Edgar Filing: TRANSOCEAN INC

form10-k.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

_________________

FORM 10-K

(Mark one)

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

For the fiscal year ended December 31, 2007

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

For the transition period from _____ to _____.

Commission file number 333-75899

_________________

TRANSOCEAN INC.

(Exact name of registrant as specified in its charter)

Cayman Islands	66-0582307
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)


4 Greenway Plaza, Houston, Texas	77046
(Address of principal executive offices)	(Zip code)

70 Harbour Drive, Grand Cayman, Cayman Islands	KYI-1003
(Address of principal executive offices)	(Zip code)

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

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

Title of class	Exchange on which registered
Ordinary Shares, par value $0.01 per share	New York Stock Exchange, Inc.

Securities registered pursuant to Section 12(g) of the Act: None

_________________

Indicate by check mark whether the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes þ No ¨

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act. Yes ¨ No þ

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 þ No ¨

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

Indicate by check mark whether the registrant is 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 þ Accelerated filer ¨ Non-accelerated filer ¨ (do not check if a smaller reporting company) Smaller reporting company ¨

Indicate by check mark whether the registrant is a shell company (as defined by Rule 12b-2 of the Exchange Act). Yes ¨ No þ

As of June 30, 2007, 289,280,582 ordinary shares were outstanding and the aggregate market value of such shares held by non-affiliates was approximately $30.6 billion (based on the reported closing market price of the ordinary shares on such date of $105.98 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 22, 2008, 317,748,270 ordinary shares were outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the registrant's definitive Proxy Statement to be filed with the Securities and Exchange Commission within 120 days of December 31, 2007, for its 2008 annual general meeting of shareholders, are incorporated by reference into Part III of this Form 10-K.

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TRANSOCEAN INC. AND SUBSIDIARIES

INDEX TO ANNUAL REPORT ON FORM 10-K

FOR THE YEAR ENDED DECEMBER 31, 2007

Item		Page

	PART I
ITEM 1.	Business	5
ITEM 1A.	Risk Factors	15
ITEM 1B.	Unresolved Staff Comments	23
ITEM 2.	Properties	23
ITEM 3.	Legal Proceedings	23
ITEM 4.	Submission of Matters to a Vote of Security Holders	27

	PART II
ITEM 5.	Market for Registrant’s Common Equity, Related Shareholder Matters and Issuer Purchases of Equity Securities	29
ITEM 6.	Selected Financial Data	31
ITEM 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	32
ITEM 7A.	Quantitative and Qualitative Disclosures About Market Risk	59
ITEM 8.	Financial Statements and Supplementary Data	60
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

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Index

Forward-Looking Information

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:

§ contract commencements,

§ contract option exercises,

§ revenues,

§ expenses,

§ results of operations,

§ commodity prices,

§ customer drilling programs,

§ supply and demand,

§ utilization rates,

§ dayrates,

§ contract backlog,

§ effects and results of the GlobalSantaFe merger and related transactions,

§ planned shipyard projects and rig mobilizations and their effects,

§ newbuild projects and opportunities,

§ the upgrade projects for the Sedco 700-series semisubmersible rigs,

§ other major upgrades,

§ contract awards,

§ newbuild completion delivery and commencement of operations dates,

§ expected downtime and lost revenue,

§ insurance proceeds,

§ cash investments of our wholly-owned captive insurance company,

§ future activity in the deepwater, mid-water and the jackup market sectors,

§ market outlook for our various geographical operating sectors and classes of rigs,

§ capacity constraints for ultra-deepwater rigs and other rig classes,

§ effects of new rigs on the market,

§ income related to and any payments to be received under the TODCO tax sharing agreement,

§ refinancing of the Bridge Loan Facility, including timing and components of the refinancing,

§ uses of excess cash,

§ share repurchases under our share repurchase program,

§ issuance of new debt,

§ debt reduction,

§ debt credit ratings,

§ planned asset sales,

§ timing of asset sales,

§ proceeds from asset sales,

§ our effective tax rate,

§ changes in tax laws, treaties and regulations,

§ tax assessments,

§ operations in international markets,

§ investments in joint ventures,

§ investments in recruitment, retention and personnel development initiative,

§ the level of expected capital expenditures,

§ results and effects of legal proceedings and governmental audits and assessments,

§ adequacy of insurance,

§ liabilities for tax issues, including those associated with our activities in Brazil, Norway and the United States,

§ liabilities for customs and environmental matters,

§ liquidity,

§ cash flow from operations,

§ adequacy of cash flow for our obligations,

§ effects of accounting changes,

§ adoption of accounting policies,

§ pension plan and other postretirement benefit plan contributions,

§ benefit payments, and

§ the timing and cost of completion of capital projects.

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Index

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

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

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

those described under “Item 1A. Risk Factors,”

the adequacy of sources of liquidity,

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

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

other factors discussed in this annual report and in the Company’s other filings with the SEC, which are available free of charge on the SEC’s website at www.sec.gov.

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

All subsequent written and oral forward-looking statements attributable to the Company 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.

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Index

PART I

ITEM 1.

Business

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. Our ordinary shares are listed on the New York Stock Exchange under the symbol “RIG.”

Transocean Inc. is a Cayman Islands exempted company with principal executive offices in the U.S. located at 4 Greenway Plaza, Houston, Texas 77046. Our telephone number at that address is (713) 232-7500. Our principal executive offices outside of the U.S. are located at 70 Harbour Drive, Grand Cayman, Cayman Islands KY1-1003. Our telephone number at that address is (345) 745-4500.

Background of Transocean

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.

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 our outstanding ordinary shares was reclassified by way of a scheme of arrangement under Cayman Islands law into (1) 0.6996 of our ordinary shares and (2) $33.03 in cash (the “Reclassification” and together with the Merger, the “Transactions”). At the effective time of the Merger, each outstanding ordinary share of GlobalSantaFe (the “GlobalSantaFe Ordinary Shares”) was exchanged for (1) 0.4757 of our ordinary shares (after giving effect to the Reclassification) and (2) $22.46 in cash. We issued approximately 107,752,000 of our ordinary shares in connection with the Merger and paid out $14.9 billion in cash in connection with the Transactions. We funded the payment of the cash consideration in the Transactions with $15.0 billion of borrowings under a $15.0 billion, one-year senior unsecured bridge loan facility (the “Bridge Loan Facility”) and have since refinanced a portion of those borrowings under the Bridge Loan Facility. We have included the financial results of GlobalSantaFe in our consolidated financial statements beginning November 27, 2007, the date the GlobalSantaFe Ordinary Shares were exchanged for our ordinary shares.

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 19—Segments, Geographical Analysis and Major Customers.

Drilling Fleet

We principally operate three types of drilling rigs:

drillships;

semisubmersibles; and

jackups.

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

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Index

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: (i) “High-Specification Floaters,” consisting of our “Ultra-Deepwater Floaters,” “Deepwater Floaters” and “Harsh Environment Floaters,” (ii) “Midwater Floaters,” (iii) “High-Specification Jackups,” (iv) “Standard Jackups” and (v) “Other Rigs.” As of February 20, 2008, our fleet of 139 rigs, which excludes assets held for sale that are not currently operating under a contract and rigs contracted for or under construction, included:

39 High-Specification Floaters, which are comprised of:

- 18 Ultra-Deepwater Floaters;

- 16 Deepwater Floaters; and

- five Harsh Environment Floaters;

29 Midwater Floaters;

10 High-Specification Jackups;

57 Standard Jackups; and

four Other Rigs, which are comprised of:

- two barge drilling rigs;

- one mobile offshore production unit; and

- one coring drillship.

As of February 20, 2008, our fleet was located in the Far East (21 units), U.K. North Sea (19 units), Middle East (18 units), U.S. Gulf of Mexico (16 units), Nigeria (13 units), India (12 units), Angola (11 units), Brazil (eight units), Norway (five units), other West African countries (five units), the Caspian Sea (three units), Trinidad (three units), Australia (two units), 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 consists 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 seven 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.

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Index

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 a Standard Jackup.

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 on short or near term contracts, generally cannot be reactivated upon short notice and normally require the hiring of most of the crew, a maintenance review and possibly significant refurbishment before they can be reactivated. 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. As of February 20, 2008, GSF High Island I, which is classified as held for sale, is warm stacked and is not included in the tables below (see "–Warm Stacked and Held for Sale").

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) GSF Explorer, which is subject to a capital lease with a remaining term of 19 years, and (3) GSF Jack Ryan, which is subject to a fully defeased capital lease with a remaining term of 13 years. None of our offshore drilling rigs are currently subject to any liens or mortgages.

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

Rigs Under Construction (8)

The following table provides certain information regarding our High-Specification Floaters contracted for or under construction as of February 20, 2008:

Name	Type	Expected completion	Water depth capacity (in feet)	Drilling depth capacity (in feet)	Contracted location
Ultra-Deepwater Floaters (a) (8)
Discoverer Americas (b)	HSD	Mid 2009	12,000	40,000	U.S. Gulf
Discoverer Clear Leader (b)	HSD	2Q 2009	12,000	40,000	U.S. Gulf
Discoverer Inspiration (b)	HSD	1Q 2010	12,000	40,000	U.S. Gulf
GSF Newbuild (b)	HSD	3Q 2010	12,000	40,000	(c)
Deepwater Pacific 1 (d)	HSD	2Q 2009	12,000	35,000	India
Deepwater Pacific 2 (d)	HSD	1Q 2010	10,000	35,000	(c)
Discoverer Luanda (b)	HSD	3Q 2010	7,500	40,000	Angola
GSF Development Driller III (b)	HSS	Mid-2009	7,500	30,000	Angola

________________________________

“HSD” means high-specification drillship.

“HSS” means high-specification semisubmersible.

(a)	Dynamically positioned.

(b)	Dual-activity.

(c)	Currently without contract.

(d)	Owned through our 50 percent interest in a joint venture company with Pacific Drilling Limited.

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Index

High-Specification Floaters (39)

The following table provides certain information regarding our High-Specification Floaters as of February 20, 2008:

Name	Type	Year entered service/upgraded(a)	Water depth capacity (in feet)	Drilling depth capacity (in feet)	Location
Ultra-Deepwater Floaters (b) (18)
Deepwater Discovery	HSD	2000	10,000	30,000	Nigeria
Deepwater Expedition	HSD	1999	10,000	30,000	Morocco
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	U.S. Gulf
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	35,000	Nigeria
Cajun Express (e)	HSS	2001	8,500	35,000	U.S. Gulf
Deepwater Nautilus (e)	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) (f)	HSS	1973/(f)	6,500	25,000	Nigeria
Sedco 706 (b) (f)	HSS	1976/(f)	6,500	25,000	Brazil
Sedco 707 (b)	HSS	1976/1997	6,500	25,000	Brazil
GSF Celtic Sea	HSS	1982/1998	5,750	25,000	U.S. Gulf
Jack Bates	HSS	1986/1997	5,400	30,000	Australia
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	Trinidad
Transocean Rather	HSS	1988	4,500	25,000	U.K. North Sea

Harsh Environment Floaters (5)
Transocean Leader	HSS	1987/1997	4,500	25,000	Norwegian N. Sea
Henry Goodrich	HSS	1985	2,000	30,000	U.S. Gulf
Paul B. Loyd, Jr	HSS	1990	2,000	25,000	U.K. North Sea
Transocean Arctic	HSS	1986	1,650	25,000	Norwegian N. Sea
Polar Pioneer	HSS	1985	1,500	25,000	Norwegian N. Sea

_______________________________________

“HSD” means high-specification drillship.

“HSS” means high-specification semisubmersible.

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

(b)	Dynamically positioned.

(c)	Enterprise-class rig.

(d)	Dual-activity.

(e)	Express-class rig.

(f)

The Sedco 702 and Sedco 706 are currently being upgraded from Midwater Floaters to Deepwater Floaters. The water depth and drilling depth capacity information assumes the completion of the upgrades. The Sedco 702 and Sedco 706 are currently expected to complete their upgrades and commence their contracts in the first quarter and the fourth quarter of 2008, respectively.

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Index

Midwater Floaters (29)

The following table provides certain information regarding our Midwater Floaters as of February 20, 2008:

Name	Type	Year entered service/upgraded(a)	Water depth capacity (in feet)	Drilling depth capacity (in feet)	Location
Sedco 700	OS	1973/1997	3,600	25,000	E. Guinea
Transocean Amirante	OS	1978/1997	3,500	25,000	U.S. Gulf
Transocean Legend	OS	1983	3,500	25,000	China
GSF Arctic I	OS	1983/1996	3,400	25,000	Brazil
C. Kirk Rhein, Jr.	OS	1976/1997	3,300	25,000	India
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	U.K. North Sea
Sedco 711	OS	1982	1,800	25,000	U.K. North Sea
Transocean John Shaw	OS	1982	1,800	25,000	U.K. North Sea
Sedco 712	OS	1983	1,600	25,000	U.K. North Sea
Sedco 714	OS	1983/1997	1,600	25,000	U.K. North Sea
Actinia	OS	1982	1,500	25,000	India
Dada Gorgud (b)	OS	1978/1998	1,500	25,000	Caspian Sea
GSF Arctic IV (c)	OS	1983/1999	1,500	25,000	U.K. North 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. North 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. North Sea
GSF Arctic II (c)	OS	1982	1,200	25,000	U.K. North Sea
Sedco 704	OS	1974/1993	1,000	25,000	U.K. North Sea

_______________________________________

“OS” means other semisubmersible.

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

(b)	Owned by the State Oil Company of the Azerbaijan Republic.

(c)

On February 15, 2008, we announced our intent to proceed with divestitures of the GSF Arctic II and the GSF Arctic IV semisubmersible rigs and the hiring of a third-party advisor. The divestitures are in furtherance of our previously announced proposed undertakings to the Office of Fair Trading in the U.K. made in connection with the Merger. As a result, we classified these rigs as held for sale.

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Index

High-Specification Jackups (10)

The following table provides certain information regarding our High-Specification Jackups as of February 20, 2008:

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

_______________________________________

(a)

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

Standard Jackups (57)

The following table provides certain information regarding our Standard Jackups as of February 20, 2008:

Name	Year entered service/upgraded(a)	Water depth capacity (in feet)	Drilling depth capacity (in feet)	Location
Trident IX	1982	400	21,000	Vietnam
Trident 17	1983	355	25,000	Malaysia
GSF Adriatic II	1981	350	25,000	Angola
GSF Adriatic III (b)	1982	350	25,000	U.S. Gulf
GSF Adriatic IX	1981	350	20,000	Gabon
GSF Adriatic X	1982	350	25,000	Egypt
GSF Key Manhattan	1980	350	25,000	Egypt
GSF Key Singapore	1982	350	25,000	Egypt
GSF Adriatic VI	1981	328	20,000	Nigeria
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	20,000	Angola
GSF Adriatic XI	1983	300	25,000	Vietnam
GSF Compact Driller	1992	300	25,000	Thailand
GSF Galveston Key	1978	300	25,000	Vietnam
GSF Key Gibraltar	1976/1996	300	25,000	Thailand
GSF Key Hawaii	1982	300	25,000	Qatar
GSF Labrador	1983	300	25,000	U.K. North 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	25,000	Indonesia
GSF Rig 134	1982	300	20,000	Malaysia
GSF Rig 136	1982	300	25,000	Indonesia
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	25,000	Vietnam
Interocean III	1978/1993	300	20,000	Egypt
Transocean Nordic	1984	300	25,000	Sakhalin Island
Trident II	1977/1985	300	25,000	India
Trident IV	1980/1999	300	25,000	Nigeria
Trident VIII	1981	300	21,000	Nigeria
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	Thailand
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	Gabon
GSF High Island VII	1982	250	20,000	Cameroon
GSF High Island VIII (b)	1981	250	20,000	U.S. Gulf
GSF High Island IX	1983	250	20,000	Nigeria
GSF Rig 103	1974	250	20,000	U.A.E.
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. North Sea
Trident VI	1981	220	21,000	Vietnam

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______________________________

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

(b)	On February 15, 2008, we entered into a definitive agreement with Hercules Offshore, Inc. to sell GSF Adriatic III, GSF High Island I (see "––Warm Stacked and Held for Sale") and GSF High Island VIII. As a result, we classified these rigs as held for sale.

Other Rigs

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

Warm Stacked and Held for Sale

As of February 20, 2008, GSF High Island I was warm stacked. We classified this rig as held for sale in connection with a definitive agreement executed on February 15, 2008 with Hercules Offshore, Inc. to sell this rig, together with GSF Adriatic III and GSF High Island VIII, which continue to operate under contract.

Markets

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

In recent years, there has been increased emphasis by oil companies on exploring for hydrocarbons in deeper waters. This 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 mid-water market sectors are serviced by our semisubmersibles and drillships. While the use of the term “deepwater” as used in the drilling industry to denote a particular sector of the market can vary and continues to evolve with technological improvements, we generally view the deepwater market sector as that which begins in water depths of approximately 4,500 feet and extends to the maximum water depths in which rigs are capable of drilling, which is currently approximately 12,000 feet. We view the mid-water market sector as that which covers water depths of about 300 feet to approximately 4,500 feet.

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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 drilling barges located in Southeast Asia.

Contract Backlog

We have been successful in building contract backlog in 2007 within all of our asset classes. Prior to the Merger, our contract backlog at October 30, 2007 was approximately $23 billion, a 15 percent and 109 percent increase compared to our contract backlog at December 31, 2006 and 2005, respectively. Our contract backlog at December 31, 2007 was approximately $32 billion including the effect of the Merger. 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

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

	Years ended December 31,
	2007		2006		2005
Operating revenues
United States	$	1,259	$	806	$	648
United Kingdom		848		439		335
India		761		291		296
Nigeria		587		447		218
Other countries (a)		2,922		1,899		1,395
Total operating revenues	$	6,377	$	3,882	$	2,892

	As of December 31,
	2007		2006
Long-lived assets
United States	$	5,856	$	2,504
United Kingdom		2,301		457
Nigeria		1,902		856
Other countries (a)		10,871		3,509
Total long-lived assets	$	20,930	$	7,326

______________________

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

Contract Drilling Services

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

A dayrate drilling contract generally extends over a period of time covering either the drilling of a single well or group of wells or covering a stated term. These contracts typically can be terminated or suspended by the client without paying a termination fee under various circumstances such as the loss or destruction of the drilling unit or the suspension of drilling operations for a specified period of time as a result of a breakdown of major equipment. 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 suspend or terminate their contracts. Some drilling contracts permit the customer to terminate the contract at the customer’s option without paying a termination fee. Suspension of drilling contracts will result in the reduction in or loss of dayrate for the period of the suspension. If our customers cancel some of our significant contracts and we are unable to secure new contracts on substantially similar terms, or if contracts are suspended for an extended period of time, it could adversely affect our consolidated statement of financial position, results of operations or cash flows.

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Drilling Management Services

As a result of the Merger, we provide drilling management services primarily on a turnkey basis through our wholly owned subsidiary, Applied Drilling Technology Inc. (“ADTI”), and through ADT International, a division of one of our U.K. subsidiaries. ADTI operates primarily in the U.S. Gulf of Mexico, and ADT International operates primarily in the North Sea. Under a typical turnkey arrangement, we will 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, with payment contingent upon successful completion of the well program. 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. In addition to turnkey arrangements, we also participate in project management operations. In our project management operations, we provide certain planning, management and engineering services, purchase equipment and provide personnel and other logistical services to customers. Our project management services differ from turnkey drilling services in that the customer retains control of the drilling operations and thus retains the risk associated with the project. These drilling management services did not represent a material portion of our revenues for the year ended December 31, 2007.

Integrated Services

From time to time, we provide well and logistics services in addition to our normal drilling services through third party contractors and our employees. We refer to these other services as integrated services. The work generally consists of individual contractual agreements 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 27, 2008, we were performing such services in India. These integrated service revenues did not represent a material portion of our revenues for any period presented.

Oil and Gas Properties

As a result of the Merger, 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 primarily in the United States offshore Louisiana and Texas and in the U.K. sector of the North Sea. These oil and gas properties did not represent a material portion of our revenues for the year ended December 31, 2007.

Joint Venture, Agency and Sponsorship Relationships and Other Investments

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

We hold a 50 percent interest in Overseas Drilling Limited (“ODL”), 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.

In early October 2007, we exercised our option to purchase a 50 percent equity interest in Transocean Pacific Drilling Inc. (“TPDI”), a joint venture company formed by us and Pacific Drilling Limited (“Pacific Drilling”), a Liberian company, whereby we acquired exclusive marketing rights for two ultra-deepwater drillships to be named Deepwater Pacific 1 and Deepwater Pacific 2, which are currently under construction. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Outlook−Drilling Market.”

In Azerbaijan, the semisubmersibles Istiglal and Dada Gorgud operate under long-term bareboat charters between (a) Caspian Drilling Company Limited (“CDC”), a joint venture in which we hold a 45 percent ownership interest, and (b) the owner of both rigs, the State Oil Company of the Azerbaijan Republic (“SOCAR”), our sole equity partner in CDC. SOCAR has granted exclusive bareboat charter rights to CDC for the life of the joint venture. During 2005, these bareboat charter rights were extended through October 2011, pursuant to an amendment to the agreement establishing CDC.

A joint venture in which we hold a passive minority interest operates primarily in Libya, and to a limited extent in Syria. 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 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 Syria. On June 30, 2006, Libya was removed from the U.S. government’s list of state sponsors of terrorism and is no longer subject to sanctions or embargoes. We believe our passive minority investment has been maintained in accordance with all applicable laws and regulations. Potential investors could view our passive minority interest in our Libyan joint venture negatively, which could adversely affect our reputation and the market for our ordinary shares. In addition, certain U.S. states have recently enacted legislation regarding investments by their retirement systems in companies that have business activities or contacts with countries that have been identified as terrorist-sponsoring states, and similar legislation may be pending or introduced in other states. 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.

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

Significant Clients

We engage in offshore drilling for most of the leading international oil companies (or their affiliates), as well as for many government-controlled and independent oil companies. Our most significant clients in 2007 were Chevron, Shell and BP accounting for 12 percent, 11 percent and 10 percent, respectively, of our 2007 operating revenues. No other client accounted for 10 percent or more of our 2007 operating revenues. The loss of any of these significant clients could, at least in the short term, have a material adverse effect on our results of operations.

Environmental Regulation

For a discussion of the effects of environmental regulation, see “Item 1A. Risk Factors—Compliance with or breach of environmental laws can be costly and could limit our operations.” We have made and will continue to make expenditures to comply with environmental requirements. To date we have not expended material amounts in order to comply and we do not believe that our compliance with such requirements will have a material adverse effect upon our results of operations or competitive position or materially increase our capital expenditures.

Employees

We require highly skilled personnel to operate our drilling units. As a result, we conduct extensive personnel recruiting, training and safety programs. At December 31, 2007, we had approximately 21,100 employees, and we also utilized approximately 3,400 persons through contract labor providers. Some of our employees, most of whom work in the U.K., Nigeria 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 salary negotiation in 2008. 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 Tribunal has recently issued its decision and we are currently reviewing the decision to determine its potential impact on our operations and expenses as well as to determine whether the decision should be appealed. The application of the Working Time Regulations to the offshore sector could result in higher labor costs and could undermine our ability to obtain a sufficient number of skilled workers in the U.K.

Available Information

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

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

Audit Committee Charter;

Corporate Governance Committee Charter;

Executive Compensation Committee Charter;

Finance and Benefits Committee Charter;

Mission Statement;

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

Corporate Governance Guidelines.

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.

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ITEM 1A.

Risk Factors

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 OPEC to set and maintain production levels and pricing;

the level of production in non-OPEC countries;

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

advances in exploration and development technology; and

the worldwide military and political environment, including uncertainty or instability resulting from an escalation or additional outbreak of armed hostilities or other crises in the Middle East or other geographic areas or further acts of terrorism in the United States, 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. We may be required to idle rigs or enter into lower rate contracts in response to market conditions in the future.

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 further 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 value of these rigs, or the goodwill balance, may not be recoverable.

Our business involves numerous operating hazards.

Our operations are subject to the usual hazards inherent in the drilling of oil and gas wells, such as blowouts, reservoir damage, loss of production, loss of well control, punch-throughs, craterings, fires and natural disasters such as hurricanes and tropical storms. In particular, the Gulf of Mexico area is subject to hurricanes and other extreme weather conditions on a relatively frequent basis, and our drilling rigs in the region may be exposed to damage or total loss by these storms (some of which may not be covered by insurance). The occurrence of these events could result in the suspension of drilling operations, damage to or destruction of the equipment involved and injury to or death of rig personnel. We are also subject to personal injury and other claims by rig personnel as a result of our drilling operations. Operations also may be suspended because of machinery breakdowns, abnormal drilling conditions, failure of subcontractors to perform or supply goods or services, or personnel shortages. In addition, offshore drilling operations are subject to perils peculiar to marine operations, including capsizing, grounding, collision and loss or damage from severe weather. Damage to the environment could also result from our operations, particularly through oil spillage or extensive uncontrolled fires. We may also be subject to property, environmental and other damage claims by oil and gas companies. Our insurance policies and contractual rights to indemnity may not adequately cover losses, and we do not have insurance coverage or rights to indemnity for all risks.

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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 broad insurance coverage, including coverage for property damage, occupational injury and illness, and general and marine third-party liabilities. Property damage insurance covers against marine and other perils, including losses due to capsizing, grounding, collision, fire, lightning, hurricanes and windstorms (excluding named storms in the U.S. Gulf of Mexico and war perils worldwide, for which we generally have no coverage), action of waves, punch-throughs, cratering, blowouts and explosion. However, 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.

Pollution and environmental risks generally are not totally insurable. 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. We do not generally have hull and machinery coverage for losses due to hurricanes in the U.S Gulf of Mexico and war perils worldwide. 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 27, 2008, all of the rigs that we owned or operated were covered by existing insurance policies.

Failure to retain key personnel could hurt our operations.

We require highly skilled personnel to operate and provide technical services and support for our business worldwide. Competition for the labor required for drilling operations, including for turnkey drilling and drilling management services businesses and construction projects, has intensified as the number of rigs activated, added to worldwide fleets or under construction has increased, leading to shortages of qualified personnel in the industry and creating upward pressure on wages and higher turnover. If turnover increases, we could see a reduction in the experience level of our personnel, which could lead to higher downtime and more operating incidents, which in turn could decrease revenues and increase costs. In response to these labor market conditions, we are increasing efforts in our recruitment, training, development and retention programs as required to meet our anticipated personnel needs. If these labor trends continue, we may experience further increases in costs or limits on operations.

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 the U.K., Nigeria 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 2008. 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 Tribunal has recently issued its decision and we are currently reviewing the decision to determine its potential impact on our operations and expenses as well as to determine whether the decision should be appealed. 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.

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Our shipyard projects are subject to delays and cost overruns.

We have committed to a total of eight deepwater newbuild rig projects and two Sedco 700-series rig upgrades. We are also discussing other potential newbuild opportunities with several of our oil and gas company and government-controlled clients. We also have a variety of other more limited shipyard projects at any given time. These shipyard projects are subject to the risks of delay or cost overruns inherent in any such construction project resulting from numerous factors, including the following:

shipyard unavailability;

shortages of equipment, materials or skilled labor;

unscheduled delays in the delivery of ordered materials and equipment;

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

work stoppages;

client acceptance delays;

weather interference or storm damage;

unanticipated cost increases; and

difficulty in obtaining necessary permits or approvals.

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

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. Recently, 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. We have recently replaced our primary global logistics provider, which may result in delays and disruptions, and potentially increased costs, in some operations. 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.

Failure to secure a drilling contract prior to deployment of two of our newbuild drillships could adversely affect our results of operations.

In September 2007, GlobalSantaFe entered into a contract with Hyundai Heavy Industries, Ltd. for the construction of a new drillship the delivery of which is scheduled for the third quarter of 2010. In addition, the drillship Deepwater Pacific 2 that is being constructed by our joint venture with Pacific Drilling is scheduled for delivery in the first quarter of 2010. We have not yet secured a drilling contract for either drillship. Historically, the industry has experienced prolonged periods of overcapacity, during which many rigs were idle for long periods of time. Our failure to secure a drilling contract for either rig prior to its deployment could adversely affect our results of operations.

The anticipated benefits of the Merger may not be realized, and there may be difficulties in integrating our operations.

We merged with GlobalSantaFe on November 27, 2007, with the expectation that the Merger would result in various benefits, including, among other things, synergies, cost savings and operating efficiencies. We may not achieve these benefits at the levels expected or at all.

We may not be able to integrate our operations with those of GlobalSantaFe without a loss of employees, customers or suppliers, a loss of revenues, an increase in operating or other costs or other difficulties. In addition, we may not be able to realize the operating efficiencies, synergies, cost savings or other benefits expected from the Merger. Any unexpected delays incurred in connection with the integration could have an adverse effect on our business, results of operations or financial condition.

Our business has changed as a result of our recent combination with GlobalSantaFe.

Our business has changed as a result of our recent combination with GlobalSantaFe. Following the Merger, our relative exposure to the jackup market has increased. Portions of the jackup market, including the U.S. Gulf of Mexico, have in recent periods experienced lower dayrates than in previous periods. Additionally, as a result of the Merger, we are now engaged in drilling management services including turnkey drilling operations and own interests in oil and gas properties, which, as described below, will expose us to additional risks.

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Our overall debt level increased as a result of the Transactions, and we may lose the ability to obtain future financing and suffer competitive disadvantages.

We have a substantial amount of debt. As a result of the Transactions, our overall debt level increased from approximately $3 billion at December 31, 2006, to approximately $17 billion at December 31, 2007. Our 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;

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.

We may not be successful in refinancing the remaining borrowings under our bridge loan facility, and the terms of any refinancing may not be favorable to us.

Our bridge loan facility has a maturity of one year. Although we expect to refinance the remaining portion of this debt on more favorable terms, such refinancing is subject to conditions in the credit markets, which are currently volatile, and there can be no assurance that we will be successful in refinancing the remaining portion of debt or that the terms of the refinancing will be favorable to us, which could adversely affect our results of operations or financial condition.

Our overall debt level and/or our inability to refinance the remaining borrowings under our bridge loan facility on favorable terms could lead the credit rating agencies to lower our corporate credit ratings below currently expected levels and possibly below investment grade.

Market conditions could prohibit us from refinancing the bridge loan facility at favorable rates and on favorable terms, which could limit our ability to efficiently repay debt and could cause us to maintain a high level of leverage or issue debt with unfavorable terms and conditions. This leverage level 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 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.

A loss of a major tax dispute or a successful tax challenge to our structure 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 Cayman Islands company and operate 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. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Outlook–Tax Matters” and “—Critical Accounting Estimates–Income Taxes.”

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 are monitoring the progress of the treaty renegotiation with a view to determining what, if any, steps are appropriate to mitigate any potential negative impact. One of these steps could include transactions that would result in certain subsidiaries or the parent entity of our group of companies having a different tax residency or different jurisdiction of incorporation. 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.

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Various proposals have been made in recent years that, if enacted into law, could have an adverse impact on us. Examples include, but are not limited to, proposals that would broaden the circumstances in which a non-U.S. company would be considered a U.S. resident and a proposal that could limit treaty benefits on certain payments by U.S. subsidiaries to non-U.S. affiliates. Such legislation, if enacted, could cause a material increase in our tax liability and effective tax rate, which could result in a significant negative impact on our earnings and cash flows from operations. In addition, our income tax returns are subject to review and examination in various jurisdictions in which we operate. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Outlook–Tax Matters” and “—Critical Accounting Estimates–Income Taxes.”

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

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

In 2007, we utilized NOL carryforwards to reduce our 2007 U.S. taxable income. The NOL carryforwards utilized in 2007 included NOL carryforwards of one of our subsidiaries from periods prior to a previous merger of two of our subsidiaries. The U.S. Internal Revenue Service (“IRS”) may take the position that the 2001 merger subjected the NOL carryforwards to various limitations under U.S. tax laws. If a limitation were imposed, it could result in a portion of our NOL carryforwards expiring unused or in our inability to fully offset taxable income with NOLs in a particular year, even though our NOL carryforwards exceed our taxable income for the year.

We may be required to accrue additional tax liability on certain earnings.

We have not provided for deferred taxes on the unremitted earnings of certain subsidiaries that are permanently reinvested. Should a distribution be made of the unremitted earnings of these subsidiaries, we could be required to record additional current and deferred taxes that, if material, could have an adverse effect on our statement of financial position, results of operations and cash flows.

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

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

terrorist acts, war and civil disturbances;

expropriation or nationalization of equipment; and

the inability to repatriate income or capital.

We are protected to some extent against loss of capital assets, but generally not loss of revenue, from most of these risks through indemnity provisions in our drilling contracts. Effective May 1, 2007, 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 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. Potential investors could view any potential violation of OFAC regulations negatively, which could adversely affect our reputation and the market for our ordinary shares. In addition, certain U.S. states have recently enacted legislation regarding investments by their retirement systems in companies that have business activities or contacts with countries that have been identified as terrorist-sponsoring states, and similar legislation may be pending or introduced in other states. 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. 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. Our internal compliance program has discovered a potential OFAC compliance issue. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Outlook–Regulatory Matters.”

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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.

Another risk inherent in our operations is the possibility of currency exchange losses where revenues are received and expenses are paid in nonconvertible currencies. We may also incur losses as a result of an inability to collect revenues because of a shortage of convertible currency available in the country of operation.

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 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 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 United States and abroad. The DOJ has 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 began developing an investigative plan which would allow us to promptly review and produce relevant and responsive information requested by the DOJ and SEC. Subsequently, we expanded this investigation 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. We prepared and presented an investigative plan to the DOJ and have informed the SEC of the ongoing investigation. We have begun implementing the investigative plan and are keeping the DOJ and SEC apprised of the scope and details of our investigation and are producing relevant information in response to their requests.

We cannot predict the ultimate outcome of these investigations, 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.

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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 de-man those rigs because we will use the crew to prepare the rig for its next contract. During times of reduced activity, reductions in costs may not be immediate as portions of the crew may be required to prepare 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.

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

Our customers may terminate or suspend many of our term drilling contracts without paying a termination fee under various circumstances such as the loss or destruction of the drilling unit, downtime or impaired performance caused by equipment or operational issues, some of which will be beyond our control, or sustained periods of downtime due to force majeure events. Suspension of drilling contracts results in loss of the dayrate for the period of the suspension. If our customers cancel some of our significant contracts and we are unable to secure new contracts on substantially similar terms, it could adversely affect our results of operations. In reaction to depressed market conditions, our customers may also seek renegotiation of firm drilling contracts to reduce their obligations.

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.

Turnkey drilling operations expose us to additional risks, which can adversely affect our profitability, because we assume the risk for operational problems and the contracts are on a fixed-price basis.

We conduct most of our drilling services under dayrate drilling contracts where the customer pays for the period of time required to drill or work over a well. However, we also enter into a significant number of turnkey contracts each year. Our compensation under turnkey contracts depends on whether we successfully drill to a specified depth or, under some of the contracts, complete the well. Unlike dayrate contracts, where ultimate control is exercised by the customer, we are exposed to additional risks when serving as a turnkey drilling contractor because we make all critical decisions. Under a turnkey contract, the amount of our compensation is fixed at the amount we bid to drill the well. Thus, we will not be paid if operational problems prevent performance unless we choose to drill a new well at our expense. Further, we must absorb the loss if problems arise that cause the cost of performance to exceed the turnkey price. Given the complexities of drilling a well, it is not unusual for unforeseen problems to arise. We do not generally insure against risks of unbudgeted costs associated with turnkey drilling operations. By contrast, in a dayrate contract, the customer retains most of these risks. As a result of the additional risks we assume in performing turnkey contracts, costs incurred from time to time exceed revenues earned. Accordingly, in prior quarters, GlobalSantaFe incurred losses on certain of its turnkey contracts, and we can expect that will continue to be the case in the future. Depending on the size of these losses, they may have a material adverse affect on the profitability of our drilling management services business in a given period.

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Turnkey drilling operations are contingent on our ability to win bids and on rig availability, and the failure to win bids or obtain rigs for any reason may have a material adverse effect on the results of operations of our drilling management services business.

Our results of operations from our drilling management services business may be limited by certain factors, including our ability to find and retain qualified personnel, to hire suitable rigs at acceptable rates, and to obtain and successfully perform turnkey drilling contracts based on competitive bids. Our ability to obtain turnkey drilling contracts is largely dependent on the number of these contracts available for bid, which in turn is influenced by market prices for oil and natural gas, among other factors. Furthermore, our ability to enter into turnkey drilling contracts may be constrained from time to time by the availability of our or third-party drilling rigs. Constraints on the availability of rigs may cause delays in our drilling management projects and a reduction in the number of projects that we can complete overall, which could have an adverse effect on the results of operations of our drilling management services business.

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 caused damage to a number of rigs in the U.S. Gulf of Mexico fleet, and rigs that were moved off location by the storms may have damaged platforms, pipelines, wellheads and other drilling rigs during their movements. The Minerals Management Service of the U.S. Department of the Interior (“MMS”) has conducted hearings and is undertaking studies to determine methods to prevent or reduce the number of such incidents in the future. In 2006, the 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.

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We are subject to anti-takeover provisions.

Our articles of association 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 ordinary 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 our board may designate the terms of any new series of preference shares;

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 the exact number of directors on our board can be set from time to time by a majority of the whole board of directors and not by our shareholders, subject to a minimum of two and a maximum of 14;

provide that directors can be removed from office only for cause, as defined in our articles of association, by the affirmative vote of the holders of the issued shares generally entitled to vote;

provide that any vacancy on the board of directors will be filled by the affirmative vote of the remaining directors and not by the shareholders; provided, however, that during the period until November 27, 2009, if the vacancy relates to a director who was a Transocean director prior to the Merger, then the vacancy will be filled by the other Transocean directors, and if the vacancy relates to a director who was a GlobalSantaFe director prior to the Merger, then the vacancy will be filled by the other GlobalSantaFe directors;

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

provide that only a majority of the directors may call extraordinary general meetings of the 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 issued voting shares.

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

ITEM 1B.

Unresolved Staff Comments

None

ITEM 2.

Properties

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

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

Through the Merger, we acquired Challenger Minerals Inc. and Challenger Minerals (North Sea) Limited (collectively, “CMI”), formerly wholly-owned subsidiaries of GlobalSantaFe. CMI conducts oil and gas activities and holds property interests primarily in the U.S. offshore Louisiana and Texas and in the U.K. sector of the North Sea.

ITEM 3.

Legal Proceedings

Several of our subsidiaries have been named, along with numerous unaffiliated defendants, in several complaints that have been filed in the Circuit Courts of the State of Mississippi involving approximately 750 plaintiffs that allege personal injury arising out of asbestos exposure in the course of their employment by some of these defendants between 1965 and 1986. The complaints also name as defendants certain of TODCO’s subsidiaries to which we may owe indemnity. Further, the complaints name other unaffiliated defendant companies, including companies that allegedly manufactured drilling related products containing asbestos. The complaints allege that the defendant drilling contractors used those asbestos-containing products in offshore drilling operations, land based drilling operations and in drilling structures, drilling rigs, vessels and other equipment and assert claims based on, among other things, negligence and strict liability, and claims authorized under the Jones Act. The plaintiffs generally seek awards of unspecified compensatory and punitive damages. We have not been provided with sufficient information to determine the number of plaintiffs who claim to have been exposed to asbestos aboard our rigs, whether they were employees, their period of employment, the period of their alleged exposure to asbestos, or their medical condition, and we have not entered into any settlements with any plaintiffs. Accordingly, we are unable to estimate our potential exposure in these lawsuits. We historically have maintained insurance which we believe will be available to address any liability arising from these claims. We intend to defend these lawsuits vigorously, but there can be no assurance as to their ultimate outcome.

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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 $133 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 February 15, 2008, the U.S. dollar equivalent of this assessment was approximately $222 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 and we have appealed the first level Brazilian court’s ruling to a higher level court in Brazil. 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. 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 $130 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, 2007, the subsidiary was a defendant in approximately 1,041 lawsuits with 102 filed during 2007. Some of these lawsuits include multiple plaintiffs and we estimate that there are approximately 3,380 plaintiffs in these lawsuits. For many of these lawsuits against the subsidiary, 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, 2007, 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 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.

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

Environmental Matters

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

We have been named as a PRP in connection with a site located in Santa Fe Springs, California, known as the Waste Disposal, Inc. site. We and other PRPs have agreed with the U.S. Environmental Protection Agency (“EPA”) and the DOJ to settle our potential liabilities for this site by agreeing to perform the remaining remediation required by the EPA. The form of the agreement is a consent decree, which has now 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.

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One of our subsidiaries has been requested to contribute approximately $140,000 toward remediation costs of the Environmental Protection Corporation (“EPC”) Eastside Disposal Facility near Bakersfield, California, by a company that has taken responsibility for site remediation from the California Department of Toxic Substances Control. Our subsidiary is alleged to have been a small contributor of the wastes that were improperly disposed by EPC at the site. We have undertaken an investigation as to whether our subsidiary is a liable party, what the total remediation costs may be and the amount of waste that may have been contributed by other parties. Until that investigation is complete we are unable to assess our potential liability, if any, for this site.

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

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

appropriate investigatory and/or remedial actions; and

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

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

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

the numbers of other PRPs and their financial viability; and

the remediation methods and technology to be used.

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 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.

The plaintiffs and the codefendant threatened to add GlobalSantaFe Corporation 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, which is also 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 United States 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 Corporation and two other subsidiaries in the lawsuit. We believe that these legal theories should not be applied against GlobalSantaFe Corporation 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. The codefendant also seeks to dismiss the bankruptcies. The efforts to assert alter ego and single business enterprise theory claims against GlobalSantaFe Corporation were rejected by the Court in Avoyelles Parish and the lawsuit against the other defendant went to trial on February 19, 2007. The action 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 settlement also purported to assign the plaintiffs’ claims in the lawsuit against our subsidiary and other parties, including GlobalSantaFe Corporation and the other two subsidiaries, to the codefendant.

In the bankruptcy case, our subsidiary has filed suit to obtain declaratory and injunctive relief against the codefendant concerning the matters described above and GlobalSantaFe Corporation has intervened in the matter. The codefendant is seeking to dismiss the bankruptcy case and a modification of the automatic stay afforded under the Bankruptcy Code to our subsidiary and its parent so that the codefendant may pursue the entities and GlobalSantaFe Corporation for contribution and indemnity and the purported assigned rights from the plaintiffs in the lawsuit including the alter ego and single business enterprise claims and potential insurance rights. 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 Bankruptcy Court will hold a hearing to determine the forum where these actions may proceed. The Bankruptcy Court did not address the codefendant’s pending claims against GlobalSantaFe Corporation and the other two subsidiaries, which will also be the subject of a future hearing. The Bankruptcy Court also denied the debtors’ requests for preliminary declaratory and injunctive relief.

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In addition, the codefendant has filed proofs of claim against both our subsidiary and its parent with regard to its claims arising out of the settlement agreement, including recovery of the settlement funds and remediation costs and damages for the purported assigned claims. A Motion for Partial Summary Judgment seeking annulment and dismissal of the codefendant’s proofs of claim has also been filed by the debtors and remains pending. Our subsidiary, its parent and GlobalSantaFe Corporation 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.

ITEM 4.

Submission of Matters to a Vote of Security Holders

At a meeting of shareholders of Transocean Inc. held on November 9, 2007, 216,923,167 shares were presented in person or by proxy out of 290,802,547 shares outstanding and entitled to vote as of the record date, constituting a quorum. The matters submitted to a vote of shareholders, as set forth in our proxy statement relating to the meeting, and the corresponding voting results were as follows:

(i)

With respect to the approval of a scheme of arrangement providing for the Reclassification, the following number of votes were cast:

For		Against / authority withheld		Abstain
213,967,649		938,988		2,016,530

(ii)

With respect to the approval of the issuance of our ordinary shares to GlobalSantaFe shareholders in the Merger, the following number of votes were cast:

For		Against / authority withheld		Abstain
213,970,926		1,038,212		1,914,029

(iii)

With respect to the approval of the amendment and restatement of our memorandum of association and articles of association, the following number of votes were cast:

For		Against / authority withheld		Abstain
213,957,432		1,017,437		1,948,298

Executive Officers of the Registrant

		Age as of
Officer	Office	February 27, 2008
Robert L. Long	Chief Executive Officer	62
Jon A. Marshall	President and Chief Operating Officer	56
Jean P. Cahuzac	Executive Vice President, Assets	54
Steven L. Newman	Executive Vice President, Performance	43
Eric B. Brown	Senior Vice President and General Counsel	56
Gregory L. Cauthen	Senior Vice President and Chief Financial Officer	50
David J. Mullen	Senior Vice President, Marketing and Planning	50
Cheryl D. Richard	SeSenior Vice President, Human Resources and Information Technology	51
John H. Briscoe	Vice President and Controller	50

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 served as President and Chief Executive Officer of the Company and a member of the board of directors from October 2002 to October 2006, at which time he relinquished the position of President. Mr. Long served as President of the Company from December 2001 to October 2002. 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.

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Jon A. Marshall is President and Chief Operating Officer and a member of the board of directors of the Company. Mr. Marshall served as a director and Chief Executive Officer of GlobalSantaFe from May 2003 until November 2007, when GlobalSantaFe merged with a subsidiary of the Company. Mr. Marshall served as the Executive Vice President and Chief Operating Officer of GlobalSantaFe from November 2001 until May 2003. From 1998 to November 2001, Mr. Marshall was employed with Global Marine Inc. (which merged into a subsidiary of Santa Fe International Corporation, which was renamed GlobalSantaFe Corporation in the merger), where he held the same position. Prior to that, Mr. Marshall served as President of several Global Marine operating subsidiaries. Mr. Marshall joined Global Marine in 1979 and held numerous operational and managerial positions before his promotion to President.

Jean P. Cahuzac is Executive Vice President, Assets of the Company. Mr. Cahuzac served as President of the Company from October 2006 to November 2007, at which time he assumed his current position. Mr. Cahuzac served as Executive Vice President and Chief Operating Officer of the Company from October 2002 to October 2006 and Executive Vice President, Operations of the Company from February 2001 until October 2002. Mr. Cahuzac served as President of Sedco Forex from January 1999 until the time of the Sedco Forex merger, at which time he assumed the positions of Executive Vice President and President, Europe, Middle East and Africa with the Company. Mr. Cahuzac served as Vice President-Operations Manager of Sedco Forex from May 1998 to January 1999, Region Manager-Europe, Africa and CIS of Sedco Forex from September 1994 to May 1998 and Vice President/General Manager-North Sea Region of Sedco Forex from February 1994 to September 1994. He had been employed by Schlumberger Limited since 1979.

Steven L. Newman is Executive Vice President, Performance of the Company. Mr. Newman served as Executive Vice President and Chief Operating Officer from October 2006 to November 2007 and Senior Vice President of Human Resources and Information Process Solutions from May 2006 to October 2006. He served as Senior Vice President of Human Resources, Information Process Solutions and Treasury from March 2005 to May 2006. Mr. Newman served as Vice President of Performance and Technology of the Company from August 2003 until March 2005. Mr. Newman served as Region Manager, Asia Australia from May 2001 until August 2003. From December 2000 to May 2001, Mr. Newman served as Region Operations Manager of the Africa-Mediterranean Region of the Company. From April 1999 to December 2000, Mr. Newman served in various operational and marketing roles in the Africa-Mediterranean and U.K. region offices. Mr. Newman has been employed by the Company since 1994.

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

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

David J. Mullen is Senior Vice President, Marketing and Planning of the Company. Mr. Mullen served as Vice President of the Company’s North and South America Unit from January 2005 to October 2006, when he assumed his present position. From May 2001 to January 2005, Mr. Mullen was President of Schlumberger Oilfield Services for North and South America, and Mr. Mullen served as the Company’s Vice President of Human Resources from January 2000 to May 2001. Prior to joining the Company at the time of our merger with Sedco Forex, Mr. Mullen served in a variety of roles with Schlumberger Limited, where he had been employed since 1983.

Cheryl D. Richard is Senior Vice President, Human Resources and Information Technology of the Company. Ms. Richard served as Senior Vice President, Human Resources of GlobalSantaFe from June 2003 until the date of the Merger. 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. Mr. Briscoe served as Vice President, Audit and Advisory Services from June 2007 to October 2007 and Director of Investor Relations and Communications from January 2007 to June 2007. From June 2005 to January 2007, Mr. Briscoe served as Finance Director for the Company’s North and South America Unit. Prior to joining the Company in June 2005, Mr. Briscoe served as Vice President of Accounting for Ferrellgas Inc. from July 2003 to June 2005, Vice President of Administration from June 2002 to July 2003 and Division Controller from June 1997 to June 2002. Prior to working for Ferrellgas, Mr. Briscoe served as Controller for Latin America for Dresser Industries Inc., which has subsequently been acquired by Halliburton, Inc. Mr. Briscoe started his career with seven years in public accounting beginning with the firm of KPMG and ending with Ernst & Young as an Audit Manager.

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PART II

ITEM 5.

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

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

	Price
	High		Low
2006
First quarter (a)	$	84.29	$	70.05
Second quarter (a)		90.16		70.75
Third quarter (a)		81.63		64.52
Fourth quarter (a)		84.23		65.57

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

_________________

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

On February 22, 2008, the last reported sales price of our ordinary shares on the NYSE Composite Tape was $137.96 per share. On such date, there were 5,250 holders of record of our ordinary shares and 317,748,270 ordinary shares outstanding.

On November 27, 2007, each of our 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 of our ordinary shares and $33.03 in cash. The closing price of our ordinary shares on November 26, 2007, the last trading day before the completion of the Transactions, was $129.39. The opening price of our ordinary shares on November 27, 2007, after the completion of the 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 the discretion of the board of directors, (3) be subject to restrictions contained in our credit facilities and other debt covenants and (4) be payable only out of our profits or share premium account in accordance with Cayman Islands law.

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

We are a Cayman Islands exempted company. Our authorized share capital is $13,000,000, divided into 800,000,000 ordinary shares, par value $0.01, and 50,000,000 preference shares, par value $0.10, of which shares may be designated and created as shares of any other classes or series of shares with the respective rights and restrictions determined by action of our board of directors. On February 27, 2008, no preference shares were outstanding.

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

With respect to the election of directors, each holder of ordinary shares entitled to vote at the election has the right to vote, in person or by proxy, the number of shares held by him for as many persons as there are directors to be elected and for whose election that holder has a right to vote. The directors are divided into three classes, with only one class being up for election each year. Although our articles of association contemplate that directors are elected by a plurality of the votes cast in the election, we have adopted a majority vote policy in the election of directors as part of our Corporate Governance Guidelines. This policy provides that the board may nominate only those candidates for director who have submitted an irrevocable letter of resignation which would be effective upon and only in the event that (1) such nominee fails to receive a sufficient number of votes from shareholders in an uncontested election and (2) the board accepts the resignation. If a nominee who has submitted such a letter of resignation does not receive more votes cast for than against the nominee’s election, the Corporate Governance Committee must promptly review the letter of resignation and recommend to the board whether to accept the tendered resignation or reject it. The board must then act on the Corporate Governance Committee’s recommendation within 90 days following the certification of the shareholder vote. The board must promptly disclose its decision regarding whether or not to accept the nominee’s resignation letter in a Form 8-K furnished to the SEC or other broadly disseminated means of communication. Cumulative voting for the election of directors is prohibited by our articles of association.

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

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

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

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

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

Our articles of association contain provisions that could prevent or delay an acquisition of our Company by means of a tender offer, proxy contest or otherwise. See “Item 1A. Risk Factors—We are subject to anti-takeover provisions.”

The foregoing description is a summary. This summary is not complete and is subject to the complete text of our memorandum and articles of association. For more information regarding our ordinary shares and our preference shares, see our Current Report on Form 8-K dated May 14, 1999, as amended by our Current Report on Form 8-K/A filed on November 27, 2007, and our memorandum and articles of association. Our memorandum and articles of association are filed as exhibits to this annual report.

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Index

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 2007		—	$	—		—		600
November 2007		203,333		133.82		—		600
December 2007		1,636		136.61		—		600
Total		204,969	$	133.84		—		600

_________________

(1)

Total number of shares purchased in the fourth quarter of 2007 consists of shares withheld by us in satisfaction of withholding taxes due upon the vesting of restricted shares granted to our employees under our Long-Term Incentive Plan to pay withholding taxes due upon vesting of a restricted share award.

(2)

In May 2006, our board of directors authorized an increase in the amount of ordinary shares which may be repurchased pursuant to our share repurchase program to $4.0 billion from $2.0 billion, which was previously authorized and announced in October 2005. The shares may be repurchased from time to time in open market or private transactions. The repurchase program does not have an established expiration date and may be suspended or discontinued at any time. Under the program, repurchased shares are retired and returned to unissued status. From inception through December 31, 2007, we have repurchased a total of 46.9 million of our ordinary shares at a total cost of $3.4 billion. We do not currently expect to make any additional share repurchases under the program in the near future.

ITEM 6.

Selected Financial Data

The selected financial data as of December 31, 2007 and 2006 and for each of the three years in the period ended December 31, 2007 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, 2005, 2004 and 2003, and for the years ended December 31, 2004 and 2003 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.”

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, we completed our merger with GlobalSantaFe and identified the Company as the acquirer in a purchase business combination for accounting purposes. 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. Per share amounts for all periods have been adjusted for the Reclassification. The Reclassification was accounted for 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.

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	Years ended December 31,
	2007			2006			2005			2004			2003
	(In millions, except per share data)
Statement of operations data
Operating revenues	$	6,377		$	3,882		$	2,892		$	2,614		$	2,434
Operating income		3,239			1,641			720			328			240
Net income (a)		3,131			1,385			716			152			19

Earnings per share
Basic	$	14.65		$	6.32		$	3.13		$	0.68		$	0.08
Diluted	$	14.14		$	6.10		$	3.03		$	0.67		$	0.08

Balance sheet data (at end of period)
Total assets	$	34,364		$	11,476		$	10,457		$	10,758		$	11,663
Debt due within one year		6,172			95			400			19			46
Long-term debt		11,085			3,203			1,197			2,462			3,612
Total shareholders’ equity		12,566			6,836			7,982			7,393			7,193

Other financial data
Cash provided by operating activities	$	3,073		$	1,237		$	864		$	600		$	525
Cash provided by (used in) investing activities		(5,677	)		(415	)		169			551			(445	)
Cash provided by (used in) financing activities		3,378			(800	)		(1,039	)		(1,174	)		(820	)
Capital expenditures		1,380			876			182			127			494
Operating margin		51	%		42	%		25	%		13	%		10	%

_________________

(a)	In the year ended December 31, 2003, we recorded a cumulative effect of an accounting change in the amount of $1 million, with no effect on basic or diluted earnings per share.

ITEM 7.

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

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

Overview

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. See “—Significant Events.” 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.

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

	Years ended December 31,
	2007			2006			Change
	(In millions, except average daily revenue and percentages)
Average daily revenue (a)(b)	$	211,900		$	142,100		$	69,800
Utilization (b)(c)		90	%		84	%		n/a
Statement of operations data
Operating revenues	$	6,377		$	3,882		$	2,495
Operating and maintenance expenses		2,781			2,155			626
Operating income		3,239			1,641			1,598
Net income		3,131			1,385			1,746
Balance sheet data (at end of period)
Cash and cash equivalents		1,241			467			774
Total assets		34,364			11,476			22,888
Total debt		17,257			3,298			13,959

_________________

“n/a” means not applicable.

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

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

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

We continue to experience strong demand, which has resulted in high utilization and historically high dayrates. We are seeing leading dayrates at or near record levels for most rig classes and customer interest for multi-year contracts. Interest in High-Specification Floaters remains particularly strong.

A shortage of qualified personnel in our industry is driving up compensation costs and suppliers are increasing prices as their backlogs grow. These labor and vendor cost increases, while meaningful, are not expected to be significant in comparison with our expected increase in revenue in 2008 and beyond.

Our revenues for the year ended December 31, 2007 increased from the prior year period primarily as a result of increased activity, higher dayrates and the addition of GlobalSantaFe’s operations for one month. 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”). In addition, our financial results for the year ended December 31, 2007 included the recognition of gains from the sales of three rigs and other income recognized under the TODCO tax sharing agreement. Total debt increased as a result of cash payments made in the Reclassification and Merger, which were financed with borrowings under the Bridge Loan Facility and refinanced with the issuance of the convertible senior notes and the senior notes and borrowings under the 364-Day Revolving Credit Facility. See “—Liquidity and Capital Resources–Sources and Uses of Liquidity.”

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 and (2) Other. 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 segment includes drilling management services and oil and gas properties. Drilling management services are provided through Applied Drilling Technology Inc. (“ADTI”), our wholly owned subsidiary, and through ADT International, a division of one of our U.K. subsidiaries. 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 Challenger Minerals Inc. and Challenger Minerals (North Sea) Limited (collectively, “CMI”), our oil and gas subsidiaries.

Significant Events

Merger with GlobalSantaFe—In November 2007, we completed the Merger with GlobalSantaFe. See Notes to Consolidated Financial Statements—Note 4—Merger with GlobalSantaFe Corporation.

Contract Backlog—We have been successful in building contract backlog in 2007 within all of our asset classes. Prior to the Merger, our contract backlog at October 30, 2007 was approximately $23 billion, a 15 percent and 109 percent increase compared to our contract backlog at December 31, 2006 and 2005, respectively. Our contract backlog at December 31, 2007 was approximately $32 billion, which includes the effect of the Merger. See “—Outlook–Drilling Market” and “—Performance and Other Key Indicators.”

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TODCO Tax Sharing Agreement (“TSA”)—In July 2007, Hercules Offshore, Inc. (“Hercules”) completed the acquisition of TODCO. The TSA requires Hercules to make an accelerated change of control payment to our wholly-owned subsidiary, Transocean Holdings Inc. within 30 days of the date of the acquisition as a result of the deemed utilization of TODCO’s pre-IPO tax benefits. We received a $118 million change of control payment from Hercules in August 2007. We recognized $276 million as other income in the third quarter of 2007 for this accelerated payment and payments received in prior periods related to TODCO’s 2006 and 2007 tax years. See Notes to Consolidated Financial Statements—Note 15—Income Taxes.

Construction and Upgrade Programs—During 2007, we were awarded a drilling contract requiring the construction of a fourth enhanced Enterprise-class drillship. We expect the rig to be contributed to a joint venture in which we expect to retain a 65 percent ownership interest. The newbuild is expected to commence operations during the third quarter of 2010. During 2006, we were awarded drilling contracts requiring the construction of three enhanced Enterprise-class drillships. The newbuilds are expected to commence operations during the second quarter of 2009, mid-2009 and the first quarter of 2010, respectively. See “—Outlook–Drilling Market.”

In connection with the Merger, we acquired one Ultra-Deepwater Floater under construction and one contracted for construction. The newbuilds are expected to commence operations in mid-2009 and the third quarter of 2010. See “—Outlook−Drilling Market.”

During 2005, we entered into agreements with clients to upgrade two of our Sedco 700-series semisubmersible rigs in our Midwater Floaters fleet, the Sedco 702 and the Sedco 706, at a cost expected to be approximately $300 million for each rig. The upgraded rigs will be dynamically positioned and will have a water depth drilling capacity of up to 6,500 feet. The Sedco 702 and Sedco 706 entered a shipyard for the upgrade in early 2006 and the fourth quarter of 2007, respectively. We have completed the upgrade of the Sedco 702 and expect the rig to commence operations in the first quarter of 2008. We expect the Sedco 706 upgrade to be completed in the fourth quarter of 2008.

Pacific Drilling Limited (“Pacific Drilling”)—In October 2007, we exercised our option to purchase a 50 percent interest in a joint venture company through which we and Pacific Drilling own two newbuild Ultra-Deepwater Floaters to be named Deepwater Pacific 1 and Deepwater Pacific 2. The newbuilds are expected to commence operations during the second quarter of 2009 and first quarter of 2010. See “—Liquidity and Capital Resources–Acquisitions, Dispositions and Capital Expenditures.”

Asset Dispositions—During 2007, we completed the sales of a Deepwater Floater (Peregrine I), a tender rig (Charley Graves) and a swamp barge (Searex VI) for net proceeds of $344 million and recognized gains on the sales of $264 million. See “—Liquidity and Capital Resources–Acquisitions, Dispositions and Capital Expenditures.”

Bank Credit Agreements—In September 2007, we entered into a $15.0 billion, one-year senior unsecured bridge loan facility (“Bridge Loan Facility”). See “—Liquidity and Capital Resources–Sources and Uses of Cash.”

In November 2007, we 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”). See “—Liquidity and Capital Resources–Sources and Uses of Cash.”

In December 2007, we entered into a $1.5 billion, 364-Day revolving credit facility under the 364-Day Revolving Credit Facility Agreement dated December 3, 2007 (“364-Day Revolving Credit Facility”). See “—Liquidity and Capital Resources–Sources and Uses of Cash.”

Debt Issuance—In December 2007, we issued $6.6 billion aggregate principal amount of 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. See “—Liquidity and Capital Resources–Sources and Uses of Liquidity.”

In December 2007, we issued $2.5 billion aggregate principal amount of 5.25% Senior Notes due 2013, 6.00% Senior Notes due 2018 and 6.80% Senior Notes due 2038. See “—Liquidity and Capital Resources–Sources and Uses of Liquidity.”

Debt Repayments—In August 2007, we terminated our existing $1.0 billion two-year term credit facility due August 2008 (“Term Credit Facility”). See “—Liquidity and Capital Resources–Sources and Uses of Liquidity.”

In connection with the Merger, we terminated our existing $1.0 billion five-year revolving credit facility expiring July 2011 (“Former Revolving Credit Facility”). See “—Liquidity and Capital Resources–Sources and Uses of Liquidity.”

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Debt Redemptions—During 2007, we called our Zero Coupon Convertible Debentures due May 2020 and our 1.5% Convertible Debentures due May 2021 for redemption. See “—Liquidity and Capital Resources–Sources and Uses of Liquidity.”

Repurchase of Ordinary Shares—During 2007, we repurchased and retired 5.2 million of our ordinary shares at a total cost of $400 million. See “—Liquidity and Capital Resources–Sources and Uses of Liquidity.” We do not currently expect to make any additional share repurchases under the program in the near future.

Outlook

Drilling Market—Demand for offshore drilling units continues to be strong, particularly for rigs capable of drilling in deepwater. Our High-Specification Floater fleet is fully committed in 2008 and only eight of our High-Specification Floater fleet have any available uncommitted time in 2009. We have only five rigs remaining in our Midwater Floater fleet that have any available uncommitted time left in 2008 and only 16 rigs remaining in this fleet that have any available uncommitted time left in 2009. We have two High-Specification Jackups and 20 Standard Jackups that have uncommitted time left in 2008, and eight High-Specification Jackups and 36 Standard Jackups have uncommitted time left in 2009. Dayrates for new contracts for both floaters and jackups continue to be strong. Our contract backlog at February 20, 2008 was approximately $32 billion, up from approximately $23 billion at October 30, 2007, with approximately $9 billion of the increase due to the Merger.

In April 2007, we entered into a marketing and purchase option agreement with Pacific Drilling that provided us with the exclusive marketing right for two newbuild Ultra-Deepwater Floaters to be named Deepwater Pacific 1 and Deepwater Pacific 2, as well as an option to purchase a 50 percent interest in a joint venture company through which we and Pacific Drilling would own the drillships. In October 2007, we obtained a firm commitment for the Deepwater Pacific 1, and we exercised our option and acquired a 50 percent interest in the joint venture, TPDI. The Deepwater Pacific 1 was awarded a firm commitment for a four-year contract which may be converted by the customer to a five-year drilling contract on or prior to October 31, 2008. The drilling contract is expected to commence in the second quarter of 2009 following shipyard construction, sea trials, mobilization to location and customer acceptance. The Deepwater Pacific 2 is expected to be completed in the first quarter of 2010. We are in advanced discussions with a customer regarding the award of a long-term contract for the rig. We estimate total capital expenditures for the construction of these rigs to be approximately $685 million and $665 million, excluding capitalized interest, respectively. See “—Liquidity and Capital Resources–Acquisitions, Dispositions and Capital Expenditures.”

As of December 31, 2007, we and Pacific Drilling had each paid $238 million in documented costs for the two rigs since the formation of the joint venture in October 2007.

We are providing construction management services for the Pacific Drilling 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 ordinary shares or cash at a purchase price based on an appraisal of the fair value of the drillships, subject to various adjustments.

In June 2007, we were awarded a five-year drilling contract for a fourth enhanced Enterprise-class drillship. The enhanced Enterprise-class drillship, to be named Discoverer Luanda, is expected to be owned and operated by a joint venture which is expected to be 65 percent owned by us and 35 percent owned by an Angolan partner. We estimate total capital expenditures for the construction of the Discoverer Luanda to be approximately $640 million, excluding capitalized interest. We currently expect the Discoverer Luanda to begin operations in Angola during the third quarter of 2010, after construction in South Korea followed by sea trials, mobilization to Angola and customer acceptance.

Prior to the Merger, GlobalSantaFe had one Ultra-Deepwater Floater under construction, the GSF Development Driller III, and one contracted for construction. The GSF Development Driller III was awarded a seven-year drilling contract and is expected to be completed in mid-2009. Construction on the other newbuild is expected to be completed in the third quarter of 2010. We estimate total capital expenditures for the construction of the GSF Development Driller III to be approximately $590 million. We estimate total capital expenditures for the construction of the other newbuild to be approximately $740 million, excluding capitalized interest. We currently expect the GSF Development Driller III to begin operations in Angola in mid-2009, after construction in Singapore followed by sea trials, mobilization to Angola and customer acceptance.

We have been successful in building contract backlog within our High-Specification Floaters fleet with 23 of our 47 current and future High-Specification Floaters, including six of the eight newbuilds and the two Sedco 700-series rig upgrades, contracted into or beyond 2011 as of February 20, 2008. These 23 units also include 16 of our 26 current Ultra-Deepwater Floaters. Our total contract backlog of approximately $32 billion as of February 20, 2008 includes an estimated $21 billion of backlog represented by our High-Specification Floaters. We continue to believe that the long-term outlook for deepwater capable rigs is favorable. In 2007 we saw successful drilling efforts in the lower tertiary trend of the U.S. Gulf of Mexico; the discovery of light oil and non-associated gas in the deepwaters of Brazil; continued exploration success in the deepwaters offshore India; a discovery in the deepwaters of the South China Sea; and exploration activity in the Orphan Basin in Canada. Additionally, the continued exploration success in the deepwaters of West Africa and the opening of additional deepwater acreage in the U.S. Gulf of Mexico supports our optimistic outlook for the deepwater drilling market sector. In November 2007, we sold the Peregrine I as part of our overall strategy to dispose of older rigs that are no longer technologically advanced or otherwise not competitive in the international marketplace. As of February 20, 2008, none of our High-Specification Floater fleet contract days are uncommitted for the remainder of 2008, while approximately 9 percent, 29 percent and 59 percent are uncommitted in 2009, 2010 and 2011, respectively.

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Our Midwater Floaters fleet, comprising 29 semisubmersible rigs, is largely committed to contracts that extend into 2009. We continue to see customer demand for multi-year contracts for these units. We completed the reactivation of the C. Kirk Rhein, Jr., which has been awarded a two-year contract in India at a $340,000 dayrate and commenced operations in February 2007. We are actively pursuing the sale of two Midwater Floaters (GSF Arctic II and GSF Arctic IV) in the North Sea in connection with our previously announced proposed undertakings to the Office of Fair Trading in the U.K. As of February 20, 2008, seven percent of our Midwater Floater fleet contract days are uncommitted for the remainder of 2008, while approximately 41 percent, 70 percent and 92 percent are uncommitted in 2009, 2010 and 2011, respectively.

We continue to see steady growth in demand for Jackups, and we believe that the increase in newbuild supply capacity can be absorbed over the short term. We do not have the visibility to see beyond the second quarter of 2008, and supply growth is a concern for the second half of 2008. As of February 20, 2008, 14 percent of our High-Specification Jackup fleet contract days are uncommitted for the remainder of 2008, while approximately 51 percent, 96 percent and 100 percent are uncommitted in 2009, 2010 and 2011, respectively. In addition, 16 percent of our Standard Jackup fleet contract days are uncommitted for the remainder of 2008, while approximately 56 percent, 77 percent and 90 percent are uncommitted in 2009, 2010 and 2011, respectively.

On February 15, 2008, we entered into a definitive agreement with Hercules Offshore, Inc. to sell three of our Standard Jackups (GSF Adriatic III, GSF High Island I and GSF High Island VIII) for approximately $320 million. At February 27, 2008, these assets were classified as held for sale.

We expect our revenues to continue to increase in 2008 due to the inclusion of GlobalSantaFe’s operations as well as the commencement of new contracts with higher dayrates. The scheduled commencement of the Sedco 702 and Sedco 706 contracts at the end of the rigs’ deepwater upgrade shipyard projects in the first and fourth quarters of 2008, respectively, are also expected to increase our revenues in 2008. We expect these increases will be partially offset by a decrease in revenue from the sale of the Peregrine I in November 2007.

The aggregate amount of out-of-service time we incur in 2008 is expected to increase substantially due to the inclusion of GlobalSantaFe’s operations, partially offset by a decrease in out-of-service time largely due to a decrease in shipyard time for the legacy Transocean rigs. However, the shipyard projects we intend to undertake in 2008 will involve rigs with higher dayrates than those that underwent shipyard projects in 2007 and, consequently, we expect lost revenue from shipyard projects in 2008 from legacy Transocean rigs to be generally in line with lost revenue in 2007.

We expect the inclusion of GlobalSantaFe’s operations, as well as industry inflation in 2008, to continue to increase our operating and maintenance costs including our shipyard and major maintenance program expenditures. In addition, the types of shipyard projects we forecast for 2008 are generally more costly, so we expect shipyard project costs to increase from 2007 to 2008 with respect to the legacy Transocean rigs despite the expected decrease in out-of-service time. We expect our operating and maintenance costs in 2008 to further increase as a result of the completion of the Sedco 702 and Sedco 706 deepwater upgrades. We expect these increases to be partially offset by lower operating costs due to the sale of the Peregrine I in November 2007. Finally, we expect to continue to invest in a number of recruitment, retention and personnel development initiatives in connection with the manning of the crews of the deepwater upgrades and newbuild rigs and our efforts to mitigate expected personnel attrition.

We expect that a number of fixed-price contract options will be exercised by our customers in 2008, which will preclude us from taking full advantage of any increased market rates for rigs subject to these contract options. We have six existing contracts with fixed-priced or capped options for dayrates that we believe are less than current market dayrates. 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.

Insurance Matters—We periodically evaluate our hull and machinery and third-party liability insurance limits and self-insured retentions. Effective May 1, 2007, 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. In the opinion of management, adequate accruals have been made based on known and estimated losses related to such exposures.

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Tax Matters—We are a Cayman Islands company and we operate through our various subsidiaries in a number of countries throughout the world. Consequently, 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 eight years. We have agreed to extensions beyond the statute of limitations in three 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, results of operations or cash flows.

In February 2007, we entered into a settlement agreement with the U.S. Internal Revenue Service (“IRS”) regarding our U.S. federal income tax returns for 2001 through 2003. The IRS agreed to settle all issues for this period. This settlement resulted in no cash tax payment.

Our 2004 and 2005 U.S. federal income tax returns are currently under examination by the IRS. In October 2007, we received from the IRS examination reports setting forth proposed changes to the U.S. federal taxable income reported for the years 2004 and 2005. The proposed changes would result in a cash tax payment of approximately $413 million, exclusive of interest. We filed a letter with the IRS protesting the proposed changes on November 19, 2007. The protest letter puts forth our position that we believe our returns are materially correct as filed. We will continue to vigorously defend against these proposed changes. The IRS audits of GlobalSantaFe’s 2004 and 2005 U.S. federal income tax returns are still in the examination phase. We do not expect the conclusion of these audits to give rise to a material tax liability.

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 $112 million, plus a 75 percent penalty and $70 million of interest through December 31, 2007. We believe our returns are materially correct as filed, and we intend to vigorously contest these assessments. We filed a protest letter with the Brazilian tax authorities on January 25, 2008.

Norwegian civil tax and criminal authorities are investigating various transactions undertaken in 2001 and 2002. The authorities initiated inquiries into these transactions in September 2004 and in March 2005 obtained additional information on the transactions pursuant to a Norwegian court order. In 2006 we filed a formal protest with respect to a notification by the Norwegian tax authorities of their intent to propose assessments that would result in increased tax of approximately $287 million, plus interest, related to certain restructuring transactions. The authorities indicated penalties imposed on the assessment could range from 15 to 60 percent of the assessment. In addition, the authorities issued a preliminary notification in February 2008 of their intent to issue a separate tax assessment of approximately $77 million related to a 2001 dividend payment, plus interest and penalties, which could range from 15 to 60 percent of the assessment. In the course of its investigations, the Norwegian authorities secured certain records located in the United Kingdom related to a Norwegian subsidiary that was previously subject to tax in Norway. The authorities are assessing the need to impose additional taxes on this Norwegian subsidiary. 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.

On January 1, 2007, as part of our implementation of FIN 48, we recorded a long-term liability of $142 million related to the Norwegian tax issues described above. Since January 1, 2007, the long-term liability has increased to $168 million due to the accrual of interest and exchange rate fluctuations. 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 15—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 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.

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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 United States and abroad. The DOJ has 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 began developing an investigative plan which would allow us to promptly review and produce relevant and responsive information requested by the DOJ and SEC. Subsequently, we expanded the investigation 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 investigations have focused on whether the agent and the customs brokers have fully complied with the terms of their respective agreements, the FCPA and local laws. We prepared and presented an investigative plan to the DOJ and have informed the SEC of the ongoing investigation. We have begun implementing the investigative plan and are keeping the DOJ and SEC apprised of the scope and details of our investigation and are producing relevant information in response to their requests. We cannot predict the ultimate outcome of the investigations, 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 OFAC, and comprehensive restrictions on the export and re-export of U.S.-origin items to Iran. 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 have retained outside counsel to conduct a thorough investigation of the matter.

Performance and Other Key Indicators

Contract Backlog—The following table presents our contract backlog, including firm commitments only, for our Contract Drilling segment at the periods ended December 31, 2007 and 2006. Firm commitments are typically represented by signed drilling contracts. 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, which are not expected to be significant to our contract drilling revenues.

	December 31, 2007		December 31, 2006
	(In millions)
Contract backlog
High-Specification Floaters	$	20,708	$	14,354
Midwater Floaters		5,728		3,770
High-Specification Jackups		768		140
Standard Jackups		4,445		1,897
Other Rigs		158		65
Total	$	31,807	$	20,226

The firm commitments that comprise the contract backlog for our Contract Drilling segment as of December 31, 2007 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 dayrate during the firm contract period after commencement of operations.

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	For the years ending December 31,
	Total		2008		2009		2010		2011		Thereafter
	(In millions, except average dayrates)
Contract backlog
High-Specification Floaters	$	20,708	$	4,599	$	4,814	$	4,017	$	2,643	$	4,635
Midwater Floaters		5,728		2,650		1,806		869		263		140
High-Specification Jackups		768		478		273		17		—		—
Standard Jackups		4,445		2,322		1,229		592		297		5
Other Rigs		158		52		36		26		26		18
Total	$	31,807	$	10,101	$	8,158	$	5,521	$	3,229	$	4,798

Average Dayrates	Total		2008		2009		2010		2011		Thereafter
High-Specification Floaters	$	404,000	$	353,000	$	393,000	$	416,000	$	443,000	$	439,000
Midwater Floaters		301,000		294,000		315,000		298,000		323,000		249,000
High-Specification Jackups		154,000		150,000		158,000		188,000		—		—
Standard Jackups		154,000		153,000		156,000		155,000		148,000		102,000
Other Rigs		60,000		50,000		56,000		68,000		68,000		65,000
Total	$	270,000	$	234,000	$	270,000	$	293,000	$	304,000	$	397,000

Fleet Average Daily Revenue and Utilization—The following table shows our average daily revenue and utilization for each of the three months ended December 31, 2007, September 30, 2007 and December 31, 2006 for our Contract Drilling segment. Average daily revenue is defined as contract drilling revenue earned per revenue earning day in the period. Utilization in the table below is defined as the total actual number of revenue earning days in the period as a percentage of the total number of calendar days in the period for all drilling rigs in our fleet.

	Three months ended
	December 31, 2007			September 30, 2007			December 31, 2006
Average daily revenue
High-Specification Floaters
Ultra-Deepwater Floaters	$	346,100		$	323,200		$	275,300
Deepwater Floaters	$	265,300		$	251,600		$	216,500
Harsh Environment Floaters	$	326,300		$	312,300		$	199,400
Total High-Specification Floaters	$	311,600		$	291,900		$	237,800
Midwater Floaters	$	274,600		$	254,000		$	184,600
High-Specification Jackups	$	173,400		$	131,600		$	133,300
Standard Jackups	$	130,800		$	120,000		$	95,300
Other Rigs	$	48,600		$	54,900		$	48,200

Total fleet average daily revenue	$	224,000		$	219,700		$	171,700

Utilization
High-Specification Floaters
Ultra-Deepwater Floaters		97	%		99	%		92	%
Deepwater Floaters		75	%		76	%		78	%
Harsh Environment Floaters		80	%		85	%		97	%
Total High-Specification Floaters		85	%		86	%		86	%
Midwater Floaters		95	%		92	%		90	%
High-Specification Jackups		100	%		100	%		100	%
Standard Jackups		91	%		89	%		89	%
Other Rigs		97	%		98	%		99	%

Total fleet average utilization		90	%		89	%		89	%

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Liquidity and Capital Resources

Sources and Uses of Cash

Our primary sources of cash in 2007 were our cash flows from operations, proceeds from asset sales, proceeds from the issuance of the convertible notes and senior notes in December 2007, borrowings under the Bridge Loan Facility and our other credit facilities, cash received under our tax sharing agreement with TODCO and proceeds from issuance of ordinary shares upon the exercise of stock options. Our primary uses of cash were payment of the cash consideration in connection with the Transactions, repurchases of our ordinary shares, capital expenditures (including for newbuild construction) and repayments of borrowings under our credit facilities. At December 31, 2007, we had $1,241 million in cash and cash equivalents.

	Years ended December 31,
	2007			2006			Change
	(In millions)
Net cash from operating activities
Net income	$	3,131		$	1,385		$	1,746
Depreciation, depletion and amortization		411			401			10
Other non-cash items		(231	)		(480	)		249
Working capital changes		(238	)		(69	)		(169	)
	$	3,073		$	1,237		$	1,836

Net cash provided by operating activities increased due to more cash generated from net income, partially offset by higher use of cash for working capital items.

	Years ended December 31,
	2007			2006			Change
	(In millions)
Net cash from investing activities
Capital expenditures	$	(1,380	)	$	(876	)	$	(504	)
Consideration paid to GlobalSantaFe shareholders		(5,129	)		—			(5,129	)
Cash balances acquired in connection with the Merger		695			—			695
Proceeds from disposal of assets, net		379			461			(82	)
Joint ventures and other investments, net		(242	)		—			(242	)
	$	(5,677	)	$	(415	)	$	(5,262	)

Net cash used in investing activities increased primarily due to cash paid out in connection with the Merger. Capital expenditures increased by $504 million over the corresponding prior year period primarily due to the construction of eight Ultra-Deepwater Floaters, the two Sedco 700-series deepwater upgrades and other equipment replaced and upgraded on our existing rigs. In addition, proceeds from asset sales were lower in 2007 during which three units were sold as compared to 2006 during which eight drilling units were sold.

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Index

	Years ended December 31,
	2007			2006			Change
	(In millions)
Net cash from financing activities
Borrowings under 364-Day Revolving Credit Facility	$	1,500		$	—		$	1,500
Borrowings under other credit facilities		15,000			1,000			14,000
Repayments under other credit facilities		(12,030	)		(300	)		(11,730	)
Proceeds from issuance of debt		9,095			1,000			8,095
Repayments of debt		(3	)		—			(3	)
Financing costs		(106	)		(5	)		(101	)
Payment to shareholders for Reclassification of ordinary shares		(9,859	)		—			(9,859	)
Proceeds from issuance of ordinary shares upon exercise of warrants		40			—			40
Proceeds from issuance of ordinary shares under share-based compensation plans, net		72			69			3
Repurchase of ordinary shares		(400	)		(2,601	)		2,201
Tax benefit from issuance of ordinary shares under share-based compensation plans		70			7			63
Other, net		(1	)		30			(31	)
	$	3,378		$	(800	)	$	4,178

Net cash provided by financing activities increased primarily due to net proceeds of $14 billion from the issuance of the convertible notes and senior notes in December 2007 and borrowings under the Bridge Loan Facility, the Five-Year Revolving Credit Facility and the 364-Day Revolving Credit Facility, compared to $2.0 billion from the issuance of the Floating Rate Notes and borrowings under the Term Credit Facility in 2006. Partially offsetting these increases was the payment to shareholders for the Reclassification of ordinary shares in connection with the Transactions. In addition, we used less cash to repurchase our ordinary shares under our share repurchase program in 2007 than in 2006, and we received more cash from the issuance of our ordinary shares under our share-based compensation program and associated tax benefit.

Acquisitions, Dispositions and Capital Expenditures

Acquisitions—Following the completion of the Transactions, we intend to focus on the repayment of debt in 2008 and 2009. Nevertheless, we could, from time to time, review possible acquisitions of businesses and drilling rigs and may in the future make significant 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 ordinary shares or other securities. In addition, from time to time, we review possible dispositions of drilling units.

In April 2007, we entered into a marketing and purchase option agreement with Pacific Drilling that provided us with the exclusive marketing right for two newbuild Ultra-Deepwater Floaters to be named Deepwater Pacific 1 and Deepwater Pacific 2, as well as an option to purchase a 50 percent interest in a joint venture company through which we and Pacific Drilling would own the drillships. In October 2007, we obtained a firm commitment for the Deepwater Pacific 1, and we exercised our option and acquired a 50 percent interest in the joint venture, TPDI. See “—Outlook–Drilling Market.” The Deepwater Pacific 1 was awarded a firm commitment for a four-year contract which may be converted to a five-year drilling contract by the customer on or prior to October 31, 2008. The drilling contract is expected to commence in the second quarter of 2009 following shipyard construction, sea trials, mobilization to location and customer acceptance. The Deepwater Pacific 2 is expected to be completed in the first quarter of 2010 and we are currently in active discussions with several customers regarding the award of a long-term contract for the rig. We estimate total capital expenditures for the construction of these rigs to be approximately $685 million and $665 million, excluding capitalized interest, respectively. As of December 31, 2007, we and Pacific Drilling had each paid $238 million in documented costs for the two rigs.

We are providing construction management services for the Deepwater Pacific newbuilds and have agreed to provide operating management services once these drillships begin operations. Beginning on October 18, 2010, Pacific Drilling will have the right to exchange its interest in the joint venture for our ordinary shares or cash based on an appraisal of the fair value of the drillships, subject to various adjustments.

Dispositions—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. On February 15, 2008, we entered into a definitive agreement with Hercules to sell three of our Standard Jackups (GSF Adriatic III, GSF High Island I and GSF High Island VIII) for approximately $320 million. In addition, on February 15, 2008, we announced our intent to proceed with divestitures of the GSF Arctic II and the GSF Arctic IV semisubmersible rigs and the hiring of a third-party advisor. The divestitures are in furtherance of our previously announced proposed undertakings to the Office of Fair Trading in the U.K. made in connection with the Merger. See “—Outlook–Drilling Market.”

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Index

Capital Expenditures—Capital expenditures, including capitalized interest of $76 million, totaled $1.4 billion during the year ended December 31, 2007, 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 in 2007 and expected in future years (in millions):

	Total costs through December 31, 2007		Expected costs for the year ending December 31, 2008		Estimated costs thereafter		Total estimated cost at completion

Discoverer Clear Leader	$	409	$	210	$	30	$	649
Sedco 700-series upgrades		396		200		—		596
GSF Development Driller III (a)		369		170		50		589
Discoverer Americas		301		190		130		621
Deepwater Pacific 1 (b)		279		130		270		679
Discoverer Inspiration		248		190		230		668
Deepwater Pacific 2 (b)		179		190		290		659
GSF Newbuild (a)		109		120		510		739
Discoverer Luanda		107		230		300		637
Capitalized Interest		92		130		150		372
Total	$	2,489	$	1,760	$	1,960	$	6,209

_________________

(a)	These costs include our initial investments in the GSF Development Driller III and GSF Newbuild of $356 million and $109 million, respectively, representing the estimated fair values of the rigs at the time of the Merger.

(b)

The costs for Deepwater Pacific 1 and Deepwater Pacific 2 represent 100 percent of expenditures incurred prior to our investment in the joint venture ($277 million and $178 million, respectively), 100 percent of expenditures incurred since our investment in the joint venture and 100 percent of expenditures to be incurred. However, Pacific Drilling shares 50 percent of these costs.

During 2008, we expect capital expenditures to be approximately $2.5 billion, including approximately $1.8 billion for our major construction and conversion projects, as detailed in the above table. The level of our capital expenditures is partly dependent upon 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 2008 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.

Sources and Uses of Liquidity

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

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.

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.

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Bank Credit Agreements—In September 2007, we entered into the Bridge Loan Facility. In connection with the Transactions, we borrowed $15 billion under the Bridge Loan Facility at the reserve-adjusted LIBOR plus the applicable margin, which is based upon our Debt Rating. As of February 27, 2008, the applicable margin was 0.4 percent. We may prepay the Bridge Loan Facility in whole or in part without premium or penalty. In addition, this facility requires mandatory prepayments of outstanding borrowings in an amount equal to 100 percent of the net cash proceeds resulting from any of the following (in each case subject to certain agreed exceptions): (1) the sale or other disposition of any of our property or assets above a predetermined threshold; (2) the receipt of certain net insurance or condemnation proceeds; (3) certain issuances of our equity securities; and (4) the incurrence of indebtedness for borrowed money by us. The Bridge Loan Facility contains a maximum leverage ratio of no greater than 350 percent as of June 30, 2008, and 300 percent thereafter. Borrowings under the Bridge Loan Facility are subject to acceleration upon the occurrence of events of default. At February 27, 2008, we had $3.1 billion outstanding under this facility at a weighted-average interest rate of 3.61 percent.

In November 2007, we entered into the Five-Year Revolving Credit Facility. Under the terms of the Five-Year Revolving Credit Facility, we may make borrowings at either (1) a base rate, determined as the greater of (a) the prime loan rate or (b) the federal funds effective rate plus 0.5 percent, or (2) the reserve-adjusted LIBOR plus the applicable margin, which is based upon our Debt Rating. A facility fee, varying from 0.07 percent to 0.17 percent depending on our Debt Rating, is incurred on the daily amount of the underlying commitment, whether used or unused, throughout the term of the facility. A utilization fee, varying from 0.05 percent to 0.10 percent depending on our Debt Rating, is payable if amounts outstanding under the Five-Year Revolving Credit Facility are greater than or equal to 50 percent of the total underlying commitment. At February 27, 2008, the applicable margin, facility fee and utilization fee were 0.26 percent, 0.09 percent and 0.10 percent, respectively. The Five-Year Revolving Credit Facility may be prepaid in whole or in part without premium or penalty. At February 27, 2008, no borrowings were outstanding under the Five-Year Revolving Credit Facility.

In December 2007, we entered into the 364-Day Revolving Credit Facility. The 364-Day Revolving Credit Facility bears interest, at our option, at either (1) a base rate, determined as the greater of (a) the prime loan rate or (b) the federal funds effective rate plus 0.50 percent, or (2) the reserve-adjusted LIBOR plus the applicable margin, which is based upon our Debt Rating. A facility fee, varying from 0.05 percent to 0.15 percent depending on our Debt Rating, is incurred on the daily amount of the underlying commitment, whether used or unused, throughout the term of the facility. A utilization fee, varying from 0.05 percent to 0.10 percent depending on our Debt Rating, is payable if amounts outstanding under the 364-Day Revolving Credit Facility are greater than or equal to 50 percent of the total underlying commitment. At February 27, 2008, the applicable margin, facility fee and utilization fee were 0.28 percent, 0.07 percent and 0.10 percent, respectively. The 364-Day Revolving Credit Facility may be prepaid in whole or in part without premium or penalty. At February 27, 2008, we had $688 million outstanding under this facility at a weighted-average interest rate of 3.43 percent.

The Five-Year Revolving Credit Facility and 364-Day Revolving Credit Facility require compliance with various covenants and provisions customary for agreements of this nature, including a debt to total tangible capitalization ratio, as defined by the credit agreements, not greater than 60 percent at December 31, 2009, and the end of each quarter thereafter and a maximum leverage ratio of no greater than 350 percent as of June 30, 2008, and 300 percent as of the end of each quarter thereafter through September 30, 2009.

Other provisions of the Bridge Loan Facility, the Five-Year Revolving Credit Facility and the 364-Day Revolving Credit Facility include limitations on creating liens, incurring subsidiary debt, transactions with affiliates, sale/leaseback transactions and mergers and sale of substantially all assets. Should we fail to comply with these covenants, we would be in default and may lose access to these facilities. We are also subject to various covenants under the indentures pursuant to which our public debt was issued, including restrictions on creating liens, engaging in sale/leaseback transactions and engaging in certain merger, consolidation or reorganization transactions. A default under our public debt could trigger a default under our credit agreements and, if not waived by the lenders, could cause us to lose access to these facilities.

In December 2007, we entered into a commercial paper program (the “Program”), the proceeds of which we are required to use to repay outstanding borrowings under the 364-Day Revolving Credit Facility or the Bridge Loan Facility. The 364-Day Revolving Credit Facility and the Five-Year Revolving Credit Facility provide liquidity for the Program. At February 27, 2008, $813 million was outstanding under the Program.

Debt Issuance—In December 2007, we 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”). We are required to pay interest on the Senior Notes on March 15 and September 15 of each year, beginning March 15, 2008. We 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. At February 27, 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.

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Index

In December 2007, we 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 Notes and the Series B Notes, the “Convertible Notes”). We are required to pay interest on the Convertible Notes on June 15 and December 15 of each year, beginning June 15, 2008. The Convertible Notes may be converted at an initial rate of 5.9310 ordinary shares per $1,000 note. The initial 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 ordinary shares, cash up to the aggregate principal amount of notes to be converted and ordinary 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. We 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 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 Series A Notes and Series B Notes will have the right to require us 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 us 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 February 27, 2008, $2.2 billion principal amount of each of the Series A Notes, Series B Notes and Series C Notes were outstanding, respectively.

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 ordinary 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 ordinary 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. Upon conversion, we will deliver, in lieu of ordinary shares, cash up to the aggregate principal amount of notes to be converted and ordinary 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 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 an 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 an 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 the obligor’s ability to incur indebtedness for borrowed money secured by certain liens and on its ability to engage in certain sale/leaseback transactions. At February 27, 2008, $250 million and $300 million aggregate principal amount of the 5% Notes and the 7% Notes, respectively, remained outstanding.

Debt Repayments and Refinancing—In December 2007, we refinanced a total of $10.5 billion of borrowings under the Bridge Loan Facility using proceeds from borrowings under the 364-Day Revolving Credit Facility and the issuance of the Senior Notes and the Convertible Notes. We recognized a loss on the retirement of the Bridge Loan Facility borrowings of $6 million. We also repaid $820 million of borrowings under the Bridge Loan Facility using internally generated cash flow. We will likely seek to refinance a portion of the remaining borrowings under the Bridge Loan Facility prior to the expiration of its one-year term. Such refinancing may be effected through additional borrowings under bank credit facilities, issuance of debt securities, including floating rate notes, or through other financing transactions. We expect to repay the remaining borrowings under the Bridge Loan Facility not refinanced using cash on hand or cash generated during 2008.

In August 2007, we repaid the then outstanding balance of $470 million under our Term Credit Facility and terminated the facility. We recognized a loss on the termination of this debt of $1 million.

Concurrent with our entry into the Five-Year Revolving Credit Facility in November 2007, we terminated the Former Revolving Credit Facility. We recognized a loss on the termination of this debt of $1 million.

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Index

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

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

Repurchase of Ordinary Shares—In May 2006, our board of directors authorized an increase in the amount of ordinary shares which may be repurchased pursuant to our share repurchase program to $4.0 billion from $2.0 billion, which was previously authorized and announced in October 2005. The ordinary shares may be repurchased from time to time in open market or private transactions. Decisions to repurchase shares are based upon our ongoing capital requirements, the price of our shares, regulatory considerations, cash flow generation, general market conditions and other factors. We plan to fund any future share repurchases under the program from current and future cash balances and we could also use debt to fund those share repurchases. The repurchase program does not have an established expiration date and may be suspended or discontinued at any time. There can be no assurance regarding the number of shares that will be repurchased under the program. Under the program, repurchased shares are retired and returned to unissued status.

During 2006, we repurchased and retired $2.6 billion of our ordinary shares, which amounted to approximately 35.7 million ordinary shares at an average purchase price of $72.78 per share. Total consideration paid to repurchase the shares was recorded in shareholders equity as a reduction in ordinary shares and additional paid-in capital. Such consideration was funded with existing cash balances, borrowings under our Former Revolving Credit Facility and our Term Credit Facility and proceeds from the issuance of our Floating Rate Notes. During 2007, we repurchased approximately $400 million of our ordinary shares, which amounted to approximately 5.2 million ordinary shares. At February 27, 2008, after prior repurchases, we had authority to repurchase an additional $600 million of our ordinary shares under the program. We do not currently expect to make any additional share repurchases under the program in the near future.

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

	For the years ending December 31,
	Total		2008			2009-2010		2011-2012	Thereafter
	(In millions)
Contractual obligations
Debt	$	17,230	$	6,170	$	2,200	$	4,566	$	4,294
Interest on debt		5,651		686		782		659		3,524
Operating leases		110		30		40		19		21
Capital lease		32		2		4		4		22
Stock warrant consideration payable		48		—		48		—		—
Purchase obligations		2,589		1,164		1,425		—		—
Defined benefit pension plans		13		8		5		—		—
Total	$	25,673	$	8,060	$	4,504	$	5,248	$	7,861

Bondholders may, at their option, require us 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 us 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.

As of December 31, 2007, the total unrecognized tax benefit related to uncertain tax positions, net of prepayments was $424 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.

We have an obligation to make contributions in 2008 to our funded U.S. and Norway defined benefit pension plans. See “—Retirement Plans and Other Postemployment Benefits” for a discussion of expected contributions for pension funding requirements and expected benefit payments for our unfunded defined benefit pension plans.

At December 31, 2007, 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.

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Index

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

	For the years ending December 31,
	Total		2008			2009-2010		2011-2012	Thereafter
	(In millions)
Other commercial commitments
Standby letters of credit	$	532	$	389	$	102	$	31	$	10
Surety bonds		24		23		1		—		—
Total	$	556	$	412	$	103	$	31	$	10

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 $34 million at December 31, 2007 and are expected to rise to approximately $110 million by the end of 2008 as the level of premiums paid to the captive insurance company continues to increase.

Derivative Instruments

We have established policies and procedures for derivative instruments that have been approved by our board of directors. These policies and procedures provide for the prior approval of derivative instruments by our Chief Financial Officer. From time to time, we may enter into a variety of derivative financial instruments in connection with the management of our exposure to fluctuations in foreign exchange rates and interest rates. We do not enter into derivative transactions for speculative purposes; however, for accounting purposes, certain transactions may not meet the criteria for hedge accounting. At December 31, 2007, we had no outstanding foreign exchange or interest rate derivative instruments.

Results of Operations

Historical 2007 compared to 2006

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			100	%
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	)		(100	)%
Other, net		295			60			235			n/m
Income tax expense		(253	)		(222	)		(31	)		14	%
Net income	$	3,131		$	1,385		$	1,746			n/m

_________________

“n/a” means not applicable

“n/m” means not meaningful

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Index

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 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 $81 million of depreciation of property and equipment acquired in the Merger and with the inclusion of approximately one month of GlobalSantaFe’s operations, including $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 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.

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2007 Pro Forma Operating Results

Our historical financial operating results include approximately one month of operating results for the combined company. Although the Merger did not materially impact 2007 results, it is expected to have a significant impact on our future results of operations and financial condition.

The purchase price is comprised of the following (in millions):

Value of Transocean shares issued to GlobalSantaFe shareholders	$	12,229
Cash consideration to GlobalSantaFe shareholders		5,094
Fair value of converted GlobalSantaFe stock options and stock appreciation rights		157
Transocean transaction costs		35
Total purchase price	$	17,515

Our unaudited pro forma consolidated results for the year ended December 31, 2007, reflected income from continuing operations of $3.8 billion or $16.95 per diluted share on pro forma operating revenues of $10.0 billion. The pro forma operating results assume the Transactions were completed as of January 1, 2007 (see Notes to Consolidated Financial Statements—Note 4―Merger with GlobalSantaFe Corporation). These pro forma results do not reflect the effects of reduced depreciation expense related to conforming the estimated lives of GlobalSantaFe rigs and the elimination of certain allocated costs from GlobalSantaFe. The pro forma financial data should not be relied on as an indication of operating results that we would have achieved had the Transactions taken place earlier or of the future results that we may achieve.

The purchase price allocation for the Merger included the following (in millions):

Historical net book value of GlobalSantaFe	$	5,776
Fair value adjustment of property and equipment—contract drilling services, net		7,385
Fair value adjustment of property and equipment—oil and gas properties, net		55
Fair value adjustment of materials and supplies, net		138
Fair value adjustment of defined benefit plans, net		31
Elimination of historical deferred revenues associated with contract drilling services		107
Elimination of historical deferred expenses associated with contract drilling services		(34	)
Adjustment to deferred income taxes resulting from various pro forma adjustments, net		(530	)
Severance costs for legacy GlobalSantaFe affected employees.		(25	)
Adjustment to goodwill—contract drilling services		5,400
Adjustment to goodwill—drilling management services		260
Adjustment to goodwill— oil and gas properties		23
Drilling contract intangibles, net		(1,303	)
Other intangible items, net		239
Other, net		(7	)
Total purchase price	$	17,515

We recorded additional goodwill of approximately $6.0 billion, representing the excess of the purchase price over estimated fair value of net assets acquired after eliminating $333 million of historical goodwill existing in the historical net book value of GlobalSantaFe at the time of the Merger. At December 31, 2007, this goodwill represented approximately 16 percent of total assets and 45 percent of total shareholders' equity. The goodwill will be tested for impairment at least annually at the reporting unit level (see Notes to Consolidated Financial Statements—Note 2—Summary of Significant Accounting Policies).

In connection with the Merger, we acquired drilling contracts for future contract drilling services of GlobalSantaFe. These contracts include fixed dayrates and dayrates that may be 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 after amortizing $88 million in contract intangible revenues in December 2007, the remaining carrying values were $179 million recorded in other assets and $1,394 million recorded in other long-term liabilities on our consolidated balance sheet at December 31, 2007. We recognize the contract intangible revenues over the respective contract period, amortizing the balances using the straight-line method. The following table provides our forecast of amortization of non-cash contract intangible revenues.

Years ending December 31,
2008	$	689
2009		281
2010		98
2011		45
2012		42
Thereafter		60
Total	$	1,215

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Additionally, we identified other intangible assets associated with drilling management services, including the trade name, customer relationships and contract backlog. We consider the ADTI trade name to be an indefinite life intangible asset, which will not be amortized and will be subject to an annual impairment test. The customer relationships and contract backlog have definite lifespans and will each be amortized over their useful lives of 15 years and three months, respectively.

Historical 2006 compared to 2005

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,
	2006			2005			Change			% Change
	(In millions, except day amounts and percentages)

Revenue earning days		26,361			26,224			137			1	%
Utilization		84	%		79	%		n/a			5	%
Average daily revenue	$	142,100		$	105,100		$	37,000			35	%

Contract drilling revenues	$	3,745		$	2,757		$	988			36	%
Other revenues		137			135			2			1	%
		3,882			2,892			990			34	%
Operating and maintenance expense		(2,155	)		(1,720	)		(435	)		25	%
Depreciation		(401	)		(406	)		5			(1	)%
General and administrative expense		(90	)		(75	)		(15	)		20	%
Gain from disposal of assets, net		405			29			376			n/m
Operating income		1,641			720			921			n/m
Other income (expense), net
Interest income		21			19			2			11	%
Interest expense, net of capitalized interest		(115	)		(111	)		(4	)		4	%
Gain from TODCO stock sales		—			165			(165	)		(100	)%
Loss on retirement of debt		—			(7	)		7			(100	)%
Other, net		60			17			43			n/m
Income tax expense		(222	)		(87	)		(135	)		n/m
Net income	$	1,385		$	716		$	669			93	%

_________________

“n/a” means not applicable

“n/m” means not meaningful

The increase in contract drilling revenues was primarily due to higher average daily revenue in all asset classes and to the reactivation of four Midwater Floaters and one High-Specification Floater in 2005 and 2006. Partially offsetting this increase were lower revenues on four rigs that were out of service in 2006 for shipyard or maintenance projects and lower revenues from one rig which was sold in 2006.

Other revenues for the year ended December 31, 2006 increased $2 million due to a $23 million increase in client reimbursable revenue partially offset by decreased integrated services revenue of $21 million.

Operating and maintenance expenses increased by $435 million primarily from shipyard projects, rig reactivations, higher labor costs and vendor price increases resulting in higher labor and rig maintenance costs. This increase included $76 million for reactivation costs associated with the Transocean Prospect, Transocean Winner and C. Kirk Rhein, Jr. and $19 million of costs incurred to repair damages sustained during hurricanes Katrina and Rita on the Transocean Marianas and the Deepwater Nautilus.

The increase in general and administrative expenses of $15 million was due primarily to $12 million higher personnel related expenses and $4 million higher legal fees, including costs related to the TODCO dispute and patent litigation with GlobalSantaFe.

During 2006, we recognized net gains of $405 million related to rig sales and disposal of other assets. During 2005, we recognized net gains of $29 million related to rig sales and disposal of other assets.

The increase in interest expense was primarily attributable to $39 million resulting from higher debt levels arising from the issuance of debt and borrowings under credit facilities in 2006, with no comparable activity in 2005. Partially offsetting this increase were reductions of $19 million associated with debt that was redeemed, retired or repurchased in 2005 and $16 million related to capitalized interest in 2006.

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During 2005, we recognized gains of $165 million from the disposition of our then remaining investment in TODCO with no comparable activity in 2006.

During 2005, we recognized a $7 million loss related to the early redemption and repurchase of $782 million aggregate principal amount of our debt, with no comparable activity in 2006.

The increase in other, net was primarily due to $40 million more income recognized in 2006 as compared to 2005 related to the tax sharing agreement with TODCO and $6 million related to extension fees on the sale of the Transocean Wildcat 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 2006 and 2005 was 18.5 percent and 16.8 percent, respectively, based on 2006 and 2005 income before income taxes and minority interest after adjusting for certain items such as a portion of net gains on sales of assets, items related to the disposition of TODCO and losses on retirements of debt. 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 period tax items, which related to the net gains on rig sales and changes in prior year tax estimates, was a net tax expense of $10 million in 2006, resulting in an effective tax rate of 13.8 percent on earnings before income taxes and minority interest. The tax impact of the various discrete items was a net tax benefit of $14 million in 2005, resulting in an effective tax rate of 10.8 percent on earnings before income taxes and minority interest. The discrete items in 2005 included a benefit of $17 million for the reduction in a valuation allowance related to U.K. net operating losses and a benefit related to the resolution of various tax audits, partially offset by expenses related to asset dispositions, a deferred tax charge attributable to the restructuring of certain non-U.S. operations and items related to the disposition of TODCO.

Critical Accounting Estimates

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 Note 2 to our consolidated financial statements. 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 believe the following are our most critical accounting policies. These policies require significant judgments and estimates used in the preparation of our consolidated financial statements. Management has discussed each of these critical accounting policies and estimates with the audit committee of the board of directors.

Income taxes—We are a Cayman Islands company. As such, our earnings are not subject to income tax in the Cayman Islands because the country does not levy a corporate tax on income. We operate through our various subsidiaries in a number of countries throughout the world. Income taxes have been provided based upon the tax laws and rates 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 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.

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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. As of December 31, 2005, the valuation allowance against certain deferred tax assets, primarily U.S. foreign tax credit carryforwards and certain net operating losses, was in the amount of $48 million, and we increased the valuation allowance to $59 million at the end of 2006. Due to a change of circumstances in 2007, we now 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. See “Results of Operations—Historical 2007 compared to 2006” and “Results of Operations—Historical 2006 compared to 2005.” 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 impairment—We perform a test for impairment of our goodwill annually as of October 1 as prescribed by SFAS 142, Goodwill and Other Intangible Assets. Because our business is cyclical in nature, goodwill could be significantly impaired depending on when the assessment is performed in the business cycle. The fair value of our reporting units is based on a blend of estimated discounted cash flows, publicly traded company multiples and acquisition multiples. Estimated discounted cash flows are based on projected utilization and dayrates. Publicly traded company multiples and acquisition multiples are derived from information on traded shares and analysis of recent acquisitions in the marketplace, respectively, for companies with operations similar to ours. Changes in the assumptions used in the fair value calculation could result in an estimated reporting unit fair value that is below the carrying value, which may give rise to an impairment of goodwill. In addition to the annual review, we also test for impairment should an event occur or circumstances change that may indicate a reduction in the fair value of a reporting unit below its carrying value.

Property and equipment—Our property and equipment represents approximately 61 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 property and equipment accounting policies are designed to depreciate our assets over their estimated useful lives. The assumptions and judgments we use in determining the estimated useful lives of our rigs reflect both historical experience and expectations regarding future operations, utilization and performance of our assets. The use of different estimates, assumptions and judgments in the establishment of property and equipment accounting policies, especially those involving the useful lives of our rigs, would likely result in materially different net book values of our assets and results of operations.

In addition, 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.

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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 $154 million while a one-year decrease would cause an increase in our annual depreciation expense of approximately $211 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. Asset impairment evaluations are based on estimated undiscounted cash flows for the assets being evaluated. Supply and demand are the key drivers of rig idle time 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 be an indication that an asset group may be impaired. Our rigs are equipped to operate in geographic regions throughout the world. Because our rigs are mobile, 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, our impairment evaluation is made by asset group. We consider our asset groups to be High-Specification Floaters, Midwater Floaters, High-Specification Jackups, Standard Jackups and Other Rigs.

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. This requires us to make judgments regarding long-term forecasts of future revenues and costs related to the assets subject to review. 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—The Merger has been accounted for using the purchase method of accounting as defined under SFAS No. 141, Business Combinations. Accounting for this acquisition has resulted in the capitalization of the cost in excess of fair value of the net assets acquired as goodwill. We estimated the fair values of the assets acquired in the Merger as of the date of acquisition, and these estimates are subject to adjustment based on our final assessments of the fair value of property and equipment, intangible assets, liabilities, evaluation of tax positions and contingencies. We expect to complete these assessments within one year of the date of the Merger. See Notes to Consolidated Financial Statements—Note 4―Merger with GlobalSantaFe Corporation.

Our estimates of fair value of property and equipment are 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 can also vary based on the rig design, condition and particular equipment configuration, and 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. We have currently classified several rigs as held for sale, and the ultimate value received may differ from our estimate of the fair values. Changes in the values of rigs or the useful lives would affect our calculations of depreciation and our recorded goodwill.

In connection with the Merger, we acquired drilling contracts for future contract drilling services at fixed dayrates that may be 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 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 of 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.

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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, 2008, based on market conditions and investment strategies, we reduced our expected long-term rate of return for our U.S. plans from 9.00 percent to 8.50 percent, which will result in an increase of approximately $3 million in our expected pension expense for 2008. 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 $9 million. For each one-half percentage point the discount rate is lowered, pension expense would increase by approximately $7 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.

Share-Based Compensation

On January 1, 2006, we adopted the Financial Accounting Standards Board (“FASB”) SFAS No. 123 (revised 2004), Share-Based Payment (“SFAS 123R”), which is a revision of SFAS No.123, Accounting for Stock-Based Compensation (“SFAS 123”). We previously accounted for share-based compensation in accordance with SFAS 123. Adoption of the new standards did not have a material effect on our consolidated statement of financial position, results of operations or cash flows.

Retirement Plans and Other Postemployment Benefits

On December 31, 2006, we adopted the recognition and disclosure provisions of SFAS 158, which require the recognition of the funded status of the Defined Benefit and Postretirement Benefits Other Than Pensions (“OPEB”) plans on the December 31, 2006 balance sheet with a corresponding adjustment to accumulated other comprehensive income. The adjustment to accumulated other comprehensive income at adoption represents the net unrecognized actuarial losses, unrecognized prior service costs, and unrecognized transition obligation remaining from the initial application of SFAS 87, all of which were previously netted against the plans' funded status in the balance sheet. These amounts will be subsequently recognized as net periodic pension cost pursuant to our historical accounting policy for amortizing such amounts. Further, actuarial gains and losses that arise in subsequent periods and are not recognized as net periodic pension cost in the same periods will be recognized as a component of other comprehensive income. Those amounts will be subsequently recognized as a component of net periodic pension cost on the same basis as the amounts recognized in accumulated other comprehensive income.

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The incremental effects of adopting SFAS 158 on the consolidated balance sheet at December 31, 2006 are presented in the following table. The adoption of SFAS 158 did not affect the consolidated statement of operations for the year ended December 31, 2006, or any prior period presented, and it will not affect our operating results in future periods. The incremental effects of adopting the provisions of SFAS 158 on the consolidated balance sheet are presented as follows:

	At December 31, 2006
	Prior to adopting SFAS 158			Effect of adopting SFAS 158			As reported

Other assets	$	322		$	(23	)	$	299
Other current liabilities		366			3			369
Deferred income taxes, net		60			(6	)		54
Other long-term liabilities		337			6			343
Accumulated other comprehensive loss		(4	)		(26	)		(30	)

Defined Benefit Pension Plans—We maintain a qualified defined benefit pension plan (the “Retirement Plan”) covering substantially all U.S. employees, and an unfunded plan (the “Supplemental Benefit Plan”) to provide certain eligible employees with benefits in excess of those allowed under the Retirement Plan. In conjunction with the R&B Falcon merger, we acquired three defined benefit pension plans two funded and one unfunded (the “Frozen Plans”), that were frozen prior to the merger for which benefits no longer accrue but the pension obligations have not been fully paid out. We refer to the Retirement Plan, the Supplemental Benefit Plan and the Frozen Plans collectively as the “U.S. Plans.”

In connection with the Merger, we assumed four defined benefit plans covering substantially all legacy GlobalSantaFe U.S. employees and a frozen defined benefit plan that provides retirement benefits to four former members of the board of directors of Global Marine Inc. (the “Assumed U.S. Pension Plans”). The frozen defined benefit plan is closed to additional participants and no additional benefits are being accrued under this plan. In addition, we assumed a defined benefit plan in the U.K. (the “Assumed U.K. Pension Plan,” and together with the Assumed U.S. Pension Plans, the “Assumed Pension Plans”), covering substantially all non-U.S. legacy GlobalSantaFe employees.

In connection with the Merger, the Supplemental Benefit Plan was amended to provide employees terminated under a severance plan with age, earnings and service benefits described in the Severance Plan, as defined below, and similar severance arrangements (“Severance Credits”). The Supplemental Benefit Plan provides credit for age, service and earnings during the period of time after termination during which severance is paid (the “Salary Continuation Period”), or if an eligible employee receives severance in a lump sum, the lump sum is considered to be paid out over the Salary Continuation Period in order to provide the value of the Severance Credits. The Supplemental Benefit Plan was also amended to 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.

Effective November 27, 2007, one of the Assumed Pension Plans, the GlobalSantaFe Pension Equalization Plan (the “PEP”), was also amended to provide certain terminated employees under the Severance Plan with Severance Credits. The PEP provides credit for age, service and earnings during the Salary Continuation Period, or if an eligible employee receives severance in a lump sum, the lump sum is considered to be paid out over the Salary Continuation Period in order to provide the value of the Severance Credits. The PEP was also amended to 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 addition, the amendment specifies that terminated employees who are ineligible to receive Severance Credits under the legacy GlobalSantaFe qualified defined benefit plan will receive Severance Credits under the PEP.

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 Non-U.S. 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 Non-U.S. Plans and the Assumed Pension Plans (collectively, the “Transocean Plans”).

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	U.S. Plans			Norway Plans			Other Non- U.S. Plans			Assumed U.S. Pension Plans			Assumed U.K. Pension Plans			Total Transocean Plans
Accumulated Benefit Obligation
At December 31, 2007	$	265		$	58		$	5		$	404		$	207		$	939
At December 31, 2006		243			43			4			—			—			290

Projected Benefit Obligation
At December 31, 2007	$	313		$	71		$	9		$	444		$	228		$	1,065
At December 31, 2006		276			69			6			—			—			351

Fair Value of Plan Assets
At December 31, 2007	$	235		$	60		$	—		$	397		$	247		$	939
At December 31, 2006		223			50			—			—			—			273

Funded Status
At December 31, 2007	$	(78	)	$	(11	)	$	(9	)	$	(47	)	$	19		$	(126	)
At December 31, 2006		(53	)		(19	)		(6	)		—			—			(78	)

Net Periodic Benefit Cost
Year ended December 31, 2007	$	16		$	8		$	2		$	—		$	1		$	27		(a)
Year ended December 31, 2006		18			6			2			—			—			26		(a)

Change in Accumulated Other Comprehensive Income
Year ended December 31, 2007	$	23		$	(9	)	$	—		$	(2	)	$	—		$	12
Year ended December 31, 2006		(4	)		11			(1	)		—			—			6

Employer Contributions
Year ended December 31, 2007	$	14		$	6		$	1		$	—		$	1		$	22
Year ended December 31, 2006		5			9			1			—			—			15

Weighted-Average Assumptions – Benefit Obligations
Discount rate
At December 31, 2007		6.02	%		5.30	%		12.90	%		6.19	%		5.90	%		6.07	%	(b)
At December 31, 2006		5.79	%		4.80	%		12.21	%		—			—			5.72	%	(b)
Rate of compensation increase
At December 31, 2007		4.18	%		4.50	%		11.17	%		4.74	%		4.40	%		4.57	%	(b)
At December 31, 2006		4.19	%		4.00	%		10.29	%		—			—			4.27	%	(b)

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	U.S. Plans			Norway Plans			Other Non- U.S. Plans			Assumed U.S. Pension Plans			Assumed U.K. Pension Plans			Total Transocean Plans
Weighted-Average Assumptions – Net Periodic Benefit Cost
Discount rate
Year ended December 31, 2007		5.79	%		4.80	%		13.27	%		6.06	%		5.90	%		5.90	%	(b)
Year ended December 31, 2006		5.58	%		5.50	%		13.00	%		—			—			5.69	%	(b)
Expected long-term rate of return on plan assets
Year ended December 31, 2007		9.00	%		5.40	%		—			9.00	%		7.50	%		8.40	%	(c)
Year ended December 31, 2006		9.00	%		6.00	%		—			—			—			8.49	%	(c)
Rate of compensation increase
Year ended December 31, 2007		4.18	%		4.00	%		11.17	%		4.75	%		4.40	%		4.59	%	(b)
Year ended December 31, 2006		4.71	%		3.50	%		10.29	%		—			—			4.54	%	(b)

______________

(a)	Pension costs were reduced by expected returns on plan assets of $26 million and $20 million for the years ended December 31, 2007 and 2006, respectively.

(b)	Weighted-average based on relative average projected benefit obligation for the year.

(c)	Weighted-average based on relative average fair value of plan assets for the year.

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 $14 million and $5 million to the funded U.S. Plans during 2007 and 2006, respectively. We contributed less than $1 million to the unfunded U.S. Plans during each of 2007 and 2006 to fund benefit payments.

Our contributions to the Transocean Plans in 2007 and 2006, respectively, were funded from our cash flows from operations.

Net periodic benefit cost for the Transocean Plans included the following components (in millions):

	Years ended December 31,
	2007			2006
Components of Net Periodic Benefit Cost (a)
Service cost	$	22		$	20
Interest cost		24			19
Expected return on plan assets		(26	)		(20	)
Recognized net actuarial losses		5			5
Amortization of prior service cost		1			1
Amortization of net transition obligation		1			1
SFAS 88 settlements/curtailments		–			–
Benefit cost	$	27		$	26

______________

(a) Amounts are before income tax effect.

Plan assets of the funded Transocean Plans have been favorably impacted by a rise in world equity markets during 2007 and an allocation of approximately 60 percent of plan assets to equity securities. Debt securities and other investments also experienced increased values, but to a lesser extent. During 2007, the market value of the investments in the Transocean Plans increased by $12 million, or 1.2 percent. The increase is due to net investment gains of $10 million, primarily in the funded U.S. Plans, resulting from the favorable performance of equity markets in 2007 and $22 million of employer contributions. These increases were offset by benefit plan payments of $17 million from these plans and $3 million of unfavorable foreign currency exchange rate changes. We expect to contribute $26 million to the Transocean Plans in 2008. These contributions are comprised of an estimated $10 million to meet minimum funding requirements for the funded U.S. Plans, $2 million to fund expected benefit payments for the unfunded U.S. Plans and Other Non-U.S. Plans and an estimated $7 million each for the funded Norway Plans and the Assumed U.K. Plans. We expect the required contributions will be funded from cash flow from operations.

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

Years ending December 31,
2008	$	64
2009		38
2010		39
2011		42
2012		44
2013-2017		285

We account for the Transocean Plans in accordance with SFAS 87 as amended by SFAS 158. These statements 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. In 2006, the increase in fair value of plan assets resulted in a decrease in the minimum pension liability of $25 million. At December 31, 2006, there was no minimum pension liability included in accumulated other comprehensive income due to our adoption of SFAS 158. The minimum pension liability adjustment did not impact our results of operations during the years ended December 31, 2005, or 2006, nor did these adjustments affect our ability to meet any financial covenants related to our debt.

Our expected long-term rate of return on plan assets for funded U.S. Plans was 9.0 percent as of December 31, 2007 and 2006, 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 6.02 percent at December 31, 2007, 5.8 percent at December 31, 2006 and 5.5 percent at December 31, 2005.

We expect pension expense related to the Transocean Plans for 2008 to increase by approximately $13 million primarily due to the assumption of seven defined benefit plans in conjunction with the Merger, offset by a change in the demographic assumptions for future periods and plan asset growth realized in 2007.

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.

Postretirement Benefits Other Than Pensions—We have several unfunded contributory and noncontributory OPEB plans covering substantially all of our U.S. employees. Funding of benefit payments for plan participants will be made as costs are incurred. In connection with the Merger, we assumed a contributory OPEB plan covering substantially all legacy GlobalSantaFe U.S. employees (the “Assumed OPEB Plan”).

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 less than $2 million for each of the years ended December 31, 2007 and 2006.

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

Years ending December 31,
2008	$	2
2009		2
2010		2
2011		2
2012		2
2013-2017		11

Deferred Compensation Plan—In connection with the Merger, we assumed a deferred compensation plan of GlobalSantaFe (the “Assumed Deferred Plan”). Eligible employees who enrolled in this plan could defer any or all of the amount of their annual salary in excess the annual IRS maximum recognizable compensation limit and up to 100 percent of their awards under GlobalSantaFe’s annual incentive plan. Effective January 1, 2008, this plan was frozen.

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Severance Plan—In connection with the Merger, we established a special transition severance plan for certain employees on the U.S. payroll involuntarily terminated during the period from November 27, 2007 through November 27, 2009 (the “Severance Plan”).

Off-Balance Sheet Arrangements

We had no off-balance sheet arrangements as of December 31, 2007.

Related Party Transactions

TPDI—In April 2007, we entered into an agreement with Pacific Drilling, whereby we acquired exclusive marketing rights for two Ultra-Deepwater drillships to be named Deepwater Pacific 1 and Deepwater Pacific 2, which are currently under construction, as well as an option to purchase a 50 percent interest in a newly formed joint venture company through which we and Pacific Drilling would own the drillships.

In early October 2007, we obtained a firm commitment to enter into a drilling contract for the first drillship and exercised our option to purchase a 50 percent equity interest in TPDI, a joint venture company, formed by us and Pacific Drilling, and received a promissory note issued by TPDI for approximately $238 million, representing 50 percent of the documented costs of the drillships at the time of exercise. Concurrently, TPDI issued a note to Pacific Drilling for approximately $238 million, which is reflected in long-term debt in our consolidated balance sheet. TPDI in turn owns two subsidiary companies: Deepwater Pacific 1 Inc. and Deepwater Pacific 2 Inc. The Deepwater Pacific 1 and Deepwater Pacific 2 are scheduled to be delivered in the second quarter of 2009 and the first quarter of 2010, respectively. We have consolidated TPDI in our financial statements for 2007. See “—Outlook−Drilling Market.”

ODL—We own a 50 percent interest in an unconsolidated joint venture company, Overseas Drilling Limited (“ODL”). ODL owns the Joides Resolution, for which we provide certain operational and management services. In 2007, we earned $1 million for those services. Siem Offshore Inc. owns the other 50 percent interest in ODL. Our director, 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 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, 2007, $3 million was outstanding under this loan agreement and was reflected as long-term debt in our consolidated balance sheet. See “—Outlook–Drilling Market.”

New Accounting Pronouncements

In September 2006, the 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. We will be required to adopt SFAS 157 in the first quarter of fiscal year 2008. We do not expect SFAS 157 to have a material effect on our consolidated statement of financial position, results of operations or cash flows.

In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities (“SFAS 159”). SFAS 159 provides companies with an option to report selected financial assets and liabilities at fair value. It also establishes presentation and disclosure requirements designed to facilitate comparisons between companies that choose different measurement attributes for similar types of assets and liabilities. SFAS 159 is effective as of the beginning of the first fiscal year beginning after November 15, 2007. We will be required to adopt SFAS 159 in the first quarter of fiscal year 2008. We do not expect SFAS 159 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. 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 also requires, among other things, that noncontrolling interests in formerly consolidated subsidiaries be measured at fair value. 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. Management is currently evaluating the requirements of SFAS 160 and has not yet determined the impact on our consolidated statement of financial position, results of operations or cash flows.

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In December 2007, the FASB issued SFAS No. 141R, Business Combinations (“SFAS 141R”). SFAS 141R replaces SFAS No. 141, Business Combinations, and among other things, (1) provides more specific guidance with respect to identifying the acquirer in a business combination, (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 would be required to apply the principles of SFAS 141R to business combinations with acquisition dates in calendar year 2009. Due to the prospective application requirements, it is not possible to determine what effect, if any, SFAS 141R would have on our consolidated statement of financial position, results of operations or cash flows.

ITEM 7A.

Quantitative and Qualitative Disclosures About Market Risk

Interest Rate Risk

Our exposure to market risk for changes in interest rates relates primarily to our long-term and short-term debt. 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, 2007 (in millions, except interest rate percentages):

	Scheduled Maturity Date (a) (b)																					Fair Value
	2008			2009			2010			2011			2012			Thereafter			Total			12/31/07
Total debt
Fixed rate	$	2		$	—		$	2,200		$	2,366		$	2,201		$	4,067		$	10,836		$	11,524
Average interest rate		9.8	%		9.8	%		1.6	%		1.9	%		1.5	%		6.5	%		3.5	%
Variable rate	$	6,170		$	—		$	—		$	—		$	—		$	238		$	6,408		$	6,408
Average interest rate		5.4	%		—	%		—	%		—	%		—	%		6.6	%		5.4	%

__________________________

(a)	Maturity dates of the face value of our debt assume the put options on the Series A Notes, the Series B Notes and the Series C Notes will be exercised in December 2010, December 2011 and December 2012, respectively.

(b)	Expected maturity amounts are based on the face value of debt.

At December 31, 2007, we had approximately $6 billion of variable rate debt at face value (37.2 percent of total debt at face value). This variable rate debt primarily represented the Floating Rate Notes and borrowings under the Bridge Loan Facility and the 364-Day Revolving Credit Facility. At December 31, 2006, the variable-rate debt represented the Floating Rate Notes and borrowings under the Term Credit Facility. Based upon the December 31, 2007 and 2006 variable rate debt outstanding amounts, a one percentage point change in interest rates would result in a corresponding change in interest expense of approximately $64 million and $17 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, 2007 and 2006 cash investment levels, a one percentage point change in interest rates would result in a corresponding change in interest income of approximately $8 million and $3 million per year, respectively.

The fair market value of our debt at December 31, 2007 was $17.9 billion compared to $3.5 billion at December 31, 2006. The increase in fair value of $14.4 billion was primarily due to the issuance and retirement of debt during the year and the redemption of convertible debentures, as well as changes in the corporate bond market.

In connection with the Merger, we acquired the GSF Jack Ryan, which is subject to a fully defeased financing lease arrangement with a remaining term of 13 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 6.02 percent as of December 31, 2007. 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 $11 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.

Foreign Exchange Risk

Our international operations expose us to foreign exchange risk. We use a variety of techniques to minimize the exposure to foreign exchange risk, 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 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, 2007, we had no open foreign exchange derivative contracts.

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ITEM 8.

Financial Statements and Supplementary Data

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

Management of Transocean Inc. (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, 2007. 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.

On November 27, 2007, we completed our merger transaction with GlobalSantaFe. Due to the close proximity of the merger date to December 31, 2007, the date of the most recent financial statements, management has excluded GlobalSantaFe from its assessment of the effectiveness of the Company’s internal control over financial reporting. GlobalSantaFe accounted for 60 percent and 14 percent of the Company’s total assets and liabilities, respectively, as of December 31, 2007, and eight percent and seven percent of the Company’s revenues and net income, respectively, for the year then ended.

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, 2007, the Company’s internal control over financial reporting was effective.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM ON INTERNAL CONTROL OVER FINANCIAL REPORTING

The Board of Directors and Shareholders of Transocean Inc.

We have audited Transocean Inc.’s internal control over financial reporting as of December 31, 2007, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Transocean Inc.’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.

As indicated in the accompanying Management’s Report on Internal Control Over Financial Reporting, management’s assessment of and conclusion on the effectiveness of internal control over financial reporting did not include the internal controls of GlobalSantaFe Corporation, which is included in the 2007 consolidated financial statements of Transocean Inc. and constituted 60 percent and 14 percent of total assets and total liabilities, respectively, as of December 31, 2007 and eight percent and seven percent of revenues and net income, respectively, for the year then ended. Our audit of internal control over financial reporting of Transocean Inc. also did not include an evaluation of the internal control over financial reporting of GlobalSantaFe Corporation.

In our opinion, Transocean Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2007, 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 Inc. as of December 31, 2007 and 2006, 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, 2007 and our report dated February 27, 2008 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

Houston, Texas

February 27, 2008

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Shareholders of Transocean Inc.

We have audited the accompanying consolidated balance sheets of Transocean Inc. and Subsidiaries as of December 31, 2007 and 2006, 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, 2007. 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 Inc. and Subsidiaries at December 31, 2007 and 2006, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2007, 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 15 to the consolidated financial statements, effective January 1, 2007, the Company adopted FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes. Also discussed in Note 2, effective January 1, 2006, the Company adopted Statement of Financial Accounting Standards No. 123 (revised 2004), Share-Based Payment and, as discussed in Note 18, 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 Inc.'s internal control over financial reporting as of December 31, 2007, 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 27, 2008 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

Houston, Texas

February 27, 2008

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TRANSOCEAN INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(In millions, except per share data)

	Years ended December 31,
	2007			2006			2005

Operating revenues
Contract drilling revenues	$	5,948		$	3,745		$	2,757
Contract intangible revenues		88			−			−
Other revenues		341			137			135
		6,377			3,882			2,892
Costs and expenses
Operating and maintenance		2,781			2,155			1,720
Depreciation, depletion and amortization		499			401			406
General and administrative		142			90			75
		3,422			2,646			2,201
Gain from disposal of assets, net		284			405			29
Operating income		3,239			1,641			720

Other income (expense), net
Interest income		30			21			19
Interest expense, net of amounts capitalized		(172	)		(115	)		(111	)
Gain from TODCO stock sales		−			−			165
Loss on retirement of debt		(8	)		−			(7	)
Other, net		295			60			17
		145			(34	)		83

Income before income tax expense		3,384			1,607			803
Income tax expense		253			222			87
Net income	$	3,131		$	1,385		$	716

Earnings per share
Basic	$	14.65		$	6.32		$	3.13
Diluted	$	14.14		$	6.10		$	3.03

Weighted average shares outstanding
Basic		214			219			229
Diluted		222			228			238

See accompanying notes.

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TRANSOCEAN INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(In millions)

	Years ended December 31,
	2007		2006		2005

Net income	$	3,131	$	1,385	$	716
Other comprehensive income (loss), net of tax
Minimum pension liability adjustments (net of tax expense (benefit) of $9 and $2 for the years ended December 31, 2006 and 2005, respectively)		—		16		4
Amortization of periodic pension benefit cost		4		—		—
Other comprehensive income (loss)		4		16		4
Total comprehensive income	$	3,135	$	1,401	$	720

See accompanying notes.

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TRANSOCEAN INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(In millions, except share data)

	December 31,
	2007			2006
ASSETS
Cash and cash equivalents	$	1,241		$	467
Accounts receivable, net
Trade		2,209			929
Other		161			17
Materials and supplies, net		333			160
Deferred income taxes, net		119			16
Other current assets		233			67
Total current assets		4,296			1,656

Property and equipment		24,545			10,539
Less accumulated depreciation		3,615			3,213
Property and equipment, net		20,930			7,326
Goodwill		8,219			2,195
Other assets		919			299
Total assets	$	34,364		$	11,476

LIABILITIES AND SHAREHOLDERS’ EQUITY

Accounts payable	$	805		$	477
Accrued income taxes		99			98
Debt due within one year		6,172			95
Other current liabilities		826			369
Total current liabilities		7,902			1,039

Long-term debt		11,085			3,203
Deferred income taxes, net		681			54
Other long-term liabilities		2,125			340
Total long-term liabilities		13,891			3,597

Commitments and contingencies

Minority interest		5			4

Preference shares, $0.10 par value; 50,000,000 shares authorized, none issued and outstanding		−			−
Ordinary shares, $0.01 par value; 800,000,000 shares authorized, 317,222,909 and 204,609,973 shares issued and outstanding at December 31, 2007 and 2006, respectively		3			2
Additional paid-in capital		10,799			8,045
Accumulated other comprehensive loss		(42	)		(30	)
Retained earnings (accumulated deficit)		1,806			(1,181	)
Total shareholders’ equity		12,566			6,836
Total liabilities and shareholders’ equity	$	34,364		$	11,476

See accompanying notes.

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Index

TRANSOCEAN INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF EQUITY

(In millions)

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

Balance at December 31, 2004		225		$	2	$	10,697		$	(24	)	$	(3,282	)	$	7,393
Net income		–			-		-			-			716			716
Repurchase of ordinary shares		(4	)		-		(400	)		-			-			(400	)
Issuance of ordinary shares under
share-based compensation plans		6			-		260			-			-			260
Minimum pension liability		-			-		-			4			-			4
Other		-			-		9			-			-			9

Balance at December 31, 2005		227			2		10,566			(20	)		(2,566	)		7,982
Net income		−			-		-			-			1,385			1,385
Repurchase of ordinary shares		(25	)		-		(2,600	)		-			-			(2,600	)
Issuance of ordinary shares under
share-based compensation plans		2			-		67			-			-			67
Minimum pension liability		−			-		-			16			-			16
Adjustment to initially apply SFAS 158, net of tax		-			-		-			(26	)		-			(26	)
Other		-			-		12			-			-			12

Balance at December 31, 2006		204			2		8,045			(30	)		(1,181	)		6,836
Net income		-			-		-			-			3,131			3,131
Repurchase of ordinary shares		(4	)		-		(400	)		-			-			(400	)
Issuance of ordinary shares under
share-based compensation plans		4			-		191			-			-			191
Accelerated share-based compensation due to the Merger		1			-		22			-			-			22
Amortization of periodic pension benefit cost		-			-		-			4			-			4
Change in funded status of defined benefit plans		-			-		-			(16	)		-			(16	)
Issuance of ordinary shares upon conversion of convertible debentures and notes		4			-		414			-			-			414
Consideration paid to GlobalSantaFe shareholders		108			1		12,385			-			-			12,386
Payment to shareholders for Reclassification of ordinary shares		-			-		(9,859	)		-			-			(9,859	)
Adjustment to initially apply FIN 48, net of tax		-			-		-			-			(144	)		(144	)
Other		-			-		1			-			-			1
Balance at December 31, 2007		317		$	3	$	10,799		$	(42	)	$	1,806		$	12,566

See accompanying notes.

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Index

TRANSOCEAN INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In millions)

	Years ended December 31,
	2007			2006			2005
Cash flows from operating activities
Net income	$	3,131		$	1,385		$	716
Adjustments to reconcile net income to net cash provided by operating activities:
Amortization of drilling contract intangibles		(88	)		—			—
Depreciation, depletion and amortization		499			401			406
Share-based compensation expense		78			20			16
Gain from disposal of assets, net		(284	)		(405	)		(29	)
Gain from TODCO stock sales		—			—			(165	)
Tax benefit from exercise of stock options to purchase and vesting of ordinary shares under share-based compensation plans		—			(10	)		22
Deferred income taxes		(40	)		(23	)		27
Deferred revenue, net		52			52			(7	)
Deferred expenses, net		(55	)		(109	)		18
Other, net		18			(5	)		(27	)
Changes in operating assets and liabilities		(238	)		(69	)		(113	)
Net cash provided by operating activities		3,073			1,237			864

Cash flows from investing activities
Capital expenditures		(1,380	)		(876	)		(182	)
Consideration paid to GlobalSantaFe shareholders		(5,129	)		—			—
Cash balances acquired in connection with the Merger		695			—			—
Proceeds from disposal of assets, net		379			461			74
Proceeds from TODCO stock sales, net		—			—			272
Joint ventures and other investments, net		(242	)		—			5
Net cash provided by (used in) investing activities		(5,677	)		(415	)		169

Cash flows from financing activities
Borrowings under 364-Day Revolving Credit Facility		1,500			—			—
Borrowings under other credit facilities		15,000			1,000			—
Repayments under other credit facilities		(12,030	)		(300	)		—
Proceeds from issuance of debt		9,095			1,000			—
Repayments of debt		(3	)		—			(880	)
Financing costs		(106	)		(5	)		(1	)
Repurchase of ordinary shares		(400	)		(2,601	)		(400	)
Proceeds from issuance of ordinary shares under share-based compensation plans, net		72			69			219
Proceeds from issuance of ordinary shares upon exercise of warrants		40			—			11
Payment to shareholders for Reclassification of ordinary shares		(9,859	)		—			—
Tax benefit from issuance of ordinary shares under share-based compensation plans		70			7			—
Other, net		(1	)		30			12
Net cash provided by (used in) financing activities		3,378			(800	)		(1,039	)

Net increase (decrease) in cash and cash equivalents		774			22			(6	)
Cash and cash equivalents at beginning of period		467			445			451
Cash and cash equivalents at end of period	$	1,241		$	467		$	445

See accompanying notes.

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Index

TRANSOCEAN INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1—Nature of Business and Principles of Consolidation

Transocean Inc. (together with its subsidiaries and predecessors, unless the context requires otherwise, “Transocean,” the “Company,” “we,” “us” or “our”) is a leading international provider of offshore contract drilling services for oil and gas wells. Our mobile offshore drilling fleet is considered one of the most modern and versatile fleets in the world. We specialize 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. 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. At December 31, 2007, we owned, had partial ownership interests in or operated 140 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), 29 Midwater Floaters, 10 High-Specification Jackups, 58 Standard Jackups and four Other Rigs. We also have eight Ultra-Deepwater Floaters contracted for or under construction (see Note 5—Drilling Fleet Expansion, Upgrades and Acquisitions).

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 R&B Falcon 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.

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 where our ownership is between 20 percent and 50 percent or where our ownership is more than 50 percent and we do not have significant control over the unconsolidated affiliate. We use the cost method of accounting for investments in unconsolidated affiliates where our ownership is less than 20 percent and where we do not have significant influence over the unconsolidated affiliate. 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 October 2007, we exercised our option to purchase a 50 percent interest in Transocean Pacific Drilling Inc. (“TPDI”), a joint venture company formed by us and Pacific Drilling Limited (“Pacific Drilling”), a Liberian company, whereby we acquired exclusive marketing rights for two ultra-deepwater drillships to be named Deepwater Pacific 1 and Deepwater Pacific 2, which are currently under construction. We are providing 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 ordinary shares or cash at a purchase price based on an appraisal of the fair value of the drillships, subject to various adjustments.

We have evaluated our interest in TPDI under the standards of Financial Accounting Standards Board (“FASB”) Interpretation No. 46, Consolidation of Variable Interest Entities (“FIN 46”). FIN 46 requires the consolidation of variable interest entities in which an enterprise absorbs a majority of the entity’s expected losses, receives a majority of the entity’s expected residual returns, or both, as a result of ownership, contractual or other financial interests in the entity. TPDI is considered a variable interest entity as its equity is not sufficient to absorb its possible losses, and we are the primary beneficiary for accounting purposes of TPDI. As a result, we consolidate TPDI in our financial statements, the note to us is eliminated and the interest that is not owned by us is reflected as minority interest on our consolidated balance sheet and consolidated statement of operations.

We recognized investments in and advances to unconsolidated affiliates of $15 million and $9 million for the years ended December 31, 2007 and 2006, 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, $5 million and $10 million for the years ended December 31, 2007, 2006 and 2005, respectively, and reported these amounts in other, net in our consolidated statement of operations.

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Index

TRANSOCEAN INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

Note 2—Summary of Significant Accounting Policies

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, including those related to bad debts, materials and supplies obsolescence, investments, intangible assets and goodwill, property and equipment and other long-lived assets, income taxes, workers’ insurance, share-based compensation, pensions and other postretirement benefits, other employment benefits and contingent liabilities. We base our estimates on historical experience and on various other assumptions 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 stated at cost plus accrued interest, which approximates fair value. 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. We record restricted cash in other assets in our consolidated balance sheet. At December 31, 2007, we had $7 million 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 $50 million and $26 million at December 31, 2007 and 2006, 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 $22 million and $19 million at December 31, 2007 and 2006, respectively.

Property and Equipment—Property and equipment, consisting primarily of offshore drilling rigs and related equipment, represented approximately 61 percent of our total assets at December 31, 2007. 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 had an estimated useful life of 30 years. During 2007, we extended the useful lives to between 35 and 45 years for six rigs, which had estimated useful lives of between 30 to 35 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 2007, 2006 and 2005, the impact of the change in estimated useful life of these rigs was a reduction in depreciation expense of $25 million ($0.11 per diluted share), $2 million ($0.01 per diluted share) and $16 million ($0.05 per diluted share), respectively, 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, 2006, we had assets held for sale in the amount $11 million that were included in other current assets. At December 31, 2007, there were no assets held for sale (see Note 6—Asset Dispositions and Note 24—Subsequent Events).

Impairment of Long-Lived Assets—The carrying value of long-lived assets, principally property and equipment, is reviewed for potential impairment when events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. For property and equipment held for use, the determination of recoverability is made based upon the estimated undiscounted future net cash flows of the related asset or group of assets being evaluated. Property and equipment held for sale are recorded at the lower of net book value or fair value.

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Index

TRANSOCEAN INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

Goodwill—We test goodwill for impairment at least annually, on October 1, 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. Prior to the Merger, we operated in one operating segment, contract drilling services, which we considered to be our sole reporting unit. Since it met all the necessary criteria, we carried forward the results of the goodwill impairment test performed at October 1, 2004 to evaluate goodwill at October 1, 2005, 2006 and 2007. As a result of these tests for impairment, we concluded that goodwill was not impaired in any of the years ended December 31, 2007, 2006 and 2005.

As a result of the Merger, we established two additional reporting units: (1) drilling management services and (2) oil and gas properties (see Note 1—Nature of Business and Principles of Consolidation). For purposes of our annual goodwill impairment testing, we will calculate the estimated fair value of these reporting units based upon the present value of their estimated future net cash flows, utilizing a discount rate based upon our cost of capital.

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

	Balance at January 1, 2007		Other (a)		Balance at December 31, 2007

Contract drilling services	$	2,195	$	5,741	$	7,936
Drilling management services		—		260		260
Oil and gas properties		—		23		23
Total	$	2,195	$	6,024	$	8,219

______________________

(a)

Primarily represents the excess of the purchase price over the estimated fair value of net assets acquired as a result of the Merger, our investment in TPDI of $22 million and net adjustments of $14 million recorded during 2007 related to income tax-related pre-acquisition contingencies.

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 over the period until the next survey on a straight-line basis.

Contract 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 be 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 have recorded $179 million in other assets and $1.4 billion in other long-term liabilities on our consolidated balance sheet for the year ended December 31, 2007. 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, oil and gas properties revenues, client reimbursable revenues, integrated services revenues and other miscellaneous revenues. For fixed priced contracts, revenues and expenses are recognized on completion of the well and acceptance by the customer. Events occurring after the date of the financial statements and before the financial statements are issued that are within the normal exposure and risk aspects of the turnkey contracts are considered refinements of the estimation process of the prior year and are recorded as adjustments at the date of the financial statements. Provisions for losses are made on contracts in progress when losses are anticipated. 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. 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.

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TRANSOCEAN INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

Capitalized Interest—We capitalize interest costs for qualifying construction and upgrade projects. We capitalized interest costs on construction work in progress of $76 million and $16 million for the years ended December 31, 2007 and 2006, respectively. There was no capitalized interest for the year ended December 31, 2005.

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 8—Financial Instruments and Risk Concentration and Note 9—Interest Rate Swaps.

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. Net foreign currency gains losses included in other income (expense) were $10 million, $3 million and $4 million, for the years ended December 31, 2007, 2006 and 2005, 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 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 15—Income Taxes.

Share-Based Compensation—On January 1, 2006, we adopted SFAS No. 123 (revised 2004), Share-Based Payment (“SFAS 123R”), which is a revision of SFAS No. 123, Accounting for Stock-Based Compensation (“SFAS 123”). SFAS 123R supersedes Accounting Principles Board (“APB”) Opinion No. 25, Accounting for Stock Issued to Employees (“APB 25”), and amends SFAS No. 95, Statement of Cash Flows (“SFAS 95”). Although the approaches in SFAS 123R and SFAS 123 are similar, SFAS 123R requires income statement recognition of all share-based payments to employees, including grants of employee stock options, based on their fair values and does not permit pro forma disclosure as an alternative. In March 2005, the Securities and Exchange Commission (“SEC”) issued Staff Accounting Bulletin (“SAB”) No. 107, Share-Based Payment (“SAB 107”), relating to SFAS 123R. We have applied the provisions of SAB 107 in our adoption of SFAS 123R.

We adopted SFAS 123R using the modified prospective method (“Prospective Method”), which requires the application of SFAS 123R as of January 1, 2006. Our consolidated financial statements as of and for the years ended December 31, 2007 and 2006 reflect the application of SFAS 123R. In accordance with the Prospective Method, our consolidated financial statements for prior periods have not been restated to reflect, and do not include, the application of SFAS 123R. Share-based compensation expense for the years ended December 31 is as follows (in millions):

	Years ended December 31,
	2007			2006			2005
Share-based compensation expense	$	78		$	20		$	16
Income tax benefit on share-based compensation expense		(9	)		(2	)		(3	)

SFAS 123R requires forfeitures to be estimated at the time of grant and revised, if necessary, in subsequent periods if actual forfeitures differ from those estimates. Additionally, SFAS 123R requires the estimated forfeiture rate be applied and the cumulative effect determined for all prior periods in which share-based compensation costs have been recorded. The cumulative effect of applying the expected forfeiture rate has been included in operating and maintenance expense and general and administrative expense, the impact of which had no material effect on our consolidated statement of financial position, results of operations or cash flows.

We adopted SFAS 123 effective January 1, 2003 and accounted for share-based compensation prospectively for all share-based awards granted or modified on or subsequent to that date. As such, adoption of SFAS 123R using the Prospective Method had no material impact on our consolidated statement of financial position, results of operations or cash flows. In addition to the compensation cost recognition requirements, SFAS 123R also requires the tax deduction benefits for an award in excess of recognized compensation cost to be reported as a financing cash flow rather than as an operating cash flow.

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Index

TRANSOCEAN INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

Under SFAS 123, we recognized compensation cost on a straight-line basis over the vesting period up to the date of actual retirement. As a result of the adoption of SFAS 123R, we now recognize compensation cost on a straight-line basis for time-based awards granted or modified after January 1, 2006 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 that are granted or modified after January 1, 2006, compensation expense is recognized 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. If we had amortized compensation cost over the service period prior to adoption of SFAS 123R, share-based compensation expense would not have been materially different for any of the periods presented.

Prior to January 1, 2003, we accounted for share-based awards to employees under the provisions of SFAS 123 using the intrinsic value method prescribed by APB 25 and related interpretations. If compensation expense for grants to employees under our long-term incentive plan prior to January 1, 2003 had been recognized using the fair value method of accounting under SFAS 123, net income and earnings per share for the year ended December 31, 2005 would have been reduced by the pro forma amount of approximately $2 million, which was not material.

The fair value of each option grant under our long-term incentive plan was estimated on the date of grant using the Black-Scholes-Merton option-pricing model with the following weighted-average assumptions:

	Years ended December 31,
	2007	2006	2005
Dividend yield	—	—	—
Expected price volatility	31%	33%-37%	26%-38%
Risk-free interest rate	4.88%-5.09%	4.52%-5.00%	2.86%-4.57%
Expected life of options	3.2 years	4.7 years	4.4 years
Weighted-average fair value of options granted	$40.69	$31.30	$21.92

The fair value of each option grant under the ESPP was estimated using the following weighted-average assumptions:

	Years ended December 31,
	2007	2006	2005
Dividend yield	–	–	–
Expected price volatility	33%	33%	28%
Risk-free interest rate	4.91%	4.42%	2.81%
Expected life of options	1.0 year	1.0 year	1.0 year
Weighted-average fair value of options granted	$23.01	$21.48	$7.10

New Accounting Pronouncements—In September 2006, the 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. We will be required to adopt SFAS 157 in the first quarter of fiscal year 2008. We do not expect SFAS 157 to have a material effect on our consolidated statement of financial position, results of operations or cash flows.

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Index

TRANSOCEAN INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

In December 2007, the FASB issued SFAS No. 141R, Business Combinations (“SFAS 141R”). SFAS 141R replaces SFAS No. 141, Business Combinations. SFAS 141R, among other things, (1) provides more specific guidance with respect to identifying the acquirer in a business combination, (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 would be required to apply the principles of SFAS 141R to business combinations with acquisition dates in calendar year 2009. Due to the prospective application requirements, it is not possible to determine what effect, if any, SFAS 141R would have on our consolidated statement of financial position, results of operations or cash flows.

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.

Note 3—Accumulated Other Comprehensive Loss

The components of accumulated other comprehensive loss at December 31, 2007, 2006 and 2005, net of tax, are as follows (in millions):

	Gain on terminated interest rate swaps		Minimum pension liability			SFAS 158 pension adjustment			Total other comprehensive income (loss)

Balance at December 31, 2004	$	3	$	(27	)	$	—		$	(24	)
Other comprehensive income (loss)		—		4			—			4
Balance at December 31, 2005		3		(23	)		—			(20	)
Other comprehensive income (loss)		—		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 income		—		—			4			4
Change in funded status of deferred benefit plans		—		—			(16	)		(16	)
Balance at December 31, 2007	$	3	$	—		$	(45	)	$	(42	)

__________________

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

Note 4—Merger with GlobalSantaFe Corporation

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. In connection with the Merger, we established a severance plan. See Note 18—Retirement Plans, Other Postemployment Benefits and Other Benefit Plans.

We issued approximately 107,752,000 of our ordinary shares and paid out $5 billion in cash in connection with the Merger. We accounted for the Merger using the purchase method of accounting with the Company treated as the accounting acquirer. As a result, the assets and liabilities of Transocean remain at historical amounts. The assets and liabilities of GlobalSantaFe are recorded at their estimated fair values at November 27, 2007, the date of completion of the 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.

The purchase price is comprised of the following (in millions):

Value of Transocean shares issued to GlobalSantaFe shareholders	$	12,229
Cash consideration to GlobalSantaFe shareholders		5,094
Fair value of converted GlobalSantaFe stock options and stock appreciation rights		157
Transocean transaction costs		35
Total purchase price	$	17,515

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Index

TRANSOCEAN INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

The purchase price allocation for the Merger included the following (in millions):

Historical net book value of GlobalSantaFe (a)	$	5,776
Fair value adjustment of property and equipment—contract drilling services, net		7,385
Fair value adjustment of property and equipment—oil and gas properties, net		55
Fair value adjustment of materials and supplies, net		138
Fair value adjustment of defined benefit plans, net		31
Elimination of historical deferred revenues associated with contract drilling services		107
Elimination of historical deferred expenses associated with contract drilling services		(34	)
Adjustment to deferred income taxes resulting from various pro forma adjustments, net		(530	)
Adjustment to goodwill – contract drilling services		5,400
Adjustment to goodwill – drilling management services		260
Adjustment to goodwill – oil and gas properties		23
Adjustment to drilling contract intangibles, net		(1,303	)
Adjustment to other intangible items, net		239
Severance costs for legacy GlobalSantaFe affected employees		(25	)
Other, net		(7	)
Total purchase price	$	17,515

____________

(a)

Historical net book value of GlobalSantaFe includes goodwill of $333 million associated with prior business combinations, which was eliminated in the purchase price allocation.

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 $430 million, other assets of $112 million and the assumption of current liabilities of $439 million, other net long-term liabilities of $2.1 billion and long-term debt of $575 million. The excess of the purchase price over the estimated fair value of net assets acquired was $5.7 billion, which has been accounted for as goodwill.

Certain purchase price allocations have not been finalized and the purchase price allocation is preliminary. Due to the number of assets acquired and the closing of the Merger close to our year-end, we are continuing our review of the valuation of property and equipment, intangible assets, liabilities, evaluation of tax positions and contingencies.

In connection with the Merger, we acquired drilling contracts for future contract drilling services of GlobalSantaFe. These contracts include fixed dayrates and dayrates that may be 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 after amortizing $88 million in contract intangible revenues in December 2007, the remaining balances were $179 million recorded in other assets and $1,394 million recorded in other long-term liabilities on our consolidated balance sheet at December 31, 2007. We will recognize contract intangible revenues over nine years, amortizing the balances using the straight-line method over the respective contract periods.

The unaudited pro forma condensed combined statements of operations have 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 Transactions. Unaudited pro forma combined operating results of the Company and GlobalSantaFe assuming the Transactions were completed as of January 1, 2007 and 2006, respectively, are as follows (in millions, except per share data):

	2007		2006
Operating revenues	$	11,022	$	7,934
Operating income		4,967		2,845
Income from continuing operations		3,756		1,614
Earnings per share
Basic	$	17.55	$	4.85
Diluted	$	16.95	$	4.69

The 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 pro forma information is not necessarily indicative of the result of operations had the Transactions been completed on the assumed dates or the results of operations for any future periods.

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TRANSOCEAN INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

Note 5—Drilling Fleet Expansion, Upgrades and Acquisitions

Construction work in progress, recorded in property and equipment, was $3.1 billion, $1.0 billion and $111 million at December 31, 2007, 2006 and 2005, respectively. The following table summarizes actual capital expenditures, including capitalized interest, for our major construction and conversion projects (in millions):

	Year ended December 31, 2007		Year ended December 31, 2006		Total Costs

GSF Development Driller III (a)	$	369	$	—	$	369
Deepwater Pacific 1 (b)		279		—		279
Sedco 700-series upgrades		250		146		396
Discoverer Clear Leader		195		214		409
Discoverer Americas		195		106		301
Deepwater Pacific 2 (b)		179		—		179
Discoverer Inspiration		120		128		248
GSF Newbuild (a)		109		—		109
Discoverer Luanda		107		—		107
Capitalized Interest		76		16		92
Total	$	1,879	$	610	$	2,489

______________________

(a)

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

(b)

The costs for Deepwater Pacific 1 and Deepwater Pacific 2 represent 100 percent of expenditures incurred prior to our investment in the joint venture ($277 million and $178 million, respectively) and 100 percent of expenditures incurred since our investment in the joint venture. However, Pacific Drilling shares 50 percent of these costs.

No major construction or conversion projects occurred during the year ended December 31, 2005.

In June 2007, we were awarded a drilling contract for a fourth enhanced Enterprise-class drillship to be named the Discoverer Luanda. As a result of the Merger, we acquired one Ultra-Deepwater Floater under construction, the GSF Development Driller III, and one contracted for construction.

Note 6—Asset Dispositions

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).

During 2005, we sold a Midwater Floater (Sedco 600), a Jackup rig (Transocean Jupiter) and a land rig. We received net proceeds from these sales of $49 million and recognized gains on the sales of $33 million ($28 million, or $0.08 per diluted share, net of tax).

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Index

TRANSOCEAN INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

Note 7—Debt

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

	December 31,
	2007		2006

Term Credit Facility due August 2008	$	–	$	700
Floating Rate Notes due September 2008 (a)		1,000		1,000
Bridge Loan Facility due November 2008 (a)		3,670		–
364-Day Revolving Credit Facility due December 2008 (a)		1,500		–
6.625% Notes due April 2011		177		180
5% Notes due February 2013		246		–
5.25% Senior Notes due March 2013		499		–
6.00% Senior Notes due March 2018		997		–
7.375% Senior Notes due April 2018		247		247
Zero Coupon Convertible Debentures due May 2020		–		18
1.5% Convertible Debentures due May 2021		–		400
Capital lease obligation due July 2026 (b)		17		–
8% Debentures due April 2027		57		57
7.45% Notes due April 2027 (c)		95		95
7% Senior Notes due June 2028		314		–
7.5% Notes due April 2031		598		598
1.625% Series A Convertible Senior Notes due December 2037		2,200		–
1.50% Series B Convertible Senior Notes due December 2037		2,200		–
1.50% Series C Convertible Senior Notes due December 2037		2,200		–
6.80% Senior Notes due March 2038		999		–
Debt to affiliates		241		3
Total debt		17,257		3,298
Less debt due within one year (a)(b)(c)		6,172		95
Total long-term debt	$	11,085	$	3,203

______________________

(a)

The Floating Rate Notes, Bridge Loan Facility and 364-Day Revolving Credit Facility were classified as debt due within one year at December 31, 2007.

(b)

The capital lease obligation had $2 million classified as debt due within one year at December 31, 2007.

(c)

The 7.45% Notes were classified as debt due within one year at December 31, 2006 since the holders had the option to require us to repurchase the notes in April 2007. At March 31, 2007, we reclassified these notes as long-term debt, as no holders had notified us of their intent to exercise their option by the required notification date of March 15, 2007.

The scheduled maturity of our debt assumes the bondholders exercise their options to require us 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. All amounts are at face value. The scheduled maturities are as follows (in millions):

Years ending December 31,
2008	$	6,172
2009		–
2010		2,200
2011		2,366
2012		2,201
Thereafter		4,308
Total	$	17,247

Commercial Paper Program—In December 2007, we entered into a commercial paper program (the “Program”). The 364-Day Revolving Credit Facility and the Five-Year Revolving Credit Facility provide liquidity for the Program. At December 31, 2007, no amounts were outstanding under the Program. See Note 24—Subsequent Events.

Former Revolving Credit Facility—In July 2005, we entered into a $500 million, five-year revolving credit agreement (“Former Revolving Credit Facility”). In May 2006, we increased the credit limit on the facility from $500 million to $1.0 billion and extended the maturity date by one year from July 2010 to July 2011, and in June 2007, we extended the maturity on the facility by another year to July 2012. At our election, the Former Revolving Credit Facility bore interest at either a base rate or at LIBOR plus a margin that could vary from 0.19 percent to 0.58 percent depending on our non-credit enhanced senior unsecured long-term debt rating (“Debt Rating”). In September 2007, we repaid the then outstanding balance and terminated this facility. See “—Debt Redemptions, Refinancings and Repayments.”

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Index

TRANSOCEAN INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

Term Credit Facility—In August 2006, we entered into a two-year term credit facility under the Term Credit Agreement dated August 30, 2006 (“Term Credit Facility”). Under the terms of the Term Credit Facility, we were able to request borrowings up to $1.0 billion over the first six months of the term. After six months, any unused capacity was cancelled. Once repaid, the funds could not be reborrowed. At our election, borrowings could be made under the Term Credit Facility at either (1) the base rate, determined as the greater of (a) the prime loan rate or (b) the sum of the weighted average overnight federal funds rate plus 0.50 percent, or (2) LIBOR plus 0.30 percent, based on current credit ratings. We terminated the facility in August 2007. See “—Debt Redemptions, Refinancings and Repayments.”

Floating Rate Notes—In September 2006, we issued $1.0 billion aggregate principal amount of floating rate notes, due September 2008 (“Floating Rate Notes”). We are required to pay interest on the Floating Rate Notes on March 5, June 5, September 5 and December 5 of each year, beginning on December 5, 2006. The per annum interest rate on the Floating Rate Notes is equal to the three month LIBOR, reset on each payment date, plus 0.20 percent. We may redeem some or all of the notes at any time after September 2007 at a price equal to 100 percent of the principal amount plus accrued and unpaid interest, if any. At December 31, 2007, $1.0 billion principal amount of these notes was outstanding at an interest rate of 5.14 percent.

Bridge Loan Facility—In September 2007, we entered into the Bridge Loan Facility. In connection with the Transactions, we borrowed $15 billion under the Bridge Loan Facility at the reserve-adjusted LIBOR plus the applicable margin, which is based upon our Debt Rating. As of December 31, 2007, the applicable margin was 0.4 percent. We may prepay the Bridge Loan Facility in whole or in part without premium or penalty. In addition, this facility requires mandatory prepayments of outstanding borrowings in an amount equal to 100 percent of the net cash proceeds resulting from any of the following (in each case subject to certain agreed exceptions): (1) the sale or other disposition of any of our property or assets above a predetermined threshold; (2) the receipt of certain net insurance or condemnation proceeds; (3) certain issuances of our equity securities; and (4) the incurrence of indebtedness for borrowed money by us. The Bridge Loan Facility also contains certain covenants that are applicable during the period in which any borrowings are outstanding, including a maximum leverage ratio. Borrowings under the Bridge Loan Facility are subject to acceleration upon the occurrence of events of default. At December 31, 2007, we had $3.7 billion outstanding under this facility at a weighted-average interest rate of 5.41 percent. See Note 24—Subsequent Events.

364-Day Revolving Credit Facility—In December 2007, we entered into a credit agreement for a 364-Day, $1.5 billion revolving credit facility (“364-Day Revolving Credit Facility”). The 364-Day Revolving Credit Facility bears interest, at our option, at either (1) a base rate, determined as the greater of (a) the prime loan rate or (b) the federal funds effective rate plus 0.50 percent, or (2) the reserve-adjusted LIBOR plus the applicable margin, which is based upon our Debt Rating. A facility fee, varying from 0.05 percent to 0.15 percent depending on our Debt Rating, is incurred on the daily amount of the underlying commitment, whether used or unused, throughout the term of the facility. A utilization fee, varying from 0.05 percent to 0.10 percent depending on our Debt Rating, is payable if amounts outstanding under the 364-Day Revolving Credit Facility are greater than or equal to 50 percent of the total underlying commitment. At December 31, 2007, the applicable margin, facility fee and utilization fee were 0.28 percent, 0.07 percent and 0.10 percent, respectively. The 364-Day Revolving Credit Facility may be prepaid in whole or in part without premium or penalty. The 364-Day Revolving Credit Facility requires compliance with various covenants and provisions customary for agreements of this nature, including a debt to total tangible capitalization ratio, as defined by the 364-Day Revolving Credit Facility, of not greater than 60 percent at December 31, 2009 and at the end of each quarter thereafter and a maximum leverage ratio of no greater than 350 percent as of June 30, 2008 and 300 percent at the end of each quarter thereafter through September 30, 2009. At December 31, 2007, we had $1.5 billion outstanding under this facility at a weighted-average interest rate of 5.52 percent. See Note 24—Subsequent Events.

Five-Year Facility—In November 2007, we 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”). Under the terms of the Five-Year Revolving Credit Facility, we may make borrowings at either (1) a base rate, determined as the greater of (a) the prime loan rate or (b) the federal funds effective rate plus 0.5 percent, or (2) the reserve-adjusted LIBOR plus the applicable margin, which is based upon our Debt Rating. A facility fee, varying from 0.07 percent to 0.17 percent depending on our Debt Rating, is incurred on the daily amount of the underlying commitment, whether used or unused, throughout the term of the facility. A utilization fee, varying from 0.05 percent to 0.10 percent depending on our Debt Rating, is payable if amounts outstanding under the Five-Year Revolving Credit Facility are greater than or equal to 50 percent of the total underlying commitment. At December 31, 2007, the applicable margin, facility fee and utilization fee were 0.26 percent, 0.09 percent and 0.10 percent, respectively. The Five-Year Revolving Credit Facility may be prepaid in whole or in part without premium or penalty. The Five-Year Revolving Credit Facility requires compliance with various covenants and provisions customary for agreements of this nature, including a debt to total tangible capitalization ratio, as defined by the Five-Year Revolving Credit Facility, of not greater than 60 percent at December 31, 2009 and at the end of each quarter thereafter and a maximum leverage ratio of no greater than 350 percent as of June 30, 2008 and 300 percent at the end of each quarter thereafter through September 30, 2009. At December 31, 2007, no borrowings were outstanding under the Five-Year Revolving Credit Facility.

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Index

TRANSOCEAN INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

6.625% Notes and 7.5% Notes—In April 2001, we 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. At December 31, 2007, $166 million and $600 million principal amount of the 6.625% Notes and 7.5% Notes, respectively, were outstanding.

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 the obligor’s ability to incur indebtedness for borrowed money secured by certain liens and on its ability to engage in certain sale/leaseback transactions. At December 31, 2007, $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, we 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”). We are required to pay interest on the Senior Notes on March 15 and September 15 of each year, beginning March 15, 2008. We 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. At December 31, 2007, $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.

Zero Coupon Convertible Debentures—In May 2000, we issued Zero Coupon Convertible Debentures due May 2020 with a face value at maturity of $865 million. The debentures were issued to the public at a price of $579.12 per debenture and accrued original issue discount at a rate of 2.75 percent per annum compounded semiannually to reach a face value at maturity of $1,000 per debenture. We paid no interest on the debentures prior to maturity and, since May 2003, we had the right to redeem the debentures for a price equal to the issuance price plus accrued original issue discount to the date of redemption. Each holder had the right to require us to repurchase the debentures on the third, eighth and thirteenth anniversary of issuance at the issuance price plus accrued original issue discount to the date of repurchase. We could pay this repurchase price with either cash or ordinary shares or a combination of cash and ordinary shares. The debentures were convertible into our ordinary shares at the option of the holder at any time at a ratio of 8.1566 shares per debenture, which was equivalent to an initial conversion price of $71.00 per share, subject to adjustments if certain events took place. See “—Debt Redemptions, Refinancings and Repayments.”

1.5% Convertible Debentures—In May 2001, we issued $400 million aggregate principal amount of 1.5% Convertible Debentures due May 2021. We had the right to redeem the debentures for a price equal to 100 percent of the principal. Each holder had the right to require us to repurchase the debentures after five, 10 and 15 years at 100 percent of the principal amount. We could pay this repurchase price with either cash or ordinary shares or a combination of cash and ordinary shares. The debentures were convertible into our ordinary shares at the option of the holder at any time at a ratio of 13.8627 shares per $1,000 principal amount debenture, which was equivalent to an initial conversion price of $72.136 per share. This ratio was subject to adjustments if certain events took place, and conversion could only occur if the closing sale price per ordinary share exceeded 110 percent of the conversion price for at least 20 trading days in a period of 30 consecutive trading days ending on the trading day immediately prior to the conversion date or if other specified conditions were met. See “—Debt Redemptions, Refinancings and Repayments.”

Capital Lease Obligations—The GSF Explorer is held under a capital lease through 2026. The capital lease for the GSF Explorer has a remaining term of 19 years. See Note 16—Commitments and Contingencies.

7.45% Notes and 8% Debentures—In April 1997, we 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 our option subject to a make-whole premium. At December 31, 2007, $100 million and $57 million principal amount of the 7.45% Notes and the 8% Debentures, respectively, were outstanding.

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Index

TRANSOCEAN INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

1.625% Series A, 1.50% Series B and 1.50% Series C Convertible Senior Notes—In December 2007, we 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”). We are required to pay interest on the Convertible Notes on June 15 and December 15 of each year, beginning June 15, 2008. The Convertible Notes may be converted under the circumstances specified below at an initial rate of 5.9310 ordinary 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 ordinary shares, cash up to the aggregate principal amount of notes to be converted and ordinary 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. We 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 us 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 us 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, 2007, $2.2 billion principal amount of each of the Series A Notes, Series B Notes and Series C Notes were outstanding.

Debt to Affiliates—In November 2005, we entered into a loan agreement with Overseas Drilling Limited (“ODL”), a company in which we own a 50 percent interest, 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, 2007, $3 million was outstanding under this loan agreement.

In October 2007, TPDI, a joint venture in which we own 50 percent, issued a promissory note to us for approximately $238 million. Concurrently, TPDI issued a note to Pacific Drilling for approximately $238 million, which is reflected in long-term debt in our consolidated balance sheet.

Debt Redemptions, Refinancings and Repayments—In August 2007, we terminated our existing two-year Term Credit Facility. Prior to the termination, we 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, we terminated our $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, we refinanced a total of $10.5 billion of borrowings under the Bridge Loan Facility using proceeds from borrowings under the 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, we repaid $820 million of borrowings under the Bridge Loan Facility using internally generated cash flow. See Note 24—Subsequent Events.

In October 2007, we called our 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 our ordinary shares at a rate of 8.1566 ordinary shares per $1,000 debenture. During this period, we issued 148,244 ordinary shares upon conversion of $18 million aggregate principal amount of debentures. In November 2007, we redeemed the remaining debentures at an approximate cost of $18,000, plus accrued and unpaid interest.

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Index

TRANSOCEAN INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

In October 2007, we also called our 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 our ordinary shares at a rate of 13.8627 ordinary shares per $1,000 debenture. During this period, we issued 5,499,613 ordinary shares upon conversion of $397 million aggregate principal amount of debentures. In November 2007, we redeemed the remaining debentures at an approximate cost of $3 million, plus accrued and unpaid interest.

Holders of our 1.5% Convertible Debentures due May 15, 2021 had the option to require us 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 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 July 2005, we acquired, pursuant to a tender offer, a total of $534 million, or approximately 76.3 percent, of the aggregate principal amount of our 6.625% Notes due April 2011 at 110.578 percent of face value, or $591 million, plus accrued and unpaid interest.

In March 2005, we redeemed our outstanding 6.95% Senior Notes due April 2008 at the make-whole premium price provided in the indenture. We recognized a loss on the redemption of debt of $7 million ($0.02 per diluted share), which had no tax effect.

Note 8—Financial Instruments and Risk Concentration

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, 2007 and 2006, 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, 2007 and 2006. See Note 9—Interest Rate Swaps.

Credit Risk—Financial instruments that potentially subject us to concentrations of credit risk are primarily cash and cash equivalents 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. In foreign locations, local financial institutions are generally utilized for local currency needs. We limit the amount of exposure to any one institution and do not believe we are exposed to any significant credit risk.

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TRANSOCEAN INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

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 19—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. 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, 2007, we had approximately 21,100 employees and we also utilized approximately 3,400 persons through contract labor providers. Some of our employees, most of whom work in the U.K., Nigeria 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 2008. 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 Tribunal has recently issued its decision and we are currently reviewing the decision to determine its potential impact on our operations and expenses as well as to determine whether the decision should be appealed. 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.

Note 9—Interest Rate Swaps

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, 2007 and 2006, such reduction amounted to $3 million ($0.01 per diluted share) for each year and $9 million ($0.04 per diluted share) for the year ended December 31, 2005. As a result of the redemption of our 6.95% Senior Notes in March 2005, we recognized $13 million ($0.06 per diluted share) of the unamortized fair value adjustment as a reduction to our loss on redemption of debt during the year ended December 31, 2005 (see Note 7—Debt). As a result of the repurchase of our 6.625% Notes in July 2005, we recognized $62 million of the unamortized fair value adjustment as a reduction to our loss on repurchase of debt, which resulted in a gain on the repurchase (see Note 7—Debt). There were no tax effects related to these reductions. At December 31, 2007 and 2006, the remaining balance to be amortized was $12 million and $15 million, respectively, which was entirely related to the 6.625% Notes due April 2011.

At December 31, 2007 and 2006, we had no outstanding interest rate swaps.

Note 10—Fair Value of Financial Instruments

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 and Accounts Receivable-Trade—The carrying amounts approximate fair value because of the short maturity of those instruments.

Debt—The fair value of our fixed rate debt is calculated based on market prices. The carrying value of variable rate debt approximates fair value.

	December 31, 2007				December 31, 2006
	Carrying amount		Fair value		Carrying amount		Fair value
	(in millions)				(in millions)

Debt	$	17,257	$	17,935	$	3,298	$	3,476

Debt to Affiliates—The fair value of long-term debt to affiliates with a carrying amount of $241 million and $3 million at December 31, 2007 and 2006, respectively, could not be determined because there is no available market price for such debts.

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TRANSOCEAN INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

Note 11—Other Current Liabilities

Other current liabilities are comprised of the following (in millions):

	December 31,
	2007		2006

Accrued payroll and employee benefits	$	447	$	150
Deferred revenue		116		77
Accrued taxes, other than income		100		30
Accrued interest		62		24
Stock warrant consideration payable		48		—
Unearned income		12		67
Other		41		21
Total other current liabilities	$	826	$	369

Note 12—Other Long-Term Liabilities

Other long-term liabilities are comprised of the following (in millions):

	December 31,
	2007		2006

Drilling contract intangibles	$	1,394	$	—
Long-term income taxes payable		410		141
Accrued pension liabilities		133		84
Accrued retiree life insurance and medical benefits		52		35
Deferred revenue		39		28
Other		97		52
Total other long-term liabilities	$	2,125	$	340

Note 13—Repurchase of Ordinary Shares

In May 2006, our board of directors authorized an increase in the overall amount of ordinary shares that may be repurchased under our share repurchase program to $4.0 billion from $2.0 billion, which was previously authorized and announced in October 2005. The repurchase program does not have an established expiration date and may be suspended or discontinued at any time. Under the program, repurchased shares are constructively retired and returned to unissued status.

A summary of the aggregate ordinary shares repurchased and retired for the years ended December 31, 2007 and 2006 is as follows (in millions, except per share data):

	December 31,
	2007		2006

Value of shares	$	400	$	2,600
Number of shares		5.2		35.7
Average purchase price per share	$	77.39	$	72.78

Total consideration paid to repurchase the shares was recorded in shareholders’ equity as a reduction in ordinary shares and additional paid-in capital. Such consideration was funded with existing cash balances and borrowings under the Former Revolving Credit Facility. At December 31, 2007, we had authority to repurchase $600 million of our ordinary shares under our share repurchase program.

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TRANSOCEAN INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

Note 14—Supplementary Cash Flow Information

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):

	Years ended December 31,
	2007			2006			2005

(Increase) in accounts receivable	$	(274	)	$	(347	)	$	(150	)
(Increase) in other current assets		(43	)		(32	)		(22	)
Increase in accounts payable and other current liabilities		73			168			87
Increase in other long-term liabilities		8			18			23
Change in income taxes receivable / payable, net		(2	)		124			(51	)
	$	(238	)	$	(69	)	$	(113	)

Supplementary cash flow information is as follows (in millions):

	Years ended December 31,
	2007		2006		2005
Non-cash activities
Capital expenditures, accrued at end of period (a)	$	233	$	186	$	31
Merger with GlobalSantaFe (b)	12,386			—		—
Joint ventures and other investments (c)		238		—		—

Cash payments for interest		208		125		129
Cash payments for income taxes		225		125		107

______________

(a)

These amounts represent additions to property and equipment for which we had accrued a corresponding liability in accounts payable.

(b)

In connection with the Merger, we issued $12.4 billion of our ordinary shares to GlobalSantaFe shareholders, acquired $20.6 billion in assets and assumed $575 million of debt and $2.5 billion of other liabilities. See Note 4—Merger with GlobalSantaFe Corporation.

(c)

In connection with our investment in and consolidation of TPDI, we recorded additions to property and equipment of $457 million, of which $238 million was in exchange for a note payable to Pacific Drilling. See Note 1—Nature of Business and Principles of Consolidation and Note 7—Debt.

Note 15—Income Taxes

We are a Cayman Islands company. Our earnings are not subject to income tax in the Cayman Islands because the country does not levy tax on corporate income. We operate through our various subsidiaries in a number of countries throughout the world. Income taxes have been provided based upon the tax laws and rates in the countries in which operations are conducted and income is earned. Due to the fact that 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.

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

	Years ended December 31,
	2007			2006			2005

Current provision	$	293		$	245		$	60
Deferred provision (benefit)		(40	)		(23	)		27
Income tax provision	$	253		$	222		$	87
Effective tax rate		7.5	%		13.8	%		10.8	%

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 at the applicable tax rates in effect.

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TRANSOCEAN INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

Significant components of deferred tax assets and liabilities are as follows (in millions):

	December 31,
	2007			2006
Deferred tax assets
Drilling contract intangibles	$	303		$	—
Net operating loss carryforwards		102			56
Tax credit carryforwards		100			118
Accrued payroll expenses not currently deductible		85			38
Deferred income		50			(1	)
Other		83			37
Valuation allowance		(29	)		(59	)
Total deferred tax assets		694			189

Deferred tax liabilities
Depreciation and amortization		(1,155	)		(218	)
Drilling management services intangibles		(83	)		—
Other		(18	)		(9	)
Total deferred tax liabilities		(1,256	)		(227	)

Net deferred tax liabilities	$	(562	)	$	(38	)

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 $524 million increase in our net deferred tax liability is composed of $599 million of net deferred tax liabilities assumed in connections with the Merger partly offset by the deferred tax benefit of $40 million and $35 million of net tax benefits charged to equity accounts as a result of the tax effects of minimum 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 incurred during the year in certain jurisdictions and for other deferred tax assets where, in the opinion of management, 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, 2007, the valuation allowance for non-current deferred tax assets decreased $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. As of December 31, 2006, our valuation allowance was $59 million which included an $11 million increase over the 2005 balance, primarily resulting from an increase in foreign tax credits.

Our U.K. net operating loss carryforwards do not expire. The tax effect of the U.K. net operating loss carryforwards was $49 million at December 31, 2007 and $56 million at December 31, 2006. We have generated additional net operating loss carryforwards in various worldwide tax jurisdictions. Our U.S. foreign tax credit carryforwards of $80 million, net of valuation allowances of $1 million, which will expire between 2009 and 2016. Our U.S. alternative minimum tax credits of $20 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. During the year ended December 31, 2005, we recognized a benefit of $67 million to record the utilization of the capital loss carryforward to offset capital gain income resulting from certain restructuring transactions. Certain payments from TODCO under the tax sharing agreement also serve to increase or decrease the capital loss carryforward. Should an opportunity to utilize the remaining capital loss arise, the total potential tax benefit at December 31, 2007 was $776 million. As of December 31, 2006, we had not recognized a deferred tax asset for certain of our U.S. net operating loss carryforwards as it was not probable that the benefit of the underlying tax deduction would be realized. During 2007, we determined that it was probable that the U.S. entity generating the previously unrecognized net operating losses will generate sufficient taxable income to utilize all net operating losses. As a result, we recognized the remaining amount of these previously unrecognized net operating losses.

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Index

TRANSOCEAN INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

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.

Transocean Inc., a Cayman Islands company, is not subject to income taxes in the Cayman Islands because the Cayman Islands does not levy a tax on corporate income. We have obtained assurance from the Cayman Islands government under the Tax Concessions Law (as amended) that in the event that any legislation is enacted in the Cayman Islands imposing tax computed on profits, income, distributions or any capital assets, gain or appreciation, or any tax in the nature of estate duty or inheritance tax, such tax shall not, until June 1, 2019, be applicable to us or to any of our operations or to our shares, debentures or other obligations.

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.

The total unrecognized tax benefits related to uncertain tax positions as of January 1, 2007 was $303 million. During 2007, our unrecognized tax benefits related to uncertain tax positions increased to $424 million. If recognized, $349 million of this amount would favorably impact the effective tax rate.

A reconciliation of the unrecognized tax benefits, excluding interest and penalties, for the year ended December 31, 2007 follows:

	Unrecognized tax benefits
Balance at January 1, 2007	$	219
Unrecognized tax benefits assumed in connection with the Merger		42
Additions for current year tax positions		48
Additions for prior year tax positions		22
Reductions for prior year tax positions		(6	)
Settlements		(26	)
Reductions related to statute of limitation expirations		―
Balance at December 31, 2007	$	299

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. In connection with the adoption of FIN 48 we recognized approximately $84 million for the payment of interest and penalties, which is included as a component of the January 1, 2007 $303 million liability for unrecognized tax benefits. During the year ended December 31, 2007, we increased the liability related to interest and penalties on our unrecognized tax benefits by $41 million, which brought the interest and penalty component included in the December 31, 2007 liability for unrecognized tax benefits balance to $125 million. Included in the $41 million increase in interest and penalties 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. During 2006, we settled disputes with tax authorities in several jurisdictions and the statute of limitations for income tax contingencies for certain issues expired. As a result of the resolution of these matters, we recognized a current tax benefit of $30 million for the year ended December 31, 2006. The amount of current tax benefit recognized in 2007 from the settlement of disputes with tax authorities and the expiration of statute of limitations was insignificant.

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Index

TRANSOCEAN INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

In February 2007, we entered into a settlement agreement with the IRS regarding the 2001 to 2003 audit. The IRS agreed to settle all issues for this period. This settlement resulted in no cash tax payment.

During the fourth quarter of 2005, we entered into a settlement agreement with the IRS with respect to our 1999 and 2000 U.S. federal income tax returns, which resulted in a payment of $36 million including interest. The IRS agreed to settle all issues for this period. This settlement did not result in a material effect on our consolidated statement of financial position, results of operations or cash flows.

On January 1, 2007, as part of our implementation of FIN 48, we recorded a long-term liability of $142 million related to Norwegian tax issues described above. Since January 1, 2007, the long-term liability has increased to $168 million due to the accrual of interest and exchange rate fluctuations. 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 Brazil tax authorities have issued tax assessments totaling $112 million, plus a 75 percent penalty and $70 million of interest through December 31, 2007. 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.

In December 2005, we restructured certain of our non-U.S. operations. As a result of the restructuring, we incurred a deferred tax charge in the amount of $33 million.

As a result of changes in our estimates of certain pre-acquisition tax contingencies and liabilities arising prior to our merger with Sedco Forex Holdings Limited (“Sedco Forex”) effective December 31, 1999, we recorded a decrease of $4 million and $5 million in goodwill and an income tax receivable of $4 million and $5 million in December 2007 and 2006, respectively.

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 Transocean Holdings 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 believe that Hercules owes an additional $11 million related to the change of control of TODCO.

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 ordinary 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, 2007 would be approximately $25 million, assuming a price of $143.15 per ordinary share at the time of exercise of the options (the actual price of our ordinary shares at the close of trading on December 31, 2007). 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.

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Index

TRANSOCEAN INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

In 2007, 2006 and 2005, respectively, we recognized $277 million ($1.24 per diluted share), $51 million ($0.22 per diluted share) and $11 million ($0.05 per diluted share) of other income in our consolidated statement of operations related to TODCO’s utilization of tax benefits and stock option deductions. Through December 31, 2007, we received $12 million in estimated payments pertaining to TODCO’s 2007 federal and state income tax returns that is deferred in other current liabilities in our consolidated balance sheet. We will recognize these estimated payments as other income when TODCO finalizes and files its 2007 federal and state income tax returns.

Note 16—Commitments and Contingencies

Lease Obligations¾We 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, 2007, the GSF Explorer drillship, recorded in property and equipment, net in the amount of $223 million, is held under a capital lease through 2026. As of December 31, 2007, future minimum rental payments related to noncancellable operating leases and the capital lease are as follows (in millions):

Years ending December 31,	Capital Lease			Operating Leases
2008	$	2		$	30
2009		2			25
2010		2			15
2011		2			10
2012		2			9
Thereafter		24			21
Total future minimum rental payments	$	34		$	110
Less amount representing imputed interest		(17	)
Present value of future minimum rental payments under capital leases		17
Less current portion included in accrued liabilities		(2	)
Long-term capital lease obligation	$	15

Rental expense for all leases, including leases with terms of less than one year, was approximately $51 million, $32 million and $30 million for the years ended December 31, 2007, 2006 and 2005, respectively.

Purchase Obligations—At December 31, 2007, our purchase obligations as defined by SFAS No. 47, Disclosure of Long-Term Obligations (as amended), related to our Sedco 700-series upgrade shipyard projects and eight newbuilds are as follows (in millions):

Years ending December 31,
2008	$	1,164
2009		1,196
2010		229
2011		—
2012		—
Thereafter		—
Total	$	2,589

Legal Proceedings—Several of our subsidiaries have been named, along with numerous unaffiliated defendants, in several complaints that have been filed in the Circuit Courts of the State of Mississippi involving approximately 750 plaintiffs that allege personal injury arising out of asbestos exposure in the course of their employment by some of these defendants between 1965 and 1986. The complaints also name as defendants certain of TODCO’s subsidiaries to whom we may owe indemnity. Further, the complaints name other unaffiliated defendant companies, including companies that allegedly manufactured drilling related products containing asbestos. The complaints allege that the defendant drilling contractors used those asbestos-containing products in offshore drilling operations, land based drilling operations and in drilling structures, drilling rigs, vessels and other equipment and assert claims based on, among other things, negligence and strict liability, and claims authorized under the Jones Act. The plaintiffs generally seek awards of unspecified compensatory and punitive damages. We have not been provided with sufficient information to determine the number of plaintiffs who claim to have been exposed to asbestos aboard our rigs, whether they were employees, their period of employment, the period of their alleged exposure to asbestos, or their medical condition, and we have not entered into any settlements with any plaintiffs. Accordingly, we are unable to estimate our potential exposure in these lawsuits. We historically have maintained insurance which we believe will be available to address any liability arising from these claims. We intend to defend these lawsuits vigorously, but there can be no assurance as to their ultimate outcome.

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Index

TRANSOCEAN INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

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, 2007, the subsidiary was a defendant in approximately 1,041 lawsuits, of which 102 were filed during 2007. Some of these lawsuits include multiple plaintiffs and we estimate that there are approximately 3,380 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, 2007, 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.

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Index

TRANSOCEAN INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

We are involved in various tax matters (see Note 15—Income Taxes). We are also 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 now 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.

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TRANSOCEAN INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

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

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

appropriate investigatory and/or remedial actions; and

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

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

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

the numbers of other PRPs and their financial viability; and

the remediation methods and technology to be used.

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Index

TRANSOCEAN INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

Retained Risk—Our insurance program is a 12-month policy period beginning May 1, 2007. 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 through self-insurance for any losses in excess of the $950 million limit.

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 the Transocean 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 $532 million and $405 million at December 31, 2007 and 2006, 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 $24 million and $6 million at December 31, 2007 and 2006, respectively.

Note 17—Share-Based Compensation Plans

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, stock appreciation rights (“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 vesting awards”) and awards that are earned based on the achievement of certain performance criteria (“performance-based awards”). Our executive compensation committee of our board of directors determines the terms and conditions of the awards under the Long-Term Incentive Plan. Options and SARs issued to date under the incentive plans have a 10-year term. Time-based vesting awards typically vest in three equal annual installments beginning on the first anniversary date of the grant. Performance-based awards issued to date under the incentive plans have a two-year performance measurement period with the number of options, shares or deferred units earned being determined following the completion of the measurement period (the “determination date”) at which time one-third of the options, shares or deferred units that have satisfied the performance criteria vest. Additional vesting occurs on January 1 of the two subsequent years following the determination date. As of December 31, 2007, we had 22.9 million ordinary shares authorized for future employee grants, including up to 6.0 million for restricted share awards, and 0.6 million ordinary shares authorized with respect to outside directors. We issue new shares when stock options are exercised and when restricted shares and deferred units vest.

We use the Black-Scholes-Merton option-pricing model to value stock options granted or modified under SFAS 123. We determine the fair value of options and SARs granted or modified based on 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 forfeiture of options. The risk-free interest rate assumption is based upon the published U.S. Treasury yield curve in effect at the time of grant for instruments with a similar life. The dividend yield assumption is based on our history and expectation of dividend payouts. See Note 2—Summary of Significant Accounting Policies.

We use a blended volatility that is comprised of two components. The first component is derived from volatility computed from historical data for an amount of time approximately equal to the expected life of the stock option. The second component is the implied volatility derived from our “at-the-money” long dated call options with a term of six months or longer. The two components are equally weighted to create a blended volatility.

The fair value for restricted ordinary shares and deferred units is initially based on the market price of our ordinary shares on the date of grant.

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TRANSOCEAN INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

As a result of the Merger, we assumed all of the outstanding employee stock options and stock appreciation rights 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 our ordinary shares remained outstanding and became fully vested and exercisable. The number and exercise prices of the options to purchase our ordinary shares were adjusted based on the market price of our ordinary shares immediately preceding the effective date of the Reclassification and Merger in order to keep the aggregate intrinsic value of the options and stock appreciation rights equal to the values immediately prior to such date. Each option to acquire our ordinary shares that was outstanding immediately prior to the Reclassification and Merger was converted into options to purchase 0.9392 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 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 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. Share-based compensation expense is recorded on the same financial statement line item as cash compensation paid to the same employees.

There were no significant modifications during the years ended December 31, 2007, 2006 or 2005.

As of December 31, 2007, total unrecognized compensation costs related to all unvested share-based awards totaled $33 million, which is expected to be recognized over a weighted average period of 2.6 years.

Time-Based Vesting Awards

Stock Options—The following table summarizes vested and unvested time-based vesting stock option (“time-based options”) activity under the Incentive Plans during the year ended December 31, 2007:

	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, 2007		4,025,915		$	30.22

Granted		3,073			110.80
Assumed in Merger		1,264,910			47.58
Exercised		(2,112,853	)		37.46
Forfeited		(11,642	)		44.11
Outstanding at December 31, 2007		3,169,403		$	34.76		3.27	$	344

Vested and exercisable at December 31, 2007		3,169,403		$	34.76		3.27	$	344

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Index

TRANSOCEAN INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

The weighted-average grant-date fair value of time-based options granted during the year ended December 31, 2007 was $40.69 per share. There were 2,132 and 50,200 time-based options granted during the years ended December 31, 2006 and 2005, respectively, with weighted-average grant-date fair values of $34.08 and $18.98 per share, respectively.

The total pretax intrinsic value of time-based options exercised during the year ended December 31, 2007 was $156 million. There were 1,904,346 and 7,227,931 time-based options exercised during the years ended December 31, 2006 and 2005, respectively. The total pretax intrinsic value of time-based options exercised was $99 million and $190 million during the years ended December 31, 2006 and 2005, respectively.

Restricted Ordinary Shares—The following table summarizes unvested share activity for time-based vesting restricted ordinary shares (“time-based shares”) granted under the Incentive Plans during the year ended December 31, 2007:

	Number of shares			Weighted-average grant-date fair value per share
Unvested at January 1, 2007		270,743		$	76.40

Granted		380,653			109.92
Vested		(261,330	)		77.12
Forfeited		(20,140	)		83.73
Unvested at December 31, 2007		369,926		$	109.98

The total grant-date fair value of time-based shares that vested during the year ended December 31, 2007 was $20 million. There were 258,313 and 24,647 time-based shares granted during the years ended December 31, 2006 and 2005, respectively. The weighted-average grant-date fair value of time-based shares granted was $78.40 and $49.01 per share for the years ended December 31, 2006 and 2005, respectively. There were 15,812 and 10,046 time-based shares that vested during the years ended December 31, 2006 and 2005, respectively. The total grant-date fair value of time-based shares that vested was less than $1 million for both years ended December 31, 2006 and 2005.

Deferred Units—A deferred unit is a unit that is equal to one ordinary share but has no voting rights until the underlying ordinary shares are issued. The following table summarizes unvested activity for time-based vesting deferred units (“time-based units”) granted under the Incentive Plans during the year ended December 31, 2007:

	Number of units			Weighted-average grant-date fair value per share
Unvested at January 1, 2007		40,964		$	69.55

Granted		64,676			105.99
Vested		(53,086	)		74.48
Forfeited		(2,432	)		98.20
Unvested at December 31, 2007		50,122		$	109.97

The total grant-date fair value of the time-based units vested during the year ended December 31, 2007 was $4 million. There were 29,641 and 13,013 time-based units granted during the years ended December 31, 2006 and 2005, respectively. The weighted-average grant-date fair value of time-based units granted was $81.55 and $45.02 per share for the years ended December 31, 2006 and 2005, respectively. There were 9,997 and 4,254 time-based units that vested during the years ended December 31, 2006 and 2005, respectively. The total grant-date fair value of deferred units that vested was less than $1 million for both years ended December 31, 2006 and 2005.

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Index

TRANSOCEAN INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

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 ordinary shares upon exercise equal in value to the difference between the market value of our ordinary shares at the exercise date and the Merger-adjusted exercise price. The following table summarizes share-settled SARs activity under the Incentive Plans during the year ended December 31, 2007:

	Number of Awards			Weighted-average exercise price per share		Weighted-average remaining contractual term (years)		Aggregate intrinsic value (in millions)
Assumed in the Merger at November 27, 2007		615,126		$	88.37

Exercised		(110,355	)		84.65
Outstanding at December 31, 2007		504,771		$	89.18		8.59	$	27

Vested and exercisable at December 31, 2007		504,771		$	89.18		8.59	$	27

The total pretax intrinsic value of share-settled SARs exercised during the period ended December 31, 2007 was $6 million.

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 ordinary 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, 2007, 2006, and 2005, and all outstanding cash-settled SARs are fully vested. 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. We had 30,598 SARs outstanding with a weighted average remaining contractual term of 2.13 years and an aggregate intrinsic value of $1 million as of December 31, 2006.

Performance-Based Awards

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 the Incentive Plans during the year ended December 31, 2007:

	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, 2007		1,206,366		$	50.51

Granted		―			―
Exercised		(661,988	)		43.77
Forfeited		(152,276	)		59.78
Outstanding at December 31, 2007		392,102		$	58.29		8.15	$	33

Vested and exercisable at December 31, 2007		392,102		$	58.29		8.15	$	33

There were 329,650 and 304,971 performance-based options granted during the years ended December 31, 2006 and 2005, respectively. The weighted-average grant-date fair value of performance-based options granted was $32.17 and $22.14 per share during the years ended December 31, 2006 and 2005, respectively.

The total pretax intrinsic value of performance-based options exercised during the year ended December 31, 2007 was $52 million. There were 158,054 and 85,864 performance-based options exercised, with a total pretax intrinsic value of $10 million and $3 million, during the years ended December 31, 2006 and 2005, respectively.

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Index

TRANSOCEAN INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

Restricted Ordinary Shares—We grant performance-based restricted ordinary shares (“performance-based shares”) that can be earned depending on the achievement of certain performance targets. The number of shares earned is quantified upon completion of the performance period at the determination date. The following table summarizes unvested share activity for performance-based shares granted under the Incentive Plans during the year ended December 31, 2007:

	Number of shares			Weighted-average grant-date fair value per share
Unvested at January 1, 2007		478,154		$	44.53

Granted		―			―
Vested		(357,544	)		38.57
Forfeited		(120,610	)		62.21
Unvested at December 31, 2007		―		$	―

Shares forfeited include the adjustment of shares at the determination date due to the application of the performance criteria.

The total grant-date fair value of performance-based shares that vested during the year ended December 31, 2007 was $14 million. There were 59,769 and 264,289 performance-based shares granted during the years ended December 31, 2006 and 2005, respectively. The weighted-average grant-date fair value was $77.56 and $57.90 per share during the years ended December 31, 2006 and 2005, respectively. There were 175,695 and 190,930 performance-based shares that vested with a total grant-date fair value of $6 million during each of the years ended December 31, 2006 and 2005, respectively.

Deferred Units—We grant performance-based deferred units (“performance-based units”) that can be earned depending on the achievement of certain performance targets. The number of units earned is quantified upon completion of the performance period at the determination date. The following table summarizes unvested unit activity for performance-based units granted under the Incentive Plans during the year ended December 31, 2007:

	Number of units			Weighted-average grant-date fair value per share
Unvested at January 1, 2007		218,640		$	55.00

Granted		―			―
Vested		(150,762	)		48.94
Forfeited		(67,878	)		68.44
Unvested at December 31, 2007		―		$	―

Units forfeited include the adjustment of units at the determination date due to the application of the performance criteria.

The total grant-date fair value of performance-based units that vested during the year ended December 31, 2007 was $7 million. There were 75,707 and 7,128 performance-based units granted during the years ended December 31, 2006 and 2005, respectively. The weighted-average grant-date fair value of performance-based units granted was $78.61 and $57.90 per share during the years ended December 31, 2006 and 2005, respectively. There were 41,236 and 10,647 performance-based units that vested with a total grant-date fair value of $2 million and less than $1 million during the years ended December 31, 2006 and 2005, respectively.

ESPP—We provide the ESPP for certain full-time employees. Under the terms of the ESPP, employees can choose each year to have between two and twenty percent of their annual base earnings withheld to purchase up to $21,250 of our ordinary shares. The purchase price of the stock is 85 percent of the lower of the beginning-of-year or end-of-year market price of our ordinary shares. At December 31, 2007, 183,363 ordinary shares were available for issuance pursuant to the ESPP after taking into account the shares to be issued for the 2007 plan year.

Note 18—Retirement Plans, Other Postemployment Benefits and Other Benefit Plans

On December 31, 2006, we adopted the recognition and disclosure provisions of 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”), which requires the recognition of the funded status of the Defined Benefit and Postretirement Benefits Other Than Pensions (“OPEB”) plans on the December 31, 2006 balance sheet with a corresponding adjustment to accumulated other comprehensive income. The adjustment to accumulated other comprehensive income at adoption represents the net unrecognized actuarial losses, unrecognized prior service costs, and unrecognized transition obligation remaining from the initial application of SFAS No. 87, Employer's Accounting for Pension (“SFAS 87”), all of which were previously netted against the plans’ funded status on the balance sheet. These amounts will be subsequently recognized as net periodic pension cost pursuant to our historical accounting policy for amortizing such amounts. Further, actuarial gains and losses that arise in subsequent periods and are not recognized as net periodic pension cost in the same periods will be recognized as a component of other comprehensive income. Those amounts will be subsequently recognized as a component of net periodic pension cost on the same basis as the amounts recognized in accumulated other comprehensive income.

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Index

TRANSOCEAN INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

The adoption of SFAS 158 did not affect the consolidated statement of operations for the year ended December 31, 2006, or any prior period presented, and it will not have a material affect on our operating results in future periods. The incremental effects of adopting the provisions of SFAS 158 on the consolidated balance sheet at December 31, 2006 are as follows:

	At December 31, 2006
	Prior to adopting SFAS 158			Effect of adopting SFAS 158			As reported

Other assets	$	322		$	(23	)	$	299
Total assets		11,499			(23	)		11,476

Other current liabilities		366			3			369
Total current liabilities		1,036			3			1,039

Deferred income taxes, net		60			(6	)		54
Other long-term liabilities		337			6			343
Total long-term liabilities		3,597			—			3,597

Accumulated other comprehensive loss		(4	)		(26	)		(30	)
Total shareholders’ equity		6,862			(26	)		6,836
Total liabilities and shareholders’ equity	$	11,499		$	(23	)	$	11,476

Defined Benefit Pension Plans—We maintain a qualified defined benefit pension plan (the “Retirement Plan”) covering substantially all U.S. employees and an unfunded plan (the “Supplemental Benefit Plan”) to provide certain eligible employees with benefits in excess of those allowed under the Retirement Plan. In conjunction with the R&B Falcon merger, we acquired three defined benefit pension plans, two funded and one unfunded (the “Frozen Plans”), that were frozen prior to the merger for which benefits no longer accrue but the pension obligations have not been fully paid out. We refer to the Retirement Plan, the Supplemental Benefit Plan and the Frozen Plans collectively as the “U.S. Plans.”

In addition, we provide several other 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 Non-U.S. Plans”) that provide retirement and severance benefits for certain of our Indonesian, Nigerian and Egyptian employees. The defined benefit pension benefits we provide are comprised of the U.S. Plans, the Norway Plans, Other Non-U.S. Plans and the Assumed Pension Plans (collectively, the “Transocean Plans”). 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.

In connection with the Merger, we amended the Supplemental Benefit Plan to provide employees terminated under the severance plan with age, earnings and service benefits described in the Severance Plan and similar severance arrangements (“Severance Credits”). The Supplemental Benefit Plan provides credit for age, service and earnings during the period of time after termination during which severance is paid (the “Salary Continuation Period”), or if an eligible employee receives severance in a lump sum, the lump sum is considered to be paid out over the Salary Continuation Period in order to provide the value of the Severance Credits. The Supplemental Benefit Plan was also amended to 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 Code.

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Index

TRANSOCEAN INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

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,
	2007			2006
Change in projected benefit obligation
Projected benefit obligation at beginning of year	$	351		$	338
Assumed Pension Plans’ projected benefit obligations at Merger date		686			—
Service cost		22			20
Interest cost		24			19
Foreign currency exchange rate changes		—			5
Benefits paid		(17	)		(15	)
Actuarial gains		(1	)		(16	)
Projected benefit obligation at end of year	$	1,065		$	351

Change in plan assets
Fair value of plan assets at beginning of year	$	273		$	242
Assumed Pension Plans’ fair value of plan assets at Merger date		655			—
Actual return on plan assets		9			28
Employer contributions		22			15
Foreign currency exchange rate changes		(3	)		3
Benefits paid		(17	)		(15	)
Fair value of plan assets at end of year	$	939		$	273

Funded status	$	(126	)	$	(78	)

Amounts recognized in the consolidated balance sheets consist of:
Pension asset, non-current	$	32		$	5
Accrued pension liability, current		31			1
Accrued pension liability, non-current		127			82
Accumulated other comprehensive income (a)		(55	)		(42	)

______________

(a)

Amounts are before income tax effect of $12 million and $9 million for December 31, 2007 and 2006, respectively.

The accumulated benefit obligation for all defined benefit pension plans was $939 million and $290 million at December 31, 2007 and 2006, 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):

	December 31,
	2007		2006

Projected benefit obligation	$	419	$	273
Fair value of plan assets		261		190

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Index

TRANSOCEAN INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

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):

	December 31,
	2007		2006

Accumulated benefit obligation	$	256	$	189
Fair value of plan assets		165		154

Net periodic benefit cost included the following components (in millions):

	Years ended December 31,
	2007			2006			2005
Components of net periodic benefit cost (a)
Service cost	$	22		$	20		$	18
Interest cost		24			19			18
Expected return on plan assets		(26	)		(20	)		(21	)
Recognized net actuarial losses		5			5			4
Amortization of prior service cost		1			1			1
Amortization of net transition obligation		1			1			—
SFAS 88 settlements/curtailments		—			—			2
Net periodic benefit cost	$	27		$	26		$	22

Increase (decrease) in minimum pension liability included in other comprehensive income	$	(b	)	$	(25	)	$	(6	)

______________

(a)

Amounts are before income tax effect.

(b)

Disclosure is not applicable for December 31, 2007 due to adoption of SFAS 158.

No plan assets are expected to be returned to us during the year ending December 31, 2008.

There were no amounts recognized in other comprehensive income as components of net periodic benefit cost in the years ended December 31, 2006 and 2005.

For the year ended December 31, 2007, our components of net periodic benefit cost totaled $4 million, which was recognized in other comprehensive income.

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):

	December 31,			December 31,
	2007 (a), (b)			2006 (a), (b)

Net loss	$	57		$	42
Net prior service credit		(3	)		(1	)
Net transition obligation		1			1
Total unrecognized accumulated other comprehensive income	$	55		$	42

______________

(a)

Disclosure is not applicable for December 31, 2005.

(b)

Amounts are before income tax effect.

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):

	Year ending December 31,
	2008

Net loss	$	2
Net prior service cost		1
Net transition obligation		1
Total amount in accumulated other comprehensive income expected to be recognized next year	$	4

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TRANSOCEAN INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

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 Aa 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:

	December 31,
	2007			2006

Discount rate		6.07	%		5.72	%
Rate of compensation increase		4.57	%		4.27	%

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

	December 31,
	2007			2006			2005

Discount rate		5.90	%		5.69	%		5.63	%
Expected long-term rate of return on plan assets		8.40	%		8.49	%		8.70	%
Rate of compensation increase		4.59	%		4.54	%		4.52	%

We have determined the asset allocation of the plans that is best able to produce maximum long-term gains without taking on undue risk. After modeling many different asset allocation scenarios, we have determined that an asset allocation mix of approximately 60 percent equity securities, 30 percent debt securities and 10 percent other investments is most appropriate. 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 may include, among others, arbitrage, short-selling, and merger and acquisition investment opportunities. We review asset allocations and results quarterly to ensure that managers are meeting specified objectives and policies as written and agreed to by us and each manager. These objectives and policies are reviewed each year.

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, from time-to-time, invest in our stock or debt. This could include taking either long or short positions in such securities. As these managers are required to maintain well diversified portfolios, the actual investment in our ordinary 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:

	December 31,
	2007			2006

Equity securities		64.9	%		60.3	%
Debt securities		28.4	%		29.2	%
Other		6.7	%		10.5	%
Total		100.0	%		100.0	%

We contributed $22 million to our defined benefit pension plans in 2007, which were funded from our cash flows from operations. During 2007, contributions of $14 million were made to the funded U.S. Plans, $6 million to the funded Norway Plans and $1 million each to the Other Non-U.S. Plans and the Assumed U.K. Pension Plans.

We expect to contribute a total of $26 million to the Transocean Plans in 2008. These contributions are comprised of an estimated $10 million to meet the minimum funding requirements for the funded U.S. Plans, $2 million to fund expected benefit payments for the unfunded U.S. Plans and the Other Non-U.S. Plans and an estimated $7 million each for the funded Norway Plans and the Assumed U.K. Pension Plan.

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Index

TRANSOCEAN INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

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

Years ending December 31,
2008	$	64
2009		38
2010		39
2011		42
2012		44
2013-2017		285

Postretirement Benefits Other Than Pensions—We have several unfunded contributory and noncontributory OPEB plans 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.

In connection with the Merger, we assumed a contributory OPEB plan covering substantially all legacy GlobalSantaFe U.S. employees (the “Assumed OPEB Plan”).

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 less than $2 million for each of the years ended December 31, 2007 and 2006, and less than $3 million for the year ended December 31, 2005.

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,
	2007			2006
Change in benefit obligation
Benefit obligation at beginning of year	$	36		$	41
Assumed OPEB Plan’s projected benefit obligations at Merger date		21			—
Service cost		1			1
Interest cost		2			2
Actuarial gains		(3	)		(6	)
Participants’ contributions		1			1
Benefits paid		(3	)		(3	)
Benefit obligation at end of year	$	55		$	36

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

Funded status	$	(55	)	$	(36	)

Amounts recognized in the consolidated balance sheets consist of:
Accrued postretirement benefit liability, current	$	3		$	1
Accrued postretirement benefit liability, non-current		52			35
Accumulated other comprehensive income		(2	)		—

There were no amounts recognized in other comprehensive income as components of net periodic benefit cost in the years ended December 31, 2007, 2006 and 2005.

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Index

TRANSOCEAN INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

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):

	December 31,			December 31,
	2007(a)			2006(a)

Net prior service credit	$	(15	)	$	(17	)
Net loss		13			17
Net transition obligation		—			—
Total unrecognized accumulated other comprehensive income	$	(2	)	$	—

______________

(a)

Amounts are before income tax effect.

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 $2 million during the year ending December 31, 2008.

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 9.73 percent for 2007 reducing on an average of approximately 0.68 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 5.96 percent and 5.64 percent for the years ended December 31, 2007 and 2006, respectively.

Weighted-average assumptions used to determine net periodic benefit cost were 5.80 percent, 5.37 percent and 5.50 percent for the years ended December 31, 2007, 2006 and 2005, respectively.

Assumed health care cost trend rates were as follows:

	December 31,
	2007			2006

Health care cost trend rate assumed for next year		9.73	%		10.25	%
Rate to which the cost trend rate is assumed to decline (the ultimate trend rate)		5	%		5	%
Year that the rate reaches the ultimate trend rate	2014			2014

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 $3 million in postretirement benefit obligations as of December 31, 2007 and less than $1 million in total service and interest cost components in 2007.

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

Years ending December 31,
2008	$	2
2009		2
2010		2
2011		2
2012		2
2013-2017		11

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Index

TRANSOCEAN INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

Defined Contribution Plans—We provide a defined contribution pension and savings plan covering senior non-U.S. field employees working outside the United States. Contributions and costs are determined to be 4.5 percent to 6.5 percent of each covered employee’s salary, based on years of service. In addition, we sponsor a U.S. defined contribution savings plan that covers certain employees and limits our contributions to no more than 4.5 percent of each covered employee’s salary, based on the employee’s contribution. We also sponsor various other defined contribution plans worldwide. We recorded approximately $33 million, $26 million and $21 million of expense related to our defined contribution plans for the years ended December 31, 2007, 2006 and 2005, respectively.

In connection with the Merger, we assumed two defined contribution plans for employees in the U.S. (the “Assumed U.S. Defined Contribution Plans”) and two defined contributions plans in the United Kingdom (the “Assumed U.K. Defined Contribution Plans,” and together with the Assumed U.S. Defined Contribution Plans, the “Assumed Defined Contribution Plans”), covering substantially all U.S. and non-U.S. legacy GlobalSantaFe employees.

Deferred Compensation Plan—We provided a deferred compensation plan (the “Deferred Plan”), which was amended and effectively frozen as of December 31, 2004. The Deferred Plan’s primary purpose was to provide tax-advantageous asset accumulation for a select group of management, highly compensated employees and non-employee members of the board of directors.

Eligible employees who enrolled in the Deferred Plan could elect to defer up to a maximum of 90 percent of base salary, 100 percent of any future performance awards, 100 percent of any special payments and 100 percent of directors meeting fees and annual retainers; however, the administrative committee (seven individuals appointed by the finance and benefits committee of the board of directors) could, at its discretion, establish minimum amounts that must be deferred by anyone electing to participate in the Deferred Plan. In addition, the executive compensation committee of the board of directors could authorize employer contributions to participants and our chief executive officer, with executive compensation committee approval, was authorized to cause us to enter into “deferred compensation award agreements” with such participants. There were no employer contributions to the Deferred Plan during the years ended December 31, 2007, 2006 or 2005. In addition, we had a liability of $8 million, $6 million and $5 million for the years ended December 31, 2007, 2006 and 2005, respectively.

In connection with the Merger, we assumed a deferred compensation plan for employees of GlobalSantaFe (the “Assumed Deferred Plan”). Eligible employees who enrolled in this plan could defer any or all of the amount of their annual salary in excess of the annual IRS maximum recognizable compensation limit and up to 100% of their awards under the GlobalSantaFe annual incentive plan. Effective January 1, 2008, the Assumed Deferred Plan was amended to freeze the Assumed Deferred Plan as of that date. We had a liability of $9 million as of December 31, 2007 in relation to this plan.

Severance Plans—On November 27, 2007, we established a special transition severance plan for certain employees on the U.S. payroll involuntarily terminated during the period from November 27, 2007 through November 27, 2009 (the “Severance Plan”). The Severance Plan covers persons who (1) were shore-based employees of Transocean and GlobalSantaFe immediately prior to the date of the completion of the Transactions, (2) remain continuously employed by Transocean until the date of their termination, (3) do not have an individual employment or severance agreement with Transocean or GlobalSantaFe, (4) are not eligible to participate in the Transocean Executive Change of Control Severance Benefit policy, (5) are terminated involuntarily and not for cause during the two-year period ending November 27, 2009, and (6) timely execute a required form of waiver and release.

The amount of the severance benefit equals (1) one month of base pay for every $20,000 of the employee’s annual base salary, plus (2) for employees with 10 or fewer years of service, one week of base pay for every year of service; for employees with 10 or more years through 20 years of service, 10 weeks of base pay plus two weeks of base pay for every year of service in excess of 10 years; and for employees with more than 20 years of service, 30 weeks of base pay plus three weeks of base pay for every year of service in excess of 20 years, plus (3) two weeks of base pay. For this purpose, base salary in excess of a $20,000 increment and partial years of service will be pro rated. Notwithstanding the foregoing, in no event will the severance benefit be less than 26 weeks or more than 104 weeks of the employee’s weekly base pay. Additionally, any affected employee who is either a U.S. citizen or working in the U.S. and over the age of 39 years on his Termination Date is eligible for an additional $2,000 lump sum, when applicable. This payment shall not be included in determination of the minimum and maximum weeks of the severance benefits.

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 age, earnings and service credit for retirement purposes. Also, any employee who qualifies for the benefit will be treated as having been terminated for convenience of Transocean 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 $29 million for the estimated severance-related costs associated with the involuntary termination of 218 employees pursuant to management's plan to consolidate operations and administrative functions post-Merger. Through December 31, 2007, approximately $2 million in severance-related costs have been paid to 11 employees whose positions were eliminated as a result of the consolidation of operations and administrative functions post-merger. We anticipate that substantially all of the remaining amounts will be paid by the end of the first quarter of 2009.

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Index

TRANSOCEAN INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

Note 19—Segments, Geographical Analysis and Major Customers

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 and (2) Other. We have combined drilling management services and oil and gas properties into the Other segment. 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 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 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):

	Years ended December 31,
	2007		2006		2005
Operating revenues
United States	$	1,259	$	806	$	648
United Kingdom		848		439		335
India		761		291		296
Nigeria		587		447		218
Other countries (a)		2,922		1,899		1,395
Total operating revenues	$	6,377	$	3,882	$	2,892

	As of December 31,
	2007		2006
Long-lived assets
United States	$	5,856	$	2,504
United Kingdom		2,301		457
Nigeria		1,902		856
Other countries (a)		10,871		3,509
Total long-lived assets	$	20,930	$	7,326

______________________

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

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 the Cayman Islands, none of our rigs operate in the Cayman Islands. As a result, we have no operating revenues or long-lived assets in the Cayman Islands.

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, 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. For the year ended December 31, 2005, Chevron and BP each accounted for approximately 12 percent of our operating revenues. The loss of these or other significant customers could have a material adverse effect on our results of operations.

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Index

TRANSOCEAN INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

Note 20—Related Party Transactions

ODL—In connection with the management and operation of the Joides Resolution on behalf of ODL, we earned $1 million, $2 million and $1 million for the years ended December 31, 2007, 2006 and 2005, respectively. Such amounts are included in other revenues in our consolidated statements of operations. At December 31, 2007 and 2006, we had receivables due from ODL of $5 million and $1 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. Our director, 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, 2007 and 2006, $3 million was outstanding under this loan agreement for each year and was reflected as long-term debt in our consolidated balance sheet (see Note 7—Debt). No dividend was declared in 2007. ODL declared a dividend in the amount of $4 million in 2006. In addition, ODL paid us cash dividends of $3 million in 2005.

TODCO—We entered into a transition services agreement under which we provided specified administrative support to TODCO during the transitional period following the closing of the TODCO IPO. TODCO provides specified administrative support on our behalf for rig operations in Trinidad and Venezuela. Amounts earned under the transition services agreement were reflected in other revenues and amounts incurred for administrative support were reflected in operating and maintenance expense in our consolidated statement of operations. While any amounts recorded between us and TODCO subsequent to the deconsolidation of TODCO in mid-December 2004 were not material, we incurred $1 million of costs related to service fees that TODCO billed to us in 2005. At December 31, 2007 and 2006, we had payables related to the agreements for the separation of TODCO of $1 million for each year, which was included in accounts payable in our consolidated balance sheet. At December 31, 2007 and 2006, we had a long-term payable related to our indemnification of certain TODCO non-U.S. income tax liabilities of $11 million for each year, which was included in other long-term liabilities in our consolidated balance sheet.

Note 21—Earnings Per Share

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.

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,
	2007		2006		2005

Numerator for earnings per share:
Net income for basic earnings per share	$	3,131	$	1,385	$	716
Add back interest expense on the 1.5% Convertible Debentures		6		6		6
Net income for diluted earnings per share	$	3,137	$	1,391	$	722

Denominator for earnings per share:
Weighted-average shares outstanding for basic earnings per share		214		219		229
Effect of dilutive securities:
Employee stock options and unvested stock grants		3		4		4
Warrants to purchase ordinary shares		2		2		2
1.5% Convertible Debentures		3		3		3
Adjusted weighted-average shares and assumed conversions for diluted earnings per share		222		228		238

Earnings per share
Basic	$	14.65	$	6.32	$	3.13
Diluted	$	14.14	$	6.10	$	3.03

Ordinary shares subject to issuance pursuant to the conversion features of the Zero Coupon Convertible Debentures and the Convertible Notes (see Note 7—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. The Zero Coupon Convertible Debentures are not included in the calculation of adjusted weighted-average shares and assumed conversions for diluted earnings per share for the year ended December 31, 2005 because the effect of including those shares is anti-dilutive.

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Index

TRANSOCEAN INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

Note 22—Stock Warrants

In connection with the R&B Falcon merger, we assumed the then outstanding R&B Falcon stock warrants. Each warrant enabled the holder to purchase 17.5 ordinary shares at an exercise price of $19.00 per share. The warrants expire on May 1, 2009. On July 25, 2007, we issued 861,700 ordinary shares and we received $16 million in cash related to the exercise of 49,240 warrants. In November 2007, we issued 1,255,625 ordinary shares and we received $24 million in cash related to the exercise of 71,750 warrants. At December 31, 2007, there were 82,910 warrants outstanding to purchase 1,015,067 ordinary shares.

The warrant agreement provided that, as a result of the Reclassification, each warrant became exercisable for 12.243 ordinary shares at an adjusted exercise price equal to $21.74 per share pursuant to formulas specified in the warrant agreement. We believe that the adjustment of the number of 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, we modified the warrant agreement to allow warrantholders to receive, upon exercise following the Reclassification, 0.6996 of our ordinary shares and $33.03 for each ordinary share for which the warrants were previously exercisable, at an exercise price of $19.00 per ordinary share for which the warrants were exercisable prior to the Reclassification. As a result, a holder of a warrant may elect to receive 12.243 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.

The cash payment feature provided for in the modification resulted in a reclassification from permanent equity. As of December 31, 2007, $48 million was recorded in other current liabilities in our consolidated balance sheet.

Note 23—Quarterly Results (Unaudited)

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

2006
Operating revenues	$	817	$	854	$	1,025	$	1,186
Operating income (d)		284		289		390		678
Net income (d)		206		249		309		621
Earnings per share (c)
Basic	$	0.90	$	1.10	$	1.42	$	3.04
Diluted	$	0.87	$	1.07	$	1.37	$	2.92
Weighted average shares outstanding (c)
Basic		228		226		218		204
Diluted		238		235		227		213

_________________________

(a)	First quarter included gain from disposal of assets of $23 million. Third quarter included gain from disposal of assets of $8 million. Fourth quarter included gain from disposal of assets of $233 million. See Note 6—Asset Dispositions.

(b)	Third quarter included other income of $276 million recognized in connection with the TODCO tax sharing agreement and a tax benefit of $52 million from various discrete tax items. Fourth quarter included loss on retirement of debt of $8 million.

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Index

TRANSOCEAN INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

(c)	All earnings per share amounts and weighted average shares outstanding have been restated for the effect of the Reclassification. The restatement adjusts shares outstanding in a manner similar to a reverse stock split in the ratio of 0.6996 for each share outstanding.

(d)

First quarter included gain from disposal of assets of $65 million. Second quarter included gain from disposal of assets of $111 million. Third quarter included gain from disposal of assets of $45 million. Fourth quarter included gain from disposal of assets of $191 million. See Note 6—Asset Dispositions.

Note 24—Subsequent Events (Unaudited)

Commercial Paper Program—As of February 27, 2008, we have issued $813 million in commercial paper in 2008. The proceeds from the issuance of commercial paper were used to repay borrowings outstanding under the 364-Day Revolving Credit Facility.

Debt Repayments—As of February 27, 2008, we have repaid $580 million of borrowings under the Bridge Loan Facility in 2008 using internally generated cash flows.

Assets Held for Sale—On February 15, 2008, we entered into a definitive agreement with Hercules Offshore, Inc. to sell three of our Standard Jackups (GSF Adriatic III, GSF High Island I and GSF High Island VIII) for approximately $320 million. At February 27, 2008, GSF Adriatic III, GSF High Island I and GSF High Island VIII were classified as assets held for sale in the amounts of $146 million, $92 million and $92 million, respectively.

In addition, we are actively pursuing the sale of two Midwater Floaters, GSF Arctic II and GSF Arctic IV, which continue to operate under contract, in connection with our previously announced proposed undertakings to the Office of Fair Trading in the U.K. At February 27, 2008, GSF Arctic II and GSF Arctic IV were classified as held for sale in the amounts at $280 million and $285 million, respectively.

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Index

ITEM 9.

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

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.

ITEM 9A.

Controls and Procedures

In accordance with Exchange Act Rules 13a-15 and 15d-15, we carried out an evaluation, under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of December 31, 2007 to provide reasonable assurance that information required to be disclosed in our reports filed or submitted under the Exchange Act (i) accumulated and communicated to our management, including our Chief Executive Officer and our Chief Financial Officer, to allow timely decisions regarding required disclosure and (ii) 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, 2007 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.

ITEM 9B.

Other Information

None

PART III

ITEM 10.

Directors, Executive Officers and Corporate Governance

ITEM 11.

Executive Compensation

ITEM 12.

Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters

ITEM 13.

Certain Relationships, Related Transactions, and Director Independence

ITEM 14.

Principal Accountant Fees and Services

The information required by Items 10, 11, 12, 13 and 14 is incorporated herein by reference to our definitive proxy statement for our 2008 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, 2007. 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.”

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Index

PART IV

ITEM 15.

Exhibits and Financial Statement Schedules

(a)

Index to Financial Statements, Financial Statement Schedules and Exhibits

(1) Financial Statements

	Page
Included in Part II of this report:
Management’s Report on Internal Control Over Financial Reporting	61
Report of Independent Registered Public Accounting Firm on
Internal Control over Financial Reporting	62
Report of Independent Registered Public Accounting Firm	63
Consolidated Statements of Operations	64
Consolidated Statements of Comprehensive Income	65
Consolidated Balance Sheets	66
Consolidated Statements of Equity	67
Consolidated Statements of Cash Flows	68
Notes to Consolidated Financial Statements	69

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

(2) Financial Statement Schedules

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Index

Transocean Inc. and Subsidiaries

Schedule II - Valuation and Qualifying Accounts

(In millions)

			Additions
	Balance at Beginning of Period		Charged to Costs and Expenses		Charged to Other Accounts Describe			Deductions Describe			Balance at End of Period

Year ended December 31, 2005
Reserves and allowances deducted from asset accounts:
Allowance for doubtful accounts receivable	$	17	$	15	$	-		$	17	(a)(b)	$	15

Allowance for obsolete materials and supplies		20		1		-			2	(b)(c)		19

Valuation allowance on deferred tax assets		115		-		-			67	(d)		48

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	(e)		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	(f)		22

Valuation allowance on deferred tax assets	$	59	$	-	$	28	(g)	$	58	(h)	$	29

_____________________________

(a)	Uncollectible accounts receivable written off, net of recoveries.

(b)	Amount includes $1 related to adjustments to the provision.

(c)	Obsolete materials and supplies written off, net of scrap.

(d)	Amount represents the utilization of the underlying deferred tax assets to offset current year income.

(e)	Amount represents $3 related to sale of rigs/inventory.

(f)	Amount represents $1 related to sale of rigs/inventory.

(g)	Amount represents the valuation allowances established in connection with the tax assets acquired and the liabilities assumed during the Merger.

(h)	Amount represents a change in estimate related to the expected utilization of our U.S. foreign tax credits.

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.

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(3) Exhibits

The following exhibits are filed in connection with this Report:

Number	Description

2.1	Agreement and Plan of Merger dated as of August 19, 2000 by and among Transocean Inc., Transocean Holdings Inc., TSF Delaware Inc. and R&B Falcon Corporation (incorporated by reference to Annex A to the Joint Proxy Statement/Prospectus dated October 30, 2000 included in a 424(b)(3) prospectus filed by the Company on November 1, 2000)

2.2	Agreement and Plan of Merger dated as of July 12, 1999 among Schlumberger Limited, Sedco Forex Holdings Limited, Transocean Offshore Inc. and Transocean SF Limited (incorporated by reference to Annex A to the Joint Proxy Statement/Prospectus dated October 27, included in a 424(b)(3) prospectus filed by the Company on November 1, 2000)

2.3	Distribution Agreement dated as of July 12, 1999 between Schlumberger Limited and Sedco Forex Holdings Limited (incorporated by reference to Annex B to the Joint Proxy Statement/Prospectus dated October 27, included in a 424(b)(3) prospectus filed by the Company on November 1, 2000)

2.4	Agreement and Plan of Merger and Conversion dated as of March 12, 1999 between Transocean Offshore Inc. and Transocean Offshore (Texas) Inc. (incorporated by reference to Exhibit 2.1 to the Registration Statement on Form S-4 of Transocean Offshore (Texas) Inc. filed on April 8, 1999 (Registration No. 333-75899))

2.5	Agreement and Plan of Merger, dated as of July 21, 2007, among Transocean Inc., GlobalSantaFe Corporation and Transocean Worldwide Inc. (incorporated by reference to Exhibit 2.1 to the Company’s Current Report on Form 8-K filed on July 23, 2007)

3.1	Certificate of Incorporation on Change of Name to Transocean Inc. (incorporated by reference to Exhibit 3.3 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2002)

3.2	Transocean Amended and Restated Memorandum of Association (incorporated by reference to Annex E to the Joint Proxy Statement of Transocean and GlobalSantaFe filed on October 3, 2007)

3.3	Transocean Amended and Restated Articles of Association (incorporated by reference to Annex F to the Joint Proxy Statement of Transocean and GlobalSantaFe filed on October 3, 2007)

4.1	Indenture dated as of April 15, 1997 between the Company and Texas Commerce Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K dated April 29, 1997)

4.2	First Supplemental Indenture dated as of April 15, 1997 between the Company and Texas Commerce Bank National Association, as trustee, supplementing the Indenture dated as of April 15, 1997 (incorporated by reference to Exhibit 4.2 to the Company’s Current Report on Form 8-K dated April 29, 1997)

4.3	Second Supplemental Indenture dated as of May 14, 1999 between the Company and Chase Bank of Texas, National Association, as trustee (incorporated by reference to Exhibit 4.5 to the Company’s Post-Effective Amendment No. 1 to Registration Statement on Form S-3 (Registration No. 333-59001-99))

4.4	Third Supplemental Indenture dated as of May 24, 2000 between the Company and Chase Bank of Texas, National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K filed on May 24, 2000)

4.5	Fourth Supplemental Indenture dated as of May 11, 2001 between the Company and The Chase Manhattan Bank (incorporated by reference to Exhibit 4.3 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2001)

4.6	Form of 7.45% Notes due April 15, 2027 (incorporated by reference to Exhibit 4.3 to the Company’s Current Report on Form 8-K dated April 29, 1997)

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4.7	Form of 8.00% Debentures due April 15, 2027 (incorporated by reference to Exhibit 4.4 to the Company’s Current Report on Form 8-K dated April 19, 1997)

4.8	Form of Zero Coupon Convertible Debenture due May 24, 2020 between the Company and Chase Bank of Texas, National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K filed on May 24, 2000)

4.9	Form of 1.5% Convertible Debenture due May 15, 2021 (incorporated by reference to Exhibit 4.2 to the Company’s Current Report on Form 8-K dated May 8, 2001)

4.10	Form of 6.625% Note due April 15, 2011 (incorporated by reference to Exhibit 4.3 to the Company’s Current Report on Form 8-K dated March 30, 2001)

4.11	Form of 7.5% Note due April 15, 2031 (incorporated by reference to Exhibit 4.3 to the Company’s Current Report on Form 8-K dated March 30, 2001)

4.12	Officers’ Certificate establishing the terms of the 6.50% Notes due 2003, 6.75% Notes due 2005, 6.95% Notes due 2008, 7.375% Notes due 2018, 9.125% Notes due 2003 and 9.50% Notes due 2008 (incorporated by reference to Exhibit 4.13 to the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2001)

4.13	Officers’ Certificate establishing the terms of the 7.375% Notes due 2018 (incorporated by reference to Exhibit 4.14 to the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2001)

4.14	Warrant Agreement, including form of Warrant, dated April 22, 1999 between R&B Falcon and American Stock Transfer & Trust Company (incorporated by reference to Exhibit 4.1 to R&B Falcon’s Registration Statement No. 333-81181 on Form S-3 dated June 21, 1999)

4.15	Supplement to Warrant Agreement dated January 31, 2001 among Transocean Sedco Forex Inc., R&B Falcon Corporation and American Stock Transfer & Trust Company (incorporated by reference to Exhibit 4.28 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2000)

4.16	Supplement to Warrant Agreement dated September 14, 2005 between Transocean Inc. and The Bank of New York (incorporated by reference to Exhibit 4.3 to the Company’s Post-Effective Amendment No. 3 on Form S-3 to Form S-4 filed on November 18, 2005)

4.17	Amendment to Warrant Agreement dated November 27, 2007 between Transocean Inc. and The Bank of New York (incorporated by reference to Exhibit 4.2 to the Company’s Current Report on Form 8-K filed on December 3, 2007)

4.18	Registration Rights Agreement dated April 22, 1999 between R&B Falcon and American Stock Transfer & Trust Company (incorporated by reference to Exhibit 4.2 to R&B Falcons Registration Statement No. 333-81181 on Form S-3 dated June 21, 1999)

4.19	Supplement to Registration Rights Agreement dated January 31, 2001 between Transocean Sedco Forex Inc. and R&B Falcon Corporation (incorporated by reference to Exhibit 4.30 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2000)

4.20	Revolving Credit Agreement, dated as of July 8, 2005, among Transocean Inc., the lenders from time to time party thereto, Citibank, N.A., Bank of America, N.A., JPMorgan Chase Bank, N.A., The Royal Bank of Scotland plc and SunTrust Bank (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K filed on July 13, 2005)

4.21	Amendment No.1 to Revolving Credit Agreement, dated as of May 12, 2006, among Transocean Inc., the lenders from time to time parties thereto, Citibank., N.A., Bank of America, N.A., JP Morgan Chase Bank, N.A., the Royal Bank of Scotland plc and SunTrust Bank (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K filed on May 12, 2006)

4.22	Amendment No. 2 to Revolving Credit Agreement, dated as of June 1, 2007, among Transocean Inc., the lenders from time to time parties thereto, Citibank, N.A., Bank of America, N.A., JPMorgan Chase Bank, N.A., The Royal Bank of Scotland plc and SunTrust Bank (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K filed on June 4, 2007)

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4.23	Term Credit Agreement dated August 30, 2006 among Transocean Inc., the lenders party thereto and JPMorgan Chase Bank, N.A. as Administrative Agent, Citibank, N.A. as Syndication Agent, and The Bank of Tokyo-Mitsubishi UFJ, Ltd., Calyon New York Branch and The Royal Bank of Scotland plc (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K filed on August 31, 2006)

4.24	Form of Officers’ Certificate of Transocean Inc. establishing the form and terms of the Floating Rate Notes due 2008 (incorporated by reference to Exhibit 4.2 to the Company’s Current Report on Form 8-K filed on September 1, 2006)

4.25	Credit Agreement dated as of September 28, 2007 among Transocean Inc., the lenders party thereto and Goldman Sachs Credit Partners, L.P. as Administrative Agent, Lehman Commercial Paper Inc. as Syndication Agent, Citibank, N.A., Calyon Corporate 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 the Company’s Current Report on Form 8-K filed on October 1, 2007)

4.26	Amendment No. 1, dated November 21, 2007, to Credit Agreement dated as of September 28, 2007 among Transocean Inc., the lenders party thereto and Goldman Sachs Credit Partners, L.P. as Administrative Agent, Lehman Commercial Paper Inc. as Syndication Agent, Citibank, N.A., Calyon Corporate 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 4.11 to the Company’s Current Report on Form 8-K filed on December 3, 2007)

4.27	Five-Year Revolving Credit Agreement dated November 27, 2007 among Transocean Inc., as borrower, the lenders from time to time parties thereto, JPMorgan Chase Bank, N.A., as administrative agent for the lenders and as issuing bank of letters of credit, Citibank, N.A., as syndication agent for the lenders and as an issuing bank of letters of credit, Calyon Corporate and Investment Bank, as co-syndication agent, and Credit Suisse, Cayman Islands Branch and The Bank of Tokyo-Mitsubishi UFJ, Ltd., as co-documentation agents for the lenders (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K filed on December 3, 2007)

4.28	Indenture dated as of February 1, 2003, between GlobalSantaFe Corporation and Wilmington Trust Company, as trustee, relating to debt securities of GlobalSantaFe Corporation (incorporated by reference to Exhibit 4.9 to GlobalSantaFe Corporation’s Annual Report on Form 10-K for the year ended December 31, 2002)

4.29	Supplemental Indenture dated November 27, 2007 among Transocean Worldwide Inc., GlobalSantaFe Corporation and Wilmington Trust Company, as trustee, to the Indenture dated as of February 1, 2003 between GlobalSantaFe Corporation and Wilmington Trust Company (incorporated by reference to Exhibit 4.4 to the Company’s Current Report on Form 8-K filed on December 3, 2007)

4.30	Form of 7% Note Due 2028 (incorporated by reference to Exhibit 4.2 of Global Marine Inc.’s Current Report on Form 8-K (Commission File No. 1-5471) dated May 20, 1998)

4.31	Terms of 7% Note Due 2028 (incorporated by reference to Exhibit 4.1 of Global Marine Inc.’s Current Report on Form 8-K (Commission File No. 1-5471) dated May 20, 1998)

4.32	Indenture dated as of September 1, 1997, between Global Marine Inc. and Wilmington Trust Company, as Trustee, relating to Debt Securities of Global Marine Inc. (incorporated by reference to Exhibit 4.1 of Global Marine Inc.’s Registration Statement on Form S-4 (No. 333-39033) filed with the Commission on October 30, 1997); First Supplemental Indenture dated as of June 23, 2000 (incorporated by reference to Exhibit 4.2 of Global Marine Inc.’s Quarterly Report on Form 10-Q (Commission File No. 1-5471) for the quarter ended June 30, 2000); Second Supplemental Indenture dated as of November 20, 2001 (incorporated by reference to Exhibit 4.2 to GlobalSantaFe Corporation’s Annual Report on Form 10-K for the year ended December 31, 2004)

4.33	Form of 5% Note due 2013 (incorporated by reference to Exhibit 4.10 to GlobalSantaFe Corporation’s Annual Report on Form 10-K for the year ended December 31, 2002)

4.34	Terms of 5% Note due 2013 (incorporated by reference to Exhibit 4.11 to GlobalSantaFe Corporation’s Annual Report on Form 10-K for the year ended December 31, 2002)

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4.35	364-Day Revolving Credit Agreement dated December 3, 2007 among Transocean Inc. and the lenders from time to time parties thereto, JPMorgan Chase Bank, N.A., as administrative agent for the lenders, Citibank, N.A., as syndication agent for the lenders, Calyon New York Branch, as co-syndication agent, and Credit Suisse, Cayman Islands Branch and The Bank of Tokyo-Mitsubishi UFJ, Ltd., as co-documentation agents for the lenders (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K filed on December 5, 2007)

†4.36	Senior Indenture, dated as of December 11, 2007, between the Company and Wells Fargo Bank, National Association

†4.37	First Supplemental Indenture, dated as of December 11, 2007, between the Company and Wells Fargo Bank, National Association

†4.38	Second Supplemental Indenture, dated as of December 11, 2007, between the Company and Wells Fargo Bank, National Association

10.1	Tax Sharing Agreement between Sonat Inc. and Sonat Offshore Drilling Inc. dated June 3, 1993 (incorporated by reference to Exhibit 10-(3) to the Company’s Form 10-Q for the quarter ended June 30, 1993)

*10.2	Performance Award and Cash Bonus Plan of Sonat Offshore Drilling Inc. (incorporated by reference to Exhibit 10-(5) to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 1993)

*10.3	Form of Sonat Offshore Drilling Inc. Executive Life Insurance Program Split Dollar Agreement and Collateral Assignment Agreement (incorporated by reference to Exhibit 10-(9) to the Company’s Annual Report on Form 10-K for the year ended December 31, 1993)

*10.4	Amended and Restated Employee Stock Purchase Plan of Transocean Inc. (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K dated May 16, 2005)

*10.5	Amended and Restated Long-Term Incentive Plan of Transocean Inc. (incorporated by reference to Appendix B to the Company’s Proxy Statement dated March 19, 2004)

*10.6	Amendment to Amended and Restated Long-Term Incentive Plan of Transocean Inc. (incorporated by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K filed on July 23, 2007)

*10.7	Deferred Compensation Plan of Transocean Offshore Inc., as amended and restated effective January 1, 2000 (incorporated by reference to Exhibit 10.10 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1999)

*10.8	Amendment to Transocean Inc. Deferred Compensation Plan (incorporate by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on December 29, 2005)

*10.9	Sedco Forex Employees Option Plan of Transocean Sedco Forex Inc. effective December 31, 1999 (incorporated by reference to Exhibit 4.5 to the Company’s Registration Statement on Form S-8 (Registration No. 333-94569) filed January 12, 2000)

*10.10	1992 Long-Term Incentive Plan of Reading & Bates Corporation (incorporated by reference to Exhibit B to Reading & Bates’ Proxy Statement dated April 27, 1992)

*10.11	1995 Long-Term Incentive Plan of Reading & Bates Corporation (incorporated by reference to Exhibit 99.A to Reading & Bates’ Proxy Statement dated March 29, 1995)

*10.12	1995 Director Stock Option Plan of Reading & Bates Corporation (incorporated by reference to Exhibit 99.B to Reading & Bates’ Proxy Statement dated March 29, 1995)

*10.13	1997 Long-Term Incentive Plan of Reading & Bates Corporation (incorporated by reference to Exhibit 99.A to Reading & Bates’ Proxy Statement dated March 18, 1997)

*10.14	1998 Employee Long-Term Incentive Plan of R&B Falcon Corporation (incorporated by reference to Exhibit 99.A to R&B Falcon’s Proxy Statement dated April 23, 1998)

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*10.15	1998 Director Long-Term Incentive Plan of R&B Falcon Corporation (incorporated by reference to Exhibit 99.B to R&B Falcon’s Proxy Statement dated April 23, 1998)

*10.16	1999 Employee Long-Term Incentive Plan of R&B Falcon Corporation (incorporated by reference to Exhibit 99.A to R&B Falcon’s Proxy Statement dated April 13, 1999)

*10.17	1999 Director Long-Term Incentive Plan of R&B Falcon Corporation (incorporated by reference to Exhibit 99.B to R&B Falcon’s Proxy Statement dated April 13, 1999)

10.18	Master Separation Agreement dated February 4, 2004 by and among Transocean Inc., Transocean Holdings Inc. and TODCO (incorporated by reference to Exhibit 99.2 to the Company’s Current Report on Form 8-K dated March 2, 2004)

10.19	Tax Sharing Agreement dated February 4, 2004 between Transocean Holdings Inc. and TODCO (incorporated by reference to Exhibit 99.3 to the Company’s Current Report on Form 8-K dated March 2, 2004)

10.20	Amended and Restated Tax Sharing Agreement effective as of February 4, 2004 between Transocean Holdings Inc. and TODCO (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K filed on November 30, 2006)

*10.21	Executive Severance Benefit of Transocean Inc. effective February 9, 2005 (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on February 15, 2005)

*10.22	Form of 2004 Performance-Based Nonqualified Share Option Award Letter (incorporated by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K filed on February 15, 2005)

*10.23	Form of 2004 Employee Contingent Restricted Ordinary Share Award (incorporated by reference to Exhibit 10.3 to the Company’s Current Report on Form 8-K filed on February 15, 2005)

*10.24	Form of 2004 Director Deferred Unit Award (incorporated by reference to Exhibit 10.4 to the Company’s Current Report on Form 8-K filed on February 15, 2005)

*10.25	Performance Award and Cash Bonus Plan of Transocean Inc. (incorporated by reference to Exhibit 10.5 to the Company’s Current Report on Form 8-K filed on February 15, 2005)

†*10.26	Description of Base Salaries of Named Executive Officers

*10.27	Executive Change of Control Severance Benefit (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on July 19, 2005)

10.28	Commitment Letter, dated July 21, 2007, among Transocean Inc., GlobalSantaFe Corporation, Goldman Sachs Credit Partners L.P., Lehman Brothers Commercial Bank, Lehman Commercial Paper Inc. and Lehman Brothers Inc. (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on July 23, 2007)

*10.29	Terms of July 2007 Employee Restricted Stock Awards (incorporated by reference to Exhibit 10.2 to the Company’s Form 10-Q for the quarter ended June 30, 2007)

*10.30	Terms of July 2007 Employee Deferred Unit Awards (incorporated by reference to Exhibit 10.3 to the Company’s Form 10-Q for the quarter ended June 30, 2007

10.31	Put Option and Registration Rights Agreement, dated as of October 18, 2007, among Pacific Drilling Limited, Transocean Pacific Drilling Inc., Transocean Inc. and Transocean Offshore International Ventures Limited (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on October 24, 2007)

10.32	Form of Novation Agreement dated as of November 27, 2007 by and among GlobalSantaFe Corporation, Transocean Offshore Deepwater Drilling Inc. and certain executives (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on December 3, 2007)

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*10.33	Form of Severance Agreement with GlobalSantaFe Corporation Executive Officers (incorporated by reference to Exhibit 10.1 to GlobalSantaFe Corporation’s Current Report on Form 8 K/A filed on July 26, 2005)

*10.34	Transocean Special Transition Severance Plan for Shore-Based Employees (incorporated by reference to Exhibit 10.3 to the Company’s Current Report on Form 8-K filed on December 3, 2007)

*10.35	Global Marine Inc. 1989 Stock Option and Incentive Plan (incorporated by reference to Exhibit 10.6 of Global Marine Inc.’s Annual Report on Form 10-K (Commission File No. 1-5471) for the year ended December 31, 1988); First Amendment (incorporated by reference to Exhibit 10.6 of Global Marine Inc.’s Annual Report on Form 10-K (Commission File No. 1-5471) for the year ended December 31, 1990); Second Amendment (incorporated by reference to Exhibit 10.7 of Global Marine Inc.’s Annual Report on Form 10-K (Commission File No. 1-5471) for the year ended December 31, 1991); Third Amendment (incorporated by reference to Exhibit 10.19 of Global Marine Inc.’s Annual Report on Form 10-K (Commission File No. 1-5471) for the year ended December 31, 1993); Fourth Amendment (incorporated by reference to Exhibit 10.16 of Global Marine Inc.’s Annual Report on Form 10-K (Commission File No. 1-5471) for the year ended December 31, 1994); Fifth Amendment (incorporated by reference to Exhibit 10.1 of Global Marine Inc.’s Quarterly Report on Form 10-Q (Commission File No. 1-5471) for the quarter ended June 30, 1996); Sixth Amendment (incorporated by reference to Exhibit 10.18 of Global Marine Inc.’s Annual Report on Form 10-K (Commission File No. 1-5471) for the year ended December 31, 1996)

*10.36	Global Marine Inc. 1990 Non-Employee Director Stock Option Plan (incorporated by reference to Exhibit 10.18 of Global Marine Inc.’s Annual Report on Form 10-K (Commission File No. 1-5471) for the year ended December 31, 1991); First Amendment (incorporated by reference to Exhibit 10.1 of Global Marine Inc.’s Quarterly Report on Form 10-Q (Commission File No. 1-5471) for the quarter ended June 30, 1995); Second Amendment (incorporated by reference to Exhibit 10.37 of Global Marine Inc.’s Annual Report on Form 10-K (Commission File No. 1-5471) for the year ended December 31, 1996)

*10.37	1997 Long-Term Incentive Plan (incorporated by reference to GlobalSantaFe Corporation’s Registration Statement on Form S-8 (No. 333-7070) filed June 13, 1997); Amendment to 1997 Long Term Incentive Plan (incorporated by reference to GlobalSantaFe Corporation’s Annual Report on Form 20-F for the calendar year ended December 31, 1998); Amendment to 1997 Long Term Incentive Plan dated December 1, 1999 (incorporated by reference to GlobalSantaFe Corporation’s Annual Report on Form 20-F for the calendar year ended December 31, 1999)

*10.38	GlobalSantaFe Corporation 1998 Stock Option and Incentive Plan (incorporated by reference to Exhibit 10.1 of Global Marine Inc.’s Quarterly Report on Form 10-Q (Commission File No. 1-5471) for the quarter ended March 31, 1998); First Amendment (incorporated by reference to Exhibit 10.2 of Global Marine Inc.’s Quarterly Report on Form 10-Q (Commission File No. 1-5471) for the quarter ended June 30, 2000)

*10.39	GlobalSantaFe Corporation 2001 Non-Employee Director Stock Option and Incentive Plan (incorporated by reference to GlobalSantaFe Corporation’s Registration Statement on Form S-8 (No. 333-73878) filed November 21, 2001)

*10.40	GlobalSantaFe Corporation 2001 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.1 to GlobalSantaFe Corporation’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2001)

*10.41	GlobalSantaFe 2003 Long-Term Incentive Plan (as Amended and Restated Effective June 7, 2005) (incorporated by reference to Exhibit 10.4 to GlobalSantaFe Corporation’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2005)

*10.42	GlobalSantaFe Pension Equalization Plan, as amended and restated, effective November 27, 2007 (incorporated by reference to Exhibit 10.12 to the Company’s Current Report on Form 8-K filed on December 3, 2007)

*10.43	Transocean U.S. Supplemental Retirement Benefit Plan, as amended and restated, effective as of November 27, 2007 (incorporated by reference to Exhibit 10.11 to the Company’s Current Report on Form 8-K filed on December 3, 2007)

10.44	Commercial Paper Dealer Agreement between Transocean Inc. and Lehman Brothers Inc., dated as of December 20, 2007 (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on December 21, 2007)

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10.45	Commercial Paper Dealer Agreement between Transocean Inc. and Morgan Stanley & Co. Incorporated, dated as of December 20, 2007 (incorporated by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K filed on December 21, 2007)

10.46	Commercial Paper Dealer Agreement between Transocean Inc. and J.P. Morgan Securities Inc., dated as of December 20, 2007 (incorporated by reference to Exhibit 10.3 to the Company’s Current Report on Form 8-K filed on December 21, 2007)

†21	Subsidiaries of the Company

†23.1	Consent of Ernst & Young LLP

†24	Powers of Attorney

†31.1	CEO Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

†31.2	CFO Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

†32.1	CEO Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

†32.2	CFO Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

_______________________________

*Compensatory plan or arrangement.

†Filed herewith.

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.

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned; thereunto duly authorized, on February 27, 2008.

	TRANSOCEAN INC.
	By	/s/ Gregory L. Cauthen
		Gregory L. Cauthen
		Senior Vice President and Chief Financial Officer

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 27, 2008.

Signature		Title


*		Chairman of the Board of Directors
Robert E. Rose


/s/ Robert L. Long		Chief Executive Officer
Robert L. Long		(Principal Executive Officer)

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


/s/ John H. Briscoe		Vice President and Controller
John H. Briscoe		(Principal Accounting Officer)


*		President, Chief Operating Officer and
Jon A. Marshall		Director


*		Director
W. Richard Anderson


*		Director
Thomas W. Cason


*		Director
Richard L. George


*		Director
Victor E. Grijalva


*		Director
Martin B. McNamara


*		Director
Edward R. Muller

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Signature		Title


*
Kristian Siem		Director


*
Robert M. Sprague		Director


*
Ian C. Strachan		Director


*
J. Michael Talbert		Director


*
John L. Whitmire		Director


By	/s/ Chipman Earle
	Chipman Earle
	(Attorney-in-Fact)

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