Edgar Filing: TRANSOCEAN INC

Voluntary Filer

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

_________________

FORM 10-K

(Mark One)

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

For the fiscal year ended December 31, 2006

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

For the transition period from _____ to ______.

Commission file number 333-75899

_________________

TRANSOCEAN INC.

(Exact name of registrant as specified in its charter)

_________________

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

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

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

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

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

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

Indicate by check mark whether the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

Yes x No o

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 o No x

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

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act.

Large accelerated filer x

Accelerated filer o

Non-accelerated filer o

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

As of June 30, 2006, 319,904,208 ordinary shares were outstanding and the aggregate market value of such shares held by non-affiliates was approximately $25.7 billion (based on the reported closing market price of the ordinary shares on such date of $80.32 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 23, 2007, 292,967,692 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, 2006, for its 2007 annual general meeting of shareholders, are incorporated by reference into Part III of this Form 10-K.

TRANSOCEAN INC. AND SUBSIDIARIES

INDEX TO ANNUAL REPORT ON FORM 10-K

FOR THE YEAR ENDED DECEMBER 31, 2006

Item		Page

	PART I
ITEM 1.	Business	5
	Background of Transocean	5
	Drilling Fleet	5
	Markets	9
	Operating Revenues and Long-Lived Assets by Country	10
	Integrated Services	10
	Drilling Contracts	11
	Significant Clients	11
	Regulation	11
	Employees	12
	Available Information	12
ITEM 1A.	Risk Factors	13
ITEM 1B.	Unresolved Staff Comments	17
ITEM 2.	Properties	17
ITEM 3.	Legal Proceedings	17
ITEM 4.	Submission of Matters to a Vote of Security Holders	19
	Executive Officers of the Registrant	19

	PART II
ITEM 5.	Market for Registrant’s Common Equity, Related Shareholder Matters and Issuer Purchases of Equity Securities	21
ITEM 6.	Selected Financial Data	23
ITEM 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	24
ITEM 7A.	Quantitative and Qualitative Disclosures About Market Risk	47
ITEM 8.	Financial Statements and Supplementary Data	48
ITEM 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	95
ITEM 9A.	Controls and Procedures	95
ITEM 9B.	Other Information	95

	PART III
ITEM 10.	Directors, Executive Officers and Corporate Governance	95
ITEM 11.	Executive Compensation	95
ITEM 12.	Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters	95
ITEM 13.	Certain Relationships and Related Transactions, and Director Independence	95
ITEM 14.	Principal Accountant Fees and Services	95

	PART IV
ITEM 15.	Exhibits and Financial Statement Schedules	96

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,	·	issuance of new debt,
·	contract option exercises,	·	debt reduction,
·	revenues,	·	planned asset sales,
·	expenses,	·	timing of asset sales,
·	results of operations,	·	proceeds from asset sales,
·	commodity prices,	·	our effective tax rate,
·	customer drilling programs,	·	changes in tax laws,
·	supply and demand,	·	treaties and regulations,
·	utilization rates,	·	tax assessments,
·	dayrates,	·	our other expectations with regard to
·	contract backlog,		market outlook,
·	planned shipyard projects and rig	·	operations in international markets,
	mobilizations and their effects,	·	the level of expected capital
·	newbuild projects and opportunities,		expenditures,
·	the upgrade projects for the Sedco 700-	·	results and effects of legal proceedings
	series semisubmersible rigs,		and governmental audits and
·	other major upgrades,		assessments,
·	rig reactivations,	·	adequacy of insurance,
·	expected downtime,	·	liabilities for tax issues, including those
·	insurance proceeds,		associated with our activities in Brazil,
·	future activity in the deepwater, mid-		Norway and the United States,
	water and the jackup market sectors,	·	liquidity,
·	market outlook for our various	·	cash flow from operations,
	geographical operating sectors,	·	adequacy of cash flow for our
·	capacity constraints for fifth-generation		obligations,
	rigs and other rig classes,	·	effects of accounting changes,
·	effects of new rigs on the market,	·	adoption of accounting policies,
·	income related to the TODCO tax	·	pension plan and other postretirement
	sharing agreement,		benefit plan contributions,
·	uses of excess cash, including ordinary	·	benefit payments, and
	share repurchases,	·	the timing and cost of completion of
·	the timing and funding of share		capital projects.
	repurchases,

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,

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Index

the effect and results of litigation, 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

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

Background of Transocean

On January 31, 2001, we completed our merger transaction (the “R&B Falcon merger”) with R&B Falcon Corporation (“R&B Falcon”). At the time of the R&B Falcon merger, R&B Falcon operated a diverse global drilling rig fleet, consisting of drillships, semisubmersibles, jackup rigs and other units in addition to the Gulf of Mexico Shallow and Inland Water segment fleet. R&B Falcon and the Gulf of Mexico Shallow and Inland Water segment later became known as TODCO (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 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 information about the revenues, operating income, assets and other information relating to our business and the geographic areas in which we operate, see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Note 21—Segments, Geographical Analysis and Major Customers to our consolidated financial statements included in Item 8 of this report.

Drilling Fleet

We principally operate three types of drilling rigs:

drillships;

semisubmersibles; and

jackups.

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

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.

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Index

As of February 2, 2007, our fleet of 82 rigs, which excludes assets held for sale and rigs under construction, included:

33 High-Specification Floaters, which are comprised of:

- 13 Fifth-Generation Deepwater Floaters;

- 16 Other Deepwater Floaters; and

- four Other High-Specification Floaters;

20 Other Floaters;

25 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 2, 2007, our fleet was located in the Far East (14 units), India (12 units), U.S. Gulf of Mexico (11 units), United Kingdom (10 units), Nigeria (eight units), the Mediterranean and Middle East (seven units), Brazil (six units), Norway (five units), other West African countries (five units), Australia (one unit), Canada (one unit), the Caspian Sea (one unit) and Venezuela (one unit).

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

Drillships are generally self-propelled, shaped like conventional ships and are the most mobile of the major rig types. All of our drillships are dynamically positioned, which allows them to maintain position without anchors through the use of their onboard propulsion and station-keeping systems. 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 include our patented dual-activity technology. Dual-activity technology includes structures 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.

During 2006, we were awarded drilling contracts requiring the construction of three enhanced Enterprise-class drillships. The newbuilds are expected to be placed in service and commence operations during the second quarter of 2009, mid-2009 and the first quarter of 2010. Newbuilds are included in our drilling fleet upon testing and acceptance of the rig. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Outlook.”

Semisubmersibles are floating vessels that can be submerged by means of a water ballast system such that the lower hulls are below the water surface during drilling operations. These rigs are capable of maintaining their position over the well through the use of an anchoring system or a computer controlled dynamic positioning thruster system. Some semisubmersible rigs are self-propelled and move between locations under their own power when afloat on pontoons although most are relocated with the assistance of tugs. Typically, semisubmersibles are better suited for operations in rougher water conditions than drillships. 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.

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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 300 feet or less.

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. For some of these rigs, the cost could be significant. We would take these factors into consideration together with market conditions, length of contract and dayrate and other contract terms in deciding whether to return a particular idle rig to service. We may consider marketing 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.

High-Specification Floaters (33)

The following tables provide certain information regarding our High-Specification Floaters as of February 2, 2007:

Year

Water

Drilling

Entered

Depth

Service/

Capacity

Name

Type

Upgraded(a)

(in feet)

Location

Fifth-Generation Deepwater Floaters (13)

Deepwater Discovery (b)

HSD

2000

10,000

30,000

Nigeria

Deepwater Expedition (b)

HSD

1999

10,000

30,000

Egypt

Deepwater Frontier (b)

HSD

1999

10,000

30,000

India

Deepwater Millennium (b)

HSD

1999

10,000

30,000

U.S. Gulf

Deepwater Pathfinder (b)

HSD

1998

10,000

30,000

Nigeria

Discoverer Deep Seas (b) (c)

HSD

2001

10,000

35,000

U.S. Gulf

Discoverer Enterprise (b) (c)

HSD

1999

10,000

35,000

U.S. Gulf

Discoverer Spirit (b) (c)

HSD

2000

10,000

35,000

U.S. Gulf

Deepwater Horizon (b)

HSS

2001

10,000

30,000

U.S. Gulf

Cajun Express (b) (d)

HSS

2001

8,500

35,000

U.S. Gulf

Deepwater Nautilus (e)

HSS

2000

8,000

30,000

U.S. Gulf

Sedco Energy (b) (d)

HSS

2001

7,500

25,000

Nigeria

Sedco Express (b) (d)

HSS

2001

7,500

25,000

Angola

Other Deepwater Floaters (16)

Deepwater Navigator (b)

HSD

2000

7,200

25,000

Brazil

Discoverer 534 (b)

HSD

1975/1991

7,000

25,000

Singapore

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 707 (b)

HSS

1976/1997

6,500

25,000

Brazil

Sedco 702

HSS

1973/(f)

6,500

(f)

Singapore

Jack Bates

HSS

1986/1997

5,400

30,000

U.S. Gulf

Peregrine I (b)

HSD

1982/1996

5,200

25,000

Brazil

Sedco 709 (b)

HSS

1977/1999

5,000

25,000

Nigeria

M. G. Hulme, Jr.

HSS

1983/1996

5,000

25,000

Nigeria

Transocean Richardson

HSS

1988

5,000

25,000

Angola

Jim Cunningham

HSS

1982/1995

4,600

25,000

Nigeria

- 7 -

Index

Year

Water

Drilling

Entered

Depth

Service/

Capacity

Name

Type

Upgraded(a)

(in feet)

Location

Transocean Leader

HSS

1987/1997

4,500

25,000

Norwegian N. Sea

Transocean Rather

HSS

1988

4,500

25,000

U.K. North Sea

Sovereign Explorer

HSS

1984

4,500

25,000

Venezuela

Sedco 710 (b)

HSS

1983/2001

4,500

25,000

Brazil

Other High-Specification Floaters (4)

Henry Goodrich

HSS

1985

2,000

30,000

Canada

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)	Express-class rig.

(e)	The Deepwater Nautilus was previously leased from its owner, an unrelated third party, pursuant to a fully defeased lease arrangement. We terminated the lease and purchased the rig in December 2006.

(f)

In the fourth quarter of 2005, we entered into agreements with clients to upgrade two of our Sedco 700-series semisubmersible rigs in our Other Floaters fleet, the Sedco 702 and Sedco 706, at a cost expected to be approximately $300 million for each rig. A rig is counted within the upgraded rig class and removed from the prior rig class when it enters the shipyard to begin upgrade work. The Sedco 702 entered the shipyard for the upgrade in early 2006.

Other Floaters (20)

The following table provides certain information regarding our Other Floaters as of February 2, 2007:

Year

Water

Drilling

Entered

Depth

Service/

Capacity

Name

Type

Upgraded(a)

(in feet)

Location

Sedco 700

1973/1997

3,600

25,000

E. Guinea

Transocean Amirante

1978/1997

3,500

25,000

U.S. Gulf

Transocean Legend

1983

3,500

25,000

Indonesia

C. Kirk Rhein, Jr.

1976/1997

3,300

25,000

U.A.E.

Transocean Driller

1991

3,000

25,000

Brazil

Falcon 100

1974/1999

2,400

25,000

U.S. Gulf

Sedco 703

1973/1995

2,000

25,000

Australia

Sedco 711

1982

1,800

25,000

U.K. North Sea

Transocean John Shaw

1982

1,800

25,000

U.K. North Sea

Sedco 714

1983/1997

1,600

25,000

U.K. North Sea

Sedco 712

1983

1,600

25,000

U.K. North Sea

Actinia

1982

1,500

25,000

India

Sedco 601

1983

1,500

25,000

Myanmar

Sedneth 701

1972/1993

1,500

25,000

Angola

Transocean Prospect

1983/1992

1,500

25,000

U.K. North Sea

Transocean Searcher

1983/1988

1,500

25,000

Norwegian N. Sea

Transocean Winner

1983

1,500

25,000

Norwegian N. Sea

J. W. McLean

1974/1996

1,250

25,000

U.K. North Sea

Sedco 704

1974/1993

1,000

25,000

U.K. North Sea

Sedco 706 (b)

1976/1994

1,000

25,000

U.K. North Sea

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Index

_______________________________________

“OS” means other semisubmersible.

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

(b)

In the fourth quarter of 2005, we entered into agreements with clients to upgrade two of our Sedco 700-series semisubmersible rigs in our Other Floaters fleet, the Sedco 702 and Sedco 706, at a cost expected to be approximately $300 million for each rig. A rig is counted within the upgraded rig class and removed from the prior rig class when it enters the shipyard to begin upgrade work. The Sedco 706 upgrade is scheduled to commence in the third quarter of 2007.

Jackups (25)

The following table provides certain information regarding our Jackups fleet as of February 2, 2007:

			Water		Drilling
	Year Entered		Depth		Depth
	Service/		Capacity		Capacity
Name	Upgraded(a)		(in feet)		(in feet)		Location
Trident IX		1982		400		21,000		Vietnam
Trident 17		1983		355		25,000		Vietnam
Trident 20		2000		350		25,000		Caspian Sea
Harvey H. Ward		1981		300		25,000		Malaysia
J. T. Angel		1982		300		25,000		Singapore
Roger W. Mowell		1982		300		25,000		Malaysia
Ron Tappmeyer		1978		300		25,000		India
D. R. Stewart		1980		300		25,000		Italy
Randolph Yost		1979		300		25,000		India
C. E. Thornton		1974		300		25,000		India
F. G. McClintock		1975		300		25,000		India
Shelf Explorer		1982		300		25,000		Malaysia
Transocean III		1978/1993		300		20,000		Egypt
Transocean Nordic		1984		300		25,000		India
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		Cameroon
Trident 15		1982		300		25,000		Thailand
Trident 16		1982		300		25,000		Thailand
George H. Galloway		1984		300		25,000		Italy
Transocean Comet		1980		250		20,000		Egypt
Transocean Mercury		1969/1998		250		20,000		Egypt
Trident VI		1981		220		21,000		Vietnam

______________________________

(a)

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

Other Rigs

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

Markets

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

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

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Index

The deepwater and mid-water market sectors are serviced by our semisubmersibles and drillships. While the use of the term “deepwater” as used in the drilling industry to denote a particular sector of the market can vary and continues to evolve with technological improvements, we generally view the deepwater market sector as that which begins in water depths of approximately 4,500 feet and extends to the maximum water depths in which rigs are capable of drilling, which is currently approximately 10,000 feet. We view the mid-water market sector as that which covers water depths of about 300 feet to approximately 4,500 feet.

The global jackup market sector begins at the outer limit of the transition zone and extends to water depths of about 300 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, shallow bay and coastal water areas. We operate in this sector using our drilling barges located in Southeast Asia.

Operating Revenues and Long-Lived Assets by Country

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

	Years ended December 31,
	2006		2005		2004
Operating Revenues
United States	$	806	$	648	$	856
United Kingdom		462		335		209
Nigeria		447		218		196
India		313		296		271
Brazil		308		265		278
Other Countries (a)		1,546		1,130		804
Total Operating Revenues	$	3,882	$	2,892	$	2,614

	As of December 31,
	2006		2005
Long-Lived Assets
United States	$	2,485	$	2,311
Nigeria		856		980
Brazil		535		762
United Kingdom		457		363
India		236		304
Other Countries (a)		2,757		2,028
Total Long-Lived Assets	$	7,326	$	6,748

______________________

(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.

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 28, 2007, we were performing such services in India. These integrated service revenues did not represent a material portion of our revenues for any period presented.

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Drilling Contracts

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

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

Significant Clients

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 2006 were Chevron, BP and Shell accounting for 14 percent, 11 percent and 11 percent, respectively, of our 2006 operating revenues. No other client accounted for 10 percent or more of our 2006 operating revenues. The loss of any of these significant clients could, at least in the short term, have a material adverse effect on our results of operations.

Regulation

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

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

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

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

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

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

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

Governmental authorities in the U.S. are also reviewing various regulations relating to rig mooring requirements, particularly in the aftermath of the hurricane activity in 2005 in the Gulf of Mexico. We and the drilling industry are working with the pertinent authorities as part of this process.

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

Employees

We require highly skilled personnel to operate our drilling units. As a result, we conduct extensive personnel recruiting, training and safety programs. At January 31, 2007, we had approximately 10,700 employees and we also utilized approximately 1,800 persons through contract labor providers. As of such date, approximately 15 percent of our employees and contract labor worldwide worked under collective bargaining agreements, most of whom worked in the U.K., Nigeria and Norway. Of these represented individuals, 60 percent are working under agreements that are subject to salary negotiation in 2007. These negotiations could result in higher personnel expenses, other increased costs or increased operating restrictions.

Available Information

Our website address is www.deepwater.com. We make our website content available for information purposes only. It should not be relied upon for investment purposes, nor is it incorporated by reference in this Form 10-K. We make available on this website under “Investor Relations-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 ethics at our website. Among the information you can find there is the following:

Corporate Governance Guidelines;

Audit Committee Charter;

Corporate Governance Committee Charter;

Executive Compensation Committee Charter;

Finance and Benefits Committee Charter; and

Code of Ethics.

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

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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 market sectors worldwide, with the U.S. and international offshore areas being our primary market sectors. 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 our customers' expectations of future commodity prices typically drive demand for our rigs. Also, increased competition for our customers’ drilling budgets could come from, among other areas, land-based energy markets in Africa, Russia, other former Soviet Union States, the Middle East and Alaska. The availability of quality drilling prospects, exploration success, relative production costs, the stage of reservoir development and political and regulatory environments also affect our customers’ drilling 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,

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. Mergers among oil and natural gas exploration and production companies have reduced the number of available customers.

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 mid-water semisubmersibles that 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 of dayrates, or reduce them, in the affected markets or result in a softening of the affected markets 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 in one or more of the regions in which we operate 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.

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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. The occurrence of these events could result in the suspension of drilling operations, damage to or destruction of the equipment involved and injury or death to rig personnel. We may also be subject to personal injury and other claims of rig personnel as a result of our drilling operations. Operations also may be suspended because of machinery breakdowns, abnormal drilling conditions, and failure of subcontractors to perform or supply goods or services or personnel shortages. In addition, offshore drilling operations are subject to perils peculiar to marine operations, including capsizing, grounding, collision and loss or damage from severe weather. Damage to the environment could also result from our operations, particularly through oil spillage or extensive uncontrolled fires. We may also be subject to property, environmental and other damage claims by oil and gas companies. Our insurance policies and contractual rights to indemnity may not adequately cover losses, and we do not have insurance coverage or rights to indemnity for all risks.

Consistent with standard industry practice, our clients generally assume, and indemnify us against, well control and subsurface risks under dayrate contracts. These risks are those associated with the loss of control of a well, such as blowout or cratering, the cost to regain control or redrill the well and associated pollution. However, there can be no assurance that these clients will necessarily be financially able to indemnify us against all these risks. Also, we may be effectively prevented from enforcing these indemnities because of the nature of our relationship with some of our larger clients.

We have historically maintained broad insurance coverages, including coverages 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, wind, storms, action of waves, punch-throughs, cratering, blowouts, explosion and war risks. We currently insure all of our offshore drilling equipment for general and third party liabilities, occupational and illness risks, and property damage. We also generally insure all of our offshore drilling rigs against property damage but the amount of such insurance may be less than the fair market value, replacement cost and net carrying value for financial reporting purposes.

In accordance with industry practices, we believe we are adequately insured for normal risks in our operations; however, such insurance coverage would 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 limits on losses due to hurricanes. 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 not be reimbursed by insurance carriers. Such lack of reimbursement may cause us to incur substantial costs. In addition, we could decide to retain substantially more risk through self-insurance.

Failure to retain key personnel could hurt our operations.

We require highly skilled personnel to operate and provide technical services and support for our drilling units. As demand for drilling services and the size of the worldwide industry fleet increases, we have begun to see shortages of qualified personnel in the industry, creating upward pressure on wages and possibly 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. We are increasing efforts in our recruitment, training, development and retention programs as required to meet our anticipated personnel needs.

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.

On January 31, 2007, approximately 15 percent of our employees and contracted labor worldwide worked under collective bargaining agreements, most of whom worked in the U.K., Nigeria and Norway. Of these represented individuals, approximately 60 percent are working under agreements that are subject to salary negotiation in 2007. These negotiations could result in higher personnel expenses, other increased costs or increased operating restrictions. Additionally, the unions in the U.K. are seeking an interpretation of the Offshore Working Directive, which was recently extended to include U.K. offshore workers, that could result in higher labor costs and undermine our ability to obtain a sufficient number of skilled workers in the U.K.

Our shipyard projects are subject to delays and cost overruns.

We have committed to three deepwater newbuild rig projects and two Sedco 700-series rig upgrades, and we are discussing other potential newbuild opportunities with several clients. We also have a variety of other more limited shipyard projects at any given time. Our 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 our customer 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.

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A loss of a major tax dispute or a successful tax challenge to our structure could result in a significant loss or in a higher tax rate on our worldwide earnings or both.

We are a Cayman Islands company and also operate through various subsidiaries around the world. Our income tax returns are subject to review and examination in the various jurisdictions in which we operate. We accrue for income tax contingencies that we believe are probable exposures and our income taxes are based upon how we are structured in countries around the world. If any country, including the U.S. and Norway, successfully challenges our income tax filings based on our operational structure there, or if we otherwise lose a material dispute, our effective tax rate on our worldwide earnings could increase substantially and our financial results 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, or their interpretation, of any country in which we operate could result in a higher tax rate on our worldwide earnings.

We operate worldwide through our various subsidiaries. Consequently, we are subject to changing tax laws and policies in the jurisdictions in which we operate, which could include laws or policies directed toward companies organized in jurisdictions with low tax rates. A material change in the tax laws or policies, or their interpretation, of any country in which we have significant operations could result in a higher effective tax rate on our worldwide earnings. 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.”

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

We operate in various regions throughout the world that 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 a substantial extent against loss of capital assets, but generally not loss of revenue, from most of these risks through insurance, indemnity provisions in our drilling contracts, or both. The necessity of insurance coverage for risks associated with political unrest, expropriation and environmental remediation for operating areas not covered under our existing insurance policies is evaluated on an individual contract basis. Although we maintain insurance in the areas in which we operate, 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 financial position, results of operations or cash flows. 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, particularly in light of the instability and developments in the insurance markets following the terrorist attacks of September 11, 2001. As of February 28, 2007, all areas in which we were operating were covered by existing insurance policies.

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. 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.

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

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

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 (“SARS”), 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 financial position, results of operations or cash flows.

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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. In addition, we may be effectively prevented from enforcing these indemnities because of the nature of our relationship with some of our larger clients.

World political events could affect the markets for drilling services.

World political events have resulted in military action in Afghanistan and Iraq and terrorist attacks and related unrest. Military action by the U.S. or other nations could escalate and further acts of terrorism may occur in the U.S. or elsewhere. Such acts of terrorism could be directed against companies such as ours. Such developments have caused instability in the world's financial and insurance markets in the past. In addition, these developments could lead to increased volatility in prices for crude oil and natural gas and could affect the markets for drilling services. Insurance premiums have increased and could rise further 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.

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.

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 over 700 persons that allege personal injury arising out of asbestos exposure in the course of their employment by some of these defendants between 1965 and 1986. The complaints also name as defendants certain of TODCO's subsidiaries to whom we may owe indemnity. 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 yet been able to conduct extensive discovery nor determine the number of plaintiffs that were employed by our subsidiaries or otherwise have any connection with our drilling operations. We intend to defend ourselves vigorously and, based on the limited information available to us at this time, we do not expect the liability, if any, resulting from these matters to have a material adverse effect on our consolidated financial position, results of operations or cash flows.

In 1990 and 1991, two of our subsidiaries were served with various assessments collectively valued at approximately $10 million from the municipality of Rio de Janeiro, Brazil to collect a municipal tax on services. We believe that neither subsidiary is liable for the taxes and have contested the assessments in the Brazilian administrative and court systems. We have received several adverse rulings by various courts with respect to a June 1991 assessment, which is valued at approximately $9 million. We are continuing to challenge the assessment and filed a writ of mandamus to stay execution of a related tax foreclosure proceeding. The government is currently attempting to enforce the judgment on this assessment and the amount claimed is approximately $24 million, which exceeds the amount we believe is at issue. We received a favorable ruling in connection with a disputed August 1990 assessment, and the government has lost what is expected to be its final appeal with respect to that ruling. We also are awaiting a ruling from the Taxpayer's Council in connection with an October 1990 assessment. If our defenses are ultimately unsuccessful, we believe that the Brazilian government-controlled oil company, Petrobras, has a contractual obligation to reimburse us for municipal tax payments. We do not expect the liability, if any, resulting from these assessments to have a material adverse effect on our consolidated financial position, results of operations or cash flows.

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The Indian Customs Department, Mumbai alleged in July 1999 that the initial entry into India in 1988 and other subsequent movements of the Trident II jackup rig operated by the subsidiary constituted imports and exports for which proper customs procedures were not followed and sought payment of customs duties of approximately $31 million based on an alleged 1998 rig value of $49 million, plus interest and penalties, and confiscation of the rig. In January 2000, the Customs Department found that we had imported the rig improperly and intentionally concealed the import from the authorities, and directed us to pay certain other fees and penalties, in addition to the amount of customs duties owed. We appealed the Customs Department ruling and an appellate tribunal granted our request that the confiscation be stayed pending the appeal. The appellate tribunal also found that the rig was originally imported without proper documentation or payment of duties and sustained our valuation of the rig at the time of import as $13 million and ruled that subsequent movements of the rig were not liable to import documentation or duties, thus limiting our exposure as to custom duties to approximately $6 million. The Supreme Court of India has affirmed the appellate ruling but the Customs Department has not agreed with our interpretation of that order. We are contesting their interpretation. We and our customer agreed to pursue and obtained the issuance of the required importation documentation from the Ministry of Petroleum that, if accepted by the Customs Department, would reduce the duty to nil. The Customs Department did not accept the documentation or agree to refund the duties already paid. We are pursuing our remedies against the Customs Department and our customer. We do not expect the liability, if any, resulting from this matter to have a material adverse effect on our consolidated financial position, results of operations or cash flows.

One of our subsidiaries is involved in an action with respect to customs penalties 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 was moved to an entity that would become one of our subsidiaries. In early 2000, the drilling contract was extended for another year. On January 10, 2000, the temporary import permit granted to the Schlumberger entity expired, and renewal filings were not made until later that January. In April 2000, the Brazilian customs authorities cancelled the import permit. The Schlumberger entity filed an action in the Brazilian federal court of Campos for the purpose of extending the temporary admission. Other proceedings were also initiated in order to secure the transfer of the temporary admission to our subsidiary. Ultimately, the court permitted the transfer to our entity but has not ruled that the temporary admission could be extended without the payment of a financial penalty. During the first quarter of 2004, the customs office renewed its efforts to collect a penalty and issued a second assessment for this penalty but has now done so against our subsidiary. The assessment is for approximately $71 million. We believe that the amount of the assessment, even if it were appropriate, should only be approximately $7 million and should in any event be assessed against the Schlumberger entity. We and Schlumberger are contesting our respective assessments. We have put Schlumberger on notice that we consider any assessment to be the responsibility of Schlumberger. We do not expect the liability, if any, resulting from this matter to have a material adverse effect on our consolidated financial position, results of operations or cash flows.

We had a dispute with TODCO concerning payment to us under the tax sharing agreement that we entered into with TODCO for the tax benefit that TODCO derives from exercises of options to purchase our ordinary shares held by employees of TODCO. During the fourth quarter of 2006, an arbitration proceeding that was initiated in January 2006 concluded. We were seeking payment of the amount of tax benefits derived from exercises of options to purchase our ordinary shares by employees of TODCO who were not on the payroll of TODCO at the time of exercise and a declaration that TODCO pay us for the benefit derived from such exercises in the future. In November 2006, we reached a negotiated settlement with TODCO. As a result of the settlement, we entered into an amended and restated tax sharing agreement with TODCO. Under the terms of the amended and restated agreement, TODCO will pay us for 55 percent of the value of the tax deductions arising from the exercise of options to purchase our ordinary shares by current and former employees and directors of TODCO. This payment rate applies retroactively to amounts previously accrued by TODCO and to future payments. Under the terms of the amended and restated agreement, TODCO will also receive a $3 million federal tax benefit for use of certain state and foreign tax assets. The amended and restated agreement also provides that the change of control provision contained in the agreement no longer applies to option deductions. However, if TODCO uses the option deductions after a change of control, it would be required to pay us for 55 percent of the value of those deductions. As a result of the settlement, we recognized other income of $51 million, net of tax, in the fourth quarter of 2006 that had previously been deferred pending resolution of the dispute.

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In the third quarter of 2006, we received tax assessments of approximately $100 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 continue to review documents related to the assessments, and while our review is not complete, 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. 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 financial position, results of operations or cash flows.

We are involved in various tax matters as described in "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Outlook—Tax Matters." We are also involved in a number of other lawsuits, including a labor dispute involving Hull Blyth workers in Angola previously reported that is not material to us, 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 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.

ITEM 4.

Submission of Matters to a Vote of Security Holders

The Company did not submit any matter to a vote of its security holders during the fourth quarter of 2006.

Executive Officers of the Registrant

		Age as of
Officer	Office	February 28, 2007
Robert L. Long	Chief Executive Officer	61
Jean P. Cahuzac	President	53
Steven L. Newman	Executive Vice President and Chief Operating Officer	42
Eric B. Brown	Senior Vice President, General Counsel and Corporate Secretary	55
Gregory L. Cauthen	Senior Vice President and Chief Financial Officer	49
David J. Mullen	Senior Vice President, Marketing and Planning	49
David A. Tonnel	Vice President and Controller	37

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.

Jean P. Cahuzac is President of the Company. Mr. Cahuzac served as Executive Vice President and Chief Operating Officer of the Company from October 2002 to October 2006, at which time he assumed his current position. Mr. Cahuzac served as 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 and Chief Operating Officer of the Company. Mr. Newman served as Senior Vice President of Human Resources and Information Process Solutions from May 2006 to October 2006, at which time he assumed his current position. 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.

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

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

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.

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

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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

2005	First Quarter	$	51.97	$	39.79
	Second Quarter		58.19		43.16
	Third Quarter		63.11		53.52
	Fourth Quarter		70.93		52.34

2006	First Quarter	$	84.29	$	70.05
	Second Quarter		90.16		70.75
	Third Quarter		81.63		64.52
	Fourth Quarter		84.23		65.57

On February 23, 2007, the last reported sales price of our ordinary shares on the NYSE Composite Tape was $78.75 per share. On such date, there were 12,434 holders of record of our ordinary shares and 292,967,692 ordinary shares outstanding.

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 (i) depend on our results of operations, financial condition, cash requirements and other relevant factors, (ii) be subject to the discretion of the board of directors, (iii) be subject to restrictions contained in our revolving credit agreement and other debt covenants and (iv) be payable only out of our profits or share premium account in accordance with Cayman Islands law.

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

We are a Cayman Islands exempted company. Our authorized share capital is $13,000,000, divided into 800,000,000 ordinary shares, par value $0.01, and 50,000,000 preference shares, par value $0.10, of which shares may be designated and created as shares of any other classes or series of shares with the respective rights and restrictions determined by action of our board of directors. On February 28, 2007, 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 has 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.

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

Issuer Purchases of Equity Securities

Period	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 2006		3,482,442	$	71.81		3,482,313	$	1,000
November 2006		—		—		—		1,000
December 2006		1,375		80.72		—		1,000
Total		3,483,817	$	71.82		3,482,313	$	1,000

_________________

(1)

Total number of shares purchased in the fourth quarter of 2006 includes 1,504 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)

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ITEM 6.

Selected Financial Data

The selected financial data as of December 31, 2006 and 2005 and for each of the three years in the period ended December 31, 2006 has been derived from the audited consolidated financial statements included elsewhere herein. The selected financial data as of December 31, 2004, 2003 and 2002, and for the years ended December 31, 2003 and 2002 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.

	Years ended December 31,
	2006			2005			2004			2003			2002
	(In millions, except per share data)
Statement of Operations
Operating revenues	$	3,882		$	2,892		$	2,614		$	2,434		$	2,674
Operating income (loss)		1,641			720			328			240			(2,310	)

Income (loss) before cumulative effect of changes in accounting principles		1,385			716			152			18			(2,368	)
Cumulative effect of changes in accounting principles.		−			−			−			1			(1,364	)
Net income (loss)		1,385			716			152			19			(3,732	)
Basic earnings (loss) per share
Income (loss) before cumulative effect of changes in accounting principles per share	$	4.42		$	2.19		$	0.47		$	0.06		$	(7.42	)
Cumulative effect of changes in accounting principles		−			−			−			−			(4.27	)
Net income (loss)	$	4.42		$	2.19		$	0.47		$	0.06		$	(11.69	)
Diluted earnings (loss) per share
Income (loss) before cumulative effect of changes in accounting principles per share	$	4.28		$	2.13		$	0.47		$	0.06		$	(7.42	)
Cumulative effect of changes in accounting principles		−			−			−			−			(4.27	)
Net income (loss)	$	4.28		$	2.13		$	0.47		$	0.06		$	(11.69	)

Balance Sheet Data (at end of period)
Total assets	$	11,476		$	10,457		$	10,758		$	11,663		$	12,665
Long-term debt		3,200			1,197			2,462			3,612			3,630
Total shareholders’ equity		6,836			7,982			7,393			7,193			7,141
Dividends per share		−			−			−			−		$	0.06

Other Financial Data
Cash provided by operating activities	$	1,237		$	864		$	600		$	525		$	939
Cash provided by (used in) investing activities		(415	)		169			551			(445	)		(45	)
Cash used in financing activities		(800	)		(1,039	)		(1,174	)		(820	)		(533	)
Capital expenditures		876			182			127			494			141
Operating margin		42	%		25	%		13	%		10	%		N/M

_________________________

“N/M” means not meaningful due to loss on impairments of long-lived assets.

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ITEM 7.

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

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

Overview

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

	Years ended December 31,
	2006			2005			Change
	(In millions, except average daily revenue and percentages)
Average daily revenue (a)(b)	$	142,100		$	105,100		$	37,000
Utilization (b)(c)		84	%		79	%		N/A
Statement of Operations
Operating revenue	$	3,882		$	2,892		$	990
Operating and maintenance expense		2,155			1,720			435
Operating income		1,641			720			921
Net income		1,385			716			669
Balance Sheet Data (at end of period)
Cash and Cash Equivalents		467			445			22
Total Assets		11,476			10,457			1,019
Total Debt		3,295			1,597			1,698

______________________

“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 for all of our asset classes, 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 for 2007 and beyond.

Our revenues for the year ended December 31, 2006 increased from the prior year period as a result of increased activity and higher dayrates. Our operating and maintenance expenses for the year increased primarily as a result of higher labor and rig maintenance costs in connection with such increased activity as well as inflationary cost increases (see “—Outlook”). In addition, our financial results for the year ended December 31, 2006 included the recognition of gains from the sales of eight rigs and other income recognized under the TODCO tax sharing agreement. Total debt increased from the end of the prior year period as a result of our issuance of the Floating Rate Notes and borrowings under the Term Credit Facility. See “—Liquidity and Capital Resources-Sources and Uses of Liquidity.”

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We operate in one business segment which 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.

Significant Events

Contract Backlog—We have been successful in building contract backlog in 2006 within all of our asset classes. Our contract backlog at December 31, 2006 was approximately $20.2 billion, an 85 percent increase compared to our contract backlog at December 31, 2005. See “—Outlook−Drilling Market” and “—Performance and Other Key Indicators.”

Construction and Upgrade Programs—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. See “—Outlook−Drilling Market.”

During 2005, we entered into agreements with clients to upgrade two of our Sedco 700-series semisubmersible rigs in our Other 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 have a water depth drilling capacity of up to 6,000 to 6,500 feet. The Sedco 702 entered the shipyard for the upgrade in early 2006. We expect the upgrade to be completed in approximately the fourth quarter of 2007. The Sedco 706 upgrade is scheduled to commence in the third quarter of 2007. We expect the upgrade to be completed in approximately the fourth quarter of 2008.

Hurricane Damage—In the third quarter of 2005, two of our semisubmersible rigs, the Deepwater Nautilus and the Transocean Marianas, sustained damage during hurricanes Katrina and Rita. During hurricane Katrina, the Deepwater Nautilus sustained damage to its mooring system and lost approximately 3,200 feet of marine riser and a portion of its subsea well control system. The rig was undergoing repairs during hurricane Rita and was set adrift following the failure of a tow line utilized by a towing vessel. Also during hurricane Rita, the Transocean Marianas sustained damage to its mooring system, was forced off its drilling location and was grounded in shallow water. The Deepwater Nautilus was out of service for 24 days in 2005 and 70 days in 2006. The Transocean Marianas was out of service for 95 days in 2005 and 72 days in 2006. Both rigs returned to service in the third quarter of 2006. Operating income in 2006 was negatively impacted by approximately $50 million due to lost revenue and higher operating and maintenance costs on the Deepwater Nautilus and the Transocean Marianas. In addition, we spent approximately $25 million on capital expenditures in 2006 to replace damaged equipment.

Asset Dispositions—During 2006, we sold three of our Other 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. See “—Liquidity and Capital Resources-Capital Expenditures and Dispositions.”

In January 2007, we completed the sale of our membership interest in Transocean CGR LLC (owner of the tender rig Charley Graves) for net proceeds of $33 million and we expect to recognize a gain on the sale of $23 million in the first quarter of 2007.

Term Credit Facility—In August 2006, we entered into a two-year, $1.0 billion term credit facility under the Term Credit Agreement dated August 30, 2006 (“Term Credit Facility”). See “—Liquidity and Capital Resources-Sources and Uses of Cash.”

Floating Rate Notes—In September 2006, we issued $1.0 billion aggregate principal amount of floating rate notes, due September 2008 (“Floating Rate Notes”). See “—Liquidity and Capital Resources-Sources and Uses of Liquidity.”

Repurchase of Ordinary Shares—During 2006, we repurchased and retired 35.7 million of our ordinary shares at a total cost of $2.6 billion. See “—Liquidity and Capital Resources-Sources and Uses of Liquidity.”

In 2007, we repurchased approximately 5.2 million of our ordinary shares at a total cost of approximately $400 million. See “—Liquidity and Capital Resources-Sources and Uses of Liquidity.”

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Tax Matters—In April 2006, we received notice from the Norwegian tax authorities regarding their intent to propose adjustments to taxable income for the tax years 1999, 2001 and 2002. These proposed assessments could result in an increase in tax of approximately $260 million plus interest, and the authorities further indicated they intend to impose penalties, which could range from 15 to 60 percent of the assessments. The anticipated assessments relate to restructuring transactions undertaken in 2001 and 2002. See “—Outlook−Tax Matters.”

TODCO Settlement—In November 2006, we reached a negotiated settlement with TODCO, our former subsidiary, arising out of the tax sharing agreement that we entered into with TODCO in connection with TODCO’s initial public offering in 2004. As a result of the settlement, we entered into an amended and restated tax sharing agreement with TODCO. Under the terms of the amended and restated agreement, TODCO will pay us for 55 percent of the value of the tax deductions arising from the exercise of options to purchase our ordinary shares by current and former employees and directors of TODCO. This payment rate applies retroactively to amounts previously accrued by TODCO and to future payments. Under the terms of the amended and restated agreement, TODCO will also receive a $3 million federal tax benefit for use of certain state and foreign tax assets. The amended and restated agreement also provides that the change of control provision contained in the agreement no longer applies to option deductions. However, if TODCO uses the option deductions after a change of control, it would be required to pay us for 55 percent of the value of those deductions. As a result of the settlement, we recognized income of $51 million, net of tax, in the fourth quarter of 2006 that had previously been deferred pending resolution of the dispute.

Outlook

Drilling Market—Demand for offshore drilling capacity continues to outpace supply. Our High-Specification Floater fleet is fully committed in 2007 and has very little time available in 2008. We have only four rigs remaining in our Other Floater fleet that have any available uncommitted time left in 2007 and only seven rigs remaining in this fleet that have any available uncommitted time left in 2008. We have four jackup rigs that have uncommitted time left in 2007, but 19 rigs (68 percent of our Jackup fleet) have uncommitted time left in 2008. Dayrates for new contracts for both floaters and jackups continue to be strong. Our contract backlog at January 31, 2007 was approximately $20.8 billion, up from approximately $20.2 billion at October 31, 2006.

During 2006, we were awarded drilling contracts with durations ranging from three to five years for three newbuild deepwater rigs, and we continue to pursue other potential newbuild opportunities with multi-year contract durations. In March 2006, we were awarded a five-year drilling contract for an enhanced Enterprise-class drillship, to be named the Discoverer Clear Leader. We estimate total capital expenditure for the construction of this rig to be approximately $630 million, excluding capitalized interest, but including approximately $30 million for additional equipment requested by the client for which the client has agreed to an increased dayrate. We currently expect this rig to begin operations in the U.S. Gulf of Mexico in the second quarter of 2009, after construction in South Korea followed by sea trials, mobilization to the U.S. Gulf of Mexico and customer acceptance.

In June 2006, we were awarded a four-year drilling contract for another enhanced Enterprise-class drillship. We estimate total capital expenditure for the construction of this rig to be approximately $630 million, excluding capitalized interest, but including approximately $11 million for additional equipment requested by the client for which the client has agreed to an increased dayrate. We currently expect this rig to begin operations in the U.S. Gulf of Mexico in mid-2009, after construction in South Korea followed by sea trials, mobilization to the U.S. Gulf of Mexico and customer acceptance.

In August 2006, we were awarded a drilling contract for a third enhanced Enterprise-class drillship, to be named the Discoverer Inspiration. We estimate total capital expenditure for the construction of this rig to be approximately $670 million, excluding capitalized interest, but including approximately $40 million for equipment that was not included in the original costs of the other two enhanced Enterprise-class drillships. The client may elect by September 2007 to shorten the term of the contract from five years to three years. We currently expect this rig to begin operations in the U.S. Gulf of Mexico in the first quarter of 2010, after construction in South Korea followed by sea trials, mobilization to the U.S. Gulf of Mexico and customer acceptance.

We have been successful in building contract backlog within our High-Specification Floaters fleet with 25 of our 37 current and future High-Specification Floaters, including the three newbuilds and the two Sedco 700-series rig upgrades, contracted into or beyond 2010 as of February 2, 2007. These 25 units also include 9 of our 13 current Fifth-Generation Deepwater Floaters. Our total contract backlog of approximately $20.8 billion as of January 31, 2007 includes an estimated $14.9 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 2006 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 the drilling of the first well in the ultra deepwaters of the Orphan Basin in Canada. These events, coupled with continued exploration success in the deepwaters of West Africa, the opening of additional deepwater acreage in the U.S. Gulf of Mexico and the announced plans of Pemex for its first tender for ultra deepwater drilling in Mexican waters support our optimistic outlook for the deepwater drilling market sector. As of February 2, 2007, none of our High-Specification Floater fleet contract days are uncommitted for the remainder of 2007, while approximately three percent, 17 percent and 55 percent are uncommitted in 2008, 2009 and 2010, respectively.

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Our Other Floaters fleet, comprised of 19 semisubmersible rigs, excluding the Sedco 706, is largely committed to contracts that extend through 2007, and we continue to see customer demand for multi-year contracts for these units. We completed the reactivations of the previously idle Transocean Winner and Transocean Prospect in August 2006 and September 2006, respectively, both of which are supported by multi-year contracts. We also 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. The sale of the Transocean Explorer was completed in the second quarter of 2006, and the sale of the Transocean Wildcat was completed in the fourth quarter of 2006. As of February 2, 2007, nine percent of our Other Floater fleet contract days are uncommitted for the remainder of 2007, while approximately 35 percent, 69 percent and 85 percent are uncommitted in 2008, 2009 and 2010, respectively.

Our outlook for activity for the Jackup market sector also remains strong. We were recently awarded a three year contract for the Trident 17 at a dayrate of $185,000. We expect to remain at or near full utilization for our Jackup fleet in 2007. We believe that Asia, India, the Middle East and West Africa will remain sources of strong demand for jackup rigs in the near to intermediate term. As of February 2, 2007, five percent of our Jackup fleet contract days are uncommitted for the remainder of 2007, while approximately 36 percent, 64 percent and 87 percent are uncommitted in 2008, 2009 and 2010, respectively.

The aggregate amount of out-of-service time we incur in 2007 is expected to decrease substantially compared to the amount we incurred in 2006, primarily because we completed the reactivations of the Transocean Winner and Transocean Prospect in the third quarter of 2006 and the C. Kirk Rhein, Jr. in February 2007. However, the reduction in out-of-service time resulting from the completed reactivations is expected to be at least partially offset by an increase in out-of-service time that we expect to incur in connection with the continued upgrades of the Sedco 702 and Sedco 706 to deepwater capabilities. Excluding reactivations and upgrades, we expect the amount of out-of-service time we incur in 2007 because of shipyard and mobilization will be generally in line with the amount of out-of-service time we incurred in 2006 because of shipyard and mobilization.

We expect our revenues to continue to increase in 2007 due largely to commencement of new contracts with higher dayrates. The reactivation of the C. Kirk Rhein, Jr. and the scheduled commencement of the Sedco 702 contract at the end of the rig’s deepwater upgrade shipyard project are also expected to increase our revenues in 2007. We also expect the anticipated commencement of six integrated services contracts in the early part of 2007 to increase our integrated services revenue for 2007.

We expect industry inflation in 2007 to continue to increase our operating and maintenance costs including our shipyard and major maintenance program expenditures. We expect our operating and maintenance costs in 2007 to further increase as a result of the six integrated services contracts discussed above. These increases are expected to be at least partially offset by lower shipyard and mobilization expenses, as we expect our 2007 out-of-service time to decrease by approximately 15 percent compared to 2006, chiefly due to the completed reactivations of the Transocean Prospect, Transocean Winner and C. Kirk Rhein, Jr. Finally, we plan to invest in a number of recruitment, retention and personnel development initiatives in connection with the manning of the crews of the two deepwater upgrades and three 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 2007, which would preclude us from taking full advantage of any increased market rates for rigs subject to these contract options. We have five 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.

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Insurance Matters—We renewed our insurance coverages for 12 months effective May 1, 2006. We currently maintain a $10 million per occurrence insurance deductible on hull and machinery, a $10 million per occurrence deductible on personal injury liability and a $5 million per occurrence deductible on third party property damage. In addition to the per occurrence deductibles described above, we also have aggregate deductibles that are applied to any occurrence in excess of the per occurrence deductible until the aggregate deductible is exhausted. Such aggregate deductibles are $20 million in the case of our hull and machinery coverage and $25 million in the case of our personal injury liability and third party property damage coverage. Additionally, for our personal injury and third-party damage liabilities, we have retained $20 million of the risk that exceeds our deductible amount. Our coverage includes an annual aggregate limit on losses due to hurricanes in the U.S Gulf of Mexico of $250 million, except in the case of a total loss of a rig, where the annual limit is approximately $300 million in aggregate. At present, the insured value of our drilling rig fleet is $13.0 billion in aggregate. We also carry $930 million of third-party liability coverage inclusive of the personal injury liability and third party property liability deductibles and retention amounts described above. We do not carry insurance for loss of revenue. As a result of these limits, we retain the risk through self-insurance for any losses in excess of these amounts. Most of our insurance programs are up for renewal in the second quarter of 2007. We could decide to retain substantially more risk through self-insurance.

Tax Matters—We are a Cayman Islands company. We operate through our various subsidiaries in a number of countries throughout the world. Consequently, we are subject to changes in tax laws, treaties and regulations in and between the countries in which we operate. A material change in these 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.

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 probable exposures.

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. 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 approximately $30 million.

Our 2004 and 2005 U.S. federal income tax returns are currently under examination by the IRS. We believe our returns are materially correct as filed, and we intend to vigorously defend against any proposed changes. While we cannot predict or provide assurance as to the final outcome, we do not expect the ultimate settlement of any liability resulting from any examination to have a material adverse effect on our consolidated financial position, results of operations or cash flows.

In April 2006, we received notice from the Norwegian tax authorities regarding their intent to propose adjustments to taxable income for the tax years 1999, 2001 and 2002. These proposed assessments could result in an increase in tax of approximately $260 million, plus interest and the authorities further indicated they intend to impose penalties, which could range from 15 to 60 percent of the assessments. The anticipated assessments relate to restructuring transactions undertaken in 2001 and 2002. The Norwegian tax authorities initiated inquiries in September 2004 related to the restructuring transactions and a separate dividend payment made during 2001. In February 2005, we filed a response to these inquiries. In March 2005, pursuant to court orders, the Norwegian tax authorities took action to obtain additional information regarding these transactions. We have continued to respond to information requests from the Norwegian authorities and filed a formal protest to the proposed assessment in June 2006. We also believe the Norwegian authorities are contemplating a tax assessment of approximately $104 million on the dividend, plus interest and a penalty, which could range from 15 to 60 percent of the assessment. Norwegian civil tax and criminal authorities continue to investigate the restructuring transactions and dividend. We plan to vigorously contest any assertions by the Norwegian authorities in connection with the restructuring transactions or dividend. 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 financial position, results of operations or cash flows.

In addition, other tax authorities are examining our tax returns in various jurisdictions. While we cannot predict or provide assurance as to the final outcome of these other existing or future assessments, we do not expect the ultimate settlement of any liability resulting from these existing or future assessments to have a material adverse effect on our consolidated financial position, results of operations or cash flows.

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GlobalSantaFe Patent Infringement—In February 2007, we reached an agreement with a competitor, GlobalSantaFe Corporation (“GlobalSantaFe”), relating to their infringement of our offshore dual activity drilling technology patents. We had commenced a patent infringement action in U.S. federal court against GlobalSantaFe, and in August 2006, the jury found in our favor. Through the court action, the validity and enforceability of the dual activity patents were upheld and we were awarded royalty damages and granted a permanent injunction against further infringement by GlobalSantaFe. GlobalSantaFe had two infringing drilling rigs operating in the Gulf of Mexico, the semisubmersible rigs Development Driller I and Development Driller II.

The agreement now reached with GlobalSantaFe will permit them to utilize our dual activity drilling technology on those two rigs currently working in the Gulf of Mexico and also on their Development Driller III rig after delivery from the shipyard in Singapore. In exchange for this right, GlobalSantaFe has agreed to discontinue any further proceedings disputing our dual activity patents and has agreed to pay $4 million for each of these three rigs as a building fee and approximately $3 million in royalties in aggregate for use to date by its two operating rigs, for a combined payment of approximately $15 million. GlobalSantaFe has further agreed to pay a license fee going forward of three percent of revenues received on the three Development Driller rigs when operating in an area where we have dual activity patent rights and five percent of revenues on any other rigs which GlobalSantaFe may acquire which incorporate the dual activity technology when operating in an area where we have patent rights. We have not granted any rights to build any additional rigs incorporating the dual activity technology and any such construction would be subject to further negotiation or litigation.

Performance and Other Key Indicators

Contract Backlog—The following table reflects our contract backlog and associated average contractual dayrates at the periods ended December 31, 2006 and 2005 and reflects firm commitments only, typically represented by signed drilling contracts. Backlog is indicative of the full contractual dayrate. 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, other 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. Our contract backlog is calculated by multiplying the contracted operating dayrate by the number of days remaining in the firm contract period, excluding revenues for mobilization, demobilization and contract preparation and such amounts are not expected to be significant to our contract drilling revenues. 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 after commencement of operations and over the firm contract period.

	December 31, 2006		December 31, 2005
	(In millions)
Contract Backlog
High-Specification Floaters	$	14,354	$	8,330
Other Floaters		3,770		1,643
Jackups		2,037		808
Other Rigs		65		132
Total	$	20,226	$	10,913

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The following table reflects the amount and the average dayrate of our contract backlog by year as of December 31, 2006.

	For the years ending December 31,
	Total		2007		2008		2009		2010		Thereafter
	(In millions, except average dayrates)
Contract Backlog
High-Specification Floaters	$	14,354	$	2,880	$	3,560	$	3,348	$	2,359	$	2,207
Other Floaters		3,770		1,439		1,259		616		285		171
Jackups		2,037		874		636		395		109		23
Other Rigs		65		27		24		14		-		-
Total	$	20,226	$	5,220	$	5,479	$	4,373	$	2,753	$	2,401

Average Dayrates	Total		2007		2008		2009		2010		Thereafter
High-Specification Floaters	$	348,000	$	272,000	$	336,000	$	369,000	$	398,000	$	439,000
Other Floaters	$	274,000	$	239,000	$	294,000	$	297,000	$	303,000	$	390,000
Jackups	$	122,000	$	112,000	$	131,000	$	137,000	$	127,000	$	100,000
Other Rigs	$	35,000	$	35,000	$	34,000	$	35,000		-		-
Total	$	275,000	$	207,000	$	268,000	$	303,000	$	356,000	$	422,000

Fleet Utilization and Average Daily Revenue—The following table shows our average daily revenue and utilization for each of the three months ended December 31, 2006, September 30, 2006 and December 31, 2005. Average daily revenue is defined as contract drilling revenue earned per revenue earning day in the period. A revenue earning day is defined as a day for which a rig earns dayrate after commencement of operations. Utilization in the table below is defined as the total actual number of revenue earning days in the period as a percentage of the total number of calendar days in the period for all drilling rigs in our fleet.

	Three months ended
	December 31, 2006			September 30, 2006			December 31, 2005
Average Daily Revenue
High-Specification Floaters
Fifth-Generation Deepwater Floaters	$	275,300		$	246,000		$	215,800
Other Deepwater Floaters	$	230,400		$	222,300		$	138,800
Other High-Specification Floaters	$	187,400		$	181,500		$	161,700
Total High-Specification Floaters	$	243,600		$	226,700		$	174,100
Other Floaters	$	178,400		$	136,800		$	98,500
Jackups	$	97,000		$	83,400		$	64,900
Other Rigs	$	48,200		$	52,400		$	48,500
Total Drilling Fleet	$	171,700		$	146,900		$	113,300

Utilization
High-Specification Floaters
Fifth-Generation Deepwater Floaters		92	%		88	%		86	%
Other Deepwater Floaters		78	%		75	%		79	%
Other High-Specification Floaters		97	%		93	%		100	%
Total High-Specification Floaters		86	%		82	%		84	%
Other Floaters		90	%		86	%		71	%
Jackups		89	%		96	%		89	%
Other Rigs		99	%		76	%		49	%
Total Drilling Fleet		89	%		87	%		78	%

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Liquidity and Capital Resources

Sources and Uses of Cash

Our primary sources of cash in 2006 were our cash flows from operations, proceeds from asset sales, proceeds from the issuance of the Floating Rate Notes, borrowings under our 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 repurchases of our ordinary shares, capital expenditures and repayments of borrowings under our credit facilities. At December 31, 2006, we had $467 million in cash and cash equivalents.

	Years ended December 31,
	2006			2005			Change
	(In millions)
Net Cash from Operating Activities
Net income	$	1,385		$	716		$	669
Depreciation		401			406			(5	)
Other non-cash items		(462	)		(122	)		(340	)
Working capital		(87	)		(136	)		49
	$	1,237		$	864		$	373

Net cash provided by operating activities increased by $373 million due to more cash generated from net income ($324 million) and less cash used for working capital items ($49 million).

	Years ended December 31,
	2006			2005			Change
	(In millions)
Net Cash from Investing Activities
Capital expenditures	$	(876	)	$	(182	)	$	(694	)
Proceeds from disposal of assets, net		461			74			387
Proceeds from TODCO stock sales, net		-			272			(272	)
Joint ventures and other investments, net		-			5			(5	)
	$	(415	)	$	169		$	(584	)

Net cash used by investing activities increased by $584 million over the previous year. The increase is primarily due to higher capital expenditures related to the construction of three enhanced Enterprise-class drillships, the two Sedco 700-series deepwater upgrades and other equipment replaced and upgraded on our existing rigs. The increase in capital expenditures was partially offset by higher proceeds from disposal of assets of $387 million. In addition, in 2005 we received proceeds from TODCO stock sales of $272 million, with no comparable activity for the corresponding period in 2006.

	Years ended December 31,
	2006			2005			Change
	(In millions)
Net Cash from Financing Activities
Proceeds from issuance of debt and borrowings under the Term Credit Facility	$	2,000		$	−		$	2,000
Repayments of debt		(300	)		(880	)		580
Repurchases of ordinary shares		(2,601	)		(400	)		(2,201	)
Net proceeds from issuance of ordinary shares under share-based compensation plans		69			219			(150	)
Proceeds from issuance of ordinary shares upon exercise of warrants		-			11			(11	)
Release of escrow funds - Nautilus lease financing		30			−			30
Decrease in cash dedicated to debt service		-			12			(12	)
Tax benefit from issuance of ordinary shares under share-based compensation plans		7			−			7
Other, net		(5	)		(1	)		(4	)
	$	(800	)	$	(1,039	)	$	239

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Net cash used in financing activities decreased by $239 million in 2006 compared to 2005. In 2006, we received proceeds of $2.0 billion from the issuance of our Floating Rate Notes and borrowings under on our Term Credit Facility, with no comparable activity in 2005. In addition, we used less cash to repay debt in 2006 as compared to 2005. Partially offsetting these decreases, we used more cash to repurchase our ordinary shares under our share repurchase program in 2006 than in 2005, and we received less cash from the issuance of our ordinary shares under our share-based compensation program.

Capital Expenditures and Dispositions

From time to time, we 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 if generally supported by firm contracts. 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. We have been awarded drilling contracts for three newbuild deepwater drilling rigs and are currently in discussions with various clients for potential other deepwater drilling contracts related to new deepwater drilling rigs. In addition, from time to time, we review possible dispositions of drilling units.

Capital Expenditures—Capital expenditures, including capitalized interest of $16 million, totaled $876 million during the year ended December 31, 2006, which included approximately $220 million on the construction of the drillship Discoverer Clear Leader, approximately $110 million on the construction of the second deepwater drillship, approximately $130 million on the construction of the drillship Discoverer Inspiration, approximately $150 million for the upgrade of two of our Sedco 700-series rigs, approximately $25 million to replace and upgrade equipment damaged during hurricanes Katrina and Rita on the Deepwater Nautilus and the Transocean Marianas and approximately $40 million to reactivate three of our Other Floaters.

During 2007, we expect capital expenditures to be approximately $1.4 billion, including approximately $800 million for the construction of the three deepwater drillships and approximately $300 million for the continued upgrade of two of our Sedco 700-series rigs. The level of our capital expenditures is partly dependent upon the actual level of operational and contracting activity. These expected capital expenditures do not include amounts that would be incurred as a result of any of the 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.”

We intend to fund the cash requirements relating to our capital expenditures through available cash balances, cash generated from operations and asset sales. We also have available credit under our Revolving Credit Facility (see “—Sources and Uses of Liquidity”) and may utilize other commercial bank or capital market financings.

Dispositions—During 2006, we sold three of our Other 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.

In January 2007, we completed the sale of our membership interest in Transocean CGR LLC (owner of the tender rig Charley Graves) for net proceeds of $33 million and expect to recognize a gain on the sale of $23 million in the first quarter of 2007.

Sources and Uses of Liquidity

We expect to use existing cash balances, internally generated 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.

When cash on hand, cash flows from operations and proceeds from asset sales exceed our expected liquidity needs, including major upgrades, new rig construction and/or drilling rig acquisitions, we may use a portion of such cash to repurchase our ordinary shares. We may also use our Revolving Credit Facility or proceeds from the issuance of new debt to repurchase our ordinary shares. We will continue to consider allowing our cash balances to increase and will continue to consider the reduction of debt prior to scheduled maturities.

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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.

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 from $2.0 billion, which was previously authorized and announced in October 2005, to $4.0 billion. 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 Revolving Credit Facility and our Term Credit Facility and proceeds from the issuance of our Floating Rate Notes. In 2007, we repurchased approximately $400 million of our ordinary shares, which amounted to approximately 5.2 million ordinary shares. At February 28, 2007, after prior repurchases, we had authority to repurchase an additional $600 million of our ordinary shares under the program.

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 is cancelled. Once repaid, the funds cannot be reborrowed. At our election, borrowings may be made under the Term Credit Facility at either (i) the base rate, determined as the greater of (a) the prime loan rate and (b) the sum of the weighted average overnight federal funds rate plus 0.50 percent, or (ii) the London Interbank Offered Rate (“LIBOR”) plus 0.30 percent, based on current credit ratings. We paid a fee of 0.065 percent per annum on the daily amount of the unused commitments under the Term Credit Facility through October 3, 2006. In October 2006, we borrowed the full $1.0 billion in capacity. We subsequently repaid $300 million in December 2006. At February 28, 2007, $700 million was outstanding under this facility at a weighted-average interest rate of 5.65 percent.

In September 2006, we issued $1.0 billion aggregate principal amount of the 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 February 28, 2007, $1.0 billion principal amount of these notes was outstanding at an interest rate of 5.57 percent.

We have access to a bank line of credit under a $1.0 billion, five-year revolving credit agreement expiring July 2011 (“Revolving Credit Facility”). At February 28, 2007, $110 million was outstanding under this facility.

The Revolving Credit Facility and Term 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. Other provisions of the credit agreements 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 April 2001, the Securities and Exchange Commission (“SEC”) declared effective our shelf registration statement on Form S-3 for the proposed offering from time to time of up to $2.0 billion in gross proceeds of senior or subordinated debt securities, preference shares, ordinary shares and warrants to purchase debt securities, preference shares, ordinary shares or other securities. At February 28, 2007, $600 million in gross proceeds of securities remained unissued under the shelf registration statement.

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

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

	For the years ending December 31,
	Total		2007		2008-2009		2010-2011		Thereafter
Contractual Obligations
Debt	$	3,288	$	100	$	1,719	$	565	$	904
Operating Leases		76		22		21		11		22
Purchase Obligations		1,551		619		926		6		-
Defined Benefit Pension Plans		7		7		-		-		-
Total Obligations	$	4,922	$	748	$	2,666	$	582	$	926

Bondholders may, at their option, require us to repurchase the 7.45% Notes due 2027, the Zero Coupon Convertible Debentures due 2020 and the 1.5% Convertible Debentures due 2021 in April 2007, May 2008 and May 2011, respectively. With regard to both series of the Convertible Debentures, we have the option to pay the repurchase price in cash, ordinary shares or any combination of cash and ordinary shares. The chart above assumes that the holders of these convertible debentures and notes exercise the options at the first available date. We are also required to repurchase the convertible debentures at the option of the holders at other later dates.

We may elect to call the Zero Coupon Convertible Debentures due 2020 or the 1.5% Convertible Debentures due 2021 for redemption at any time. If we call the 1.5% Convertible Debentures for redemption or if other specified conditions are met, the holders will have the right to convert the debentures into our ordinary shares. The holders of the Zero Coupon Convertible Debentures may convert the debentures into our ordinary shares at any time.

We have an obligation to make contributions in 2007 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, 2006, we had other commitments that we are contractually obligated to fulfill with cash should the obligations be called. These obligations include standby letters of credit and surety bonds that guarantee our performance as it relates to our drilling contracts, insurance, customs, tax and other obligations in various jurisdictions. Letters of credit are issued under a number of facilities provided by several banks. The obligations that are the subject of these surety bonds and letters of credit are geographically concentrated in Nigeria and India. These letters of credit and surety bond obligations are not normally called as we typically comply with the underlying performance requirement. The 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		2007		2008-2009		2010-2011		Thereafter
	(In millions)
Other Commercial Commitments
Standby Letters of Credit	$	405	$	299	$	49	$	57	$	-
Surety Bonds		6		6		-		-		-
Total	$	411	$	305	$	49	$	57	$	-

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, 2006, we had no outstanding foreign exchange derivative instruments.

In June 2001, we entered into interest rate swaps of $700 million aggregate notional amount as a fair value hedge against our 6.625% Notes due April 2011. The swaps effectively converted the fixed interest rate on the note into a floating rate. The market value of the swaps was carried as an asset or a liability in our consolidated balance sheet and the carrying value of the hedged debt was adjusted accordingly.

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In 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 long-term debt in our consolidated balance sheet. We amortize this amount as a reduction to interest expense over the life of the underlying debt. During the year ended December 31, 2006, such reduction amounted to $3 million. The remaining balance to be amortized at December 31, 2006 of $15 million relates to the 6.625% Notes due April 2011.

Results of Operations

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 Other 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.

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Index

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 Corporation.

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.

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 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 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 in 2006, resulting in a tax rate of 13.8 percent on earnings before income taxes and minority interest. The impact of the various discrete items was a net benefit of $14 million in 2005, resulting in a 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.

Historical 2005 compared to 2004

Through December 16, 2004, our operations were aggregated into two reportable segments: (i) Transocean Drilling and (ii) TODCO. The Transocean Drilling segment consists of floaters, jackups and other rigs used in support of offshore drilling activities and offshore support services on a worldwide basis. The TODCO segment consisted of our interest in TODCO, which conducts jackup, drilling barge, land rig, submersible and other operations in the U.S. Gulf of Mexico and inland waters, Mexico, Trinidad and Venezuela. The organization and aggregation of our business into the two segments were based on differences in economic characteristics, customer base, asset class, contract structure and management structure. In addition, the TODCO segment fleet was highly dependent upon the U.S. natural gas industry while the Transocean Drilling segment’s operations are more dependent upon the worldwide oil industry. As a result of the deconsolidation of TODCO, we now operate in one business segment, the Transocean Drilling segment.

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Index

Transocean Drilling Segment

	Years ended
	December 31,
	2005			2004			Change			% Change
	(In millions, except day amounts and percentages)

Revenue earning days		26,224			23,427			2,797			12	%
Utilization		79	%		68	%		N/A			11	%
Average daily revenue	$	105,100		$	91,100		$	14,000			15	%

Contract drilling revenues	$	2,757		$	2,134		$	623			29	%
Other revenues		135			146			(11	)		(8	)%
		2,892			2,280			612			27	%
Operating and maintenance expense		(1,720	)		(1,433	)		(287	)		20	%
Depreciation		(406	)		(432	)		26			(6	)%
Gain from disposal of assets, net		29			13			16			N/M
Operating income before general and administrative expense	$	795		$	428		$	367			86	%

_________________

“N/A” means not applicable

“N/M” means not meaningful

The $623 million increase in contract drilling revenues was primarily related to increased activity and utilization combined with lower revenues in 2004 of approximately $38 million resulting from the labor strike in Norway, a fire on the Trident 20 and the Jim Cunningham well control incident with no comparable incidents in 2005. Partially offsetting these increases was a decrease in revenue of approximately $14 million resulting from the 2004 favorable settlement of the 2003 Discoverer Enterprise riser separation incident with no comparable activity in 2005. Contract drilling revenues were also negatively impacted in 2005 by approximately $21 million due to lost revenue on the Transocean Marianas and the Deepwater Nautilus as a result of the rigs undergoing repairs due to damages sustained during hurricanes Katrina and Rita.

Other revenues for the year ended December 31, 2005 decreased $11 million due to a $23 million decrease in integrated services revenue, partially offset by an $11 million increase in client reimbursable revenue and compensation received in 2005 relating to the 2004 labor strike in Norway of $5 million.

Operating and maintenance expenses increased by $287 million primarily from increased activity, pay increases to employees and vendor price increases resulting in higher labor and rig maintenance costs. Operating and maintenance expenses also increased by $39 million as a result of the favorable settlement in 2004 of an insurance claim and a turnkey dispute with no comparable activity in 2005, increased costs in 2005 on the Transocean Marianas and the Deepwater Nautilus to repair damages sustained during hurricanes Katrina and Rita and increased local personnel taxes in 2005 related to stock option exercises and restricted shares vestings with no comparable activity in 2004. Partially offsetting these increases were expenses of $35 million incurred related to a fire on the Trident 20 in 2004 with no comparable activity in 2005, a favorable settlement of a vendor dispute and lower property damage, personal injury and medical/dental insurance claim expenses in 2005.

The decrease in depreciation expense was due primarily to extending the useful lives to 35 years in the fourth quarter of 2004 for four rigs with original useful lives ranging from 30 to 32 years and the reduction in depreciation on two rigs and certain other equipment that were substantially depreciated during 2004.

During 2005, we recognized net gains of $29 million related to the sale of the semisubmersible rig Sedco 600, the jackup rig Transocean Jupiter, a land rig and the sales and disposal of other assets. During 2004, we recognized net gains of $13 million related to the sale of the semisubmersible rig Sedco 602 and the sales and disposal of other assets.

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Index

Total Company Results of Operations

	Years ended
	December 31,
	2005			2004			Change			% Change
	(In millions, except percentages)

General and Administrative Expense	$	75		$	67		$	8			12	%
Other (Income) Expense, net
Interest income		(19	)		(9	)		(10	)		N/M
Interest expense		111			172			(61	)		35	%
Gain from TODCO stock sales		(165	)		(309	)		144			(47	)%
Non-cash TODCO tax sharing agreement charge		-			167			(167	)		N/M
Loss on retirement of debt		7			76			(69	)		91	%
Other, net		(17	)		(9	)		(8	)		89	%
Income Tax Expense		87			91			(4	)		4	%
Minority Interest		-			(3	)		3			N/M

_________________________

“N/M” means not meaningful

The increase in general and administrative expense was primarily attributable to increases of approximately $6 million in accounting, legal and professional fees as well as $4 million in increased personnel cost, rent expense, computer equipment and pension and other post-employment retirement plan expense, partially offset by decreased stock compensation expense of $3 million.

The increase in interest income was primarily due to an increase in average cash balances for 2005 compared to 2004 and an increase in interest rates on cash investments, the combination of which resulted in an increase in interest income of $8 million.

Approximately $56 million of the decrease in interest expense was attributable to debt that was redeemed, retired or repurchased during or subsequent to 2004. An additional decrease of approximately $4 million related to interest expense in 2004 on TODCO’s debt as a result of the TODCO deconsolidation in December 2004.

Gains from TODCO stock sales decreased $144 million during 2005 compared to 2004.

During 2004, we recognized a $167 million non-cash charge related to contingent amounts due from TODCO under a tax sharing agreement between us and TODCO.

During 2005, we recognized losses of $7 million related to the early redemption and repurchase of $782 million aggregate principal amount of our debt. During 2004, we recognized losses of $76 million related to the early retirements of $775 million aggregate principal amount of our debt.

The $8 million favorable change in other, net primarily relates to $11 million of income recognized under the tax sharing agreement with TODCO, partially offset by the effect of foreign currency exchange rate changes on our monetary assets and liabilities denominated in currencies other than the U.S. dollar.

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 effective tax rate for 2005 and 2004 was 16.8 percent and 49.7 percent, respectively, based on 2005 and 2004 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 of the excluded items as well as settlements of prior year tax liabilities and changes in estimates of prior year tax are all treated as discrete period tax expenses or benefits. The impact of the various discrete period tax items was a net benefit of $14 million in 2005, resulting in a tax rate of 10.8 percent on earnings before income taxes and minority interest. The discrete items 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 changes related to the disposition of TODCO. For 2004, the impact of the various discrete items was a net expense of $12 million, including a provision for a valuation allowance of approximately $32 million related to the TODCO IPO.

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Index

The decrease in minority interest was primarily attributable to the deconsolidation of TODCO.

TODCO Segment

The results presented below for the TODCO segment are through December 16, 2004 as a result of the TODCO stock sales and the deconsolidation of TODCO.

	Years ended
	December 31,
	2005		2004			Change			% Change
	(In millions, except day amounts and percentages)

Revenue earning days		−		10,476			(10,476	)		N/M
Utilization		−		43	%		N/A			N/M
Average daily revenue		−	$	26,900		$	(26,900	)		N/M

Contract drilling revenues		−	$	283		$	(283	)		N/M
Other revenues		−		51			(51	)		N/M
		−		334			(334	)		N/M
Operating and maintenance expense		−		(281	)		281			N/M
Depreciation		−		(92	)		92			N/M
Gain (loss) from disposal of assets, net		−		6			(6	)		N/M
Operating loss before general and administrative expense		−	$	(33	)	$	33			N/M

________________

“N/A” means not applicable

“N/M” means not meaningful

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 on-going basis, we evaluate our estimates, including those related to bad debts, materials and supplies obsolescence, investments, property and equipment, intangible assets and goodwill, income taxes, 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 and we are not subject to income tax in the Cayman Islands. 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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Index

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 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 is 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 estimated to not be realizable. As of December 31, 2004, we had established a valuation allowance against certain deferred tax assets, primarily U.S. foreign tax credit carryforwards and certain net operating losses, in the amount of $115 million. We decreased the valuation allowance to $48 million, as of December 31, 2005, and we increased the valuation allowance to $59 million, as of December 31, 2006. If our facts or financial results were to change, thereby impacting the likelihood of realizing the deferred tax assets, judgment would have to be applied to determine changes to the amount of the valuation allowance in any given period. Such changes could result in either a decrease or an increase in our provision for income taxes, depending on whether the change in judgment resulted in an increase or a decrease to the valuation allowance. See “Results of Operations—Historical 2006 compared to 2005” and “Results of Operations—Historical 2005 compared to 2004.” 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 financial position, results of operations or cash flows.

Property and equipment—Our property and equipment represents approximately 64 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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Index

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 $48 million while a one year decrease would cause an increase in our annual depreciation expense of approximately $84 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 Statements of Financial Accounting Standard (“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, Other Floaters, 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.

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 123(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 evaluate our assumptions regarding the estimated long-term rate of return on plan assets based on historical experience and future expectations on investment returns, which are calculated by our third party investment advisor utilizing the asset allocation classes held by the plan’s portfolios. We utilize 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.

For each percentage point the expected long-term rate of return assumption is lowered, pension expense would increase by approximately $2 million. For each one-half percentage point the discount rate is lowered, pension expense would increase by approximately $3 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 change that affect our previous assumptions with respect to the likelihood or amount of loss. Reserves for contingent liabilities are based upon our assumptions and estimates regarding the probable outcome of the matter. Should the outcome differ from our assumptions and estimates 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.

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Index

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 123(R)”), 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 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 accumulate other comprehensive income. The adjustment to accumulate 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.

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.”

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Index

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

	Retirement Plan			Supplemental Retirement Plan			Frozen Plans			Subtotal U.S. Plans			Norway Plans			Other Non- U.S. Plans			Total Transocean Plans
	(in millions)
Accumulated Benefit Obligation
At December 31, 2006	$	139		$	6		$	98		$	243		$	43		$	4		$	290
At December 31, 2005		132			4			103			239			39			1			279

Projected Benefit Obligation
At December 31, 2006	$	170		$	8		$	98		$	276		$	69		$	6		$	351
At December 31, 2005		174			7			103			284			50			2			336

Fair Value of Plan Assets
At December 31, 2006	$	125		$	-		$	98		$	223		$	50		$	-		$	273
At December 31, 2005		111			-			93			204			38			-			242

Funded Status
At December 31, 2006	$	(45	)	$	(8	)	$	-		$	(53	)	$	(19	)	$	(6	)	$	(78	)
At December 31, 2005		(63	)		(7	)		(10	)		(80	)		(12	)		(2	)		(94	)

Net Periodic Benefit Cost (Income)
Year Ended December 31, 2006	$	17		$	1		$	-		$	18		$	6		$	2		$	26		(a)
Year Ended December 31, 2005		14			3			(1	)		16			5			1			22		(a)

Change in Accumulated Other Comprehensive Income
Year Ended December 31, 2006	$	5		$	1		$	(10	)	$	(4	)	$	11		$	(1	)	$	6
Year Ended December 31, 2005		-			(3	)		(3	)		(6	)		-			-			(6	)

Employer Contributions
Year Ended December 31, 2006	$	5		$	-		$	-		$	5		$	9		$	1		$	15
Year Ended December 31, 2005		-			1			-			1			5			-			6

Weighted-Average Assumptions - Benefit Obligations
Discount Rate
At December 31, 2006		5.85	%		5.76	%		5.69	%					4.80	%		12.21	%		5.72	%	(b)
At December 31, 2005		5.66	%		5.54	%		5.38	%					5.50	%		14.62	%		5.60	%	(b)
Rate of compensation increase
At December 31, 2006		4.20	%		3.79	%		-						4.00	%		10.29	%		4.27	%	(b)
At December 31, 2005		4.72	%		4.29	%		-						3.50	%		11.64	%		4.50	%	(b)

Weighted-Average Assumptions - Net Periodic Benefit Cost
Discount Rate
Year Ended December 31, 2006		5.66	%		5.54	%		5.43	%					5.50	%		13.00	%		5.69	%	(b)
Year Ended December 31, 2005		5.50	%		5.50	%		5.50	%					6.00	%		14.62	%		5.63	%	(b)

- 43 -

Index

	Retirement Plan			Supplemental Retirement Plan			Frozen Plans			Subtotal U.S. Plans	Norway Plans			Other Non- U.S. Plans			Total Transocean Plans

Expected long-term rate of return on plan assets
Year Ended December 31, 2006		9.00	%		-			9.00	%			6.00	%		-			8.49	%	(c)
Year Ended December 31, 2005		9.00	%		-			9.00	%			7.00	%		-			8.70	%	(c)
Rate of compensation increase
Year Ended December 31, 2006		4.72	%		4.29	%		-				3.50	%		10.29	%		4.54	%	(b)
Year Ended December 31, 2005		4.75	%		4.29	%		-				3.50	%		11.64	%		4.52	%	(b)

______________

(a)	Pension costs were reduced by expected returns on plan assets of $20 million and $21 million for the years ended December 31, 2006 and 2005, 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 $5 million to the funded U.S. Plans during 2006. No contributions were made to the funded U.S. Plans during 2005. We contributed less than $1 million to the unfunded U.S. Plans during 2006 to fund benefit payments. We contributed $1 million to the unfunded U.S. Plans during 2005 to fund benefit payments.

Our contributions to the Transocean Plans in 2006 and 2005, 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,
	2006			2005
Components of Net Periodic Benefit Cost (a)
Service cost	$	20		$	18
Interest cost		19			18
Expected return on plan assets		(20	)		(21	)
Recognized net actuarial losses		5			4
Amortization of prior service cost		1			1
Amortization of net transition obligation		1			-
SFAS 88 settlements/curtailments		-			2
Benefit cost	$	26		$	22

______________

(a)

Amounts are before income tax effect.

Plan assets of the funded Transocean Plans have been favorably impacted by a substantial rise in world equity markets during 2006 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 2006, the market value of the investments in the Transocean Plans increased by $31 million, or 12.8 percent. The increase is due to net investment gains of $28 million, primarily in the funded U.S. Plans, resulting from the favorable performance of equity markets in 2006, $15 million of employer contributions and $3 million of favorable foreign currency exchange rate changes. These increases were offset by benefit plan payments of $15 million from these plans. We expect to contribute $17 million to the Transocean Plans in 2007. These contributions are comprised of an estimated $8 million to meet minimum funding requirements for the funded U.S. Plans, $1 million to fund expected benefit payments for the unfunded U.S. Plans and Other Non-U.S. Plans and an estimated $8 million for the funded Norway Plans. We expect the required contributions will be funded from cash flow from operations.

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Index

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

Years ending December 31,
2007	$	15
2008		16
2009		17
2010		17
2011		18
2012-2016		97

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 2005, the increase in the fair value of plan assets offset the decrease in the discount rate resulting in a decrease in the minimum pension liability of $6 million. In 2006, the fair value of plan assets continued to increase, resulting 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, 2004, 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, 2006 and 2005. The expected long-term rate of return on plan assets was developed by reviewing each plan’s target asset allocation and asset class long-term rate of return expectations. We regularly review our actual asset allocation and periodically rebalance plan assets as appropriate. For the U.S. Plans, we discounted our future pension obligations using a rate of 5.8 percent at December 31, 2006, 5.5 percent at December 31, 2005 and 6.0 percent at December 31, 2004.

We expect pension expense related to the Transocean Plans for 2007 to decrease by approximately $4 million primarily due to a change in the demographic assumptions for future periods and plan asset growth realized in 2006.

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 postretirement benefit plans covering substantially all of our U.S. employees. Funding of benefit payments for plan participants will be made as costs are incurred. Net periodic benefit cost for these other postretirement plans included the following components (in millions):

	Years ended December 31,
	2006			2005
Components of Net Periodic Benefit Cost (a)
Service cost	$	1		$	1
Interest cost		2			2
Amortization of prior service credit		(2	)		(2	)
Recognized net actuarial losses		1			2
Benefit cost	$	2		$	3

______________

(a)

Amounts are before income tax effect.

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Index

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

Years ending December 31,
2007	$	2
2008		2
2009		2
2010		2
2011		2
2012-2016		11

Off-Balance Sheet Arrangements

We had no off-balance sheet arrangements as of December 31, 2006.

Related Party Transactions

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 2006, we earned $2 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 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, 2006 and 2005, $3 million and $4 million, respectively, was outstanding under this loan agreement and was reflected as other long-term liabilities in our consolidated balance sheet. In 2006, ODL declared a dividend in the amount of $4 million. In addition, ODL paid us cash dividends of $3 million and $11 million in 2005 and 2004, respectively.

Separation of TODCO

Tax Sharing Agreement with TODCO—Our wholly owned subsidiary, Transocean Holdings Inc., is party to a tax sharing agreement with TODCO that was entered into in connection with the TODCO IPO. See “Item 3. Legal Proceedings.”

New Accounting Pronouncements

In July 2006, the FASB issued FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes—an interpretation of FASB Statement No. 109 (“FIN 48”). FIN 48 clarifies the accounting for income taxes recognized in an entity’s financial statements in accordance with SFAS No. 109, Accounting for Income Taxes. It prescribes a minimum recognition threshold and measurement attribute for recognizing and measuring the benefit of tax positions taken or expected to be taken in a tax return. FIN 48 also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. FIN 48 is effective for fiscal years beginning after December 15, 2006. We will be required to adopt this interpretation in the first quarter of fiscal year 2007. Management is in the process of quantifying the impact of FIN 48 on the consolidated financial statements and has not yet finalized its evaluation.

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 applies under other accounting pronouncements that require or permit fair value measurements because the FASB previously concluded in those accounting pronouncements that fair value is the relevant measurement attribute. Accordingly, SFAS 157 does not require any new fair value measurements. 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. Management is currently evaluating the requirements of SFAS 157 and has not yet determined the impact on the consolidated financial statements.

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. Management is currently evaluating the requirements of SFAS 159 and has not yet determined the impact on the consolidated financial statements.

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Index

In June 2006, the FASB reached consensus on Emerging Issues Task Force ("EITF") No. 06-3, "How Taxes Collected from Customers and Remitted to Governmental Authorities Should be Presented in the Income Statement" ("EITF 06-3"). The scope of EITF 06-3 includes any tax assessed by a governmental authority that is directly imposed on a revenue-producing transaction between a seller and a customer and may include, but is not limited to, sales, use, value added, and excise taxes. The Task Force affirmed its conclusion that entities should present these taxes in the consolidated statement of operations on either a gross or a net basis, based on their accounting policy, which should be disclosed pursuant to Accounting Principles Board Opinion No. 22, Disclosure of Accounting Policies. If those taxes are significant, and are presented on a gross basis, the amounts of those taxes should be disclosed. The consensus on EITF 06-3 is effective as of the beginning of the first fiscal year beginning after December 15, 2006. We generally record our tax-assessed revenue transactions on a net basis in our consolidated statements of operations; therefore, we do not expect EITF 06-3 to have a material effect on our consolidated balance sheet, statement 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, 2006.

At December 31, 2006 (in millions, except interest rate percentages):

	Scheduled Maturity Date (a) (b)																					Fair Value
	2007			2008			2009			2010			2011			Thereafter			Total			12/31/06
Total debt
Fixed rate	$	100		$	19		$	−		$	−		$	565		$	904		$	1,588		$	1,773
Average interest rate		7.5	%		2.8	%		−	%		−	%		3.0	%		7.5	%		5.8	%
Variable rate	$	−		$	1,700		$	−		$	−		$	−		$	−		$	1,700		$	1,700
Average interest rate		−	%		5.6	%		−	%		−	%		−	%		−	%		5.6	%

__________________________

(a)	Maturity dates of the face value of our debt assume the put options on the 7.45% Notes, Zero Coupon Convertible Debentures and the 1.5% Convertible Debentures will be exercised in April 2007, May 2008 and May 2011, respectively.

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

At December 31, 2006, we had approximately $1.7 billion of variable rate debt at face value (52 percent of total debt at face value). This variable rate debt represented the Term Credit Facility and the Floating Rate Notes issued during 2006. At December 31, 2005, we had no variable rate debt outstanding. Based upon the December 31, 2006 and 2005 variable rate debt outstanding amounts, a one percentage point change in interest rates would result in a corresponding change in interest expense of approximately $17 million and no change per year, respectively. In addition, a large part of our cash investments would earn commensurately higher rates of return if interest rates increase. Using December 31, 2006 and 2005 cash investment levels, a one percentage point change in interest rates would result in a corresponding change in interest income of approximately $3 million per year for both periods.

The fair market value of our debt at December 31, 2006 was $3.5 billion compared to $1.9 billion at December 31, 2005. The increase in fair value of $1.6 billion was primarily due to the issuance of debt during the year, as well as changes in the corporate bond market.

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, 2006, we had no open foreign exchange derivative contracts.

- 47 -

Index

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, 2006. In making this assessment, management used the criteria for internal control over financial reporting described in Internal Control-Integrated Framework by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). Management’s assessment included an evaluation of the design of the Company’s internal control over financial reporting and testing of the operating effectiveness of its internal control over financial reporting. Management reviewed the results of its assessment with the Audit Committee of the Company’s Board of Directors. Based on this assessment, management has concluded that, as of December 31, 2006, the Company’s internal control over financial reporting was effective.

Ernst & Young LLP, an independent registered public accounting firm, audited management’s assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2006. Their report included elsewhere herein expresses an unqualified opinion on management’s assessment and on the effectiveness of our internal control over financial reporting as of December 31, 2006.

- 48 -

Index

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 management’s assessment, included in the accompanying Management’s Report on Internal Control Over Financial Reporting, that Transocean Inc. maintained effective internal control over financial reporting as of December 31, 2006, 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. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of 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, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

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

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

In our opinion, management’s assessment that Transocean Inc. maintained effective internal control over financial reporting as of December 31, 2006, is fairly stated, in all material respects, based on the COSO criteria. Also, in our opinion, Transocean Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2006, 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. and Subsidiaries as of December 31, 2006 and 2005, 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, 2006 and our report dated February 27, 2007 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

Houston, Texas

February 27, 2007

- 49 -

Index

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, 2006 and 2005, 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, 2006. 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, 2006 and 2005, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2006, 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 2 to the consolidated financial statements, effective January 1, 2006, the Company adopted Statement of Financial Accounting Standards No. 123 (revised 2004), Share-Based Payment and, as discussed in Note 19, 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), the effectiveness of Transocean Inc.’s internal control over financial reporting as of December 31, 2006, 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, 2007 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

Houston, Texas

February 27, 2007

- 50 -

Index

TRANSOCEAN INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(In millions, except per share data)

	Years ended December 31,
	2006			2005			2004

Operating Revenues
Contract drilling revenues	$	3,745		$	2,757		$	2,416
Other revenues		137			135			198
		3,882			2,892			2,614
Costs and Expenses
Operating and maintenance		2,155			1,720			1,714
Depreciation		401			406			524
General and administrative		90			75			67
		2,646			2,201			2,305
Gain from disposal of assets, net		405			29			19
Operating Income		1,641			720			328

Other Income (Expense), net
Interest income		21			19			9
Interest expense, net of amounts capitalized		(115	)		(111	)		(172	)
Gain from TODCO stock sales		−			165			309
Non-cash TODCO tax sharing agreement charge		−			−			(167	)
Loss on retirement of debt		−			(7	)		(76	)
Other, net		60			17			9
		(34	)		83			(88	)

Income Before Income Taxes and Minority Interest		1,607			803			240
Income Tax Expense		222			87			91
Minority Interest		−			−			(3	)
Net Income	$	1,385		$	716		$	152

Earnings Per Share
Basic	$	4.42		$	2.19		$	0.47
Diluted	$	4.28		$	2.13		$	0.47

Weighted Average Shares Outstanding
Basic		313			327			321
Diluted		325			339			325

See accompanying notes.

- 51 -

Index

TRANSOCEAN INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(In millions)

	Years ended December 31,
	2006		2005		2004

Net Income	$	1,385	$	716	$	152
Other Comprehensive Income (Loss), net of tax
Minimum pension liability adjustments (net of tax expense (benefit) $9, $2 and $(2) for the years ended December 31, 2006, 2005 and 2004, respectively)		16		4		(4	)
Other Comprehensive Income (Loss)		16		4		(4	)
Total Comprehensive Income	$	1,401	$	720	$	148

See accompanying notes.

- 52 -

Index

TRANSOCEAN INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(In millions, except share data)

	December 31,
	2006			2005
ASSETS
Cash and Cash Equivalents	$	467		$	445
Accounts Receivable, net
Trade		929			583
Other		17			17
Materials and Supplies, net		160			156
Deferred Income Taxes, net		16			23
Other Current Assets		67			55
Total Current Assets		1,656			1,279

Property and Equipment		10,539			9,791
Less Accumulated Depreciation		3,213			3,043
Property and Equipment, net		7,326			6,748
Goodwill		2,195			2,209
Other Assets		299			221
Total Assets	$	11,476		$	10,457

LIABILITIES AND SHAREHOLDERS' EQUITY

Accounts Payable	$	477		$	254
Accrued Income Taxes		98			27
Debt Due Within One Year		95			400
Other Current Liabilities		369			242
Total Current Liabilities		1,039			923

Long-Term Debt		3,200			1,197
Deferred Income Taxes, net		54			65
Other Long-Term Liabilities		343			286
Total Long-Term Liabilities		3,597			1,548

Commitments and Contingencies

Minority Interest		4			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, 292,454,457 and 324,750,166 shares issued and outstanding at December 31, 2006 and 2005, respectively		3			3
Additional Paid-in Capital		8,044			10,565
Accumulated Other Comprehensive Loss		(30	)		(20	)
Accumulated Deficit		(1,181	)		(2,566	)
Total Shareholders' Equity		6,836			7,982
Total Liabilities and Shareholders' Equity	$	11,476		$	10,457

See accompanying notes.

- 53 -

Index

TRANSOCEAN INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF EQUITY

(In millions)

									Accumulated			Retained
						Additional			Other			Earnings
	Ordinary Shares					Paid-in			Comprehensive			(Accumulated			Total
	Shares			Amount		Capital			Income (Loss)			Deficit)			Equity

Balance at December 31, 2003		320		$	3	$	10,644		$	(20	)	$	(3,434	)	$	7,193
Net income		-			-		-			-			152			152
Issuance of ordinary shares under share-based compensation plans		2			-		38			-			-			38
Minimum pension liability		-			-		-			(4	)		-			(4	)
Other		-			-		14			-			-			14

Balance at December 31, 2004		322			3		10,696			(24	)		(3,282	)		7,393
Net income		-			-		-			-			716			716
Repurchase of ordinary shares		(6	)		-		(400	)		-			-			(400	)
Issuance of ordinary shares under share-based compensation plans		9			-		260			-			-			260
Minimum pension liability		-			-		-			4			-			4
Other		-			-		9			-			-			9

Balance at December 31, 2005		325			3		10,565			(20	)		(2,566	)		7,982
Net income		−			-		-			-			1,385			1,385
Repurchase of ordinary shares		(36	)		-		(2,600	)		-			-			(2,600	)
Issuance of ordinary shares under share-based compensation plans		3			-		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		292		$	3	$	8,044		$	(30	)	$	(1,181	)	$	6,836

See accompanying notes.

- 54 -

Index

TRANSOCEAN INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In millions)

	Years ended December 31,
	2006			2005			2004
Cash Flows from Operating Activities
Net income	$	1,385		$	716		$	152
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation		401			406			524
Share-based compensation expense		20			16			25
Deferred income taxes		(23	)		27			18
Equity in earnings of unconsolidated affiliates		(5	)		(10	)		(9	)
Net gain from disposal of assets		(405	)		(29	)		(19	)
Gain from TODCO stock sales		−			(165	)		(309	)
Non-cash TODCO tax sharing agreement charge		−			−			167
Loss on retirement of debt		−			7			76
Amortization of debt-related discounts/premiums, fair value adjustments and issue costs, net		−			(7	)		(21	)
Deferred income, net		52			(7	)		36
Deferred expenses, net		(109	)		18			(22	)
Tax benefit from exercise of stock options to purchase and vesting of ordinary shares under share-based compensation plans		(10	)		22			6
Other long-term liabilities		18			23			10
Other, net		−			(17	)		(6	)
Changes in operating assets and liabilities
Accounts receivable		(347	)		(150	)		(29	)
Accounts payable and other current liabilities		168			87			5
Income taxes receivable/payable, net		124			(51	)		1
Other current assets		(32	)		(22	)		(5	)
Net Cash Provided by Operating Activities		1,237			864			600

Cash Flows from Investing Activities
Capital expenditures		(876	)		(182	)		(127	)
Proceeds from disposal of assets, net		461			74			53
Proceeds from TODCO stock sales, net		−			272			684
Reduction of cash from the deconsolidation of TODCO		−			−			(69	)
Joint ventures and other investments, net		−			5			10
Net Cash Provided by (Used in) Investing Activities		(415	)		169			551

See accompanying notes.

- 55 -

Index

TRANSOCEAN INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (Continued)

(In millions)

	Years ended December 31,
	2006			2005			2004
Cash Flows from Financing Activities
Proceeds from issuance of debt and borrowings under the Term Credit Facility		2,000			−			−
Net changes in borrowings under the Revolving Credit Facility		−			−			(250	)
Repayments of debt		(300	)		(880	)		(955	)
Repurchase of ordinary shares		(2,601	)		(400	)		-
Net proceeds from issuance of ordinary shares under share-based compensation plans		69			219			30
Proceeds from issuance of ordinary shares upon exercise of warrants		−			11			−
Release of escrow funds - Nautilus lease financing		30			−			−
Decrease in cash dedicated to debt service		−			12			−
Tax benefit from issuance of ordinary shares under share-based compensation plans		7			−			−
Other, net		(5	)		(1	)		1
Net Cash Used in Financing Activities		(800	)		(1,039	)		(1,174	)

Net Increase (Decrease) in Cash and Cash Equivalents		22			(6	)		(23	)
Cash and Cash Equivalents at Beginning of Period		445			451			474
Cash and Cash Equivalents at End of Period	$	467		$	445		$	451

See accompanying notes.

- 56 -

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 additional services, including integrated services. At December 31, 2006, we owned, had partial ownership interests in or operated 82 mobile offshore drilling units. As of this date, our fleet consisted of 33 High-Specification semisubmersibles and drillships (“High-Specification Floaters”), 20 Other Floaters, 25 Jackups and four Other Rigs. We also have three High-Specification Floaters under construction (see Note 5—Drilling Fleet Expansion, Upgrades and Acquisition).

On January 31, 2001, we completed a merger transaction (the “R&B Falcon merger”) with R&B Falcon Corporation (“R&B Falcon”). At the time of the merger, R&B Falcon operated a diverse global drilling rig fleet consisting of drillships, semisubmersibles, jackup rigs and other units 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 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 TODCO’s outstanding shares of its common stock. In September 2004 and December 2004, respectively, we completed additional public offerings of TODCO common stock (respectively referred to as the “September 2004 Offering” and “December 2004 Offering” and, together with the TODCO IPO, the “2004 Offerings”). We sold 30 percent of TODCO’s outstanding shares of its common stock in the September 2004 Offering and 25 percent of TODCO’s outstanding shares of its common stock in the December 2004 Offering. Prior to the December 2004 Offering, we held TODCO class B common stock, which was entitled to five votes per share (compared to one vote per share of TODCO class A common stock) and converted automatically into class A common stock upon any sale by us to a third party. In conjunction with the December 2004 Offering, we converted all of our remaining TODCO class B common stock not sold in the 2004 Offerings into shares of class A common stock. After the 2004 Offerings, we held a 22 percent ownership and voting interest in TODCO.

We consolidated TODCO in our financial statements through December 16, 2004 and that portion of TODCO that we did not own was reported as minority interest in our consolidated statements of operations and balance sheets. As a result of the conversion of the TODCO class B common stock into class A common stock, we no longer had a majority voting interest in TODCO and 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 of TODCO common stock 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,” collectively referred to as the “2005 Offering and Sale,” and, collectively with the 2004 Offerings, the “TODCO stock sales”). We sold 20 percent of TODCO’s total outstanding shares in the May Offering and our remaining two percent of TODCO’s total outstanding shares in 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. See Note 4—TODCO Stock Sales.

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.

- 57 -

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.

As a result of the Deepwater Nautilus project financing in 1999, we were required to maintain in cash an amount to cover certain principal and interest payments. Such restricted cash, classified as other current assets in the consolidated balance sheet, was $12 million at December 31, 2004. As a result of the repayment of the project financing (see Note 7—Debt), the restricted cash balance was released in May 2005.

Accounts Receivable—Accounts receivable are stated at the historical carrying amount net of write-offs and allowance for doubtful accounts receivable. Uncollectible accounts receivable are written off when a settlement is reached for an amount that is less than the outstanding historical balance.

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 $26 million and $15 million at December 31, 2006 and 2005, respectively. We derive a majority of our revenue from services to international and government-owned or government-controlled oil companies, and, generally, do not 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 $19 million at December 31, 2006 and 2005.

Property and Equipment—Property and equipment, consisting primarily of offshore drilling rigs and related equipment, represented approximately 64 percent of our total assets at December 31, 2006. 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 (loss) 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 useful life. During the fourth quarter of 2004, we extended the useful lives to 35 years for four rigs, which had estimated useful lives ranging from 30 to 32 years. 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. We determined 35 years was 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 2006, 2005 and 2004, the impact of the change in estimated useful life of these rigs was a reduction in depreciation expense of $2 million ($0.01 per diluted share), $16 million ($0.05 per diluted share) and $5 million ($0.01 per diluted share), respectively, which had no tax effect.

- 58 -

Index

TRANSOCEAN INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued

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 the Financial Accounting Standards Board's (“FASB”) Statement of Financial Accounting Standards (“SFAS”) No. 144, Accounting for Impairment or Disposal of Long-Lived Assets. At December 31, 2006 and 2005, we had assets held for sale in the amounts of $11 million and $16 million, respectively, that were included in other current assets (see Note 6—Asset Dispositions).

Goodwill—In accordance with SFAS No. 142, Goodwill and Other Intangible Assets (“SFAS 142”), goodwill is tested for impairment at least annually at the reporting unit level, which is defined as an operating segment or a component of an operating segment that constitutes a business for which financial information is available and is regularly reviewed by management. Management has determined that our reporting units are the same as our operating segments for the purpose of allocating goodwill and the subsequent testing of goodwill for impairment.

Since the disposition of TODCO, we operate in one operating segment (see Note 1), which is also our reporting unit for the test of goodwill impairment. The goodwill impairment test performed at October 1, 2004 was carried forward to October 1, 2005 and 2006 since it met all necessary carry forward criteria within the scope of SFAS 142. We perform our annual test of goodwill impairment as of October 1. As a result of these tests for impairment, we had no impairment of goodwill for the years ended December 31, 2006, 2005 and 2004.

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

	Balance at January 1, 2006		Other (a)			Balance at December 31, 2006

Transocean Drilling	$	2,209	$	(14	)	$	2,195

______________________

(a)

Primarily represents net adjustments during 2006 of income tax-related pre-acquisition contingencies.

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.

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 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 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.

Other Revenue—Our other revenue represents client reimbursable revenue, integrated services revenue and other miscellaneous revenues. 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 that we provide under certain contracts that include well and logistics services in addition to our normal drilling services through third party contractors and our employees.

- 59 -

Index

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 $16 million for the year ended December 31, 2006. There was no capitalized interest for the years ended December 31, 2005 and 2004.

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 $(3) million and $(4) million, for the years ended December 31, 2006 and 2005, respectively. The foreign currency gains (losses) for the year ended December 31, 2004 were immaterial to the financial statements.

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 123(R)”), which is a revision of SFAS No. 123, Accounting for Stock-Based Compensation (“SFAS 123”). SFAS 123(R) 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”). While the approach in SFAS 123(R) is similar to the approach described in SFAS 123, SFAS 123(R) requires recognition in the income statement of all share-based payments to employees, including grants of employee stock options based on their fair values and pro forma disclosure is no longer 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 123(R). We have applied the provisions of SAB 107 in our adoption of SFAS 123(R).

We adopted SFAS 123(R) using the modified prospective method (“Prospective Method”), which requires the application of SFAS 123(R) as of January 1, 2006. Our consolidated financial statements as of and for the year ended December 31, 2006 reflect the application of SFAS 123(R). 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 123(R). Share-based compensation expense for the years ended December 31 are as follows (in millions):

	Years ended December 31,
	2006			2005			2004
Share-based compensation expense	$	20		$	16		$	25
Income tax benefit on share-based compensation expense		(2	)		(3	)		(7	)

SFAS 123(R) 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 123(R) 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. Prior to our adoption of SFAS 123(R), we accounted for forfeitures as they occurred. Upon adopting SFAS 123(R), we estimated expected forfeitures over the life of each individual award and have included the impact of these expected forfeitures in our share-based compensation expense for the year ended December 31, 2006 in addition to all prior periods on a cumulative basis. The effect of this change is to reverse compensation cost recognized in prior period financial statements for awards that are not expected to vest based upon the expected forfeiture rate. 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 financial position, results of operations or cash flows.

- 60 -

Index

TRANSOCEAN INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued

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 123(R) using the Prospective Method had no material impact on our consolidated financial position, results of operations or cash flows. In addition to the compensation cost recognition requirements, SFAS 123(R) 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, which was required under SFAS 95. We reported operating cash flows related to tax deduction benefits of $22 million and $6 million for the years ended December 31, 2005 and 2004, respectively.

Under SFAS 123, we recognized compensation cost on a straight line basis over the vesting period up to the date of actual retirement. We will continue this practice for awards granted prior to adoption of SFAS 123(R). As a result of the adoption of SFAS 123(R), 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 123(R), 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 years ended December 31, 2005 and 2004 would have been reduced to the pro forma amounts indicated below (in millions, except per share data):

	Years ended December 31,
	2005			2004
Net Income as Reported	$	716		$	152
Add back: Share-based compensation expense included in reported net income, net of related tax effects		13			18

Deduct: Total share-based compensation expense determined under the fair value method for all awards, net of related tax effects
Long-Term Incentive Plan		(11	)		(22	)
Employee Stock Purchase Plan (“ESPP”)		(4	)		(3	)

Pro Forma Net Income	$	714		$	145

Basic Earnings Per Share
As Reported	$	2.19		$	0.47
Pro Forma		2.18			0.45

Diluted Earnings Per Share
As Reported	$	2.13		$	0.47
Pro Forma		2.12			0.45

The above pro forma amounts are not indicative of future results. 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 used:

	Years ended December 31,
	2006			2005			2004
Dividend yield		-			-			-
Expected price volatility		33%-37	%		26%-38	%		38%-42	%
Risk-free interest rate		4.52%-5.00	%		2.86%-4.57	%		2.59%-3.71	%
Expected life of options		4.70			4.40			4.30
Weighted-average fair value of options granted	$	31.30		$	21.92		$	10.65

- 61 -

Index

TRANSOCEAN INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued

The fair value of each option grant under the Employee Stock Purchase Plan (“ESPP”) was estimated using the following weighted-average assumptions:

	Years ended December 31,
	2006			2005			2004
Dividend yield		-			-			-
Expected price volatility		33	%		28	%		27	%
Risk-free interest rate		4.42	%		2.81	%		1.19	%
Expected life of options		Less than one year			Less than one year			Less than one year
Weighted-average fair value of options granted	$	10.50		$	7.10		$	4.10

New Accounting Pronouncements—In July 2006, the FASB issued FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes—an interpretation of FASB Statement No. 109 (“FIN 48”). FIN 48 clarifies the accounting for income taxes recognized in an entity’s financial statements in accordance with SFAS No. 109, Accounting for Income Taxes. It prescribes a minimum recognition threshold and measurement attribute for recognizing and measuring the benefit of tax positions taken or expected to be taken in a tax return. FIN 48 also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. FIN 48 is effective for fiscal years beginning after December 15, 2006. We will be required to adopt this interpretation in the first quarter of fiscal year 2007. Management is in the process of quantifying the impact of FIN 48 on the consolidated financial statements and has not yet finalized its evaluation.

In June 2006, the FASB reached consensus on Emerging Issues Task Force ("EITF") No. 06-3, "How Taxes Collected from Customers and Remitted to Governmental Authorities Should be Presented in the Income Statement" ("EITF 06-3"). The scope of EITF 06-3 includes any tax assessed by a governmental authority that is directly imposed on a revenue-producing transaction between a seller and a customer and may include, but is not limited to, sales, use, value added, and excise taxes. The Task Force affirmed its conclusion that entities should present these taxes in the consolidated statement of operations on either a gross or a net basis, based on their accounting policy, which should be disclosed pursuant to APB Opinion No. 22, Disclosure of Accounting Policies. If those taxes are significant, and are presented on a gross basis, the amounts of those taxes should be disclosed. The consensus on EITF 06-3 is effective as of the beginning of the first fiscal year beginning after December 15, 2006. We generally record our tax-assessed revenue transactions on a net basis in our consolidated statements of operations; therefore, we do not expect EITF 06-3 to have a material effect on our consolidated balance sheet, statement 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 the consolidated financial statements.

- 62 -

Index

TRANSOCEAN INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued

Note 3—Accumulated Other Comprehensive Loss

The components of accumulated other comprehensive loss at December 31, 2006, 2005 and 2004, 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, 2003	$	3	$	(23	)	$	−		$	(20	)
Other comprehensive income (loss)		−		(4	)		−			(4	)
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	)

__________________

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

Note 4—TODCO Stock Sales

In February 2004, we completed the TODCO IPO in which we sold 13.8 million shares of TODCO’s class A common stock, representing 23 percent of TODCO’s total outstanding shares, at $12.00 per share. We received net proceeds of $156 million from the TODCO IPO and recognized a gain of $39 million ($0.12 per diluted share), which had no tax effect, in the first quarter of 2004 and represented the excess of net proceeds received over the net book value of the shares sold in the TODCO IPO.

In conjunction with the closing of the TODCO IPO, TODCO granted restricted shares and stock options to some of its employees under its long-term incentive plan and some of these awards vested at the time of grant. In accordance with the provisions of SFAS 123, TODCO recognized compensation expense of $6 million ($0.02 per Transocean’s diluted share), which had no tax effect, in the first quarter of 2004 as a result of the immediate vesting of these awards. In addition, certain of TODCO’s employees held options that were granted prior to the TODCO IPO to acquire our ordinary shares. In accordance with the employee matters agreement with TODCO, these options were modified at the TODCO IPO date, which resulted in the accelerated vesting of the options and the extension of the term of the options through the original contractual life. In connection with the modification of these options, TODCO recognized additional compensation expense of $2 million, which had no tax effect, in the first quarter of 2004.

In September 2004, we completed the September 2004 Offering in which we sold 18.0 million shares of TODCO’s class A common stock, representing 30 percent of TODCO’s total outstanding shares, at $15.75 per share. We received net proceeds of $270 million from the September 2004 Offering and recognized a gain of $129 million ($0.40 per diluted share), which had no tax effect, in the third quarter of 2004 and represented the excess of net proceeds received over the net book value of the TODCO shares sold in the September 2004 Offering.

In December 2004, we completed the December 2004 Offering in which we sold 15.0 million shares of TODCO’s class A common stock, representing 25 percent of TODCO’s total outstanding shares, at $18.00 per share. We received net proceeds of $258 million from the December 2004 Offering and recognized a gain of $140 million ($0.43 per diluted share), which had no tax effect, in the fourth quarter of 2004 and represented the excess of net proceeds received over the net book value of the TODCO shares sold in the December 2004 Offering.

We sold 12.0 million shares of TODCO’s class A common stock, representing 20 percent of TODCO’s total outstanding shares, at $20.50 per share in the May Offering. We sold our remaining 1.3 million shares of TODCO’s class A common stock, representing two percent of TODCO’s total outstanding shares, at $23.57 per share in the June Sale. We received net proceeds of $272 million from the 2005 Offering and Sale and recognized a gain in the second quarter of 2005 of $165 million ($0.49 per diluted share), which had no tax effect and represented the excess of net proceeds received over the net book value of the shares sold in the 2005 Offering and Sale.

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Index

TRANSOCEAN INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued

Note 5—Drilling Fleet Expansion, Upgrades and Acquisition

Capital expenditures, including capitalized interest, totaled $876 million during the year ended December 31, 2006 and related to the construction of three enhanced Enterprise-class drillships totaling $460 million and two Sedco 700-series rig upgrades totaling $150 million. The remaining $266 million related to corporate infrastructure and our existing fleet, including the replacement of equipment damaged during hurricanes Katrina and Rita on the semisubmersible rigs Deepwater Nautilus and the Transocean Marianas and the reactivation of three of our Other Floaters.

In March 2006, we were awarded a five-year drilling contract for an enhanced Enterprise-class drillship, to be named the Discoverer Clear Leader. We estimate total capital expenditure for the construction of this rig to be approximately $630 million, excluding capitalized interest, but including approximately $30 million for additional equipment requested by the client for which the client has agreed to an increased dayrate. This rig is expected to be operational in 2009.

In August 2006, were awarded a drilling contract for a third enhanced Enterprise-class drillship, to be named the Discoverer Inspiration. We estimate total capital expenditure for the construction of this rig to be approximately $670 million, excluding capitalized interest. This amount includes approximately $40 million for equipment that was not included in the original costs of the other two enhanced Enterprise-class drillships. This rig is expected to be operational in 2010.

Capital expenditures totaled $182 million during the year ended December 31, 2005 and related to corporate infrastructure and our existing fleet, including the replacement of equipment damaged during hurricanes Katrina and Rita on the Deepwater Nautilus and the Transocean Marianas and the purchase of the M.G. Hulme, Jr., which we had previously operated under a lease arrangement that resulted from a sale/leaseback transaction with a special purpose entity (see Note 16—Off-Balance Sheet Arrangement).

Capital expenditures totaled $127 million during the year ended December 31, 2004 and related to our existing fleet and corporate infrastructure. A substantial majority of the capital expenditures in 2004 related to the Transocean Drilling segment. See Note 21—Segments, Geographical Analysis and Major Customers.

Note 6—Asset Dispositions

During 2006, we sold three of our Other 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). In addition, we sold and disposed of certain other assets for net proceeds of $5 million and recognized net losses of $6 million ($0.02 per diluted share), which had no tax effect.

In August 2006, we entered into agreements to sell Transocean CGR LLC (owner of the tender rig Charley Graves) and the drilling barge Searex VI in connection with our efforts to dispose of non-strategic assets. We received deposits totaling $1 million, which was reflected as unearned income and included in other current liabilities in our consolidated balance sheet at December 31, 2006. At December 31, 2006, the Charley Graves and Searex VI were classified as assets held for sale in the amounts of $8 million and $2 million, respectively, and were included in other current assets in our consolidated balance sheet. See Note 2―Summary of Significant Accounting Policies and Note 26―Subsequent Events.

During 2005, we sold an Other 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). In addition, we sold and disposed of certain other assets for net proceeds of $18 million and we recognized net losses of $4 million ($0.01 per diluted share), which had no tax effect.

During 2004, we sold an Other Floater (Sedco 602) for net proceeds of $28 million and recognized a gain on the sale of $22 million ($0.07 per diluted share), which had no tax effect, in our Transocean Drilling segment. In addition, we settled insurance claims and sold and disposed of marine support vessels and certain other assets for net proceeds of $22 million. We recognized net losses of $8 million ($4 million, or $0.01 per diluted share, net of tax) in our Transocean Drilling segment and net gains of $6 million ($0.02 per diluted share), which had no tax effect, in our TODCO segment.

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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,
	2006		2005

Term Credit Facility, due August 2008	$	700	$	-
Floating Rate Notes, due September 2008		1,000		-
6.625% Notes, due April 2011		180		183
7.375% Senior Notes, due April 2018		247		247
Zero Coupon Convertible Debentures, due May 2020 (put options exercisable May 2008 and May 2013)		18		17
1.5% Convertible Debentures, due May 2021 (put options exercisable May 2011and May 2016) (a)		400		400
8% Debentures, due April 2027		57		57
7.45% Notes, due April 2027 (put options exercisable April 2007)(b)		95		95
7.5% Notes, due April 2031		598		598
Total Debt		3,295		1,597
Less Debt Due Within One Year (a)(b)		95		400
Total Long-Term Debt	$	3,200	$	1,197

______________________

(a)

The 1.5% Convertible Debentures were classified as debt due within one year at December 31, 2005 since the holders had the option to require us to repurchase the debentures in May 2006.

(b)

The 7.45% Notes are classified as debt due within one year at December 31, 2006 since the holders can exercise their right to require us to repurchase the notes in April 2007.

The scheduled maturity of our debt assumes the bondholders exercise their options to require us to repurchase the 7.45% Notes, Zero Coupon Convertible Debentures and 1.5% Convertible Debentures in April 2007, May 2008 and May 2011, respectively. All amounts are at face value except for the Zero Coupon Convertible Debentures, which are included at the price we would be required to pay should the bondholders exercise their right to require us to repurchase the debentures in May 2008. The scheduled maturities are as follows (in millions):

Years ending December 31,
2007	$	100
2008		1,719
2009		-
2010		-
2011		565
Thereafter		904
Total	$	3,288

Revolving Credit Facility—In July 2005, we entered into a $500 million, five-year revolving credit agreement (“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. The Revolving Credit Facility bears interest, at our option, at a base rate or at the London Interbank Offered Rate (“LIBOR”) plus a margin that can vary from 0.19 percent to 0.58 percent depending on our non-credit enhanced senior unsecured public debt rating. A facility fee, varying from 0.06 percent to 0.17 percent depending on our non-credit enhanced senior unsecured public 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 non-credit enhanced senior unsecured public debt rating, is payable if amounts outstanding under the Revolving Credit Facility are greater than or equal to 50 percent of the total underlying commitment. At December 31, 2006, the applicable margin, facility fee and utilization fee were 0.225 percent, 0.075 percent and 0.100 percent, respectively. The 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 Revolving Credit Facility, of not greater than 60 percent. At December 31, 2006, we had no borrowings outstanding and $1.0 billion remained available under this facility.

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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 is cancelled. Once repaid, the funds cannot be reborrowed. At our election, borrowings may be made under the Term Credit Facility at either (i) the base rate, determined as the greater of (a) the prime loan rate and (b) the sum of the weighted average overnight federal funds rate plus 0.50 percent, or (ii) LIBOR plus 0.30 percent, based on current credit ratings. We paid a fee of 0.065 percent per annum on the daily amount of the unused commitments under the Term Credit Facility through October 3, 2006. In October 2006, we borrowed the full $1.0 billion in capacity. At December 31, 2006, we had $700 million outstanding at a weighted-average interest rate of 5.65 percent.

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, 2006, $1.0 billion principal amount of these notes was outstanding at an interest rate of 5.57 percent.

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, 2006, $166 million and $600 million principal amount of the 6.625% Notes and 7.5% Notes, respectively, were outstanding (see “—Debt Redemptions and Repayments”).

6.5%, 6.75%, 6.95%, 7.375%, 9.125% and 9.5% Senior Notes and Exchange Offer—In March 2002, we completed exchange offers and consent solicitations for TODCO’s 6.5%, 6.75%, 6.95%, 7.375%, 9.125% and 9.5% Senior Notes (“the Exchange Offer”). After the Exchange Offer, approximately $5 million, $8 million, $2 million, $4 million, $10 million and $10 million principal amount of the outstanding 6.5%, 6.75%, 6.95%, 7.375%, 9.125% and 9.5% Senior Notes, respectively, not exchanged remained the obligation of TODCO. At December 31, 2006, $247 million principal amount of 7.375% Senior Notes were outstanding. TODCO’s remaining Senior Notes were deconsolidated from our consolidated balance sheets at December 31, 2004 (see Note 4—TODCO Stock Sales). See “―Debt Redemptions 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 have the right to redeem the debentures for a price equal to 100 percent of the principal. Each holder has the right to require us to repurchase the debentures after five, 10 and 15 years at 100 percent of the principal amount (see “—Debt Redemptions and Repayments”). We may pay this repurchase price with either cash or ordinary shares or a combination of cash and ordinary shares. The debentures are 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 is equivalent to an initial conversion price of $72.136 per share. This ratio is subject to adjustments if certain events take place, and conversion may only occur if the closing sale price per ordinary share exceeds 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 are met. At December 31, 2006, $400 million principal amount of these notes was outstanding.

Zero Coupon Convertible Debentures—In May 2000, we issued Zero Coupon Convertible Debentures due May 2020 with a face value at maturity of $865.0 million. The debentures were issued to the public at a price of $579.12 per debenture and accrue 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 will pay no interest on the debentures prior to maturity and, since May 2003, we have 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 has 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 may pay this repurchase price with either cash or ordinary shares or a combination of cash and ordinary shares. The debentures are convertible into our ordinary shares at the option of the holder at any time at a ratio of 8.1566 shares per debenture, which is equivalent to an initial conversion price of $71.00 per share, subject to adjustments if certain events take place. At December 31, 2006, $26 million face value of these notes was outstanding with a discounted value of $18 million. Should all of the debentures be put to us in May 2008, the debentures will have a discounted value of $19 million.

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Index

TRANSOCEAN INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued

7.45% Notes and 8% Debentures—In April 1997, we issued $100 million aggregate principal amount of 7.45% Notes due April 2027 and $200 million aggregate principal amount of 8% Debentures due April 2027. Holders of the 7.45% Notes may elect to have all or any portion of the 7.45% Notes repaid in April 2007 at 100 percent of the principal amount. The 7.45% Notes, at any time after April 2007, and the 8% Debentures, at any time, are redeemable at our option at a make-whole premium. At December 31, 2006, $100 million and $57 million principal amount of these notes was outstanding, respectively (see “—Debt Redemptions and Repayments”).

Debt Redemptions and Repayments—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.

In December 2004, we acquired, pursuant to a tender offer, a total of $143 million aggregate principal amount of our 8% Debentures due April 2027 at 130.449 percent of face value, or $186 million. We recognized a loss on the repurchase of $45 million ($0.14 per diluted share), which had no tax effect.

In October 2004, we redeemed our $342 million aggregate principal amount outstanding 6.75% Senior Notes due April 2005 at the make-whole premium price provided in the indenture. We redeemed these notes at 102.127 percent of face value or $350 million. We recognized a loss on the redemption of $3 million ($0.01 per diluted share), which had no tax effect.

In March 2004, we redeemed our $290 million aggregate principal amount outstanding 9.5% Senior Notes due December 2008 at the make-whole premium price provided in the indenture. We redeemed these notes at 127.796 percent of face value or $370 million. We recognized a loss on the redemption of debt of $28 million ($0.09 per 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, 2006 and 2005, 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.

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Index

TRANSOCEAN INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued

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.

The major risks in using interest rate derivatives include changes in interest rates affecting the value of such instruments, potential increases in our interest expense due to market increases in floating interest rates in the case of derivatives that exchange fixed interest rates for floating interest rates and the credit worthiness of the counterparties in such transactions.

We had no interest rate swap transactions outstanding as of December 31, 2006 and 2005. See Note 9—Interest Rate Swaps.

The market values of any open swap transactions would be carried on our consolidated balance sheet as an asset or liability depending on the movement of interest rates after the transaction is entered into and depending on the security being hedged.

Should a counterparty default at a time in which the market value of the swap with that counterparty is classified as an asset in our consolidated balance sheet, we may be unable to collect on that asset. To mitigate such risk of failure, we enter into swap transactions with a diverse group of high-quality institutions.

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.

We derive the majority of our revenue from services to international oil companies and government-owned and government-controlled oil companies. Receivables are dispersed in various countries. See Note 21—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, 2006, we had approximately 10,800 employees and we also utilized approximately 1,700 persons through contract labor providers. As of such date, approximately 15 percent of our employees and contract labor worldwide worked under collective bargaining agreements, most of whom worked in Norway, U.K. and Nigeria. Of these represented individuals, 60 percent are working under agreements that are subject to salary negotiation in 2007.

Note 9—Interest Rate Swaps

In June 2001, we entered into interest rate swap agreements in the aggregate notional amount of $700 million with a group of banks relating to our $700 million aggregate principal amount of 6.625% Notes due April 2011. In February 2002, we entered into interest rate swap agreements with a group of banks in the aggregate notional amount of $900 million relating to our $350 million aggregate principal amount of 6.75% Senior Notes due April 2005, $250 million aggregate principal amount of 6.95% Senior Notes due April 2008 and $300 million aggregate principal amount of 9.5% Senior Notes due December 2008. The objective of each transaction was to protect the debt against changes in fair value due to changes in the benchmark interest rate. Under each interest rate swap, we received the fixed rate equal to the coupon of the hedged item and paid LIBOR plus a specified margin, which was designated as the respective benchmark interest rates, on each of the interest payment dates until maturity of the respective notes. The hedges were considered perfectly effective against changes in the fair value of the debt due to changes in the benchmark interest rates over their term. As a result, the shortcut method applied and there was no requirement to periodically reassess the effectiveness of the hedges during the term of the swaps.

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Index

TRANSOCEAN INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued

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, 2006, 2005 and 2004, such reduction amounted to $3 million ($0.01 per diluted share), $9 million ($0.03 per diluted share) and $23 million ($0.07 per diluted share), respectively. As a result of the redemption of our 6.95% Senior Notes in March 2005, 6.75% Senior Notes in October 2004 and 9.5% Senior Notes in March 2004, we recognized $13 million ($0.08 per diluted share) and $26 million ($0.08 per diluted share) during the years ended December 31, 2005 and 2004, respectively, of the unamortized fair value adjustment as a reduction to our loss on redemption of debt (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 this repurchase (see Note 7—Debt). There were no tax effects related to these reductions. At December 31, 2006 and 2005, the remaining balance to be amortized was $15 million and $18 million, respectively, and related to the 6.625% Notes due April 2011.

At December 31, 2006 and 2005, 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, 2006				December 31, 2005
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(in millions)				(in millions)

Debt	$	3,295	$	3,473	$	1,597	$	1,865

Note 11—Other Current Liabilities

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

	December 31,
	2006		2005

Accrued payroll and employee benefits	$	150	$	121
Deferred revenue		77		43
Unearned income		67		30
Accrued interest		24		19
Accrued taxes, other than income		30		17
Other		21		12
Total Other Current Liabilities	$	369	$	242

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Index

TRANSOCEAN INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued

Note 12—Other Long-Term Liabilities

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

	December 31,
	2006		2005

Long-term income taxes payable	$	141	$	116
Accrued pension liabilities		84		65
Accrued retiree life insurance and medical benefits		35		36
Deferred revenue		28		16
Other		55		53
Total Other Long-Term Liabilities	$	343	$	286

Note 13—Repurchase of Ordinary Shares

In October 2005, our board of directors authorized the repurchase of up to $2.0 billion of our ordinary shares. 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.

In May 2006, our board of directors authorized an increase in the overall amount of ordinary shares which may be repurchased under our share repurchase program from $2.0 billion to $4.0 billion.

The summary of shares repurchased is as follows (in millions, except per share data):

	December 31,
	2006		2005

Shares repurchased and retired	$	2,600	$	400
Ordinary shares		35.7		6.0
Average purchase price per share	$	72.78	$	66.50

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 Revolving Credit Facility and our Term Credit Facility and proceeds from the issuance of our Floating Rate Notes (see Note 7—Debt).

At December 31, 2006, we repurchased a total of $3.0 billion of our ordinary shares and we had authority to repurchase an additional $1.0 billion of our ordinary shares under the program. See Note 26—Subsequent Events

Note 14—Supplementary Cash Flow Information

Non-cash investing activities for the years ended December 31, 2006, 2005 and 2004 included $186 million, $31 million and $10 million, respectively, related to accruals of capital expenditures. The accruals have been reflected in the consolidated balance sheet as an increase in property and equipment, net and accounts payable.

Cash payments for interest were $125 million, $129 million and $201 million for the years ended December 31, 2006, 2005 and 2004, respectively. Cash payments for income taxes, net, were $125 million, $107 million and $75 million for the years ended December 31, 2006, 2005 and 2004, respectively.

Note 15—Income Taxes

We are a Cayman Islands company, and we are not subject to income tax in the Cayman Islands. 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 income taxes because the countries in which we operate 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.

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Index

TRANSOCEAN INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued

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

	Years ended December 31,
	2006			2005		2004

Current provision	$	245		$	60	$	73
Deferred provision (benefit)		(23	)		27		18
Income tax provision	$	222		$	87	$	91

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

	December 31,
	2006			2005
Deferred Tax Assets
Tax credit carryforwards	$	118		$	101
Net operating loss carryforwards		56			85
Retirement and benefit plan accruals		35			19
Other accruals		11			12
Deferred interest expense deduction		11			-
Other		24			27
Valuation allowance		(59	)		(48	)
Total Deferred Tax Assets		196			196

Deferred Tax Liabilities
Depreciation and amortization		(219	)		(222	)
Other		(15	)		(16	)
Total Deferred Tax Liabilities		(234	)		(238	)

Net Deferred Tax Liabilities	$	(38	)	$	(42	)

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. 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 financial position, results of operations or cash flows.

The $4 million decrease in our net deferred tax liability is composed of the deferred tax benefit of $23 million, reduced by a $9 million adjustment to additional paid-in capital for the tax effect of prior year equity compensation deductions, a $3 million adjustment to accumulated other comprehensive income for the tax effect of the adoption of SFAS 158, and an $8 million reclassification to current income tax liability for prior year prepaid tax on an intracompany transaction.

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. During the year ended December 31, 2006, the valuation allowance for non-current deferred tax assets increased $11 million, which resulted primarily from the increase of foreign tax credits. In the year ended December 31, 2005, the valuation allowance decreased $67 million, which resulted primarily from the utilization of the underlying deferred assets to offset current year income, from adjustments related to the settlement of certain audits and from adjustments related to the restructuring of certain of our non-U.S. operations.

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Index

TRANSOCEAN INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued

Our U.K. net operating loss carryforwards do not expire. The tax effect of the U.K. net operating loss carryforwards was $56 million at December 31, 2006. Our U.S. foreign tax credit carryforwards of $59 million, net of valuation allowances of $58 million, will expire between 2009 and 2016. Our U.S. alternative minimum tax credits of $1 million do not expire.

In addition to our recognized tax attributes, we have an unrecognized U.S. capital loss carryforward and an unrecognized U.S. net operating 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. In the year ended December 31, 2005, we recognized a benefit of $66 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, 2006 was $841 million. We have not recognized a deferred tax asset for certain of our U.S. net operating loss carryforwards as it is not probable that we will realize the benefit of the underlying tax deduction. Should an opportunity to utilize the unrecognized net operating loss arise, the total potential tax benefit at December 31, 2006 was $8 million.

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. For the three years ended December 31, 2006, there was no Cayman Islands income or profits tax, withholding tax, capital gains tax, capital transfer tax, estate duty or inheritance tax payable by a Cayman Islands company or its shareholders. We have obtained assurance from the Cayman Islands government under the Tax Concessions Law (1995 Revision) 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.

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.

Our 2004 and 2005 U.S. federal income tax returns are currently under examination by the U.S. Internal Revenue Service (“IRS”). We believe our returns are materially correct as filed, and we intend to vigorously defend against any proposed changes. While we cannot predict or provide assurance as to the final outcome, we do not expect the ultimate settlement of any liability resulting from any examination to have a material adverse effect on our consolidated financial position, results of operations or cash flows.

In April 2006, we received notice from the Norwegian tax authorities regarding their intent to propose adjustments to taxable income for the tax years 1999, 2001 and 2002. These proposed assessments could result in an increase in tax of approximately $260 million, plus interest and the authorities further indicated they intend to impose penalties, which could range from 15 to 60 percent of the assessments. The anticipated assessments relate to restructuring transactions undertaken in 2001 and 2002. The Norwegian tax authorities initiated inquiries in September 2004 related to the restructuring transactions and a separate dividend payment made during 2001. In February 2005, we filed a response to these inquiries. In March 2005, pursuant to court orders, the Norwegian tax authorities took action to obtain additional information regarding these transactions. We have continued to respond to information requests from the Norwegian authorities and filed a formal protest to the proposed assessment in June 2006. We also believe the Norwegian authorities are contemplating a tax assessment of approximately $104 million on the dividend, plus interest and a penalty, which could range from 15 to 60 percent of the assessment. Norwegian civil tax and criminal authorities continue to investigate the restructuring transactions and dividend. We plan to vigorously contest any assertions by the Norwegian authorities in connection with the restructuring transactions or dividend. 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 financial position, results of operations or cash flows.

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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 financial position, results of operations or cash flows.

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 $5 million in goodwill and an income tax receivable of $5 million in December 2006.

Our wholly owned subsidiary, Transocean Holdings Inc. (“Transocean Holdings”), entered into a tax sharing agreement with TODCO in connection with the TODCO IPO. The tax sharing agreement governs Transocean Holdings’ and TODCO’s 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 this agreement, 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 the account of Transocean Holdings. Accordingly, Transocean Holdings generally is liable for any income taxes that accrued on or before the closing of the TODCO IPO, but TODCO generally must pay Transocean Holdings 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. While TODCO was included in our consolidated statements of operations and balance sheet as a consolidated subsidiary until the fourth quarter of 2004, we followed the provisions of SFAS No. 109, Accounting for Income Taxes (“SFAS 109”), which allowed us to evaluate the recoverability of the deferred tax assets associated with the tax sharing agreement considering TODCO’s deferred tax liabilities.

Because we no longer own shares of TODCO, we no longer include TODCO as a consolidated subsidiary in our financial statements. As a result, we recorded a non-cash charge of $167 million ($0.51 per diluted share), which had no tax effect, in the fourth quarter of 2004 related to contingent amounts due from TODCO under the tax sharing agreement. The non-cash charge was necessary as the future payments under the tax sharing agreement are dependent on TODCO generating future taxable income, which cannot be assumed until such income is actually generated. Future payments we receive from TODCO’s utilization of the pre-TODCO IPO deferred tax assets will be recognized in other income as those amounts are realized, which is generally based on when TODCO files its annual tax returns. In 2006, we reached a settlement agreement with TODCO regarding the dispute in which we were seeking payment of these amounts, and TODCO was seeking to void the entire tax sharing agreement. See Note 17—Commitments and Contingencies.

In 2006 and 2005, respectively, we recognized $51 million ($0.16 per diluted share) and $11 million ($0.03 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, 2006, we received $66 million in estimated payments pertaining to TODCO’s 2006 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 2006 federal and state income tax returns. As of December, 31, 2006, tax benefits in excess of $200 million remain to be utilized by TODCO under the tax sharing agreement, based on estimated usage to date. The ultimate amount and timing of the utilization is contingent on a variety of factors including potential revisions to the tax benefits upon examination by the IRS and the amount of taxable income that TODCO realizes in future years.

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Index

TRANSOCEAN INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued

As a result of the deconsolidation of TODCO from our other U.S. subsidiaries for U.S. federal income tax purposes in conjunction with the TODCO IPO (see Note 4—TODCO Stock Sales), we established an initial valuation allowance in the first quarter of 2004 of $31 million ($0.09 per diluted share) against the estimated deferred tax assets of TODCO in excess of its deferred tax liabilities and other deferred tax assets not expected to be realized, taking into account prudent and feasible tax planning strategies as required by SFAS 109. We adjusted the initial valuation allowance during 2004 to reflect changes in our estimate of the ultimate amount of TODCO’s deferred tax assets and other deferred tax assets not expected to be realized. An allocation of tax benefits between TODCO and our other U.S. subsidiaries occurred in the third quarter of 2005 upon the filing of our 2004 U.S. consolidated federal income tax return. As a result of this allocation, we recorded additional income tax expense of approximately $8 million ($0.02 per diluted share) in 2005 to adjust the previously estimated allocation. This allocation is subject to potential revision upon subsequent IRS audit of our tax return and such revision, should it occur, could impact our effective tax rate for future years as well as the ultimate amount of payments by TODCO related to the tax sharing agreement.

Note 16—Off-Balance Sheet Arrangement

We leased the semisubmersible M. G. Hulme, Jr. from Deep Sea Investors, L.L.C. (“Deep Sea Investors”), a special purpose entity formed by several leasing companies to acquire the rig from one of our subsidiaries in November 1995 in a sale/leaseback transaction. We accounted for the lease of this semisubmersible drilling rig as an operating lease. We recorded $5 million and $13 million of such rent expense for the years ended December 31, 2005 and 2004, respectively. In May 2005, we purchased the rig for $43 million. The rig was reflected as property and equipment in the consolidated balance sheet at December 31, 2005.

Effective December 31, 2003, we adopted and applied the provisions of FASB Interpretation No. 46, Consolidation of Variable Interest Entities (“FIN 46”), as revised December 31, 2003, for all variable interest entities. 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. Because the sale/leaseback agreement was with an entity in which we had no direct investment, we were not entitled to receive the financial information of the leasing entity and the equity holders of the leasing company would not release the financial statements or other financial information to us in order for us to make the determination of whether the entity was a variable interest entity. In addition, without the financial statements or other financial information, we were unable to determine if we were the primary beneficiary of the entity and, if so, what we would have consolidated. We had no exposure to loss as a result of the sale/leaseback agreement. As a result of the purchase of the M. G. Hulme, Jr., we are no longer associated with Deep Seas Investors and, as such, are no longer required to review for FIN 46 applicability.

Note 17—Commitments and Contingencies

Operating Leases¾We 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. As of December 31, 2006, future minimum rental payments related to noncancellable operating leases are as follows (in millions):

Years ending December 31,
2007	$	22
2008		13
2009		8
2010		6
2011		5
Thereafter		22
Total	$	76

Rental expense for all operating leases, including leases with terms of less than one year, was approximately $32 million, $30 million and $40 million for the years ended December 31, 2006, 2005 and 2004, respectively.

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Index

TRANSOCEAN INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued

Purchase Obligations—At December 31, 2006, our purchase obligations as defined by SFAS No.47, Disclosure of Long-Term Obligations (as amended), related to our Sedco 706 upgrade shipyard project and three enhanced Enterprise-class newbuilds are as follows (in millions):

Years ending December 31,
2007	$	616
2008		571
2009		335
2010		6
Total	$	1,528

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 over 700 persons that allege personal injury arising out of asbestos exposure in the course of their employment by some of these defendants between 1965 and 1986. The complaints also name as defendants certain of TODCO's subsidiaries to whom we may owe indemnity. 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 yet been able to conduct extensive discovery nor determine the number of plaintiffs that were employed by our subsidiaries or otherwise have any connection with our drilling operations. We intend to defend ourselves vigorously and, based on the limited information available to us at this time, we do not expect the liability, if any, resulting from these matters to have a material adverse effect on our consolidated financial position, results of operations or cash flows.

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Index

TRANSOCEAN INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued

In November 2006, we reached a negotiated settlement with TODCO, our former subsidiary, arising out of the tax sharing agreement that we entered into with TODCO in connection with TODCO’s initial public offering in 2004. As a result of the settlement, we entered into an amended and restated tax sharing agreement with TODCO. Under the terms of the amended and restated agreement, TODCO will pay us for 55 percent of the value of the tax deductions arising from the exercise of options to purchase our ordinary shares by current and former employees and directors of TODCO. This payment rate applies retroactively to amounts previously accrued by TODCO and to future payments. Under the terms of the amended and restated agreement, TODCO will also receive a $3 million federal tax benefit for use of certain state and foreign tax assets. The amended and restated agreement also provides that the change of control provision contained in the agreement no longer applies to option deductions. However, if TODCO uses the option deductions after a change of control, it would be required to pay us for 55 percent of the value of those deductions. See Note 15—Income Taxes.

We are involved in a number of other lawsuits, including a labor dispute involving Hull Blyth workers in Angola previously reported that is not material to us, all of which have arisen in the ordinary course of our business. We do not expect the liability, if any, resulting from these matters to have a material adverse effect on our consolidated financial position, results of operations or cash flows. We are also involved in various tax matters (see Note 15—Income Taxes).

Retained Risk—We retain the risk, through self-insurance, for the deductible portion of our insurance coverage as well as losses due to hurricanes in the U.S. Gulf of Mexico in excess of $250 million in aggregate annually, except in the case of a total loss of a rig where the annual limit is approximately $300 million in aggregate. We also retain any risk of losses in excess of the insured value of our drilling rig fleet (currently $13.0 billion in aggregate), losses in excess of the $930 million limit on personal injury and third-party liability claims and losses related to loss of revenue. We currently maintain a $10 million per occurrence insurance deductible on hull and machinery, a $10 million per occurrence deductible on personal injury liability and a $5 million per occurrence deductible on third party property damage. In addition to the per occurrence deductibles described above, we also have aggregate deductibles that are applied to any occurrence in excess of the per occurrence deductible until the aggregate deductible is exhausted. Such aggregate deductibles are $20 million in the case of our hull and machinery coverage and $25 million in the case of our personal injury liability and third party property damage coverage. Additionally, for our personal injury and third-party damage liabilities, we have retained $20 million of the risk that exceeds our deductible amount. 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 $405 million and $314 million at December 31, 2006 and 2005, 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 $6 million and $8 million at December 31, 2006 and 2005, respectively.

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Index

TRANSOCEAN INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued

Note 18—Share-Based Compensation Plans

We have a long-term incentive plan for executives, key employees and outside directors (the “Incentive Plan”). Under the Incentive Plan, awards can be granted in the form of stock options, restricted shares, deferred units, stock appreciation rights (“SARs”) and cash performance awards. Such awards 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 Incentive Plan. Options issued to date under the Incentive Plan 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 Plan have a two-year performance year with the number of options, shares or deferred units earned being determined following the completion of the performance year (the “determination date”) at which time one-third of the options, shares or deferred units vest. Additional vesting occurs on January 1 of the two subsequent years following the determination date. As of December 31, 2006, we were authorized under the Incentive Plan to grant awards covered by up to (i) 22.9 million ordinary shares, which includes up to 6.0 million restricted shares, to employees and (ii) 0.6 million ordinary shares to outside directors. We issue new shares when stock options are exercised and restricted shares and deferred units vest.

Prior to adoption of SFAS 123(R), we used the Black-Scholes-Merton model to value stock options granted or modified under SFAS 123 and have elected to continue using this model to value stock options granted or modified under SFAS 123(R). We determine the fair value of options granted or modified based on the expected term, risk-free interest rate, dividend yield and expected volatility. The expected term 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.

Under SFAS 123, we based expected volatility solely on historical data. Upon the adoption of SFAS 123(R), we began using a blended volatility for the volatility assumption. We changed the calculation of our volatility to better reflect our expectation of how our share price will react to the future cyclicality of our industry. The blended volatility is calculated using two components. The first component is derived from volatility computed from historical data for a year of time approximately equal to the expected term of the stock option, starting from the date of grant. 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. This change in estimate did not have a material effect on our consolidated financial statements. The fair value for restricted ordinary shares and deferred units is based on the market price of our ordinary shares on the date of grant.

Share-based compensation expense is recorded on the same financial statement line item as cash compensation paid to the same employees.

Due to termination of employment for convenience of the company, we had 11 and seven individuals whose share-based compensation awards were modified during the years ended December 31, 2005 and 2004, respectively. As a result of these modifications, we recorded additional share-based compensation expense of $2 million in both years ended December 31, 2005 and 2004. There were no significant modifications during the year ended December 31, 2006.

As of December 31, 2006, total unrecognized compensation costs related to all unvested share-based awards totaled $36 million, which is expected to be recognized over a weighted average period of 2.3 years.

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Index

TRANSOCEAN INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued

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 Plan during the year ended December 31, 2006:

	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, 2006		6,312,707		$	29.43

Granted		2,270			82.61
Exercised		(2,027,626	)		31.68
Forfeited		(815	)		51.92
Outstanding at December 31, 2006		4,286,536		$	28.38		3.56	$	225

Vested or expected to vest as of December 31, 2006		4,279,923		$	28.38		3.56	$	225
Exercisable at December 31, 2006		4,200,752		$	28.46		3.54	$	220

Time-based options expected to vest in the table above include options that have not time vested, where the amount is net of a discount for our estimated termination related forfeitures. There were 53,450 time-based options granted during the year ended December 31, 2005, with a weighted-average grant-date fair value of $17.83 per share. No time-based options were granted during the year ended December 31, 2004.

The total pretax intrinsic value of time-based options exercised during the year ended December 31, 2006 was $99 million. There were 7,695,838 and 1,153,857 time-based options exercised during the years ended December 31, 2005 and 2004, respectively. The total pretax intrinsic value of time-based options exercised was $190 million and $17 million during the years ended December 31, 2005 and 2004, respectively.

The following table summarizes unvested time-based option activity under the Incentive Plan during the year ended December 31, 2006:

	Number of Shares Under Option			Weighted-Average Grant-Date Fair Value per Share
Unvested at January 1, 2006		184,998		$	8.71

Granted		2,270			32.01
Vested		(101,477	)		8.31
Forfeited		(7	)		14.11
Unvested at December 31, 2006		85,784		$	9.81

The total grant-date fair value of time-based options vested during the year ended December 31, 2006 was $1 million. There were 595,412 and 1,407,602 time-based options that vested during the years ended December 31, 2005 and 2004, respectively. The total grant-date fair value of time-based options that vested was $7 million and $20 million during the years ended December 31, 2005 and 2004, respectively.

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Index

TRANSOCEAN INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued

Restricted Ordinary Shares—The following table summarizes unvested share activity for time-based vesting restricted ordinary shares (“time-based shares”) granted under the Incentive Plan during the year ended December 31, 2006:

	Number of Shares			Weighted-Average Grant-Date Fair Value per Share
Unvested at January 1, 2006		46,940		$	42.63

Granted		369,229			78.40
Vested		(22,602	)		40.21
Forfeited		(5,572	)		71.78
Unvested at December 31, 2006		387,995		$	76.40

The total grant-date fair value of time-based shares that vested during the year ended December 31, 2006 was $1 million. There were 35,230 and 8,281 time-based shares granted during the years ended December 31, 2005 and 2004, respectively. The weighted-average grant-date fair value of time-based shares granted was $49.01 and $28.12 per share for the years ended December 31, 2005 and 2004, respectively. There were 14,359 and 21,519 time-based shares that vested during the years ended December 31, 2005 and 2004, respectively. The total grant-date fair value of time-based shares that vested was less than $1 million for both years ended December 31, 2005 and 2004.

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 Plan during the year ended December 31, 2006:

	Number of Units			Weighted-Average Grant-Date Fair Value per Share
Unvested at January 1, 2006		30,776		$	37.48

Granted		42,369			81.55
Vested		(14,289	)		35.88
Forfeited		(244	)		78.61
Unvested at December 31, 2006		58,612		$	69.55

The total grant-date fair value of the time-based units vested during the year ended December 31, 2006 was $1 million. There were 18,600 and 20,538 time-based units granted during the years ended December 31, 2005 and 2004, respectively. The weighted-average grant-date fair value was $45.02 and $27.17 per share for the years ended December 31, 2005 and 2004, respectively. There were 6,080 time-based units vested with a total grant-date fair value of less than $1 million during the year ended December 31, 2005. No time-based units vested during the year ended December 31, 2004.

SARs—The following table summarizes time-based vesting SARs activity under the Incentive Plan during the year ended December 31, 2006:

	Number of SARs			Weighted-Average Exercise Price per Share		Weighted-Average Remaining Contractual Term (years)		Aggregate Intrinsic Value (in millions)
Outstanding at January 1, 2006		50,976		$	35.43

Exercised		(18,390	)		33.68
Outstanding at December 31, 2006		32,586		$	36.43		2.13	$	1

Exercisable at December 31, 2006		32,586		$	36.43		2.13	$	1

No SARs were granted during the years ended December 31, 2006, 2005 and 2004. The total pretax intrinsic value of SARs exercised was $1 million during the year ended December 31, 2006. There were 80,782 and 666 SARs exercised during the years ended December 31, 2005 and 2004, respectively. The total pretax intrinsic value of SARs exercised was $1 million and less than $1 million for the years ended December 31, 2005 and 2004, respectively.

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Index

TRANSOCEAN INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued

As of December 31, 2006, all SARs granted under the Incentive Plan are fully vested. There were 6,053 and 13,494 SARs vested during the years ended December 31, 2005 and 2004, respectively. The total grant-date fair value of SARs vested was less than $1 million for both years ended December 31, 2005 and 2004.

Performance-Based Awards

Stock Options—We granted 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 year at the determination date. The following table summarizes vested and unvested performance-based option activity under the Incentive Plan during the year ended December 31, 2006:

	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, 2006		1,253,125		$	33.19

Granted		350,990			78.17
Exercised		(168,286	)		22.78
Forfeited		(151,314	)		28.12
Outstanding at December 31, 2006		1,284,515		$	47.44		8.11	$	43

Vested or expected to vest as of December 31, 2006		810,945		$	36.62		7.61	$	36
Exercisable at December 31, 2006		195,805		$	24.20		6.95	$	11

The number of performance-based options expected to vest in the table above includes both (i) options that have reached their determination date but have not time vested, in which case the amount is net of a discount for our estimated termination-related forfeitures, and (ii) option grants that have not reached their determination date, in which case the amount is net of a discount for expected forfeitures based upon our current estimate of the number of options expected to be earned using the performance criteria at the determination date.

There were 324,714 and 544,273 performance-based options granted during the years ended December 31, 2005 and 2004, respectively. The weighted-average grant-date fair value of performance-based options granted was $20.79 and $11.26 per share during the years ended December 31, 2005 and 2004, respectively.

The total pretax intrinsic value of performance-based options exercised during the year ended December 31, 2006 was $10 million. There were 91,423 performance-based options exercised, with a total pretax intrinsic value of $3 million, during the year ended December 31, 2005. No performance-based options were exercised during the year ended December 31, 2004.

The following table summarizes unvested performance-based option activity under the Incentive Plan during the year ended December 31, 2006:

	Number of Shares Under Option			Weighted-Average Grant-Date Fair Value per Share
Unvested at January 1, 2006		1,178,535		$	13.12

Granted		350,990			30.21
Vested		(289,501	)		9.70
Forfeited		(151,314	)		11.26
Unvested at December 31, 2006		1,088,710		$	19.77

Unvested options include options that have not reached their determination date and thus the number of such options could be reduced due to the performance criteria applied at the determination date. Options forfeited or cancelled include the adjustment of options at the determination date due to the application of the performance criteria.

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Index

TRANSOCEAN INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued

The total grant-date fair value of performance-based options vested during the year ended December 31, 2006 was $3 million. There were 166,013 performance-based options vested with a total grant-date fair value of $1 million during the year ended December 31, 2005. No performance-based options vested during the year ended December 31, 2004.

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 year at the determination date. The following table summarizes unvested share activity for performance-based shares granted under the Incentive Plan during the year ended December 31, 2006:

	Number of Shares			Weighted-Average Grant-Date Fair Value per Share
Unvested at January 1, 2006		1,242,829		$	35.56

2004 Performance-based shares converted to deferred units		(133,932	)		28.12
2005 Performance-based shares converted to deferred units		(103,152	)		56.34

Granted		85,433			77.56
Vested		(251,137	)		24.46
Forfeited		(156,573	)		30.38
Unvested at December 31, 2006		683,468		$	44.53

Unvested shares include shares that have not reached their determination date and thus the number of such shares could be reduced due to the performance criteria applied at the determination date. Shares forfeited or cancelled 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, 2006 was $6 million. There were 377,772 and 645,604 performance-based shares granted during the years ended December 31, 2005 and 2004, respectively. The weighted-average grant-date fair value was $57.90 and $28.12 per share during the years ended December 31, 2005 and 2004, respectively. There were 272,913 performance-based shares that vested with a total grant-date fair value of $6 million during the year ended December 31, 2005. No performance-based shares vested during the year ended December 31, 2004.

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 year at the determination date. The following table summarizes unvested unit activity for performance-based units granted under the Incentive Plan during the year ended December 31, 2006:

	Number of Units			Weighted-Average Grant-Date Fair Value per Share
Unvested at January 1, 2006		91,338		$	29.15

2004 Performance-based shares converted to deferred units		133,932			28.12
2005 Performance-based shares converted to deferred units		103,152			56.34
Granted		108,215			78.61
Vested		(58,942	)		26.50
Forfeited		(65,174	)		28.86
Unvested at December 31, 2006		312,521		$	55.00

Unvested units include units that have not reached their determination date and thus the number of such units could be reduced due to the performance criteria applied at the determination date. Units forfeited or cancelled 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, 2006 was $2 million. There were 10,189 and 54,747 performance-based units granted during the years ended December 31, 2005 and 2004, respectively. The weighted-average grant-date fair value of performance-based units granted was $57.90 and $28.12 per share during the years ended December 31, 2005 and 2004, respectively. There were 15,219 performance-based units that vested with a total grant-date fair value of less than $1 million during the year ended December 31, 2005. No performance-based units vested during the year ended December 31, 2004.

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Index

TRANSOCEAN INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued

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 20 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, 2006, 962,924 ordinary shares were available for issuance pursuant to the ESPP after taking into account the shares to be issued for the 2006 plan year.

Note 19—Retirement Plans, Other Postemployment Benefits and Other Benefit Plans

On December 31, 2006, we adopted the recognition and disclosure provisions of SFAS No.158, Employer’s Accounting for Defined Benefit Pension and other Postretirement Plans, an amendment of FASB Statements No. 87, 88 and 123(R) (“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 No. 87, Employers' 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.

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 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 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
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”.

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Index

TRANSOCEAN INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued

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 defined benefit pension benefits we provide are comprised of the U.S. Plans, the Norway Plans and Other Non-U.S. 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.

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,
	2006			2005
Change in projected benefit obligation
Projected benefit obligation at beginning of year	$	338	(a)	$	328
Service cost		20			18
Interest cost		19			18
Foreign currency exchange rate changes		5			(4	)
Settlements / curtailments		-			(2	)
Benefits paid		(15	)		(18	)
Actuarial gains		(16	)		(4	)
Projected benefit obligation at end of year	$	351		$	336

Change in plan assets
Fair value of plan assets at beginning of year	$	242		$	237
Actual return on plan assets		28			18
Employer contributions		15			6
Foreign currency exchange rate changes		3			(3	)
Actuarial gains		-			2
Benefits paid		(15	)		(18	)
Fair value of plan assets at end of year	$	273		$	242

Funded status	$	(78	)	$	(94	)
Unrecognized transition asset		(b	)		(3	)
Unrecognized net actuarial loss		(b	)		74
Unrecognized prior service cost		(b	)		(2	)
Accrued pension liability	$	(b	)	$	(25	)

Amounts recognized in the consolidated balance sheets consist of:
Pension asset, non-current	$	5		$	-
Prepaid benefit cost, non-current		-			3
Intangible asset		-			1
Accrued pension liability, current		1			-
Accrued pension liability, non-current		82			65
Accumulated other comprehensive income (c)		(42	)		(36	)

__________
(a)	Change in beginning balance is due to the addition of the Indonesia Plan’s January 1, 2006 beginning balance of $2 million.
(b)	Disclosure is not applicable upon adoption of SFAS 158.
(c)	Amounts are before income tax effect of $9 million and $13 million for December 31, 2006 and 2005, respectively.

The accumulated benefit obligation for all defined benefit pension plans was $290 million and $279 million at December 31, 2006 and 2005, respectively.

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Index

TRANSOCEAN INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued

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,
	2006		2005

Projected benefit obligation	$	273	$	327
Fair value of plan assets		190		232

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,
	2006		2005

Accumulated benefit obligation	$	189	$	261
Fair value of plan assets		154		219

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

	Years ended December 31,
	2006			2005			2004
Components of Net Periodic Benefit Cost (a)
Service cost	$	20		$	18		$	17
Interest cost		19			18			17
Expected return on plan assets		(20	)		(21	)		(20	)
Recognized net actuarial losses		5			4			2
Amortization of prior service cost		1			1			1
Amortization of net transition obligation		1			-			-
SFAS 88 settlements/curtailments		-			2			-
Benefit cost	$	26		$	22		$	17

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

____________
(a)	Amounts are before income tax effect.

No plan assets are expected to be returned to us during the year ending December 31, 2007.

There were no amounts recognized in other comprehensive income as components of net periodic benefit cost in the years ended December 31, 2006, 2005 and 2004.

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,
	2006 (a), (b)

Net loss	$	42
Net prior service credit		(1	)
Net transition obligation		1
Total unrecognized accumulated other comprehensive income	$	42
_____________
(a) Disclosure is not applicable for December 31, 2005 and 2004.
(b) Amounts are before income tax effect.

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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 expected to be recognized as components of net periodic benefit cost during the next fiscal year (in millions):

	Year ending December 31,
	2007

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

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 a third party 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. Prior to December 31, 2005, we utilized the Moody’s Aa long-term corporate bond yield 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,
	2006			2005

Discount rate		5.72	%		5.60	%
Rate of compensation increase		4.27	%		4.50	%

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

	December 31,
	2006			2005			2004

Discount rate		5.69	%		5.63	%		6.01	%
Expected long-term rate of return on plan assets		8.49	%		8.70	%		8.73	%
Rate of compensation increase		4.54	%		4.52	%		5.00	%

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.

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Index

TRANSOCEAN INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued

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,
	2006			2005

Equity securities		60.3	%		55.5	%
Debt securities		29.2	%		31.3	%
Other		10.5	%		13.2	%
Total		100.0	%		100.0	%

We contributed $15 million to our defined benefit pension plans in 2006, which were funded from our cash flows from operations. During 2006, contributions of $5 million were made to the funded U.S. Plans, $9 million to the funded Norway Plans and $1 million to the Other Non-U.S. Plans.

We expect to contribute a total of $17 million to the Transocean Plans in 2007. These contributions are comprised of an estimated $8 million to meet the minimum funding requirements for the funded U.S. Plans, $1 million to fund expected benefit payments for the unfunded U.S. Plans and the Other Non-U.S. Plans and an estimated $8 million for the funded Norway Plans.

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

Years ending December 31,
2007	$	15
2008		16
2009		17
2010		17
2011		18
2012-2016		97

Postretirement Benefits Other Than Pensions (“OPEB”)—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.

We amended our postretirement medical plans effective January 1, 2004. The amendments placed limits on our medical benefits payments to retirees. In addition, the amendments harmonized the benefits provided under each of our postretirement medical plans. These changes to the plans resulted in a reduction of $23 million in plan benefit obligations.

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Index

TRANSOCEAN INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued

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,
	2006			2005
Change in benefit obligation
Benefit obligation at beginning of year	$	41		$	38
Service cost		1			1
Interest cost		2			2
Actuarial (gains) losses		(6	)		2
Participants’ contributions		1			1
Benefits paid		(3	)		(3	)
Benefit obligation at end of year	$	36		$	41

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	$	(36	)	$	(41	)
Unrecognized net actuarial gain		(a	)		24
Unrecognized prior service cost		(a	)		(19	)
Accrued postretirement benefit liability	$	(a	)	$	(36	)

Amounts recognized in the consolidated balance sheets consist of:
Accrued postretirement benefit liability, current	$	1		$	-
Accrued postretirement benefit liability, non-current		35			36
Accumulated other comprehensive income		−			-

____________
(a)	Not applicable upon adoption of SFAS 158.

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

	Years ended December 31,
	2006			2005			2004
Components of Net Periodic Benefit Cost (a)
Service cost	$	1		$	1		$	1
Interest cost		2			2			2
Amortization of prior service credit		(2	)		(2	)		(2	)
Recognized net actuarial losses		1			2			1
Benefit Cost	$	2		$	3		$	2

____________
(a)	Amounts are before income tax effect.

There were no amounts recognized in other comprehensive income as components of net periodic benefit cost in the years ended December 31, 2006, 2005 and 2004.

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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,
	2006(a), (b)

Net prior service credit	$	(17	)
Net loss		17
Net transition obligation		-
Total unrecognized accumulated other comprehensive income	$	-

__________
(a)	Disclosure is not applicable for December 31, 2005 and 2004.
(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,
	2007

Net loss	$	1
Net prior service credit		(2	)
Net transition obligation		-
Total amount in accumulated other comprehensive income expected to be recognized next year	$	(1	)

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 10.25 percent for 2006 reducing on an average of approximately 0.65 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 5.64 percent and 5.37 percent for the years ended December 31, 2006 and 2005, respectively.

Weighted-average assumptions used to determine net periodic benefit cost were as follows:

	December 31,
	2006			2005			2004

Discount rate		5.37	%		5.50	%		6.00	%

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Index

TRANSOCEAN INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued

Assumed health care cost trend rates were as follows:

	December 31,
	2006			2005

Health care cost trend rate assumed for next year		10.25	%		9	%
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			2009

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 have the following effects (in millions):

	One-		One-
	Percentage		Percentage
	Point		Point
	Increase		Decrease
Effect on total service and interest cost components in 2006	$	-	$	-
Effect on postretirement benefit obligations as of December 31, 2006	$	4	$	(5	)

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

Years ending December 31,
2007	$	2
2008		2
2009		2
2010		2
2011		2
2012-2016		11

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 as 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 $26 million, $21 million and $20 million of expense related to our defined contribution plans for the years ended December 31, 2006, 2005 and 2004, respectively.

Deferred Compensation Plan—We provided a Deferred Compensation Plan (the “Plan”). The 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 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 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 Plan during the years ended December 31, 2006, 2005 or 2004.

In 2005, the Plan was amended to effectively freeze the Plan as of December 31, 2004.

Note 20—Investments in and Advances to Unconsolidated Affiliates

We have 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. We recognized investments in and advances to unconsolidated affiliates of $9 million and $8 million for the years ended December 31, 2006 and 2005, respectively, and reported these amounts in other assets in our consolidated balance sheet. See Note 22—Related Party Transactions.

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Index

TRANSOCEAN INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued

We recognized equity in earnings of unconsolidated affiliates of $5 million, $10 million and $9 million for the three years ended December 31, 2006, 2005 and 2004, respectively, and reported these amounts in other, net in our consolidated statement of operations.

As a result of our deconsolidation of TODCO at December 17, 2004, we accounted for our 22 percent interest in TODCO as an investment in an unconsolidated subsidiary and recognized our investment in TODCO under the equity method of accounting. As a result of the May Offering, we accounted for our remaining two percent interest using the cost method of accounting and as a result of the June Sale, we no longer own any shares of TODCO. See Note 4—TODCO Stock Sales.

Note 21—Segments, Geographical Analysis and Major Customers

Through December 16, 2004, our operations were aggregated into two reportable segments: (i) Transocean Drilling and (ii) TODCO. The Transocean Drilling segment consists of floaters, jackups and other rigs used in support of offshore drilling activities and offshore support services. The TODCO segment consisted of our interest in TODCO, which conducts jackup, drilling barge, land rig, submersible and other operations located in the U.S. Gulf of Mexico and inland waters, Mexico, Trinidad and Venezuela. The organization and aggregation of our business into the two segments were based on differences in economic characteristics, customer base, asset class, contract structure and management structure. In addition, the TODCO segment fleet was highly dependent upon the U.S. natural gas industry while the Transocean Drilling segment’s operations are more dependent upon the worldwide oil industry. As a result of the deconsolidation of TODCO (see Note 1—Nature of Business and Principles of Consolidation), we now operate in one industry segment, the Transocean Drilling segment.

Our Transocean 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. 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).

Operating revenues and income before income taxes and minority interest by segment were as follows (in millions):

	Year ended December 31,
	2004
Operating Revenues
Transocean Drilling	$	2,280
TODCO (a)		334
Total Operating Revenues	$	2,614

Operating Income (Loss) Before General and Administrative Expense
Transocean Drilling	$	428
TODCO (a) (b)		(33	)
		395
Unallocated general and administrative expense		(67	)
Unallocated other income (expense), net (c)		(88	)
Income Before Income Taxes and Minority Interest(c)	$	240

______________

(a)	Includes results from the TODCO segment to December 17, 2004, the effective date of the TODCO deconsolidation.

(b)	Includes $32 million of operating and maintenance expense that TODCO classifies as general and administrative expense.

(c)	Includes gains from the TODCO stock sales of $309 million and a non-cash charge of $167 million related to contingent amounts due from TODCO under a tax sharing agreement between us and TODCO. See Note 4—TODCO Stock Sales and Note 15—Income Taxes.

- 90 -

Index

TRANSOCEAN INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued

Depreciation expense by segment was as follows (in millions):

	Year ended December 31,
	2004
Transocean Drilling	$	432
TODCO		92
Total Depreciation Expense	$	524

Total capital expenditures by segment were as follows (in millions):

	Year ended December 31,
	2004

Transocean Drilling	$	118
TODCO		9
Total Capital Expenditures	$	127

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

	Years ended December 31,
	2006		2005		2004
Operating Revenues
United States	$	806	$	648	$	856
United Kingdom		462		335		209
Nigeria		447		218		196
India		313		296		271
Brazil		308		265		278
Other Countries (a)		1,546		1,130		804
Total Operating Revenues	$	3,882	$	2,892	$	2,614

	As of December 31,
	2006		2005
Long-Lived Assets
United States	$	2,485	$	2,311
Nigeria		856		980
Brazil		535		762
Other Countries (a)		3,450		2,695
Total Long-Lived Assets	$	7,326	$	6,748

______________________

(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, 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. For the year ended December 31, 2004, BP, Petrobras and Chevron each accounted for approximately 10 percent of our operating revenues, of which the majority was reported in the Transocean Drilling segment. 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 22—Related Party Transactions

ODL—In conjunction with the management and operation of the Joides Resolution on behalf of ODL, we earned $2 million, $1 million and $2 million for the years ended December 31, 2006, 2005 and 2004, respectively. Such amounts are included in other revenues in our consolidated statements of operations. At December 31, 2006 and 2005, we had receivables due from ODL of $1 million and $2 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.

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. Prior to the deconsolidation of TODCO (see Note 1—Nature of Business and Principles of Consolidation and Note 4—TODCO Stock Sales), amounts we earned under the transition services agreement and amounts we incurred for administrative support from TODCO were eliminated upon consolidation. As a result of our deconsolidation of TODCO, amounts earned under the transition services agreement were reflected in other revenues and amounts incurred for administrative support are 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, 2006 and 2005, we had payables related to the agreements for the separation of TODCO of $1 million, which was included in accounts payable in our consolidated balance sheet. At December 31, 2006 and 2005, we had a long-term payable related to our indemnification of certain TODCO non-U.S. income tax liabilities of $11 million, which was included in other long-term liabilities in our consolidated balance sheet.

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TRANSOCEAN INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued

Note 23—Earnings Per Share

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

	Years ended December 31,
	2006		2005		2004
Numerator for Basic Earnings per Share
Net Income for basic earnings per share	$	1,385	$	716	$	152

Numerator for Diluted Earnings per Share
Net Income	$	1,385	$	716	$	152
Add back interest expense on the 1.5% convertible debentures		6		6		−
Net Income for diluted earnings per share	$	1,391	$	722	$	152

Denominator for Diluted Earnings per Share
Weighted-average shares outstanding for basic earnings per share		313		327		321
Effect of dilutive securities:
Employee stock options and unvested stock grants		4		4		2
Warrants to purchase ordinary shares		3		3		2
1.5% convertible debentures		5		5		−
Adjusted weighted-average shares and assumed conversions for diluted earnings per share		325		339		325

Basic Earnings Per Share
Net Income	$	4.42	$	2.19	$	0.47

Diluted Earnings Per Share
Net Income	$	4.28	$	2.13	$	0.47

Ordinary shares subject to issuance pursuant to the conversion features of the Zero Coupon Convertible Debentures (see Note 7—Debt) are not included in the calculation of adjusted weighted-average shares and assumed conversions for diluted earnings per share for the years ended December 31, 2005 and 2004 because the effect of including those shares is anti-dilutive. 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. Ordinary shares subject to issuance pursuant to the conversion features of the 1.5% Convertible Debentures are not included in the calculation of the adjusted weighted-average shares and assumed conversions for diluted earnings per share for the year ended December 31, 2004 because the effect of including those shares is anti-dilutive.

Note 24—Stock Warrants

In connection with the R&B Falcon merger, we assumed the then outstanding R&B Falcon stock warrants. Each warrant enables 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 March 1, 2006, we issued 333,039 ordinary shares related to a cashless exercise of 25,100 warrants. At December 31, 2006, there were 203,900 warrants outstanding to purchase 3,568,250 ordinary shares.

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Index

TRANSOCEAN INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued

Note 25—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)
2006
	Operating Revenues	$	817	$	854	$	1,025	$	1,186
	Operating Income (a)		284		289		390		678
	Net Income (a)		206		249		309		621
	Basic Earnings Per Share	$	0.63	$	0.77	$	0.99	$	2.13
	Diluted Earnings Per Share	$	0.61	$	0.75	$	0.96	$	2.05
	Weighted Average Shares Outstanding
	Shares for basic earnings per share		325		324		312		292
	Shares for diluted earnings per share		337		336		323		304

2005
	Operating Revenues	$	631	$	727	$	763	$	771
	Operating Income (b)		143		185		204		188
	Net Income (b) (c)		92		302		170		152
	Basic Earnings Per Share	$	0.28	$	0.93	$	0.52	$	0.46
	Diluted Earnings Per Share	$	0.28	$	0.90	$	0.50	$	0.45
	Weighted Average Shares Outstanding
	Shares for basic earnings per share		324		326		329		330
	Shares for diluted earnings per share		331		338		341		336

_________________________

(a)

First quarter 2006 included gain on sale of assets of $65 million. Second quarter 2006 included gain on sale of assets of $111 million. Third quarter 2006 included gain on sale of assets of $45 million. Fourth quarter 2006 included gain on sale of assets of $191 million. See Note 6—Asset Dispositions.

(b)	First quarter 2005 included gain on sale of an asset of $19 million. Second quarter 2005 included gain on sale of assets of $14 million. See Note 6—Asset Dispositions.

(c)

First quarter 2005 included a loss on retirement of debt of $7 million (see Note 7—Debt). Second quarter 2005 included gain from TODCO stock sales of $165 million (see Note 4—TODCO Stock Sales). Fourth quarter 2005 included a net income tax benefit of $16 million related to various tax adjustments (see Note 15—Income Taxes).

Note 26—Subsequent Events (Unaudited)

Asset Dispositions—In January 2007, we completed the sale of our membership interest in Transocean CGR LLC (owner of the tender rig Charley Graves) for net proceeds of $33 million and expect to recognize a gain on the sale of $23 million ($20 million or $0.07 per diluted share, net of tax).

Share Repurchases—In 2007, we repurchased approximately $400 million of our ordinary shares, which amounted to approximately 5.2 million ordinary shares. Total consideration was funded with existing cash balances and borrowings under our Revolving Credit Facility.

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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, 2006 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, 2006 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 2007 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, 2006. 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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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	48
Report of Independent Registered Public Accounting Firm on
Internal Control over Financial Reporting	49
Report of Independent Registered Public Accounting Firm	50
Consolidated Statements of Operations	51
Consolidated Statements of Comprehensive Income	52
Consolidated Balance Sheets	53
Consolidated Statements of Equity	54
Consolidated Statements of Cash Flows	55
Notes to Consolidated Financial Statements	57

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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Transocean Inc. and Subsidiaries

Schedule II - Valuation and Qualifying Accounts

(In millions)

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

Year ended December 31, 2004
Reserves and allowances deducted from asset accounts:
Allowance for doubtful accounts receivable	$	29	$	10	$	-	$	22	(a)	$	17

Allowance for obsolete materials and supplies		18		3		-		1	(b)		20

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

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

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

_____________________________

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

(b)	Includes amounts related to the TODCO deconsolidation.

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

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

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

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))

3.1	Memorandum of Association of Transocean Sedco Forex Inc., as amended (incorporated by reference to Annex E to the Joint Proxy Statement/Prospectus dated October 30, 2000 included in a 424(b)(3) prospectus filed by the Company on November 1, 2000)

3.2	Articles of Association of Transocean Sedco Forex Inc., as amended (incorporated by reference to Annex F to the Joint Proxy Statement/Prospectus dated October 30, 2000 included in a 424(b)(3) prospectus filed by the Company on November 1, 2000)

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

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 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 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 Form 8-K dated April 29, 1997)

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

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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 our Post-Effective Amendment No. 3 on Form S-3 to Form S-4 filed on November 18, 2005)

4.17	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 Falcon's Registration Statement No. 333-81181 on Form S-3 dated June 21, 1999)

4.18	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)

4.19	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 our Current Report on Form 8-K filed on July 13, 2005)

4.20	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 our Current Report on Form 8-K filed on May 12, 2006)

4.21	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 our Current Report on Form 8-K filed on August 31, 2006)

4.22	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 our Current Report on Form 8-K filed on September 1, 2006)

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)

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Index

*10.2	Performance Award and Cash Bonus Plan of Sonat Offshore Drilling Inc. (incorporated by reference to Exhibit 10-(5) to the Company's 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 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	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)

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

*10.8	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)

*10.9	1992 Long-Term Incentive Plan of Reading & Bates Corporation (incorporated by reference to Exhibit B to Reading & Bates' Proxy Statement dated April 27, 1992)

*10.10	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)

*10.11	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)

*10.12	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)

*10.13	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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Index

*10.14	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)

*10.15	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)

*10.16	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)

10.17	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)

10.18	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)

10.19	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 our Current Report on Form 8-K filed on November 30, 2006)

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

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

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

*10.23	Form of 2004 Director Deferred Unit Award (incorporated by reference to Exhibit 10.4 to our Current Report on Form 8-K filed on February 15, 2005)

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

†*10.25	Description of Base Salaries of Named Executive Officers

*10.26	Executive Change of Control Severance Benefit (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed on July 19, 2005)

†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.

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Index

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 March 1, 2007.

	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 March 1, 2007.

Signature		Title


*		Chairman of the Board of Directors
J. Michael Talbert


/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/ David A. Tonnel		Vice President and Controller
David A. Tonnel		(Principal Accounting Officer)


*		Director
Victor E. Grijalva


*		Director
Mark A. Hellerstein


*		Director
Judy J. Kelly


*		Director
Arthur Lindenauer


*		Director
Michael E. McMahon


*		Director
Martin B. McNamara


*		Director
Roberto Monti

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Index

Signature		Title


*		Director
Kristian Siem


*		Director
Robert M. Sprague


*		Director
Ian C. Strachan

By	/s/ William E. Turcotte
	William E. Turcotte
	(Attorney-in-Fact)

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