and indemnify ADTI for, liability associated with blowouts in excess of $50 million.

At present, the insured value of our drilling rig fleet is approximately $34 billion in aggregate. We do not generally have commercial market insurance coverage for physical damage losses to our fleet due to hurricanes in the U.S. Gulf of Mexico and war perils worldwide. We do not carry insurance for loss of revenue. In the opinion of management, adequate accruals have been made based on known and estimated losses related to such exposures.

Letters of credit and surety bonds—We had letters of credit outstanding totaling $751 million and $532 million at December 31, 2008 and 2007, respectively. These letters of credit guarantee various contract bidding and performance activities under various uncommitted lines provided by several banks.

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. Surety bonds outstanding totaled $37 million and $24 million at December 31, 2008 and 2007, respectively.

We have (i) a long-term incentive plan (the "Long-Term Incentive Plan") for executives, key employees and outside directors under which awards can be granted in the form of stock options, restricted shares, deferred units, SARs and cash performance awards and (ii) other incentive plans under which awards are currently outstanding. Awards that may be granted under the Long-Term Incentive Plan include traditional time-vesting awards ("time-based awards") and awards that are earned based on the achievement of certain performance criteria ("performance-based awards") or market factors ("market-based awards"). Our executive compensation committee of our board of directors determines the terms and conditions of the awards granted under the Long-Term Incentive Plan. As of December 31, 2008, we had 22.9 million shares authorized for future employee grants, including up to 6.0 million for restricted share awards, and 0.6 million shares authorized with respect to outside directors.

Time-based awards typically vest either in three equal annual installments beginning on the first anniversary date of the grant or in an aggregate installment at the end of the stated vesting period. Performance-based and market-based awards are typically awarded subject to either a two-year or a three-year measurement period during which the number of options, shares or deferred units remains uncertain. At the end of the measurement period, the awarded number of options, shares or deferred units is determined (the "determination date") subject to the stated vesting period. The two-year awards generally vest in three equal installments beginning on the determination date and on January 1 of each of the two subsequent years. The three-year awards generally vest in one aggregate installment following the determination date. Once vested, options and SARs generally have a 10-year term during which they are exercisable.

As of December 31, 2008, total unrecognized compensation costs related to all unvested share-based awards totaled $97 million, which is expected to be recognized over a weighted-average period of 2.0 years. There were no significant modifications during any of the years presented.

As a result of the Merger, we assumed all of the outstanding employee stock options and SARs of GlobalSantaFe. Each option and stock appreciation right of GlobalSantaFe outstanding as of the Merger effective date, to the extent not already fully vested and exercisable, became fully vested and exercisable into an option or SAR with respect to 0.6368 shares of Transocean at that time. The aggregate fair market value of options and SARs assumed in the Merger, computed as of the Merger date, was $157 million or $83.56 per option or SAR.

At the effective time of the Reclassification, all outstanding options to acquire Transocean-Cayman ordinary shares remained outstanding and became fully vested and exercisable. The number and exercise prices of the options to purchase Transocean-Cayman ordinary shares were adjusted based on the market price of Transocean-Cayman ordinary shares immediately preceding the effective date of the Reclassification and Merger in order to keep the aggregate intrinsic value of the options and SARs equal to the values immediately prior to such date. Each option to acquire Transocean-Cayman ordinary shares that was outstanding immediately prior to the Reclassification and Merger was converted into options to purchase 0.9392 Transocean-Cayman ordinary shares (rounded down to the nearest whole share) with a per share exercise price equal to the exercise price of the option immediately prior to the Reclassification and Merger divided by 0.9392 (rounded up to the nearest whole cent). Share amounts and related share prices with respect to stock options have been retroactively restated for all periods presented to give effect to the Reclassification.

All Transocean deferred units and restricted shares were exchanged for the same consideration for which each outstanding Transocean-Cayman ordinary share was exchanged in the Reclassification. As a result, holders of deferred units and restricted shares received $33.03 in cash and 0.6996 Transocean-Cayman ordinary shares for each deferred unit or restricted share they held immediately prior to the Reclassification. With respect to time-based deferred unit and restricted share awards made prior to July 21, 2007, all such consideration was fully vested as of the Merger date. However, with respect to those awards made on or after July 21, 2007, only the cash component of the consideration vested as of the Merger date, and the share consideration remained subject to the vesting restrictions set forth in the applicable award agreement. All performance-based awards for which the performance determination occurred prior to the

Merger date became fully vested at that time. All unvested performance-based shares for which the performance determination had not yet occurred as of the Merger date became vested at 50 percent on the Merger date. The remaining shares not vested were forfeited in 2007. As a result, there were no performance-based shares outstanding at December 31, 2007. The numbers of restricted shares and deferred units in the tables and discussions below have been retroactively restated for all periods presented to give effect to reduction in shares that occurred in connection with the Reclassification. Weighted-average grant-date fair values per share for deferred units and restricted shares have not been restated.

As a result of the accelerated vesting of options, deferred units and restricted shares in connection with the Merger, we accelerated the recognition of $38 million of previously unrecognized compensation expense in the fourth quarter of 2007.

In connection with the Redomestication Transaction, we adopted and assumed the Long-Term Incentive Plan and other employee benefit plans and arrangements of Transocean-Cayman, and those plans and arrangements were amended as necessary to give effect to the Redomestication Transaction, including to provide (1) that our shares will be issued, held, available or used to measure benefits as appropriate under the plans and arrangements, in lieu of Transocean-Cayman ordinary shares, including upon exercise of any options or SARs issued under those plans and arrangements; and (2) for the appropriate substitution of us for Transocean-Cayman in those plans and arrangements. Additionally, we issued 16 million of our shares to Transocean-Cayman, 16 million of which remain available as of December 31, 2008, for future use to satisfy our obligations to deliver shares in connection with awards granted under incentive plans, warrants or other rights to acquire our shares.

We estimated the fair value of each option award under the Long-Term Incentive Plan on the grant date using the Black-Scholes-Merton option-pricing model with the following weighted-average assumptions:

We estimated the fair value of each option grant under the Employee Stock Purchase Plan ("ESPP") using the Black-Scholes-Merton option-pricing model with the following weighted-average assumptions:

Stock options—The following table summarizes vested and unvested time-based vesting stock option ("time-based options") activity under our incentive plans during the year ended December 31, 2008:

The weighted-average grant-date fair value of time-based options granted during the year ended December 31, 2008 was $49.32 per share. There were 3,073 and 2,132 time-based options granted during the years ended December 31, 2007 and 2006, respectively, with weighted-average grant-date fair values of $40.69 and $34.08 per share, respectively.

The total pretax intrinsic value of time-based options exercised during the year ended December 31, 2008 was $101 million. There were 2,112,853 and 1,904,346 time-based options exercised during the years ended December 31, 2007 and 2006, respectively. The total pretax intrinsic value of time-based options exercised was $156 million and $99 million during the years ended December 31, 2006 and 2005, respectively.

Restricted shares—The following table summarizes unvested share activity for time-based vesting restricted shares ("time-based shares") granted under our incentive plans during the year ended December 31, 2008:

The total grant-date fair value of time-based shares that vested during the year ended December 31, 2008 was $14 million. There were 380,653 and 258,313 time-based shares granted during the years ended December 31, 2007 and 2006, respectively. The weighted-average grant-date fair value of time-based shares granted was $109.92 and $78.40 per share for the years ended December 31, 2007 and 2006, respectively. There were 261,330 and 15,812 time-based shares that vested during the years ended December 31, 2007 and 2006, respectively. The total grant-date fair value of time-based shares that vested was $20 million and less than $1 million for the years ended December 31, 2007 and 2006, respectively.

Deferred units—A deferred unit is a unit that is equal to one share but has no voting rights until the underlying shares are issued. The following table summarizes unvested activity for time-based vesting deferred units ("time-based units") granted under our incentive plans during the year ended December 31, 2008:

The total grant-date fair value of the time-based units vested during the year ended December 31, 2008 was $3 million. There were 64,676 and 29,641 time-based units granted during the years ended December 31, 2007 and 2006, respectively. The weighted-average grant-date fair value of time-based units granted was $105.99 and $81.55 per share for the years ended December 31, 2007 and 2006, respectively. There were 53,086 and 9,997 time-based units that vested during the years ended December 31, 2007 and 2006, respectively. The total grant-date fair value of deferred units that vested was $4 million and less than $1 million for the years ended December 31, 2007 and 2006, respectively.

Share-settled SARs—Under an incentive plan assumed in connection with the Merger, we assumed share-settled SARs granted to key employees and to non-employee directors of GlobalSantaFe at no cost to the grantee. The grantee receives a number of shares upon exercise equal in value to the difference between the market value of our shares at the exercise date and the Merger-adjusted exercise price. The following table summarizes share-settled SARs activity under our incentive plans during the year ended December 31, 2008:

At December 31, 2008, we have presented the aggregate intrinsic value as zero since the weighted-average exercise price per share exceeds the market price of our shares on that date.

The total pretax intrinsic value of share-settled SARs exercised during the period ended December 31, 2008 was zero. There were 110,355 SARs exercised in 2007 after November 27, 2007, when we assumed them in the GSF Merger.

Cash-settled SARs—Under our incentive plans, we have outstanding SARs previously granted to employees that can be settled in cash for the difference between the market value of our shares on the date of exercise and the exercise price. The cash-settled SARs are recorded in other current liabilities in our consolidated balance sheet until they are exercised. We have not granted any cash-settled SARs in the years ended December 31, 2008, 2007, and 2006, and all outstanding cash-settled SARs are fully vested. We had 14,547 SARs outstanding with a weighted-average remaining contractual term of 0.75 years and an aggregate intrinsic value of less than $1 million as of December 31, 2008. We had 21,669 SARs outstanding with a weighted-average remaining contractual term of 1.29 years and an aggregate intrinsic value of $2 million as of December 31, 2007.

Stock options—We grant performance-based stock options ("performance-based options") that can be earned depending on the achievement of certain performance targets. The number of options earned is quantified upon completion of the performance period at the determination date. The following table summarizes vested and unvested performance-based option activity under our incentive plans during the year ended December 31, 2008:

At December 31, 2008, we have presented the aggregate intrinsic value as zero since the weighted-average exercise price per share exceeds the market price of our shares on that date.

We did not grant performance-based options during the year ended December 31, 2007. There were 329,650 performance-based options granted during the year ended December 31, 2006. The weighted-average grant-date fair value of performance-based options granted during the year ended December 31, 2006 was $32.17.

The total pretax intrinsic value of performance-based options exercised during the year ended December 31, 2008 was $22 million. There were 661,988 and 158,054 performance-based options exercised, with a total pretax intrinsic value of $52 million and $10 million, during the years ended December 31, 2007 and 2006, respectively.

Restricted shares—We have previously granted performance-based restricted shares ("performance-based shares") that could be earned depending on the achievement of certain performance targets. The number of shares earned was quantified upon completion of the performance period at the determination date.

We did not grant performance-based shares during the years ended December 31, 2008 and 2007. There were 59,769 performance-based shares granted during the year ended December 31, 2006. The weighted-average grant-date fair value was $77.56 per share during the year ended December 31, 2006. There were 357,544 and 175,695 performance-based shares that vested with a total grant-date fair value of $14 million and $6 million during the years ended December 31, 2007 and 2006, respectively.

Deferred units—We have previously granted performance-based deferred units ("performance-based units") that could be earned depending on the achievement of certain performance targets. The number of units earned was quantified upon completion of the performance period at the determination date.

We did not grant performance-based units during the years ended December 31, 2008 and 2007. There were 75,707 performance-based units granted during the year ended December 31, 2006. The weighted-average grant-date fair value of performance-based units granted was $78.61 per share during the year ended December 31, 2006. There were 150,762 and 41,236 performance-based units that vested with a total grant-date fair value of $7 million and $2 million during the years ended December 31, 2007 and 2006, respectively.

Deferred units—We grant market-based deferred units ("market-based units") that can be earned depending on the achievement of certain market conditions. The number of units earned is quantified upon completion of the specified period at the determination date. The following table summarizes unvested activity for market-based units granted under our incentive plans during the year ended December 31, 2008:

There were no market-based units granted during the years ended December 31, 2007 and 2006.

ESPP—Through December 31, 2008, we offered an ESPP under which certain full-time employees could choose to have between two and 20 percent of their annual base earnings withheld to purchase up to $21,250 of our shares each year. The purchase price of the shares is 85 percent of the lower of the beginning-of-year or end-of-year market price of our shares. At December 31, 2008, 577,537 shares were available for issuance. As of January 1, 2009, we discontinued offering the ESPP.

In connection with its merger with R&B Falcon, Transocean-Cayman assumed the R&B Falcon stock warrants, which expire on May 1, 2009. The warrant agreement provided that, as a result of the Reclassification, each warrant became exercisable for 12.243 Transocean-Cayman ordinary shares at an adjusted exercise price equal to $21.74 per share pursuant to formulas specified in the warrant agreement. Transocean-Cayman believed that the adjustment of the number of Transocean-Cayman ordinary shares for which the warrants were exercisable and the exercise price pursuant to the warrant agreement would not allow holders to receive the full economic benefit of the Reclassification. In order to place the warrantholders in a position more comparable to that of ordinary shareholders, Transocean-Cayman modified the warrant agreement to allow warrantholders to receive, upon exercise following the Reclassification, 0.6996 Transocean-Cayman ordinary shares and $33.03 for each Transocean-Cayman ordinary share for which the warrants were previously exercisable, at an exercise price of $19.00 per Transocean-Cayman ordinary share for which the warrants were exercisable prior to the Reclassification. As a result, a holder of a warrant was allowed to elect to receive 12.243 Transocean-Cayman ordinary shares and $578.025 in cash at an exercise price of $332.50 upon exercise. This modification represents the same consideration that a warrantholder would have owned immediately after the Reclassification if the warrantholder had exercised its warrant immediately before the Reclassification.

In 2008, Transocean-Cayman issued 363,492 ordinary shares upon the exercise of 29,690 warrants and, as a result, paid $7 million, net of a $10 million aggregate exercise price. The cash payment feature provided for in the modification resulted in a reclassification from permanent equity. As of December 31, 2008 and 2007, $31 million and $48 million, respectively, were recorded in other current liabilities in our consolidated balance sheet.

In December 2008, in connection with the Redomestication Transaction, we assumed Transocean-Cayman's obligations under the warrants, so that our shares are issuable upon exercise of the warrants, in lieu of Transocean-Cayman's ordinary shares. We issued 16 million of our shares by Transocean-Cayman, 16 million of which remain available as of December 31, 2008, for future use to satisfy our obligations to deliver shares in connection with the warrants and other rights to acquire our shares. At December 31, 2008, 53,220 warrants remained outstanding to purchase 651,575 of our shares.

In May 2006, Transocean-Cayman's board of directors authorized an increase in the overall amount of ordinary shares that could be repurchased under its share repurchase program to $4.0 billion from $2.0 billion, which was previously authorized and announced in October 2005. The repurchase program did not have an established expiration date and could be suspended or discontinued at any time. Under the program, repurchased shares were constructively retired and returned to unissued status. During 2007, Transocean-Cayman repurchased and retired 5.2 million aggregate ordinary shares for $400 million at an average purchase price of $77.39 per share. There were no repurchases during 2008.

Total consideration paid to repurchase the shares was recorded in shareholders' equity as a reduction in shares and additional paid-in capital. Such consideration was funded with existing cash balances and borrowings under the Former Revolving Credit Facility. As a result of the Redomestication, the Transocean-Cayman share repurchase program was terminated. See Note 26—Subsequent Events.

The components of accumulated other comprehensive income (loss) at December 31, 2008, 2007 and 2006, net of tax, are as follows (in millions):

(a) Adjustment to initially apply SFAS 158 resulting in a net adjustment of $26 million.

We include investments in highly liquid debt instruments with an original maturity of three months or less in cash and cash equivalents. See Note 2—Significant Accounting Policies. As of September 30, 2008, we had $74 million invested in The Reserve Primary Fund and $334 million invested in The Reserve International Liquidity Fund Ltd. In September 2008, The Reserve announced that certain funds had lost the ability to maintain a net asset value of $1.00 per share due to losses in connection with the bankruptcy of Lehman Brothers Holdings, Inc. ("Lehman Holdings"). According to public disclosures by The Reserve, The Reserve stopped processing redemption requests in order to develop an orderly plan of liquidation that would protect all of the funds' shareholders. Based on statements made by the funds, in September 2008 we reclassified $408 million from cash and cash equivalents to short-term investments and recorded an impairment charge in the amount of $16 million associated with our proportional interest in the debt instruments of Lehman Holdings held by the funds until such time as we receive our liquidated portion of the assets. Our statement of cash flows presents a use of cash in the amount of this reclassification. As of December 31, 2008, we had received $59 million invested in The Reserve Primary Fund. At December 31, 2008, the carrying values of our investments in The Reserve Primary Fund and The Reserve International Liquidity Fund were $15 million and $318 million, respectively. The timing of our ability to access these funds is uncertain but is expected to be during 2009. Potential rulings or decisions by courts or regulators may impact further distributions by the funds. See Note 26—Subsequent Events.

Net cash provided by (used in) operating activities attributable to the net change in operating assets and liabilities is composed of the following (in millions):

Prior to the Merger, we operated in one business segment. As a result of the Merger, we have established two reportable segments: (1) contract drilling services and (2) other operations. The drilling management services and oil and gas properties do not meet the quantitative thresholds for determining reportable segments and are combined for reporting purposes in the other operations segment. Accounting policies of the segments are the same as those described in the Summary of Significant Accounting Policies (see Note 2—Summary of Significant Accounting Policies).

Our contract drilling services segment fleet operates in a single, global market for the provision of contract drilling services. The location of our rigs and the allocation of resources to build or upgrade rigs are determined by the activities and needs of our customers. Operating revenues and long-lived assets by country were as follows (in millions):

A substantial portion of our assets are mobile. Asset locations at the end of the period are not necessarily indicative of the geographic distribution of the revenues generated by such assets during the periods. Although we are organized under the laws of Switzerland, we do not conduct any operations in Switzerland. As a result, we have no operating revenues or long-lived assets in Switzerland.

Our international operations are subject to certain political and other uncertainties, including risks of war and civil disturbances (or other events that disrupt markets), expropriation of equipment, repatriation of income or capital, taxation policies, and the general hazards associated with certain areas in which operations are conducted.

For the year ended December 31, 2008, BP accounted for approximately 11 percent of our operating revenues. For the year ended December 31, 2007, Chevron, Shell and BP accounted for approximately 12 percent, 11 percent and 10 percent, respectively, of our operating revenues. For the year ended December 31, 2006, Chevron, BP and Shell accounted for approximately 14 percent, 11 percent and 11 percent, respectively, of our operating revenues. The loss of these or other significant customers could have a material adverse effect on our results of operations.

Pacific Drilling Limited—We hold a 50 percent equity interest in TPDI, a British Virgin Islands joint venture company formed by us and Pacific Drilling, a Liberian company, to own two ultra-deepwater drillships to be named Dhirubhai Deepwater KG1 and Dhirubhai Deepwater KG2, which are currently under construction. Beginning on October 18, 2010, Pacific Drilling will have the right to exchange its interest in the joint venture for our shares or cash at a purchase price based on an appraisal of the fair value of the drillships, subject to various adjustments.

At December 31, 2008, TPDI had outstanding promissory notes in the aggregate amount of $222 million, of which $111 million is due to Pacific Drilling and is included in long-term debt in our consolidated balance sheet.

Overseas Drilling Limited—In connection with the management and operation of Joides Resolution on behalf of Overseas Drilling Limited ("ODL"), we earned $2 million, $1 million and $2 million for the years ended December 31, 2008, 2007 and 2006, respectively. Such amounts are included in other revenues in our consolidated statements of operations. At December 31, 2008 and 2007, we had receivables due from ODL of $4 million and $5 million, respectively, which were recorded as accounts receivable - other in our consolidated balance sheets. Siem Offshore Inc. owns the other 50 percent interest in ODL. A former director of Transocean-Cayman, Kristian Siem, is the chairman of Siem Offshore Inc. and is also a director and officer of ODL. Mr. Siem is also chairman and chief executive officer of Siem Industries, Inc., which owns an approximate 45 percent interest in Siem Offshore Inc.

In November 2005, we entered into a loan agreement with ODL pursuant to which we may borrow up to $8 million. ODL may demand repayment at any time upon five business days prior written notice given to us and any amount due to us from ODL may be offset against the loan amount at the time of repayment. As of December 31, 2008, no amounts were outstanding under this loan agreement. As of December 31, 2007, $3 million was outstanding under this loan agreement and was reflected as long-term debt in our consolidated balance sheet (see Note 11—Debt). No dividend was declared in 2008 or 2007. ODL declared a dividend in the amount of $4 million in 2006.

Shown below are selected unaudited quarterly data. Amounts are rounded for consistency in presentation with no effect to the results of operations previously reported on Form 10-Q or Form 10-K.

	Three months ended
	March 31,		June 30,		September 30,		December 31,

	(In millions, except per share data)
2008
Operating revenues	$	3,110	$	3,102	$	3,192	$	3,270
Operating income (a)		1,540		1,350		1,383		1,084
Net income (a)		1,189		1,107		1,106		800
Earnings per share
Basic	$	3.75	$	3.48	$	3.47	$	2.51
Diluted	$	3.71	$	3.45	$	3.44	$	2.50
Weighted-average shares outstanding
Basic		317		318		319		319
Diluted		321		321		321		320

2007
Operating revenues	$	1,328	$	1,434	$	1,538	$	2,077
Operating income (b)		657		676		753		1,153
Net income (b) (c)		553		549		973		1,056
Earnings per share (d)
Basic	$	2.72	$	2.73	$	4.80	$	4.27
Diluted	$	2.62	$	2.63	$	4.63	$	4.17
Weighted-average shares outstanding (d)
Basic		203		202		203		247
Diluted		212		210		210		254

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

Short-term investments—In January 2009, we received a distribution in the amount of $216 million from The Reserve International Liquidity Fund. In February 2009, we received a distribution in the amount of $5 million from The Reserve Primary Fund. At February 20, 2009, the carrying values of our investments in The Reserve Primary Fund and The Reserve International Liquidity Fund were $10 million and $102 million, respectively.

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

variability of its cash interest payments. Under the interest rate swaps, Transocean-Cayman will receive interest at one-month LIBOR and pay interest at a fixed rate of 0.768 percent over the six-month period ending August 6, 2009.

Term Loan repayment—In February 2009, Transocean-Cayman repaid $200 million of borrowings under the Term Loan. As of February 20, 2009, the outstanding borrowings under the Term Loan were $1.8 billion.

We have not had a change in or disagreement with our accountants within 24 months prior to the date of our most recent financial statements or in any period subsequent to such date.

In accordance with Exchange Act Rules 13a-15 and 15d-15, we carried out an evaluation, under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of December 31, 2008 to provide reasonable assurance that information required to be disclosed in our reports filed or submitted under the Exchange Act is (1) accumulated and communicated to our management, including our Chief Executive Officer and our Chief Financial Officer, to allow timely decisions regarding required disclosure and (2) recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission's rules and forms.

There were no changes in these internal controls during the quarter ended December 31, 2008 that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

See "Management's Report on Internal Control Over Financial Reporting" and "Report of Independent Registered Public Accounting Firm on Internal Control over Financial Reporting" included in Item 8 of this Annual Report.

The information required by Items 10, 11, 12, 13 and 14 is incorporated herein by reference to our definitive proxy statement for our 2009 annual general meeting of shareholders, which will be filed with the Securities and Exchange Commission pursuant to Regulation 14A under the Securities Exchange Act of 1934 within 120 days of December 31, 2008. Certain information with respect to our executive officers is set forth in Item 4 of this annual report under the caption "Executive Officers of the Registrant."

Financial statements of unconsolidated subsidiaries are not presented herein because such subsidiaries do not meet the significance test.

			Additions
	Balance at beginning of period		Charge to cost and expenses		Charge to other accounts - describe			Deductions - describe				Balance at end of period
Year ended December 31, 2006
Reserves and allowances deducted from asset accounts:
Allowance for doubtful accounts receivable	$	15	$	32	$	—		$	21	(a)	$	26

Allowance for obsolete materials and supplies		19		3		—			3	(b)		19

Valuation allowance on deferred tax assets		48		11		—			—			59

Year ended December 31, 2007
Reserves and allowances deducted from asset accounts:
Allowance for doubtful accounts receivable		26		57		—			33	(a)		50

Allowance for obsolete materials and supplies		19		4		—			1	(c)		22

Valuation allowance on deferred tax assets		59		—		28	(d)		58	(e)		29

Year ended December 31, 2008
Reserves and allowances deducted from asset accounts:
Allowance for doubtful accounts receivable		50		95		—			31	(a)		114

Allowance for obsolete materials and supplies		22		27		—			—			49

Valuation allowance on deferred tax assets	$	29	$	4	$	—		$	10	(d)	$	23

Other schedules are omitted either because they are not required or are not applicable or because the required information is included in the financial statements or notes thereto.

and Investment Bank and JPMorgan Chase Bank, N.A., as Co-Documentation Agents, and Goldman Sachs Credit Partners, L.P. and Lehman Brothers Inc. as Joint Lead Arrangers and Joint Bookrunners (incorporated by reference to Exhibit 4.1 to Transocean Inc.'s Current Report on Form 8-K (Commission File No. 333-75899) filed on October 1, 2007)

Exhibits listed above as previously having been filed with the SEC are incorporated herein by reference pursuant to Rule 12b-32 under the Securities Exchange Act of 1934 and made a part hereof with the same effect as if filed herewith.

Certain instruments relating to our long-term debt and our subsidiaries have not been filed as exhibits since the total amount of securities authorized under any such instrument does not exceed 10 percent of our total assets and our subsidiaries on a consolidated basis. We agree to furnish a copy of each such instrument to the SEC upon request.

Certain agreements filed as exhibits to this Report may contain representations and warranties by the parties to such agreements. These representations and warranties have been made solely for the benefit of the parties to such agreements and (1) may be intended not as statements of fact, but rather as a way of allocating the risk to one of the parties if those statements prove to be inaccurate, (2) may have been qualified by certain disclosures that were made to other parties in connection with the negotiation of such agreements, which disclosures are not reflected in such agreements, and (3) may apply standards of materiality in a way that is different from what may be viewed as material to investors.

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned; thereunto duly authorized, on February 25, 2009.

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant in the capacities indicated on February 25, 2009.

Item		Page

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

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

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

	PART IV
ITEM 15.	Exhibits and Financial Statement Schedules	108

•"anticipates”	•“may”
•“believes”	•“might”
•“budgets”	•“plans”
•“could”	•“predicts”
•“estimates”	•“projects”
•“expects”	•“scheduled”
•“forecasts”	•“should”
•“intends”

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

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

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

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

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

Issuer Purchases of Equity Securities

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

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

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

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

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

Years ending December 31,
2009	$	40
2010		39
2011		44
2012		44
2013		47
2014-2018		286

	Scheduled Maturity Date (a) (b)																					Fair Value
	2009			2010			2011			2012			2013			Thereafter			Total			12/31/08
Total debt
Fixed rate	$	1		$	2,200		$	2,366		$	2,200		$	751		$	3,317		$	10,835		$	9,496
Average interest rate		5.8	%		1.6	%		1.9	%		1.5	%		5.2	%		6.8	%		3.5	%
Variable rate	$	663		$	2,000		$	65		$	27		$	28		$	559		$	3,342		$	3,342
Average interest rate		5.8	%		5.0	%		3.8	%		3.8	%		3.8	%		3.2	%		4.8	%

		2008			2007
Deferred tax assets	$			$
Drilling contract intangibles		46			303
Net operating loss carryforwards		75			102
Tax credit carryforwards		40			100
Accrued payroll expenses not currently deductible		62			85
Deferred income		53			50
Other		13			83
Valuation allowance		(23	)		(29	)
Total deferred tax assets		266			694
Deferred tax liabilities
Depreciation and amortization		(795	)		(1,155	)
Drilling management services intangibles		(55	)		(83	)
Other		(19	)		(18	)
Total deferred tax liabilities		(869	)		(1,256	)
Net deferred tax liabilities	$	(603	)		(562	)

		2008			2007
Balance at beginning of year	$	299		$	219
Unrecognized tax benefits assumed in connection with the Merger		―			42
Additions for current year tax positions		46			48
Additions for prior year tax positions		67			22
Reductions for prior year tax positions		(36	)		(6	)
Settlements		(3	)		(26	)
Reductions related to statute of limitation expirations		(1	)		―
Balance at end of year	$	372		$	299

	Balance at January 1, 2008		Net adjustments				Balance at December 31, 2008

Contract drilling services	$	8,020	$	106		(a)	$	8,126
Drilling management services		176		(176	)	(b)		—
Oil and gas properties		23		(21	)	(c)		2
Total	$	8,219	$	(91	)		$	8,128

	Balance at January 1, 2008		Impairments		Balance at December 31, 2008

Trade name	$	76	$	(31)	$	45

Years ending December 31,		Drilling Contract Intangibles			ADTI Customer Relationships	Amortization expense (income), net

2009	$	(281	)	$	9	$	(272	)
2010		(98	)		9		(89	)
2011		(45	)		9		(36	)
2012		(42	)		9		(33	)
2013		(25	)		9		(16	)
Thereafter		(34	)		76		42
Total intangible assets and liabilities, net	$	(525	)	$	121	$	(404	)

		December 31, 2008			December 31, 2007
		Carrying value	Fair value		Carrying value		Fair value
Long-term debt, including current maturities	$	14,186	$	12,838	$	17,257	$	17,935

	December 31,
	2008 (a)			2007 (a)

Net actuarial loss	$	446		$	57
Net prior service credit		(15	)		(3	)
Net transition obligation		1			1
Total unrecognized accumulated other comprehensive income	$	432		$	55

	Year ending December 31,
	2009

Net actuarial loss	$	14
Net prior service credit		(1	)
Net transition obligation		1
Total amount in accumulated other comprehensive income expected to be recognized next year	$	14

Years ending December 31,	Capital Lease			Operating Leases
2009	$	2		$	34
2010		2			31
2011		2			18
2012		2			12
2013		2			9
Thereafter		22			25
Total future minimum rental payment	$	32		$	129
Less amount representing imputed interest		(16	)
Present value of future minimum rental payments under capital leases		16
Less current portion included in accrued liabilities		(2	)
Long-term capital lease obligation	$	14

	Number of shares under option		Weighted-average exercise price per share		Weighted-average remaining contractual term (years)	Aggregate intrinsic value (in millions)
Outstanding at January 1, 2008	3,183,030		$	34.72	3.27	$	345

Granted	276,281			144.32
Exercised	(1,066,173	)		41.26
Forfeited	(34,395	)		41.45
Outstanding at December 31, 2008	2,358,743		$	44.50	2.90	$	6

Vested and exercisable at December 31, 2008	2,085,429		$	31.42	2.03	$	33

	Number of shares		Weighted-average grant-date fair value per share
Unvested at January 1, 2008	369,926		$	109.98

Granted	259,057			126.26
Vested	(129,979	)		110.62
Forfeited	(71,539	)		116.43
Unvested at December 31, 2008	427,465		$	118.58

	Number of units		Weighted-average grant-date fair value per share
Unvested at January 1, 2008	50,122		$	109.97

Granted	498,216			143.85
Vested	(25,740	)		124.84
Forfeited	(17,649	)		136.36
Unvested at December 31, 2008	504,949		$	141.72

	Number of awards		Weighted-average exercise price per share		Weighted-average remaining contractual term (years)	Aggregate intrinsic value (in millions)
Outstanding at January 1, 2008	504,771		$	89.18	8.59	$	27

Exercised	(315,408	)		86.74
Outstanding at December 31, 2008	189,363		$	93.26	7.75	$	—

Vested and exercisable at December 31, 2008	189,363		$	93.26	7.75	$	—

	Gain (loss) on terminated interest rate swaps			Unrealized loss on securities held for sale			Minimum pension liability			Adjustment to pension plan funded status			Total other comprehensive income (loss)

Balance at December 31, 2005	$	3		$	—		$	(23	)	$	—		$	(20	)
Other comprehensive income		—			—			16			—			16
Adjustment to initially apply SFAS 158, net of tax		—			—			7	(a)		(33	) (a)		(26	)
Balance at December 31, 2006		3			—			—			(33	)		(30	)
Other comprehensive loss		—			—			—			(12	)		(12	)
Balance at December 31, 2007		3			—			—			(45	)		(42	)
Other comprehensive loss		(1	)		(3	)		—			(374	)		(378	)
Balance at December 31, 2008	$	2		$	(3	)	$	—		$	(419	)	$	(420	)

Included in Part II of this report:
Management's Report on Internal Control Over Financial Reporting	57
Report of Independent Registered Public Accounting Firm on
Internal Control over Financial Reporting	58
Report of Independent Registered Public Accounting Firm	59
Consolidated Statements of Operations	60
Consolidated Statements of Comprehensive Income	61
Consolidated Balance Sheets	62
Consolidated Statements of Equity	63
Consolidated Statements of Cash Flows	64
Notes to Consolidated Financial Statements	65