Transocean 10K 2009 Annual report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

_________________________

FORM 10-K

(Mark one)

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

For the fiscal year ended December 31, 2009

¨ 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 000-53533

_________________________

TRANSOCEAN LTD.

(Exact name of registrant as specified in its charter)

Zug, Switzerland	98-0599916
(State or other jurisdiction	(I.R.S. Employer
of incorporation or organization)	Identification No.)
Blandonnet International Business Center Chemin de Blandonnet 2 Building F, 7th Floor Vernier, Switzerland (Address of principal executive offices)	1214 (Zip Code)

Registrant’s telephone number, including area code: +41 (22) 930-9000

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

Title of class	Exchange on which registered
Shares, par value CHF 15.00 per share	New York Stock Exchange

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

_________________________

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

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

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes þ No ¨

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

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

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

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

As of June 30, 2009, 320,953,074 shares were outstanding and the aggregate market value of shares held by non-affiliates was approximately $23.8 billion (based on the reported closing market price of the shares of Transocean Ltd. on such date of $74.29 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 19, 2010, 321,628,110 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, 2009, for its 2010 annual general meeting of shareholders, are incorporated by reference into Part III of this Form 10-K.

TRANSOCEAN LTD. AND SUBSIDIARIES

INDEX TO ANNUAL REPORT ON FORM 10-K

FOR THE YEAR ENDED DECEMBER 31, 2009

Item		Page

	PART I
ITEM 1.	Business	4
ITEM 1A.	Risk Factors	13
ITEM 1B.	Unresolved Staff Comments	23
ITEM 2.	Properties	23
ITEM 3.	Legal Proceedings	23
ITEM 4.	Submission of Matters to Vote of Security Holders	26

	PART II
ITEM 5.	Market for Registrant’s Common Equity, Related Shareholder Matters and Issuer Purchases of Equity Securities	28
ITEM 6.	Selected Financial Data	31
ITEM 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	32
ITEM 7A.	Quantitative and Qualitative Disclosures About Market Risk	55
ITEM 8.	Financial Statements and Supplementary Data	56
ITEM 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	104
ITEM 9A.	Controls and Procedures	104
ITEM 9B.	Other Information	104

	PART III
ITEM 10.	Directors, Executive Officers and Corporate Governance	105
ITEM 11.	Executive Compensation	105
ITEM 12.	Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters	105
ITEM 13.	Certain Relationships and Related Transactions, and Director Independence	105
ITEM 14.	Principal Accountant Fees and Services	105

	PART IV
ITEM 15.	Exhibits and Financial Statement Schedules	105

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Index

Forward-Looking Information

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

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

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

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

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

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

§	uses of excess cash, including the payment of dividends and other distributions, debt retirement and share repurchases under our share repurchase program,

§	the timing of acquisitions and dispositions and the proceeds of dispositions,

§	tax matters, including our effective tax rate, changes in tax laws, treaties and regulations, tax assessments and liabilities for tax issues, including those associated with our activities in Brazil, Norway and the United States (“U.S.”),

§	the listing of our shares on the SIX Swiss Exchange (“SIX”),

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

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

§	debt levels, including impacts of the financial and economic downturn,

§	effects of accounting changes and adoption of accounting policies, and

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

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

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

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

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

§	the adequacy of sources of liquidity,

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

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

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

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

The foregoing risks and uncertainties are beyond our ability to control, and in many cases, we cannot predict the risks and uncertainties that could cause our actual results to differ materially from those indicated by the forward-looking statements. Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual results may vary materially from those indicated.

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

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Index

PART I

ITEM 1.

Business

Overview

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

Transocean Ltd. is a Swiss corporation with principal executive offices located at Blandonnet International Business Center, Chemin de Blandonnet 2, Building F, 7th Floor, 1214 Vernier, Switzerland. Our telephone number at that address is +41 22 930-9000. Our shares are listed on the New York Stock Exchange (“NYSE”) under the symbol “RIG.” On February 16, 2010, we announced our intention to list our shares on the SIX in the second quarter of 2010, subject to the approval of the SIX. Our shares will continue to be listed on the NYSE. For information about the revenues, operating income, assets and other information related to our business, our segments and the geographic areas in which we operate, see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Notes to Consolidated Financial Statements—Note 23—Segments, Geographical Analysis and Major Customers.

Background

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

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

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Index

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 coring drillship.

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

We categorize our fleet as follows: (1) “High-Specification Floaters,” consisting of our “Ultra-Deepwater Floaters,” “Deepwater Floaters” and “Harsh Environment Floaters,” (2) “Midwater Floaters,” (3) “High-Specification Jackups,” (4) “Standard Jackups” and (5) “Other Rigs.” As of February 2, 2010, our fleet of 138 rigs, excluding rigs under construction, included:

§	44 High-Specification Floaters, which are comprised of:

§	23 Ultra-Deepwater Floaters;

§	16 Deepwater Floaters; and

§	five Harsh Environment Floaters;

§	26 Midwater Floaters;

§	10 High-Specification Jackups;

§	55 Standard Jackups; and

§	three Other Rigs, which are comprised of:

§	two barge drilling rigs; and

§	one coring drillship.

As of February 2, 2010, our fleet was located in the Far East (25 units), U.K. North Sea (16 units), Middle East (16 units), U.S. Gulf of Mexico (15 units), West African countries other than Nigeria and Angola (14 units), India (12 units), Brazil (10 units), Nigeria (seven units), Angola (six units), Norway (five units), the Mediterranean (four units), Trinidad (two units), Australia (two units), Canada (two units), the Netherlands (one unit) and the Caspian Sea (one unit).

High-Specification Floaters are specialized offshore drilling units that we categorize into three sub-classifications based on their capabilities. Ultra-Deepwater Floaters have high-pressure mud pumps and a water depth capability of 7,500 feet or greater. Deepwater Floaters are generally those other semisubmersible rigs and drillships that have a water depth capacity between 7,500 and 4,500 feet. Harsh Environment Floaters have a water depth capacity between 5,000 and 1,500 feet, are capable of drilling in harsh environments and have greater displacement, resulting in larger variable load capacity, more useable deck space and better motion characteristics. Midwater Floaters are generally comprised of those non-high-specification semisubmersibles with a water depth capacity of less than 4,500 feet. High-Specification Jackups consist of our harsh environment and high-performance jackups, and Standard Jackups consist of our remaining jackup fleet. Other Rigs consist of rigs that are of a different type or use than those mentioned above.

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

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

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Index

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

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

Depending on market conditions, we may idle or stack non-contracted rigs. An idle rig is between contracts, readily available for operations, and operating costs are typically at or near normal levels. A stacked rig is manned by a reduced crew or unmanned and typically has reduced operating costs and is (a) preparing for an extended period of inactivity, (b) expected to continue to be inactive for an extended period, or (c) completing a period of extended inactivity. Some idle rigs and all stacked rigs require additional costs to return to service. The actual cost, which could fluctuate over time, depends 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. Under certain circumstances, the cost could be significant. We consider these factors, together with market conditions, length of contract and dayrate and other contract terms, when deciding whether to return a stacked rig to service. We may consider marketing stacked rigs as accommodation units or for other alternative uses, from time to time, until drilling activity increases and we obtain drilling contracts for these units.

As of February 2, 2010, we owned all of the drilling rigs in our fleet noted in the tables below, except for the following: (1) those specifically described as being owned wholly or in part by unaffiliated parties, (2) GSF Explorer, which is subject to a capital lease through July 2026 (3) GSF Jack Ryan, which is subject to a fully defeased capital lease through November 2020 and (4) Petrobras 10000, which is subject to a capital lease through August 2029.

In the tables presented below, the location of each rig indicates the current drilling location for operating rigs or the next operating location for rigs in shipyards with a follow-on contract, unless otherwise noted. In addition to the rigs presented below, we also own or operate three Other Rigs, including two drilling barges and a coring drillship.

Rigs Under Construction (5)

The following table provides certain information regarding our Ultra-Deepwater Floaters under construction as of February 2, 2010:

			Water	Drilling
			depth	depth
		Expected	capacity	capacity	Contracted
Name	Type	completion	(in feet)	(in feet)	location
Ultra-Deepwater Floaters (a)
Discoverer Inspiration (b)	HSD	1Q 2010	12,000	40,000	U.S. Gulf
Deepwater Champion (b)	HSD	1Q 2011	12,000	40,000	To be advised
Dhirubhai Deepwater KG2 (c)	HSD	1Q 2010	10,000	35,000	India
Discoverer India (b)	HSD	4Q 2010	10,000	40,000	India
Discoverer Luanda (b) (d)	HSD	3Q 2010	7,500	40,000	Angola

______________________________

“HSD” means high-specification drillship.

(a)	Dynamically positioned.

(b)	Dual-activity.

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

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

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Index

High-Specification Floaters (44)

The following table provides certain information regarding our High-Specification Floaters as of February 2, 2010:

		Year	Water	Drilling
		entered	depth	depth
		service/	capacity	capacity
Name	Type	upgraded (a)	(in feet)	(in feet)	Location
Ultra-Deepwater Floaters (23)
Discoverer Clear Leader (b) (c) (d)	HSD	2009	12,000	40,000	U.S. Gulf
Discoverer Americas (b) (c) (d)	HSD	2009	12,000	40,000	U.S. Gulf
Petrobras 10000 (b) (c)	HSD	2009	12,000	37,500	Angola
Dhirubhai Deepwater KG1 (b) (e)	HSD	2009	12,000	35,000	India
Discoverer Deep Seas (b) (c) (d)	HSD	2001	10,000	35,000	U.S. Gulf
Discoverer Enterprise (b) (c) (d)	HSD	1999	10,000	35,000	U.S. Gulf
Discoverer Spirit (b) (c) (d)	HSD	2000	10,000	35,000	U.S. Gulf
GSF C.R. Luigs (b)	HSD	2000	10,000	35,000	U.S. Gulf
GSF Jack Ryan (b)	HSD	2000	10,000	35,000	Nigeria
Deepwater Discovery (b)	HSD	2000	10,000	30,000	Brazil
Deepwater Expedition (b)	HSD	1999	10,000	30,000	India
Deepwater Frontier (b)	HSD	1999	10,000	30,000	India
Deepwater Horizon (b)	HSS	2001	10,000	30,000	U.S. Gulf
Deepwater Millennium (b)	HSD	1999	10,000	30,000	Brazil
Deepwater Pathfinder (b)	HSD	1998	10,000	30,000	Ivory Coast
Cajun Express (b) (f)	HSS	2001	8,500	35,000	U.S. Gulf
Deepwater Nautilus (g)	HSS	2000	8,000	30,000	U.S. Gulf
GSF Explorer (b)	HSD	1972/1998	7,800	30,000	Singapore
GSF Development Driller I (b) (c)	HSS	2005	7,500	37,500	U.S. Gulf
GSF Development Driller II (b) (c)	HSS	2005	7,500	37,500	U.S. Gulf
Development Driller III (b) (c)	HSS	2009	7,500	37,500	U.S. Gulf
Sedco Energy (b) (f)	HSS	2001	7,500	35,000	Nigeria
Sedco Express (b) (f)	HSS	2001	7,500	35,000	Angola
Deepwater Floaters (16)
Deepwater Navigator (b)	HSD	1971/2000	7,200	25,000	Brazil
Discoverer 534 (b)	HSD	1975/1991	7,000	25,000	India
Discoverer Seven Seas (b)	HSD	1976/1997	7,000	25,000	India
Transocean Marianas (g)	HSS	1979/1998	7,000	25,000	U.S. Gulf
Sedco 702 (b)	HSS	1973/2007	6,500	25,000	Ghana
Sedco 706 (b)	HSS	1976/2008	6,500	25,000	Brazil
Sedco 707 (b)	HSS	1976/1997	6,500	25,000	Brazil
GSF Celtic Sea (g)	HSS	1982/1998	5,750	25,000	Brazil
Jack Bates (g)	HSS	1986/1997	5,400	30,000	Australia
M.G. Hulme, Jr. (g)	HSS	1983/1996	5,000	25,000	Singapore
Sedco 709 (b)	HSS	1977/1999	5,000	25,000	Stacked
Transocean Richardson (g)	HSS	1988	5,000	25,000	Angola
Jim Cunningham (g)	HSS	1982/1995	4,600	25,000	Angola
Sedco 710 (b)	HSS	1983/2001	4,500	25,000	Brazil
Sovereign Explorer (g)	HSS	1984	4,500	25,000	Brazil
Transocean Rather (g)	HSS	1988	4,500	25,000	Idle
Harsh Environment Floaters (5) (g)
Henry Goodrich	HSS	1985/2007	5,000	30,000	Canada
Transocean Leader	HSS	1987/1997	4,500	25,000	Norwegian N. Sea
Paul B. Loyd, Jr.	HSS	1990	2,000	25,000	U.K. N. Sea
Transocean Arctic	HSS	1986	1,650	25,000	Norwegian N. Sea
Polar Pioneer	HSS	1985	1,500	25,000	Norwegian N. Sea

______________________________

“HSD” means high-specification drillship.

“HSS” means high-specification semisubmersible.

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

(b)	Dynamically positioned.

(c)	Dual-activity.

(d)	Enhanced Enterprise-class or Enterprise-class rig.

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

(f)	Express-class rig.

(g)	Moored floaters.

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Index

Midwater Floaters (26)

The following table provides certain information regarding our Midwater Floaters as of February 2, 2010:

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

______________________________

“OS” means other semisubmersible.

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

(b)	Owned by AWILCO Arctic IV Limited and operated by us under a short-term bareboat charter between us and AWILCO Arctic IV Limited.

High-Specification Jackups (10)

The following table provides certain information regarding our High-Specification Jackups as of February 2, 2010:

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

______________________________

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

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Index

Standard Jackups (55)

The following table provides certain information regarding our Standard Jackups as of February 2, 2010:

	Year	Water	Drilling
	entered	depth	depth
	service/	capacity	capacity
Name	upgraded (a)	(in feet)	(in feet)	Location
Trident IX	1982	400	21,000	Idle
GSF Adriatic II	1981	350	25,000	Stacked
GSF Adriatic IX	1981	350	25,000	Nigeria
GSF Adriatic X	1982	350	30,000	Egypt
GSF Key Manhattan	1980	350	25,000	Idle
GSF Key Singapore	1982	350	25,000	Egypt
GSF Adriatic VI	1981	328	25,000	Stacked
GSF Adriatic VIII	1983	328	25,000	Nigeria
C. E. Thornton	1974	300	25,000	India
D. R. Stewart	1980	300	25,000	Italy
F. G. McClintock	1975	300	25,000	India
George H. Galloway	1984	300	25,000	Stacked
GSF Adriatic I	1981	300	25,000	Stacked
GSF Adriatic V	1979	300	25,000	Stacked
GSF Adriatic XI	1983	300	25,000	Stacked
GSF Compact Driller	1992	300	25,000	Thailand
GSF Galveston Key	1978	300	25,000	Vietnam
GSF Key Gibraltar	1976/1996	300	25,000	Stacked
GSF Key Hawaii	1982	300	25,000	Stacked
GSF Labrador	1983	300	25,000	U.K. N. Sea
GSF Main Pass I	1982	300	25,000	Arabian Gulf
GSF Main Pass IV	1982	300	25,000	Arabian Gulf
GSF Rig 136	1982/2002	300	25,000	Stacked
Harvey H. Ward	1981	300	25,000	Malaysia
J. T. Angel	1982	300	25,000	India
Randolph Yost	1979	300	25,000	India
Roger W. Mowell	1982	300	25,000	Malaysia
Ron Tappmeyer	1978	300	25,000	India
Transocean Shelf Explorer	1982	300	20,000	Stacked
Interocean III	1978/1993	300	25,000	Stacked
Transocean Nordic	1984	300	25,000	Stacked
Trident II	1977/1985	300	25,000	India
Trident IV-A	1980/1999	300	25,000	Stacked
Trident 17	1983	300	25,000	Stacked
Trident XII	1982/1992	300	25,000	India
Trident XIV	1982/1994	300	25,000	Angola
Trident 15	1982	300	25,000	Thailand
Trident 16	1982	300	25,000	Vietnam
Trident VIII	1981	300	21,000	Stacked
GSF Parameswara	1983	300	20,000	Indonesia
GSF Rig 134	1982	300	20,000	Malaysia
GSF High Island II	1979	270	20,000	Arabian Gulf
GSF High Island IV	1980/2001	270	20,000	Arabian Gulf
GSF High Island V	1981	270	20,000	Stacked
GSF High Island VII	1982	250	20,000	Cameroon
GSF High Island IX	1983	250	20,000	Stacked
GSF Rig 103	1974	250	20,000	Stacked
GSF Rig 105	1975	250	20,000	Egypt
GSF Rig 124	1980	250	20,000	Egypt
GSF Rig 127	1981	250	20,000	Stacked
GSF Rig 141	1982	250	20,000	Egypt
Transocean Comet	1980	250	20,000	Egypt
Transocean Mercury	1969/1998	250	20,000	Stacked
Trident VI	1981	220	21,000	Stacked
GSF Britannia	1968	200	20,000	Stacked

______________________________

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

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Markets

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

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

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

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

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

Contract Backlog

Our contract backlog at December 31, 2009 was approximately $31 billion, representing a 23 percent and 3 percent decrease compared to our contract backlog of $40 billion and $32 billion at December 31, 2008 and 2007, respectively. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Outlook—Drilling Market” and “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Performance and Other Key Indicators.”

Operating Revenues and Long-Lived Assets by Country

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

	Years ended December 31,
	2009		2008		2007
Operating revenues
U.S.	$	2,239	$	2,578	$	1,259
U.K.		1,563		2,012		848
India		1,084		890		761
Other countries (a)		6,670		7,194		3,509
Total operating revenues	$	11,556	$	12,674	$	6,377

	December 31,
	2009		2008
Long-lived assets			(As adjusted)
U.S.	$	6,203	$	4,128
South Korea		3,128		3,218
Other countries (a)		13,687		13,515
Total long-lived assets	$	23,018	$	20,861

______________________________

(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.

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Contract Drilling Services

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

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

Drilling Management Services

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

In addition to turnkey drilling services, we participate in project management operations that include providing certain planning, management and engineering services, purchasing equipment and providing personnel and other logistical services to customers. Our project management services differ from turnkey drilling services in that the customer assumes control of the drilling operations and thereby retains the risks associated with the project.

These drilling management services revenues represented less than three percent of our consolidated revenues for the year ended December 31, 2009. In the course of providing drilling management services, ADTI may use a drilling rig in our fleet or contract for a rig owned by another contract driller.

Integrated Services

From time to time, we provide well and logistics services in addition to our normal drilling services through third party contractors and our employees. We refer to these other services as integrated services, which are generally subject to individual contractual agreements executed to meet specific customer needs and may be provided on either a dayrate, cost plus or fixed-price basis, depending on the daily activity. As of February 2, 2010, we were only performing such services in India. These integrated services revenues represented less than two percent of our consolidated revenues for the year ended December 31, 2009.

Oil and Gas Properties

We conduct oil and gas exploration, development and production activities through our oil and gas subsidiaries. We acquire interests in oil and gas properties principally in order to facilitate the awarding of turnkey contracts for our drilling management services operations. Our oil and gas activities are conducted through Challenger Minerals Inc. and Challenger Minerals (North Sea) Limited (together, “CMI”), which holds property interests primarily in the U.S. offshore Louisiana and Texas and in the U.K. sector of the North Sea. The oil and gas properties revenues represented less than one percent of our consolidated revenues for the year ended December 31, 2009.

Joint Venture, Agency and Sponsorship Relationships and Other Investments

In some areas of the world, local customs and practice or governmental requirements necessitate the formation of joint ventures with local participation, which we may or may not control. We are an active participant in several joint venture drilling companies, principally in Angola, India, Indonesia, Malaysia and Nigeria. Local laws or customs in some areas of the world also effectively mandate establishment of a relationship with a local agent or sponsor. When appropriate in these areas, we enter into agency or sponsorship agreements.

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

We hold a 65 percent interest in Angola Deepwater Drilling Company Limited (“ADDCL”), a Cayman Islands joint venture company formed to construct, own and operate an ultra-deepwater drillship to be named Discoverer Luanda. Angco Cayman Limited, a Cayman Islands company, holds the remaining 35 percent interest in ADDCL. Under a management services agreement with ADDCL, we provide construction management services and have agreed to provide operating management services once the drillship begins operations, which is currently expected to be in the third quarter of 2010. Beginning on the fifth anniversary of the first well commencement date, Angco Cayman Limited will have the right to exchange its interest in the joint venture for cash at a purchase price based on an appraisal of the fair value of the drillship, subject to various adjustments.

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

See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Related Party Transactions.”

Significant Customers

We engage in offshore drilling services 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 customer in 2009 was BP, accounting for 12 percent of our 2009 operating revenues. The loss of this significant customer could, at least in the short term, have a material adverse effect on our results of operations. No other customer accounted for 10 percent or more of our 2009 operating revenues.

Employees

We require highly skilled personnel to operate our drilling units. We conduct extensive personnel recruiting, training and safety programs. At December 31, 2009, we had approximately 19,300 employees, and we had engaged approximately 2,200 persons through contract labor providers. Some of our employees working in Angola, the U.K. and Norway, are represented by, and some of our contracted labor work under, collective bargaining agreements. Many of these represented individuals are working under agreements that are subject to ongoing salary negotiation in 2010. These negotiations could result in higher personnel expenses, other increased costs or increased operation restrictions as the outcome of such negotiations apply to all offshore employees not just the union members.

Legislation has been introduced in the U.S. Congress that could encourage additional unionization efforts in the U.S., as well as increase the chances that such efforts succeed. Additional unionization efforts, if successful, new collective bargaining agreements or work stoppages could materially increase our labor costs and operating restrictions.

Technological Innovation

We are the world’s largest offshore drilling contactor and leading provider of drilling management services worldwide. Our fleet is considered one of the most modern and versatile in the world due to its emphasis on technically demanding sectors of the offshore drilling business. Since launching the offshore industry’s first jackup drilling rig in 1954, we have achieved a long history of technological innovations, including the first dynamically positioned drillship, the first rig to drill year-round in the North Sea, the first semisubmersible rig for Sub-Arctic, year-round operations, and the latest generations of ultra-deepwater drillships and semisubmersibles. Nine of our existing fleet are, and four of our newbuilds will be, equipped with our patented dual-activity technology, which allows our rigs to perform simultaneous drilling tasks in a parallel rather than sequential manner and reduces critical path activity while improving efficiency in both exploration and development drilling. The effective use of and continued improvements in technology are critical to the maintenance of our competitive position within the drilling services industry. We expect to continue to develop technology internally or to acquire technology through strategic acquisitions.

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Environmental Regulation

For a discussion of the effects of environmental regulation, see “Item 1A. Risk Factors—Compliance with or breach of environmental laws can be costly and could limit our operations.”

Our operations are subject to a variety of global environmental regulations. We monitor environmental regulation in each country of operation and, while we see an increase in general environmental regulation, we have made and will continue to make the required expenditures to comply with current and future environmental requirements. We make expenditures to further our commitment to environmental improvement and the setting of a global environmental standard as part of our wider corporate responsibility effort. We assess the environmental impacts of our business, specifically in the areas of greenhouse gas emissions, climate change, discharges and waste management. We report our global emissions data each year through the Carbon Disclosure Project in addition to a description of our actions being undertaken to manage under future emissions legislation under development in a number of countries in North America and Europe. Our actions are designed to reduce risk in our future operations and promote sound environmental management. While we continue to assess further projects designed to reduce our overall emissions, to date, we have not expended material amounts in order to comply with recent legislation, and we do not believe that our compliance with such requirements will have a material adverse effect upon our results of operations or competitive position or materially increase our capital expenditures.

Available Information

Our website address is www.deepwater.com. Information contained on or accessible from our website is not incorporated by reference into this annual report on Form 10-K and should not be considered a part of this report or any other filing that we make with the SEC. We make available on this website free of charge, our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports as soon as reasonably practicable after we electronically file those materials with, or furnish those materials to, the SEC. You may also find information related to our corporate governance, board committees and company code of business conduct and ethics on our website. The SEC also maintains a website, www.sec.gov, that contains reports, proxy statements and other information regarding SEC registrants, including us.

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

ITEM 1A. Risk Factors

Risks related to our business

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

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

The worldwide financial and economic downturn may continue to negatively impact our business and financial condition.

The continued economic downturn and related instability in the global financial system has had, and may continue to have, an impact on our business and our financial condition. Our ability to access the capital markets may be severely restricted at a time when we would like, or need, to access such markets, which could have an impact on our flexibility to react to changing economic and business conditions. The economic downturn has impacted lenders participating in our credit facilities and our customers, and an extended or worsening economic downturn may cause them to fail to meet their obligations to us.

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

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

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

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

§	the ability of the Organization of the Petroleum Exporting Countries (“OPEC”) to set and maintain production levels and pricing;

§	the level of production in non-OPEC countries;

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

§	advances in exploration and development technology; and

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

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

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

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

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

We rely heavily on a relatively small number of customers and the loss of a significant customer and/or a dispute that leads to the loss of a customer could have a material adverse impact on our financial results.

We engage in offshore drilling services 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 customer in 2009 was BP, accounting for 12 percent of our 2009 operating revenues. The loss of this customer or another significant customer could, at least in the short term, have a material adverse effect on our results of operations.

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

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

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

As of February 2, 2010, we had a total of five deepwater newbuild rig projects. We also have a variety of other more limited shipyard projects at any given time. These shipyard projects are subject to the risks of delay or cost overruns inherent in any such construction project resulting from numerous factors, including the following:

§	shipyard availability;

§	shortages of equipment, materials or skilled labor;

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

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

§	work stoppages;

§	customer acceptance delays;

§	weather interference or storm damage;

§	unanticipated cost increases; and

§	difficulty in obtaining necessary permits or approvals.

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

Our operations also rely on a significant supply of capital and consumable spare parts and equipment to maintain and repair our fleet. We also rely on the supply of ancillary services, including supply boats and helicopters. Shortages in materials, delays in the delivery of necessary spare parts, equipment or other materials, or the unavailability of ancillary services could negatively impact our future operations and result in increases in rig downtime, and delays in the repair and maintenance of our fleet.

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

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

Our current backlog of contract drilling revenue may not be fully realized.

Our contract backlog as of February 2, 2010 was approximately $30.4 billion. This amount represents the firm term of the contract multiplied by the contractual operating rate, which may be higher than other rates included in the contract such as waiting on weather rate, repair rate or force majeure rate. Our contract backlog includes signed drilling contracts and, in some cases, other definitive agreements awaiting contract execution. We may not be able to realize the full amount of our contract backlog due to events beyond our control. In addition, some of our customers have experienced liquidity issues, and these liquidity issues could increase if commodity prices decline to lower levels for an extended period of time. Liquidity issues could lead our customers to go into bankruptcy or could encourage our customers to seek to repudiate, cancel or renegotiate these agreements for various reasons, as described under “Our drilling contracts may be terminated due to a number of events” above. Our inability to realize the full amount of our contract backlog may have a material adverse effect on our consolidated statement of financial position, results of operations or cash flows.

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

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

§	terrorist acts, war, piracy and civil disturbances;

§	seizure, expropriation or nationalization of equipment;

§	imposition of trade barriers;

§	import-export quotas;

§	wage and price controls;

§	unexpected changes in law and regulatory requirements, including changes in interpretation and enforcement of existing laws;

§	damage to our equipment or violence directed at our employees, including kidnappings;

§	complications associated with supplying, repairing and replacing equipment in remote locations; and

§	the inability to repatriate income or capital.

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

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

Our non-U.S. contract drilling operations are subject to various laws and regulations in certain countries in which we operate, including laws and regulations relating to the import and export, equipment and operation of drilling units, currency conversions and repatriation, oil and gas exploration and development, and taxation of offshore earnings and earnings of expatriate personnel. We are also subject to the U.S. Treasury Department’s Office of Foreign Assets Control (“OFAC”) and other U.S. laws and regulations governing our international operations. In addition, various state and municipal governments, universities and other investors have proposed or adopted divestment and other initiatives regarding investments (including, with respect to state governments, by state retirement systems) in companies that do business with countries that have been designated as state sponsors of terrorism by the U.S. State Department. We had a noncontrolling interest in a Libyan joint venture that operates to a limited extent in Syria, which has been designated as a state sponsor of terrorism by the U.S. State Department. We sold our noncontrolling interest in this joint venture in November 2009. Our internal compliance program has identified and we have self-reported a potential OFAC compliance issue involving the shipment of goods by a freight forwarder through Iran, a country that has been designated as a state sponsor of terrorism by the U.S. State Department. See “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Outlook–Regulatory Matters.” We also operate a rig in Myanmar, a country that is subject to some U.S. trading sanctions. Failure to comply with applicable laws and regulations, including those relating to sanctions and export restrictions, may subject us to criminal sanctions or civil remedies, including fines, denial of export privileges, injunctions or seizures of assets. Investors could view any potential violations of OFAC regulations negatively, which could adversely affect our reputation and the market for our shares.

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

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

The shipment of goods, services and technology across international borders subjects us to extensive trade laws and regulations. Our import and export activities are governed by unique customs laws and regulations in each of the countries where we operate. Moreover, many countries, including the U.S., control the import and export of certain goods, services and technology and impose related import and export recordkeeping and reporting obligations. Governments also may impose economic sanctions against certain countries, persons and other entities that may restrict or prohibit transactions involving such countries, persons and entities, and we are also subject to the U.S. anti-boycott law.

The laws and regulations concerning import and export activity, recordkeeping and reporting, import and export control and economic sanctions are complex and constantly changing. These laws and regulations may be enacted, amended, enforced or interpreted in a manner materially impacting our operations. The adverse impact of the global economic crisis may increase some foreign government’s efforts to enact, enforce, amend or interpret laws and regulations as a method to increase revenue. Shipments can be delayed and denied import or export for a variety of reasons, some of which are outside our control and some of which may result from failure to comply with existing legal and regulatory regimes. Shipping delays or denials could cause unscheduled operational downtime. Any failure to comply with these applicable legal and regulatory obligations also could result in criminal and civil penalties and sanctions, such as fines, imprisonment, debarment from government contracts, seizure of shipments and loss of import and export privileges.

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An inability to obtain visas and work permits for our employees on a timely basis could hurt our operations and have an adverse effect on our business.

Our ability to operate worldwide depends on our ability to obtain the necessary visas and work permits for our personnel to travel in and out of, and to work in, the jurisdictions in which we operate. Governmental actions in some of the jurisdictions in which we operate may make it difficult for us to move our personnel in and out of these jurisdictions by delaying or withholding the approval of these permits. As a result of a change in government enforcement of the immigration policy in Angola, we have recently experienced considerable difficulty in obtaining the necessary visas and work permits for our employees to work in Angola, where we operate a number of rigs. If we are not able to obtain visas and work permits for the employees we need to operate our rigs on a timely basis, we might not be able to perform our obligations under our drilling contracts, which could allow our customers to cancel the contracts. If our customers cancel some of our contracts, and we are unable to secure new contracts on a timely basis and on substantially similar terms, it could adversely effect our consolidated statement of financial position, results of operations or cash flows.

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

As an international company, we are subject to many laws and regulations, including but not limited to the U.S. Foreign Corrupt Practices Act (“FCPA”). We are currently involved in several investigations by the U.S. Department of Justice and the SEC involving our operations and whether or not we or any of our employees have violated the FCPA. We cannot predict the ultimate outcome of any current or future investigations, the total costs to be incurred in completing such investigations, the potential impact on personnel, the effect of implementing any further measures that may be necessary to ensure full compliance with applicable laws or to what extent, if at all, we could be subject to fines, sanctions or other penalties which could be material under certain circumstances.

Our current investigations include a review of amounts paid to and by customs brokers in connection with the obtaining of permits for the temporary importation of vessels and the clearance of goods and materials. These permits and clearances are necessary in order for us to operate our vessels in certain jurisdictions. There is a risk that we may not be able to obtain import permits or renew temporary importation permits in West African countries, including Nigeria, in a manner that complies with the FCPA. As a result, we may not have the means to renew temporary importation permits for rigs located in the relevant jurisdictions as they expire or to send goods and equipment into those jurisdictions, in which event we may be forced to terminate the pending drilling contracts and relocate the rigs or leave the rigs in these countries and risk permanent importation issues, either of which could have an adverse effect on our financial results. In addition, termination of drilling contracts could result in damage claims by customers. Following the completion of existing investigations, we will continue to be subject to the FCPA and these risks. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Outlook–Regulatory Matters.”

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

Some of our employees working in Angola, the U.K. and Norway, are represented by, and some of our contracted labor work under, collective bargaining agreements. Many of these represented individuals are working under agreements that are subject to ongoing salary negotiation in 2010. These negotiations could result in higher personnel expenses, other increased costs or increased operation restrictions as the outcome of such negotiations apply to all offshore employees not just the union members. Additionally, the unions in the U.K. sought an interpretation of the application of the Working Time Regulations to the offshore sector. The Employment Tribunal issued its decision in favor of the unions and held, in part, that offshore workers are entitled to 28 days of annual leave. Such decision has been overturned on appeal by the Employment Appeal Tribunal, but the unions have appealed this decision of the Court of Session for a hearing in June 2010. The application of the Working Time Regulations to the offshore sector could result in higher labor costs and could undermine our ability to obtain a sufficient number of skilled workers in the U.K. Legislation has been introduced in the U.S. Congress that could encourage additional unionization efforts in the U.S., as well as increase the chances that such efforts succeed. Additional unionization efforts, if successful, new collective bargaining agreements or work stoppages could materially increase our labor costs and operating restrictions.

Our business involves numerous operating hazards.

Our operations are subject to the usual hazards inherent in the drilling of oil and gas wells, such as blowouts, reservoir damage, loss of production, loss of well control, punch-throughs, craterings, fires and natural disasters such as hurricanes and tropical storms. In particular, the South China Sea, the Northwest Coast of Australia and the Gulf of Mexico area are subject to typhoons, hurricanes or other extreme weather conditions on a relatively frequent basis, and our drilling rigs in these regions may be exposed to damage or total loss by these storms, some of which may not be covered by insurance. The occurrence of these events could result in the suspension of drilling operations, damage to or destruction of the equipment involved and injury to or death of rig personnel. Some experts believe global climate change could increase the frequency and severity of these extreme weather conditions. We are also subject to personal injury and other claims by rig personnel as a result of our drilling operations. Operations also may be suspended because of machinery breakdowns, abnormal drilling conditions, failure of subcontractors to perform or supply goods or services, or personnel shortages. In addition, offshore drilling operations are subject to perils peculiar to marine operations, including capsizing, grounding, collision and loss or damage from severe weather. Damage to the environment could also result from our operations, particularly through oil spillage or extensive uncontrolled fires. We may also be subject to property, environmental

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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 customers generally assume, and indemnify us against, well control and subsurface risks under dayrate contracts. These are risks associated with the loss of control of a well, such as blowout or cratering, the cost to regain control of or redrill the well and associated pollution. However, there can be no assurance that these customers will be financially able to indemnify us against all these risks.

We maintain insurance coverage for property damage, occupational injury and illness, and general and marine third-party liabilities. We generally have no coverage for named storms in the U.S. Gulf of Mexico and war perils worldwide. Also, pollution and environmental risks generally are not totally insurable. We maintain large self-insured deductibles for damage to our offshore drilling equipment and third-party liabilities. We also self-insure coverage for expenses to ADTI and CMI related to well control and redrill liability for well blowouts.

If a significant accident or other event occurs and is not fully covered by insurance or an enforceable or recoverable indemnity from a customer, it could adversely affect our consolidated statement of financial position, results of operations or cash flows. The amount of our insurance may be less than the related impact on enterprise value after a loss. Our insurance coverage will not in all situations provide sufficient funds to protect us from all liabilities that could result from our drilling operations. Our coverage includes annual aggregate policy limits. As a result, we retain the risk through self-insurance for any losses in excess of these limits. We generally do not carry insurance for loss of revenue unless contractually required, and certain other claims may also not be reimbursed by insurance carriers. Any such lack of reimbursement may cause us to incur substantial costs. In addition, we could decide to retain substantially more risk through self-insurance in the future. Moreover, no assurance can be made that we will be able to maintain adequate insurance in the future at rates we consider reasonable or be able to obtain insurance against certain risks. As of February 19, 2010, all of the rigs that we owned or operated were covered by existing insurance policies.

Regulation of greenhouse gases and climate change could have a negative impact on our business.

Some scientific studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases” (“GHGs”) and including carbon dioxide and methane, may be contributing to warming of the Earth’s atmosphere and other climatic changes. In response to such studies, the issue of climate change and the effect of GHG emissions, in particular emissions from fossil fuels, is attracting increasing attention worldwide.

On October 30, 2009, the U.S. Environmental Protection Agency (“EPA”) published a final rule requiring the reporting of GHG emissions from specified large sources in the U.S. beginning in 2011 for emissions occurring in 2010. In addition, on December 15, 2009, the EPA published a final rule finding that current and projected concentrations of six key GHGs in the atmosphere threaten public health and welfare of current and future generations. The EPA also found that the combined emissions of these GHGs from new motor vehicles and new motor vehicle engines contribute to the GHG pollution that threatens public health and welfare. This final rule, also known as EPA’s “Endangerment Finding,” does not impose any requirements on industry or other entities directly; however, after the rule’s January 14, 2010 effective date, the EPA will be able to finalize motor vehicle GHG standards, the effect of which could reduce demand for motor fuels refined from crude oil. Finally, according to the EPA, the final motor vehicle GHG standards will trigger construction and operating permit requirements for stationary sources. As a result, the EPA has proposed to tailor these programs such that only stationary sources, including refineries that emit over 25,000 tons of GHG emissions per year, will be subject to air permitting requirements. In addition, on September 22, 2009, the EPA issued a “Mandatory Reporting of Greenhouse Gases” final rule. This rule establishes a new comprehensive scheme requiring operators of stationary sources emitting more than established annual thresholds of carbon dioxide-equivalent GHGs to inventory and report their GHG emissions annually on a facility-by-facility basis. Further, proposed legislation has been introduced in the U.S. Congress that would establish an economy-wide cap on emissions of GHGs in the U.S. and would require most sources of GHG emissions to obtain GHG emission “allowances” corresponding to their annual emissions of GHGs. Moreover, in 2005, the Kyoto Protocol to the 1992 United Nations Framework Convention on Climate Change, which establishes a binding set of emission targets for greenhouse gases, became binding on all those countries that had ratified it. International discussions are currently underway to develop a treaty to replace the Kyoto Protocol after its expiration in 2012.

Because our business depends on the level of activity in the offshore oil and gas industry, existing or future laws, regulations, treaties or international agreements related to GHGs and climate change, including incentives to conserve energy or use alternative energy sources, could have a negative impact on our business if such laws, regulations, treaties or international agreements reduce the worldwide demand for oil and gas. In addition, such laws, regulations, treaties or international agreements could result in increased compliance costs or additional operating restrictions, which may have a negative impact on our business.

Failure to retain key personnel could hurt our operations.

We require highly skilled personnel to operate and provide technical services and support for our business worldwide. Over the last few years, competition for the labor required for drilling operations, including for turnkey drilling and drilling management services businesses and construction projects, intensified as the number of rigs activated, added to worldwide fleets or under construction increased, leading to shortages of qualified personnel in the industry and creating upward pressure on wages and higher

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turnover. We may experience a reduction in the experience level of our personnel as a result of any increased turnover, which could lead to higher downtime and more operating incidents, which in turn could decrease revenues and increase costs. In response to these historical labor market conditions, we increased efforts in our recruitment, training, development and retention programs as required to meet our anticipated personnel needs. Although we expect current market conditions to slow employee turnover, if increased competition for labor were to intensify in the future we may experience further increases in costs or limits on operations.

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

Our overall debt level was $12 billion and $14 billion at December 31, 2009 and December 31, 2008, respectively. This substantial level of debt and other obligations could have significant adverse consequences on our business and future prospects, including the following:

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

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

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

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

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

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

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

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

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

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

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

Public health threats, such as the H1N1 flu virus, Severe Acute Respiratory Syndrome, and other highly communicable diseases, outbreaks of which have already occurred in various parts of the world in which we operate, could adversely impact our operations, the operations of our customers 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 or waste disposals related to those operations. Laws and regulations protecting the environment

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have become more stringent in recent years, and may in some cases impose strict liability, rendering a person liable for environmental damage without regard to negligence. These laws and regulations may expose us to liability for the conduct of or conditions caused by others or for acts that were in compliance with all applicable laws at the time they were performed. The application of these requirements or the adoption of new requirements could have a material adverse effect on our consolidated statement of financial position, results of operations or cash flows.

We have generally been able to obtain some degree of contractual indemnification pursuant to which our customers 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 customers will have the financial capability to fulfill their contractual obligations to us. Also, these indemnities may not be enforceable in all instances.

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

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

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

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

Other risks

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

We operate worldwide through our various subsidiaries. Consequently, we are subject to changes in applicable tax laws, treaties or regulations 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, or in which we are incorporated or resident, could result in a higher effective tax rate on our worldwide earnings and such change could be significant to our financial results.

Tax legislative proposals intending to eliminate some perceived tax advantages of companies that have legal domiciles outside the U.S. but have certain U.S. connections have repeatedly been introduced in the U.S. Congress. Recent examples include, but are not limited to, legislative proposals that would broaden the circumstances in which a non-U.S. company would be considered a U.S. resident and proposals that could override certain tax treaties and limit treaty benefits on certain payments by U.S. subsidiaries to non-U.S. affiliates. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Outlook–Tax Matters.”

U.S. tax authorities could treat us as a "passive foreign investment company," which could have adverse U.S. federal income tax consequences to U.S. holders.

A foreign corporation will be treated as a "passive foreign investment company," or PFIC, for U.S. federal income tax purposes if either (1) at least 75 percent of its gross income for any taxable year consists of certain types of "passive income" or (2) at least 50 percent of the average value of the corporation's assets produce or are held for the production of those types of "passive income." For purposes of these tests, “passive income” includes dividends, interest and gains from the sale or exchange of investment property and certain rents and royalties, but does not include income derived from the performance of services.

We believe that we have not been and will not be a PFIC with respect to any taxable year. Based upon our operations as described herein, our income from offshore contract drilling services should be treated as services income for purposes of determining whether we are a PFIC. Accordingly, we believe that our income from our offshore contract drilling services should not constitute "passive income," and the assets that we own and operate in connection with the production of that income should not constitute passive assets.

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There is significant legal authority supporting this position, including statutory provisions, legislative history, case law and U.S. Internal Revenue Service (“IRS”) pronouncements concerning the characterization, for other tax purposes, of income derived from services where a substantial component of such income is attributable to the value of the property or equipment used in connection with providing such services. It should be noted, however, that a recent case and an IRS pronouncement which relies on the recent case characterize income from time chartering of vessels as rental income rather than services income for other tax purposes. However, we believe that the terms of the time charters in the recent case differ in material respects from the terms of our drilling contracts with customers. No assurance can be given that the IRS or a court will accept our position, and there is a risk that the IRS or a court could determine that we are a PFIC.

If we were to be treated as a PFIC for any taxable year, our U.S. shareholders would face adverse U.S. tax consequences. Under the PFIC rules, unless a shareholder makes certain elections available under the Internal Revenue Code of 1986, as amended (which elections could themselves have adverse consequences for such shareholder), such shareholder would be liable to pay U.S. federal income tax at the highest applicable income tax rates on ordinary income upon the receipt of excess distributions (as defined for U.S. tax purposes) and upon any gain from the disposition of our shares, plus interest on such amounts, as if such excess distribution or gain had been recognized ratably over the shareholder’s holding period of our shares. In addition, under applicable statutory provisions, the preferential 15 percent tax rate on “qualified dividend income,” which applies to dividends paid to non-corporate shareholders prior to 2011, does not apply to dividends paid by a foreign corporation if the foreign corporation is a PFIC for the taxable year in which the dividend is paid or the preceding taxable year.

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

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

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

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

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

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

Swiss law allows our shareholders to authorize share capital that can be issued by the board of directors without additional shareholder approval, but this authorization is limited to 50 percent of the existing registered share capital and must be renewed by the shareholders every two years. Additionally, subject to specified exceptions, Swiss law grants preemptive rights to existing shareholders to subscribe for new issuances of shares. Swiss law also does not provide as much flexibility in the various terms that can attach to different classes of shares as the laws of some other jurisdictions. In the event we need to raise common equity capital at a time when the trading price of our shares is below the par value of the shares (currently 15 Swiss francs, equivalent to U.S. $13.89

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based on a foreign exchange rate of 1.08 Swiss francs to $1.00 on February 19, 2010), we will need to obtain approval of shareholders to decrease the par value of our shares or issue another class of shares with a lower par value. Any reduction in par value would decrease our par value available for future repayment of share capital not subject to Swiss withholding tax. Swiss law also reserves for approval by shareholders certain corporate actions over which a board of directors would have authority in some other jurisdictions. For example, dividends must be approved by shareholders. These Swiss law requirements relating to our capital management may limit our flexibility, and situations may arise where greater flexibility would have provided substantial benefits to our shareholders.

If we are not successful in our efforts to make distributions, if any, through a reduction of par value or, after January 1, 2011, make distributions, if any, out of qualifying additional paid-in capital as shown on Transocean Ltd.’s standalone Swiss statutory financial statements, then any dividends paid by us will generally be subject to a Swiss federal withholding tax at a rate of 35 percent. Payment of a capital distribution in the form of a par value reduction is not subject to Swiss withholding tax. On February 16, 2010, we announced that our board of directors has decided to recommend that shareholders at our May 2010 annual general meeting approve a distribution in the form of a par value reduction denominated in Swiss francs for an amount equivalent to approximately U.S. $1.0 billion, payable in four installments. However, our shareholders may not approve the proposal, or we may not be able to meet the other legal requirements for a reduction in par value. The Swiss withholding tax rules could also be changed in the future. In addition, over the long term, the amount of par value available for us to use for par value reductions or the amount of qualifying additional paid-in capital available for us to pay out as distributions will be limited. If we are unable to make a distribution through a reduction in par value or, after January 1, 2011, make a distribution out of qualifying additional paid-in capital as shown on Transocean Ltd.’s standalone Swiss statutory financial statements, we may not be able to make distributions without subjecting our shareholders to Swiss withholding taxes.

Under present Swiss tax law, repurchases of shares for the purposes of capital reduction are treated as a partial liquidation subject to a 35 percent Swiss withholding tax on the difference between the repurchase price and the par value. At our 2009 annual general meeting, our shareholders approved the repurchase of up to 3.5 billion Swiss francs of our registered shares for cancellation (the “Share Repurchase Program”). On February 12, 2010, our board of directors authorized our management to implement the Share Repurchase Program. In addition, we announced our intention to list our shares on the SIX in the second quarter of 2010. Should we complete the listing of our shares on the SIX, we may repurchase shares under the Share Repurchase Program via a second trading line on the SIX from institutional investors who are generally able to receive a full refund of the Swiss withholding tax. Alternatively, in relation to the U.S. market, we may repurchase shares under the Share Repurchase Program using an alternative procedure pursuant to which we can repurchase shares under the Share Repurchase Program via a "virtual second trading line" from market players (in particular, banks and institutional investors) who are generally entitled to receive a full refund of the Swiss withholding tax. If we complete the listing of our shares on the SIX, there may not be sufficient liquidity in our shares on the SIX to repurchase the amount of shares that we would like to repurchase using the second trading line on the SIX. In addition, following the listing of our shares on the SIX our ability to use the “virtual second trading line” will be limited to the share repurchase program currently approved by our shareholders, and any use of the “virtual second trading line” with respect to future shares programs will require the approval of the competent Swiss tax and other authorities. We may not be able to repurchase as many shares as we would like to repurchase for purposes of capital reduction on either the “virtual second trading line” or, in the future, a SIX second trading line without subjecting the selling shareholders to Swiss withholding taxes.

We are subject to anti-takeover provisions.

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

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

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

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

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

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

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

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

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

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ITEM 1B.

Unresolved Staff Comments

None.

ITEM 2.

Properties

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

We maintain offices, land bases and other facilities worldwide, including our principal executive offices in Vernier, Switzerland, our corporate offices in Zug, Switzerland; Houston, Texas; Cayman Islands and Barbados and our regional operational office in France. 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

Asbestos litigation—In 2004, several of our subsidiaries were named, along with numerous other unaffiliated defendants, in 21 complaints filed on behalf of 769 plaintiffs in the Circuit Courts of the State of Mississippi and which claimed injuries arising out of exposure to asbestos allegedly contained in drilling mud during these plaintiffs’ employment in drilling activities between 1965 and 1986. A Special Master, appointed to administer these cases pre-trial, subsequently required that each individual plaintiff file a separate lawsuit, and the original 21 multi-plaintiff complaints were then dismissed by the Circuit Courts. The amended complaints resulted in one of our subsidiaries being named as a direct defendant in seven cases. We have or may have an indirect interest in an additional 17 cases. The complaints generally allege that the defendants used or manufactured asbestos-containing products in connection with drilling operations and have included allegations of negligence, products liability, strict liability and claims allowed under the Jones Act and general maritime law. The plaintiffs generally seek awards of unspecified compensatory and punitive damages. In each of these cases, the complaints have named other unaffiliated defendant companies, including companies that allegedly manufactured the drilling-related products that contained asbestos. None of the cases in which one of our subsidiaries is a named defendant has been scheduled for trial in 2010, and the preliminary information available on these claims is not sufficient to determine if there is an identifiable period for alleged exposure to asbestos, whether any asbestos exposure in fact occurred, the vessels potentially involved in the claims, or the basis on which the plaintiffs would support claims that their injuries were related to exposure to asbestos. However, the initial evidence available would suggest that we would have significant defenses to liability and damages. In 2009, two cases that were part of the original 2004 multi-plaintiff suits went to trial in Mississippi against unaffiliated defendant companies which allegedly manufactured drilling-related products containing asbestos. We were not a defendant in either of these cases. One of the cases resulted in a substantial jury verdict in favor of the plaintiff, and this verdict was subsequently vacated by the trial judge on the basis that the plaintiff failed to meet its burden of proof. While the court’s decision is consistent with our general evaluation of the strength of these cases, it has not been reviewed on appeal. The second case resulted in a verdict completely in favor of the defendants. There have been no other trials involving any of the parties to the original 21 complaints. We intend to defend these lawsuits vigorously, although there can be no assurance as to the ultimate outcome. We historically have maintained broad liability insurance, although we are not certain whether insurance will cover the liabilities, if any, arising out of these claims. Based on our evaluation of the exposure to date, we do not expect the liability, if any, resulting from these claims to have a material adverse effect on our consolidated statement of financial position, results of operations or cash flows.

One of our subsidiaries is involved in lawsuits arising out of the subsidiary’s involvement in the design, construction and refurbishment of major industrial complexes. The operating assets of the subsidiary were sold and its operations discontinued in 1989, and the subsidiary has no remaining assets other than the insurance policies involved in its litigation, fundings from settlements with the primary insurers and funds received from the cancellation of certain insurance policies. The subsidiary has been named as a defendant, along with numerous other companies, in lawsuits alleging personal injury as a result of exposure to asbestos. As of December 31, 2009, the subsidiary was a defendant in approximately 1,041 lawsuits. Some of these lawsuits include multiple plaintiffs and we estimate that there are approximately 2,623 plaintiffs in these lawsuits. For many of these lawsuits, we have not been provided with sufficient information from the plaintiffs to determine whether all or some of the plaintiffs have claims against the subsidiary, the basis of any such claims, or the nature of their alleged injuries. The first of the asbestos-related lawsuits was filed against this subsidiary in 1990. Through December 31, 2009, the amounts expended to resolve claims (including both attorneys’ fees and expenses, and settlement costs) have not been material, and all deductibles with respect to the primary insurance have been satisfied. The subsidiary continues to be named as a defendant in additional lawsuits and we cannot predict the number of additional cases in which it may be named a defendant nor can we predict the potential costs to resolve such additional cases or to resolve the pending cases. However, the subsidiary has in excess of $1 billion in insurance limits potentially available to the subsidiary. Although not all of the policies may be fully available due to the insolvency of certain insurers, we believe that the subsidiary will have sufficient insurance and funds from the settlements of litigation with insurance carriers available to respond to these claims. While we cannot predict or provide assurance as to the final outcome of these matters, we do not believe that the current value of the claims where we have been identified will have a material impact on our consolidated statement of financial position, results of operations or cash flows.

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transferred. When the temporary import permit granted to Schlumberger expired in 2000, renewal filings were not immediately made and the Brazilian authorities threatened to cancel the temporary import permit and to collect customs duties as if the rig had been nationalized in Brazil. Together with Schlumberger, we jointly filed an action for the purpose of avoiding cancellation of, and extending, the temporary import permit and to avoid collection of any customs duty. Other proceedings were also initiated to secure the transfer of the temporary import permit to us. The court initially permitted the transfer of the temporary import permit but did not rule on whether the temporary admission could be extended without the payment of a financial penalty in the form of Brazilian customs duties. In 2004, the Brazilian authorities issued an assessment totaling approximately $167 million (based on the initial assessment amount, accrued interest and current exchange rate) against our subsidiary based on the expiration of the temporary import permit. This amount continued to grow as a result of interest and changes in the exchange rate. The first level Brazilian court also ruled in 2007 that the financial penalties were appropriate and this ruling was subsequently upheld at the next level. We continued to contest this decision but ultimately decided to participate in November 2009 in a Brazilian tax amnesty program and paid $142 million to settle all tax claims by the Brazilian authorities in this matter. In addition, we reached a settlement with Schlumberger with respect to our allegation that Schlumberger should be responsible for the assessment.

Rio de Janeiro tax assessment—In the third quarter of 2006, we received tax assessments of approximately $164 million from the state tax authorities of Rio de Janeiro in Brazil against one of our Brazilian subsidiaries for taxes on equipment imported into the state in connection with our operations. The assessments resulted from a preliminary finding by these authorities that our subsidiary’s record keeping practices were deficient. We currently believe that the substantial majority of these assessments are without merit. We filed an initial response with the Rio de Janeiro tax authorities on September 9, 2006 refuting these additional tax assessments. In September 2007, we received confirmation from the state tax authorities that they believe the additional tax assessments are valid, and as a result, we filed an appeal on September 27, 2007 to the state Taxpayer’s Council contesting these assessments. While we cannot predict or provide assurance as to the final outcome of these proceedings, we do not expect it to have a material adverse effect on our consolidated statement of financial position, results of operations or cash flows.

Patent Litigation—Several of our subsidiaries have been sued by Heerema Engineering Services (“Heerema”) in the U.S. District Court for the Southern District of Texas for patent infringement, claiming that we infringe their U.S. patent entitled Method and Device for Drilling Oil and Gas. Heerema claims that our Enterprise class, advanced Enterprise class, Express class and Development Driller class of drilling rigs operating in the U.S. Gulf of Mexico infringe on this patent. They seek unspecified damages and injunctive relief. The court has held a hearing on construction of their patent but has not yet issued a decision. We deny liability for patent infringement, believe that their patent is invalid and intend to vigorously defend against the claim. We do not expect the liability, if any, resulting from this claim to have a material adverse effect on our consolidated statement of financial position, results of operations or cash flows.

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

Environmental Matters

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

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

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One of our subsidiaries has been ordered by the California Regional Water Quality Control Board (“CRWQCB”) to develop a testing plan for a site known as Campus 1000 Fremont in Alhambra, California. This site was formerly owned and operated by certain of our subsidiaries. It is presently owned by an unrelated party, which has received an order to test the property. We have also been advised that one or more of our subsidiaries is likely to be named by the EPA as a PRP for the San Gabriel Valley, Area 3, Superfund site, which includes this property. Testing has been completed at the property but no contaminants of concern were detected. In discussions with CRWQCB staff we were advised of their intent to issue us a “no further action” letter but it has not yet been received. Based on the test results, we would contest any potential liability. We have no knowledge at this time of the potential cost of any remediation, who else will be named as PRPs, and whether in fact any of our subsidiaries is a responsible party. The subsidiaries in question do not own any operating assets and have limited ability to respond to any liabilities.

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

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

§	appropriate investigatory and/or remedial actions; and

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

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

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

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

§	the remediation methods and technology to be used.

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

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

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

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

The codefendant filed a Notice of Appeal of the rulings of the Bankruptcy Court. GlobalSantaFe and its two subsidiaries also filed Notices of Appeal to the U.S. District Court for the District of Delaware. On January 27, 2009, the codefendant’s appeal was granted by the District Court and the bankruptcy case was remanded to the Bankruptcy Court with instructions to have the case dismissed. On February 10, 2009, the Bankruptcy Court entered an order dismissing the bankruptcy case. The debtors, GlobalSantaFe and the two subsidiaries have filed Notices of Appeal of the District Court’s ruling with the U.S. Court of Appeals for the Third Circuit. On February 18, 2009, the District Court stayed its ruling which instructed the Bankruptcy Court to dismiss the case. The appeal was heard on September 14, 2009. On December 22, 2009, the Court of Appeals affirmed the ruling of the District Court. On January 5, 2010, we petitioned the Third Circuit for a rehearing of that ruling. On January 27, 2010, the Third Circuit declined the petitions for rehearing.

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

ITEM 4. Submission of Matters to Vote of Security Holders

The Company did not submit any matter to a vote of its security holders during the fourth quarter of 2009.

Executive Officers of the Registrant

We have included the following information, presented as of December 31, 2009, on our executive officers in Part I of this report in reliance on General Instruction (3) to Form 10-K. The officers of the Company are elected annually by the board of directors. There is no family relationship between any of the executive officers named below.

		Age as of
Officer	Office	February 24, 2010
Robert L. Long (a)	Chief Executive Officer	64
Steven L. Newman (a)	President	45
Arnaud A.Y. Bobillier (b)	Executive Vice President, Assets	54
Eric B. Brown	Senior Vice President, General Counsel and Assistant Corporate Secretary	58
Cheryl D. Richard	Senior Vice President, Human Resources and Information Technology	53
Ricardo H. Rosa (c)	Senior Vice President and Chief Financial Officer	53
Ihab Toma	Senior Vice President, Marketing and Planning	47
John H. Briscoe	Vice President and Controller	52

______________________________

(a)

Robert L. Long will retire as Chief Executive Officer and resign as a member of the board of directors effective March 1, 2010. The board of directors has named Steven L. Newman to succeed Mr. Long upon his retirement. Mr. Newman will be nominated as a candidate for election as a member of the board of directors for a three-year term.

(b)	Arnaud A.Y. Bobillier will temporarily perform the functions of principal operating officer effective March 1, 2010.

(c)	Effective September 1, 2009, Ricardo H. Rosa succeeded Gregory L. Cauthen as Senior Vice President and Chief Financial Officer.

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

Steven L. Newman is President of the Company. Mr. Newman has served as President since May 2008. Mr. Newman also served as Chief Operating Officer from May 2008 to November 2009. From November 2007 until May 2008, Mr. Newman served as Executive Vice President, Performance, leading the Company’s three business units and focusing on customer service delivery and performance improvement across the company’s worldwide fleet. He previously served in senior management roles, including Executive Vice President and Chief Operating Officer from October 2006 to November 2007, Senior Vice President of Human Resources and Information Process Solutions from May 2006 to October 2006, Senior Vice President of Human Resources, Information Process Solutions and Treasury from March 2005 until May 2006, and Vice President of Performance and Technology from August 2003 until March 2005. He also has served as Regional Manager for the Asia and Australia Region and in international field and operations management positions, including Project Engineer, Rig Manager, Division Manager, Region Marketing Manager and Region Operations Manager. Mr. Newman joined the Company in 1994 in the Corporate Planning Department.

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

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

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

Ricardo H. Rosa is Senior Vice President and Chief Financial Officer of the Company. Before being named to his current position in September 2009, Mr. Rosa served as Senior Vice President of the Company's Europe and Africa Unit, which covers offshore drilling operations in 15 countries, from April 2008 to August 2009. Previously, Mr. Rosa served as Senior Vice President of the Asia and Pacific Unit from January 2008 to March 2008. He also served as served as the Vice President of the Asia and Pacific Unit from May 2005 to December 2007 and the Regional Manager for the Asia Region from June 2003 to April 2005. Mr. Rosa also served as Vice President and Controller from December 1999 to May 2003. Beginning in September 1995, Mr. Rosa was Controller of Sedco Forex Holdings Limited, one of our predecessor companies. Having previously held various financial positions in operating subsidiaries of Schlumberger Ltd., Mr. Rosa started his career with six years in public accounting in the U.K. and Brazil with PricewaterhouseCoopers.

Ihab Toma is Senior Vice President, Marketing and Planning of the Company. Before being named to his current position in August 2009, Mr. Toma served as Vice President, Sales and Marketing for Europe, Africa and Caspian for Schlumberger Oilfield Services from April 2006 to August 2009. Previously, Mr. Toma led Schlumberger’s information solutions business in various capacities, including Vice President, Sales and Marketing from 2004 to April 2006, prior to which he served in a variety of positions with Schlumberger Ltd., including President of Information Solutions, Vice President of Information Management and Vice President of Europe, Africa and CIS Operations. He started his career with Schlumberger in 1986.

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

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PART II

ITEM 5.

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

Market and share prices—Our shares are listed on the NYSE under the symbol “RIG.” On February 16, 2010, we announced our intention to list our shares on the SIX in the second quarter of 2010, subject to the approval of the SIX. Following such a listing, our shares would continue to be listed on the NYSE. The following table sets forth the high and low sales prices of our shares for the periods indicated as reported on the NYSE Composite Tape, including trading of the shares of Transocean Inc. through December 18, 2008 and trading of the shares of Transocean Ltd. after such date.

	Price
	2009				2008
	High		Low		High			Low
First quarter	$	67.17	$	46.11	$	147.25	$	111.34
Second quarter		85.57		56.75		163.00		132.46
Third quarter		87.22		65.04		154.50		105.16
Fourth quarter		94.44		78.71		109.16		41.95

On February 19, 2010, the last reported sales price of our shares on the NYSE Composite Tape was $85.12 per share. On such date, there were 7,323 holders of record of our shares and 321,628,110 shares outstanding.

Shareholder matters—We did not declare or pay a cash dividend in either of the two most recent fiscal years. On February 16, 2010, we announced that our board of directors has decided to recommend that shareholders at our May 2010 annual general meeting approve a distribution in the form of a par value reduction denominated in Swiss francs for an amount equivalent to approximately U.S. $1.0 billion, or approximately U.S. $3.11 per share based on the then current number of issued shares. The Swiss franc equivalent will be determined based on the exchange rate determined by us approximately two business days prior to the date of the 2010 annual general meeting. The distribution will, if approved, be paid in four installments with expected payment dates in July 2010, October 2010, January 2011 and April 2011. Distributions to shareholders in the form of a reduction in par value of our shares are not subject to the 35 percent Swiss withholding tax. Shareholders will be paid in U.S. dollars converted using an exchange rate determined by us approximately two business days prior to the payment date, unless shareholders elect to receive the payment in Swiss francs.

Any future declaration and payment of any cash distributions will (1) depend on our results of operations, financial condition, cash requirements and other relevant factors, (2) be subject to shareholder approval, (3) be subject to restrictions contained in our credit facilities and other debt covenants and (4) be subject to restrictions imposed by Swiss law, including the requirement that sufficient distributable profits from the previous year or freely distributable reserves must exist.

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

Swiss Tax Consequences to Shareholders of Transocean

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

Swiss Income Tax on Dividends and Similar Distributions

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

Swiss Wealth Tax

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

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Swiss Capital Gains Tax upon Disposal of Shares

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

Swiss Withholding Tax— Distributions to Shareholders

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

Exemption from Swiss Withholding Tax—Distributions to Shareholders

Under present Swiss tax law, distributions to shareholders in relation to a reduction of par value are exempt from Swiss withholding tax. Beginning on January 1, 2011, distributions to shareholders out of qualifying additional paid-in capital for Swiss statutory purposes are as a matter of principle exempt from the Swiss withholding tax. The particulars of this general principle are, however, subject to regulations still to be promulgated by the competent Swiss tax authorities. On December 31, 2009, the aggregate amount of par value and qualifying additional paid-in capital of our outstanding shares was 5.0 billion Swiss francs and 11.4 billion Swiss francs, respectively (which is equivalent to approximately U.S. $4.8 billion and U.S. $11.0 billion, respectively, at an exchange rate as of the close of trading on December 31, 2009 of U.S. $1.00 to 1.04 Swiss francs.) Consequently, we expect that a substantial amount of any potential future distributions may be exempt from Swiss withholding tax.

Repurchases of Shares

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

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

In most instances, Swiss companies listed on the SIX carry out share repurchase programs through a second trading line on the SIX. Swiss institutional investors typically purchase shares from shareholders on the open market and then sell the shares on the second trading line back to the company. The Swiss institutional investors are generally able to receive a full refund of the withholding tax. Due to, among other things, the time delay between the sale to the company and the institutional investors’ receipt of the refund, the price companies pay to repurchase their shares has historically been slightly higher (but less than one percent) than the price of such companies’ shares in ordinary trading on the SIX first trading line. On February 16, 2010, we announced our intention to list our shares on the SIX in the second quarter of 2010. Should we complete the listing of our shares on the SIX, we may repurchase such shares from institutional investors who are generally able to receive a full refund of the Swiss withholding tax via a second trading line on the SIX. Alternatively, in relation to the U.S. market, we may repurchase such shares using an alternative procedure pursuant to which we repurchase such shares via a "virtual second trading line" from market players (in particular, banks and institutional investors) who are generally entitled to receive a full refund of the Swiss withholding tax. If we complete the listing of our shares on the SIX, there may not be sufficient liquidity in our shares on the SIX to repurchase the amount of shares that we would like to repurchase using the second trading line on the SIX. In addition, following the listing of our shares on the SIX, our ability to use the “virtual second trading line” will be limited to the share repurchase program currently approved by our shareholders, and any use of the “virtual second trading line” with respect to future share repurchase programs will require approval of the competent Swiss tax and other authorities. We may not be able to repurchase as many shares as we would like to repurchase for purposes of capital reduction on either the “virtual second trading line” or, in the future, a SIX second trading line without subjecting the selling shareholders to Swiss withholding taxes.

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

At our 2009 annual general meeting our shareholders approved a release of qualifying additional paid-in-capital (for Swiss statutory purposes) to other reserves (for Swiss statutory purposes) that is necessary for the possible repurchase of shares for cancellation.

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Refund of Swiss Withholding Tax on Dividends and Other Distributions

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

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

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

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

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

§	beneficial ownership,

§	U.S. residency, and

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

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

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

Issuer Purchases of Equity Securities

Period	Total Number of Shares Purchased (1)		Average Price Paid Per Share	Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs (2)		Maximum Number (or Approximate Dollar Value) of Shares that May Yet Be Purchased Under the Plans or Programs (2) (in millions)
October 2009	1,001	$	85.21	—	$	—
November 2009	4,432		85.21	—		—
December 2009	5,116		83.03	—		—
Total	10,549	$	84.15	—	$	—

______________________________

(1)	Total number of shares purchased in the fourth quarter of 2009 consists of shares withheld by us in satisfaction of withholding taxes due upon the vesting of share-based awards granted to our employees under our Long-Term Incentive Plan.

(2)

In May 2009, at the annual general meeting of Transocean Ltd., our shareholders approved and authorized our board of directors, at its discretion, to repurchase an amount of our shares for cancellation with an aggregate purchase price of up to 3.5 billion Swiss francs (which is equivalent to approximately U.S. $3.2 billion at an exchange rate as of the close of trading on February 19, 2010 of U.S. $1.00 to 1.08 Swiss francs). On February 12, 2010, our board of directors authorized our management to implement the share repurchase program.

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ITEM 6. Selected Financial Data

The selected financial data as of December 31, 2009 and 2008 and for each of the three years in the period ended December 31, 2009 have been derived from the audited consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data.” 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.”

	Years ended December 31,
	2009			2008			2007 (a)			2006			2005 (b)
	(In millions, except per share data)
				(As adjusted) (c)
Statement of operations data
Operating revenues	$	11,556		$	12,674		$	6,377		$	3,882		$	2,892
Operating income		4,400			5,357			3,239			1,641			720
Net income		3,170			4,029			3,121			1,385			716
Net income attributable to controlling interest		3,181			4,031			3,121			1,385			716

Earnings per share
Basic	$	9.87		$	12.63		$	14.58		$	6.31		$	3.12
Diluted	$	9.84		$	12.53		$	14.08		$	6.10		$	3.03

Balance sheet data (at end of period)
Total assets	$	36,436		$	35,182		$	34,356		$	11,476		$	10,457
Debt due within one year		1,868			664			6,172			95			400
Long-term debt		9,849			12,893			10,266			3,203			1,197
Total equity		20,559			17,167			13,382			6,836			7,982

Other financial data
Cash provided by operating activities	$	5,598		$	4,959		$	3,073		$	1,237		$	864
Cash provided by (used in) investing activities		(2,694	)		(2,196	)		(5,677	)		(415	)		169
Cash provided by (used in) financing activities		(2,737	)		(3,041	)		3,378			(800	)		(1,039	)
Capital expenditures		3,052			2,208			1,380			876			182

______________________________

(a)

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

(b)

In May 2005 and June 2005, respectively, we completed the public offering and sale of our remaining interest in TODCO, a former wholly-owned subsidiary, pursuant to Rule 144 under the Securities Act of 1933, as amended (respectively referred to as the “May Offering” and the “June Sale”). Following our initial and subsequent public offerings in the year ended December 31, 2004, we accounted for our remaining investment in TODCO using the equity method of accounting. Following the May Offering, we accounted for our investment in TODCO using the cost method of accounting. As a result of the June Sale, we no longer own any shares of TODCO common stock.

(c)

Historical amounts have been adjusted to reflect our retrospective application of the accounting standards updates related to (i) convertible debt instruments that may be settled in cash upon conversion, (ii) noncontrolling interests in subsidiaries and (iii) earnings per share calculations considering participating securities.

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ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

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

Overview

We operate in two reportable segments: (1) contract drilling services and (2) other operations. Contract drilling services, our primary business, involves contracting our mobile offshore drilling fleet, related equipment and work crews primarily on a dayrate basis to drill oil and gas wells. We believe our drilling fleet is one of the most modern and versatile fleets in the world, consisting of floaters, jackups and other rigs used in support of offshore drilling activities and offshore support services on a worldwide basis. We specialize in technically demanding regions of the offshore drilling business with a particular focus on deepwater and harsh environment drilling services.

Our contract drilling operations are geographically dispersed in oil and gas exploration and development areas throughout the world. Although rigs can be moved from one region to another, the cost of moving rigs and the availability of rig-moving vessels may cause the supply and demand balance to fluctuate somewhat between regions. Still, significant variations between regions do not tend to persist long term because of rig mobility. Our fleet operates in a single, global market for the provision of contract drilling services. The location of our rigs and the allocation of resources to build or upgrade rigs are determined by the activities and needs of our customers.

The other operations segment includes drilling management services and oil and gas properties. Drilling management services are provided through Applied Drilling Technology Inc., our wholly owned subsidiary, and through ADT International, a division of one of our U.K. subsidiaries (together, “ADTI”). ADTI provides oil and gas drilling management services on either a dayrate basis or a completed-project, fixed-price (or “turnkey”) basis, as well as drilling engineering and drilling project management services. Our oil and gas properties consist of exploration, development and production activities carried out through Challenger Minerals Inc. and Challenger Minerals (North Sea) Limited (together, “CMI”), our oil and gas subsidiaries.

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

Significant Events

Share repurchase program—In May 2009, at our annual general meeting, our shareholders approved and authorized our board of directors, at its discretion, to repurchase an amount of our shares for cancellation with an aggregate purchase price of up to 3.5 billion Swiss francs, which is equivalent to approximately U.S. $3.2 billion at an exchange rate as of the close of trading on February 19, 2010 of U.S. $1.00 to 1.08 Swiss francs. On February 12, 2010, our board of directors authorized our management to implement the share repurchase program. See “—Liquidity and Capital Resources—Sources and Uses of Liquidity—Share repurchase program.”

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Fleet expansion—We have recently completed construction of seven Ultra-Deepwater newbuilds and each has departed the shipyard. As of February 2, 2010, five of these units had been accepted by their respective customers and commenced their respective contracts. See “—Outlook.”

Impairments—During 2009, we recorded impairment losses of $334 million, of which $279 million was associated with GSF Arctic II and GSF Arctic IV, which were classified as held for sale until these rigs were sold in January 2010. Additionally, we recorded impairment losses of $49 million and $6 million related to customer relationships and trade name, respectively, associated with our drilling management services reporting unit. These impairments were due primarily to the global economic downturn and depressed commodity prices.

Debt repayments—In March 2008, Transocean Inc. entered into a term credit facility under the Term Credit Agreement dated March 13, 2008 (the “Term Loan”) and borrowed $1.925 billion under the facility. In April 2008, Transocean Inc. borrowed an additional $75 million, increasing the borrowings under this facility to $2.0 billion, the maximum allowed under the Term Loan. During the year ended December 31, 2009, we repaid the outstanding borrowings and terminated the Term Loan. In addition, we repurchased $901 million aggregate principal amount of the 1.625% Series A Convertible Senior Notes for an aggregate cash purchase price of $865 million. See “—Liquidity and Capital Resources—Sources and Uses of Liquidity.”

Exchange listing—On February 16, 2010, we announced our intention to list our shares on the SIX in the second quarter of 2010, subject to the approval of the SIX. We will continue to list our shares on the New York Stock Exchange.

Outlook

Drilling market—We believe the economic downturn and lower oil and gas prices, having fallen from the historical highs experienced in 2008, have led to diminished demand for jackups, midwater and moored deepwater units, resulting in lower utilization levels for these classes of assets. Still, we expect market utilization to stabilize over the next few quarters, although possibly at lower levels than those of 2008, due to recent stability in oil and gas prices and the credit markets. In addition, we expect this stability to result in improved contracting opportunities for our High-Specification Floater fleet during 2010. However, we cannot be certain of the effect that the uncontracted capacity in 2010 and 2011 from newbuilds and existing units in the market could have on utilization for our High-Specification Floater fleet. Consequently, we do not believe that the increased tendering will lead to a corresponding increase in dayrates or to a return to the highs experienced in 2008 in the near term. See “Item 1A. Risk Factors” for a discussion of some of the risks associated with a continued decline in commodity prices and an extended worldwide economic downturn.

As of February 2, 2010, our contract backlog has declined to $30.4 billion compared to $32.2 billion as of November 2, 2009 and $39.8 billion as of December 31, 2008. Although we are currently engaged in advanced discussions with customers on several additional opportunities, our backlog may continue to decline if we are unable to obtain new contracts for our rigs that sufficiently replace existing backlog as it is consumed over time.

Fleet status—The uncommitted fleet rate is the number of uncommitted days as a percentage of the total number of available rig calendar days in the period. As of February 2, 2010, the uncommitted fleet rates for the remainder of 2010, 2011, 2012 and 2013 are as follows:

	Years ending December 31,
Uncommitted fleet rate	2010		2011		2012		2013
High-Specification Floaters	9	%	25	%	42	%	51	%
Midwater Floaters	33	%	73	%	84	%	95	%
High-Specification Jackups	64	%	86	%	90	%	100	%
Standard Jackups	61	%	80	%	94	%	98	%

We have 11 existing contracts with fixed-price or capped options, and given current market conditions, we expect that a number of these options will not be exercised by our customers in 2010. Well-in-progress or similar provisions of our existing contracts may delay the start of higher dayrates in subsequent contracts, and some of the delays could be significant.

High-Specification Floaters—Our Ultra-Deepwater Floater fleet is fully contracted for 2010, and we recently contracted one of our Deepwater Floaters that was available in 2011 for a three-year period. Recent subletting of our High-Specification Floater fleet had minimal impact on our operations in 2009, but we cannot be certain of the impact on our operations in 2010 and beyond.

As of February 2, 2010, we had 42 of our 49 current and future High-Specification Floaters contracted through the end of 2010, with 31, including all of our newbuilds, contracted beyond 2011. These 42 units also include all of our Ultra-Deepwater Floaters. We believe the continued exploration successes in the deepwater offshore provinces will foster significant demand and should support our long-term positive outlook for our High-Specification Floater fleet.

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Midwater Floaters—For our Midwater Floater fleet, which includes 26 semisubmersible rigs, near-term customer interest has remained steady and in line with the previous quarter. Market utilization for this fleet, however, may face challenges from the deepwater moored floaters coming available in 2010 and potentially competing in the midwater floater market due to the lack of current opportunities in the deepwater market. Tenders for our Midwater Floaters are generally shorter in duration, resulting in these units working on well-to-well programs. Sixty-nine percent of our Midwater Floater fleet is committed to contracts that extend into the second quarter of 2010. Although we have six stacked Midwater Floaters, we believe the recent increased tendering activity could result in a few units being extended or returned to work in the second half of 2010.

High-Specification Jackups and Standard Jackups—We continue to experience weakness in the jackup market. Considering the number of units currently stacked and the number of newbuild units expected to enter the market without customer contracts and the absence of a corresponding increase in customer demand, we expect near-term dayrates for our jackup fleet to decline as contracts are renewed or completed. As of February 2, 2010, we had three of our 10 High-Specification Jackups and 22 of our 55 Standard Jackups stacked. Although we have two High-Specification Jackups and 10 Standard Jackups completing their current contracts in the first quarter of 2010, the continued increase in tendering activity may result in the extension of these contracts or reactivation of a few of our stacked units in the second half of 2010.

Operating results—Key measures of our results of operations and financial condition are as follows:

	Years ended December 31,
	2009			2008			Change
	(In millions, except average daily revenue and percentages)
				(As adjusted)
Average daily revenue (a)(b)	$	271,400		$	240,300		$	31,100
Utilization (b)(c)		80	%		90	%		n/a
Statement of operations data
Operating revenues	$	11,556		$	12,674		$	(1,118	)
Operating and maintenance expenses		5,140			5,355			(215	)
Operating income		4,400			5,357			(957	)
Net income attributable to controlling interest		3,181			4,031			(850	)

Balance sheet data (at end of period)
Cash and cash equivalents		1,130			963			167
Total assets		36,436			35,182			1,254
Total debt		11,717			13,557			(1,840	)

______________________________

“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. Stacking rigs, such as Midwater Floaters, High-Specification Jackups and Standard Jackups, has the effect of increasing the average daily revenue since these rig types are typically contracted at lower dayrates compared to the High-Specification Floaters.

(b)	Calculation excludes results for Joides Resolution, a drillship engaged in scientific geological coring activities that is owned by an unconsolidated joint venture in which we have a 50 percent interest and for which we apply 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. Idle and stacked rigs are included in the calculation and reduce the utilization rate to the extent these rigs are not earning revenues. Newbuilds are included in the calculation upon acceptance by the customer.

Resulting from the market pressures experienced in the year ended December 31, 2009, our revenues declined relative to those recognized in the prior year. This decline was partially offset by revenues from the commencement of operations of five of our newbuild units. Similarly, decreased operating activity resulted in a decline in our operating and maintenance expenses for the same period compared to the prior year period, which was partially offset by costs associated with the commencement of operations of five of our newbuild units. As of December 31, 2009, we had reduced our total debt compared to December 31, 2008, considering repayments of borrowings under the Term Loan, reduced borrowings under our commercial paper program and repurchases of the 1.625% Series A Convertible Senior Notes (see “—Liquidity and Capital Resources—Sources and Uses of Liquidity”).

For the year ending December 31, 2010, we expect our total revenues to decline slightly compared to 2009. The reduction is primarily caused by reduced drilling activity associated with stacked and idle rigs and reduced operating activity associated with our integrated services. However, we expect the decrease in revenue to be partially offset by a full year of drilling operations of our newbuilds delivered in 2009, the commencement of drilling operations of four additional newbuilds to be delivered in 2010, and increased operating activities of our other operations segment.

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We expect our total operating and maintenance costs for 2010 to be in line with operating and maintenance costs for 2009 primarily due to a full year of drilling operations of our newbuilds delivered in 2009, the commencement of drilling operations of additional newbuilds to be delivered in 2010, an increase in planned shipyard and maintenance project costs, and an increase in operating activities of our other operations segment. These increases are mostly offset by stacked and idle rigs and reduced integrated services activity. Our projected operating and maintenance costs for 2010 remain uncertain and could be impacted by the actual level of activity as well as other factors.

Insurance matters—We periodically evaluate our hull and machinery and third-party liability insurance limits and self-insured retentions. Effective May 1, 2009, we renewed our hull and machinery and third-party liability insurance coverages with provisions similar to previous policies. Subject to large self-insured retentions, we carry hull and machinery insurance covering physical damage to the rigs for operational risks worldwide, and we carry liability insurance covering damage to third parties. However, we do not generally have commercial market insurance coverage for physical damage losses, including liability for removal of wreck expenses, to our rigs due to named windstorms in the U.S. Gulf of Mexico and war perils worldwide. Additionally, we do not carry insurance for loss of revenue, except on Dhirubhai Deepwater KG1 and Dhirubhai Deepwater KG2, with respect to which loss of revenue coverage is contractually required. Also, for our subsidiaries ADTI and CMI, we generally self-insure operators’ extra expense coverage. This coverage provides protection against expenses related to well control and redrill liability associated with blowouts. Generally, ADTI’s customers assume, and indemnify ADTI for, liability associated with blowouts in excess of $50 million. In the opinion of management, adequate accruals have been made based on known and estimated losses related to such exposures.

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

Our income tax return filings in the major jurisdictions in which we operate worldwide are generally subject to examination for periods ranging from three to six years. We have agreed to extensions beyond the statute of limitations in three major jurisdictions for up to 15 years. Tax authorities in certain jurisdictions are examining our tax returns and in some cases have issued assessments. We are defending our tax positions in those jurisdictions. While we cannot predict or provide assurance as to the final outcome of these proceedings, we do not expect the ultimate liability to have a material adverse effect on our consolidated statement of financial position or results of operations although it may have a material adverse effect on our consolidated cash flows.

With respect to our 2004 and 2005 U.S. federal income tax returns, the U.S. tax authorities have withdrawn all of their previously proposed tax adjustments, except a claim regarding transfer pricing for certain charters of drilling rigs between our subsidiaries, reducing the total proposed adjustment to approximately $79 million, exclusive of interest. We believe an unfavorable outcome on this assessment with respect to 2004 and 2005 activities would not result in a material adverse effect on our consolidated financial position, results of operations or cash flows. If the authorities were to continue to pursue this position with respect to subsequent years and were successful in such assertion, our effective tax rate on worldwide earnings with respect to years following 2005 could increase substantially, and our earnings and cash flows from operations could be materially and adversely affected. Although we believe the transfer pricing for these charters is materially correct, we have been unable to reach a resolution with the tax authorities and we expect the matter to proceed to litigation.

The U.S. tax authorities’ original assessment also asserted that one of our key subsidiaries maintains a permanent establishment in the U.S. and is, therefore, subject to U.S. taxation on certain earnings effectively connected to such U.S. business. In November 2009, we were notified that this position was withdrawn by the U.S. tax authorities. If the authorities were to continue to pursue this position with respect to years following 2005 and were successful in such assertion, our effective tax rate on worldwide earnings with respect to those years could increase substantially, and our earnings and cash flows from operations could be materially and adversely affected. We believe our returns are materially correct as filed, and we will continue to vigorously defend against any such claim.

In October 2009, we received verbal notification from the U.S. tax authorities of potential adjustments related to a series of restructuring transactions that occurred between 2001 and 2004, but we have not received a formal assessment or notification that a formal assessment will be issued. These restructuring transactions ultimately resulted in the disposition of our TODCO entity in 2004. We believe that our tax returns are materially correct as filed, and we will vigorously defend against any potential claim.

Norwegian civil tax and criminal authorities are investigating various transactions undertaken by our subsidiaries in 2001 and 2002 as well as the actions of our former external advisors on these transactions. The authorities issued tax assessments of approximately $269 million, plus interest, related to certain restructuring transactions, approximately $71 million, plus interest, related to a 2001 dividend payment, approximately $5 million, plus interest, related to foreign exchange deductions and approximately $2 million, plus interest, related to dividend withholding tax. We plan to appeal these tax assessments. We may be required to provide some form of financial security, in an amount up to $736 million, including interest and penalties, for these assessed amounts as this dispute is appealed and addressed by the Norwegian courts. Furthermore, the authorities have also issued notification of their intent to issue a tax assessment of approximately $173 million, plus interest, related to the migration of a subsidiary that was previously

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subject to tax in Norway. The authorities have indicated that they plan to seek penalties of 60 percent on all matters. We have and will continue to respond to all information requests from the Norwegian authorities. We plan to vigorously contest any assertions by the Norwegian authorities in connection with the various transactions being investigated.

During the year ended December 31, 2009, our long-term liability for unrecognized tax benefits related to these Norwegian tax issues increased by $35 million to $181 million due to the accrual of interest and exchange rate fluctuations. While we cannot predict or provide assurance as to the final outcome of these proceedings, we do not expect the ultimate resolution of these matters to have a material adverse effect on our consolidated financial position or results of operations, although it may have a material adverse effect on our consolidated cash flows.

Certain of our Brazilian income tax returns for the years 2000 through 2004 are currently under examination. The Brazil tax authorities have issued tax assessments totaling $114 million, plus a 75 percent penalty of $86 million and interest of $99 million through December 31, 2009. We believe our returns are materially correct as filed, and we are vigorously contesting these assessments. We filed a protest letter with the Brazilian tax authorities on January 25, 2008, and we are currently engaged in the appeals process.

See Notes to Consolidated Financial Statements—Note 7—Income Taxes.

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

On July 25, 2007, our legal representatives met with the DOJ in response to a notice we received requesting such a meeting regarding our engagement of Panalpina Inc. for freight forwarding and other services in the U.S. and abroad. The DOJ informed us that it was conducting an investigation of alleged FCPA violations by oil service companies who used Panalpina Inc. and other brokers in Nigeria and other parts of the world. We developed an investigative plan which has continued to be amended and which would allow us to review and produce relevant and responsive information requested by the DOJ and SEC. The investigation was expanded to include one of our agents for Nigeria. This investigation and the legacy GlobalSantaFe investigation are being conducted by outside counsel who reports directly to the audit committee of our board of directors. The investigation has focused on whether the agent and the customs brokers have fully complied with the terms of their respective agreements, the FCPA and local laws and the company’s and its employees’ possible involvement in any inappropriate or illegal conduct in connection with such brokers and agent. Our outside counsel has coordinated their efforts with the DOJ and the SEC with respect to the implementation of our investigative plan, including keeping the DOJ and SEC apprised of the scope and details of the investigation and producing relevant information in response to their requests. The SEC has also now issued a formal order of investigation in this case and issued a subpoena for further information, including information related to the U.S. Treasury Department’s Office of Foreign Assets Control (“OFAC”) investigation described below.

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

We are continuing to cooperate with the DOJ, SEC and OFAC. We expect these investigations will continue to result in the incurrence of significant legal fees and related expenses as well as involve significant management time. We cannot predict the ultimate outcome of these investigations, the total costs to be incurred in completing the investigations, the potential impact on personnel, the effect of implementing any further measures that may be necessary to ensure full compliance with applicable laws or to what extent, if at all, we could be subject to fines, sanctions or other penalties. In response to these investigations, we have implemented measures to strengthen and expand our compliance program and training.

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In addition, from time to time, we receive inquiries from governmental regulatory agencies regarding our operations around the world, including inquiries with respect to types of matters similar to those described above. To the extent appropriate under the circumstances, we investigate such matters, respond to such inquiries and cooperate with the regulatory agencies. Although we are unable to predict the outcome of any of these matters, we do not expect the liability, if any, resulting from these inquiries to have a material adverse effect on our consolidated statement of financial position, results of operations or cash flows.

Performance and Other Key Indicators

Contract backlog—The following table presents our contract backlog, including firm commitments only, for our contract drilling services segment as of December 31, 2009 and 2008. Firm commitments are represented by signed drilling contracts or, in some cases, by other definitive agreements awaiting contract execution. Our contract backlog is calculated by multiplying the full contractual operating dayrate by the number of days remaining in the firm contract period, excluding revenues for mobilization, demobilization and contract preparation or other incentive provisions, which are not expected to be significant to our contract drilling revenues. The contractual operating dayrate may be higher than certain other rates included in the contract, such as a waiting-on-weather rate, repair rate or force majeure rate.

	December 31,
	2009		2008
Contract backlog	(In millions)
High-Specification Floaters	$	25,704	$	29,770
Midwater Floaters		3,412		5,801
High-Specification Jackups		374		507
Standard Jackups		1,601		3,568
Other Rigs		80		107
Total	$	31,171	$	39,753

The firm commitments that comprise the contract backlog for our contract drilling services segment as of December 31, 2009 are presented in the following table along with the associated average contractual dayrates. The actual amounts of revenues earned and the actual periods during which revenues are earned will differ from the amounts and periods shown in the tables below due to various factors, including shipyard and maintenance projects, unplanned downtime and other factors that result in lower applicable dayrates than the full contractual operating dayrate. Additional factors that could affect the amount and timing of actual revenue to be recognized and timing include customer liquidity issues and contract terminations, which are available to our customers under certain circumstances. The contract backlog average contractual dayrate is defined as the contracted operating dayrate to be earned per revenue earning day in the period. A revenue earning day is defined as a day for which a rig earns a dayrate during the firm contract period after commencement of operations.

		For the years ending December 31,
		Total		2010		2011		2012		2013		Thereafter
Contract backlog		(In millions, except average dayrates)
High-Specification Floaters		$	25,704	$	6,258	$	6,219	$	4,776	$	4,104	$	4,347
Midwater Floaters			3,412		1,894		735		438		118		227
High-Specification Jackups			374		223		84		65		2		—
Standard Jackups			1,601		935		462		135		34		35
Other Rigs			80		28		26		26		—		—
Total contract backlog		$	31,171	$	9,338	$	7,526	$	5,440	$	4,258	$	4,609

Average contractual dayrates		Total		2010		2011		2012		2013		Thereafter
High-Specification Floaters		$	465,000	$	448,000	$	479,000	$	482,000	$	480,000	$	441,000
Midwater Floaters	��		337,000		344,000		366,000		338,000		261,000		265,000
High-Specification Jackups			168,000		166,000		162,000		185,000		185,000		—
Standard Jackups			130,000		141,000		128,000		109,000		84,000		78,000
Other Rigs			73,000		73,000		73,000		73,000		—		—
Total fleet average		$	385,000	$	335,000	$	386,000	$	414,000	$	452,000	$	413,000

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Fleet average daily revenue and utilization—The following table presents the average daily revenue and utilization for our contract drilling services segment for each of the quarters ended December 31, 2009, September 30, 2009 and December 31, 2008. Average daily revenue is defined as contract drilling revenue earned per revenue earning day in the period. A revenue earning day is defined as a day for which a rig earns a dayrate after commencement of operations. Utilization is defined as the total actual number of revenue earning days in the period as a percentage of the total number of calendar days in the period for all drilling rigs in our fleet.

	Three months ended
	December 31, 2009			September 30, 2009			December 31, 2008
Average daily revenue
High-Specification Floaters
Ultra-Deepwater Floaters	$	486,200		$	458,500		$	423,600
Deepwater Floaters	$	346,600		$	355,600		$	299,000
Harsh Environment Floaters	$	405,800		$	386,000		$	358,900
Total High-Specification Floaters	$	425,900		$	409,300		$	370,500
Midwater Floaters	$	325,100		$	355,800		$	329,200
High-Specification Jackups	$	175,100		$	161,000		$	169,100
Standard Jackups	$	147,300		$	156,200		$	156,100
Other Rigs	$	72,300		$	73,300		$	37,800
Total fleet average daily revenue	$	295,700		$	283,800		$	251,500


Utilization
High-Specification Floaters
Ultra-Deepwater Floaters		91	%		90	%		96	%
Deepwater Floaters		88	%		89	%		75	%
Harsh Environment Floaters		83	%		80	%		100	%
Total High-Specification Floaters		89	%		88	%		88	%
Midwater Floaters		69	%		72	%		92	%
High-Specification Jackups		53	%		70	%		94	%
Standard Jackups		57	%		68	%		90	%
Other Rigs		50	%		42	%		99	%
Total fleet average utilization		69	%		75	%		90	%

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Liquidity and Capital Resources

Sources and Uses of Cash

Our primary source of cash during the year ended December 31, 2009 was our cash flows from operating activities. Our primary uses of cash were capital expenditures (including for newbuild construction), repayments of borrowings under our credit facilities and repurchases of our convertible senior notes. At December 31, 2009, we had $1.1 billion in cash and cash equivalents.

	Years ended December 31,
	2009			2008			Change
	(In millions)
Cash flows from operating activities				(As adjusted)
Net income	$	3,170		$	4,029		$	(859	)
Amortization of drilling contract intangibles		(281	)		(690	)		409
Depreciation, depletion and amortization		1,464			1,436			28
Loss on impairment		334			320			14
Other non-cash items		477			185			292
Changes in operating assets and liabilities, net		434			(321	)		755
	$	5,598		$	4,959		$	639

Net cash provided by operating activities increased primarily due to cash generated from net income, adjusted for non-cash activity resulting primarily from intangible amortization and other non-cash items as well as cash generated from net operating assets and liabilities, including increased collections of accounts receivables. Increases from other non-cash items were primarily related to deferred expenses, deferred revenues and deferred income taxes.

	Years ended December 31,
	2009			2008			Change
	(In millions)
Cash flows from investing activities
Capital expenditures	$	(3,052	)	$	(2,208	)	$	(844	)
Proceeds from disposal of assets, net		18			348			(330	)
Proceeds from short-term investments		564			59			505
Purchases of short-term investments		(269	)		(408	)		139
Joint ventures and other investments, net		45			13			32
	$	(2,694	)	$	(2,196	)	$	(498	)

Net cash used in investing activities increased primarily due to capital expenditures for the construction of nine of our 10 Ultra-Deepwater Floaters and decreased proceeds from asset sales due to the sale of three rigs during 2008 with no corresponding activity in 2009. Partially offsetting the increase in net cash used in investing activities was greater proceeds from and less purchases of short-term investments.

We include investments in highly liquid debt instruments with an original maturity of three months or less in cash and cash equivalents. In September 2008, The Reserve announced that certain funds, including The Reserve Primary Fund and The Reserve International Liquidity Fund Ltd., had lost the ability to maintain a net asset value of $1.00 per share due to losses in connection with the bankruptcy of Lehman Brothers Holdings, Inc. (“Lehman Holdings”). According to its public disclosures, The Reserve stopped processing redemption requests in order to develop an orderly plan of liquidation that would protect all of the funds’ shareholders. Based on statements made by the funds, we recognized an impairment loss of $16 million, recorded in other, net, in the quarter ended September 30, 2008, associated with our proportional interest in the debt instruments of Lehman Holdings held by the funds. During the year ended December 31, 2009, we received distributions of $10 million and $286 million from The Reserve Primary Fund and the Reserve International Liquidity Fund Ltd., respectively. As of December 31, 2009, the carrying values of our investments in The Reserve Primary Fund and The Reserve International Liquidity Fund Ltd. were $5 million and $33 million, respectively. The timing of our ability to access the remaining funds is uncertain. In January 2010, we received a distribution of $5 million from The Reserve Primary Fund representing the final amount of our expected recovery from this fund.

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Shortly following the Lehman Holdings bankruptcy, the funds announced that all redemption requests received by the funds prior to a cut-off time on the day following the bankruptcy of Lehman Holdings would be redeemed at a net asset value of $1.00 per share. Some investors in the funds that submitted redemption requests prior to this cut-off time are seeking redemption of their interests at this amount, which would reduce funds available for distribution to other investors, including us. We have filed a motion to intervene in pending litigation against The Reserve International Liquidity Fund Ltd. seeking a declaration that we are entitled to a pro rata distribution with respect to the redemption of our remaining interest in the fund, damages and other relief. Potential rulings or decisions by courts or regulators relating to this litigation or otherwise relating to this fund may impact further distributions by this fund and result in losses in excess of our previously recognized losses on impairment.

	Years ended December 31,
	2009			2008			Change
	(In millions)
Cash flows from financing activities
Change in short-term borrowings, net	$	(382	)	$	(837	)	$	455
Proceeds from debt		514			2,661			(2,147	)
Repayments of debt		(2,871	)		(4,893	)		2,022
Financing costs		(2	)		(24	)		22
Payments for warrant exercises, net		(13	)		(7	)		(6	)
Proceeds from share-based compensation plans, net		17			51			(34	)
Excess tax benefit from share-based compensation plans		2			10			(8	)
Other, net		(2	)		(2	)		—
	$	(2,737	)	$	(3,041	)	$	304

Net cash used in financing activities decreased primarily due to offsetting reductions in proceeds from and repayments of debt during 2009 compared to the same period in 2008.

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Fleet Expansion and Dispositions

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

Capital expenditures, including capitalized interest of $182 million, totaled $3.1 billion during the year ended December 31, 2009, substantially all of which related to our contract drilling services segment. The following table presents the historical and projected capital expenditures and other capital additions, including capitalized interest, for our major construction and conversion projects (in millions):

	Total costs through December 31, 2009		Expected costs for the year ending December 31, 2010		Total estimated costs at completion
	(As adjusted)
Petrobras 10000 (a) (b)	$	735	$	—	$	735
Dhirubhai Deepwater KG1 (a) (c)		679		—		679
Discoverer Inspiration		667		3		670
Dhirubhai Deepwater KG2 (c)		641		49		690
Discoverer Clear Leader (a)		631		—		631
Discoverer Americas (a)		626		—		626
Development Driller III (a) (d)		600		50		650
Sedco 700-series upgrades (a)		591		—		591
Discoverer India		541		199		740
Discoverer Luanda (e)		535		145		680
Deepwater Champion (d)		527		218		745
Capitalized Interest		422		90		512
Mobilization costs		155		80		235
Total	$	7,350	$	834	$	8,184

______________________________

(a)	The accumulated construction costs of these rigs are no longer included in construction work in progress, as their construction or conversion projects had been completed as of December 31, 2009.

(b)

In June 2008, we reached an agreement with a joint venture formed by subsidiaries of Petrobras and Mitsui to acquire Petrobras 10000 under a capital lease contract. In connection with the agreement, we agreed to provide assistance and advisory services for the construction of the rig and operating management services once the rig commenced operations. On August 4, 2009, we accepted delivery of Petrobras 10000 and recorded non-cash additions of $716 million to property and equipment, net, along with a corresponding increase to long-term debt. Total capital additions include $716 million in capital costs incurred by Petrobras and Mitsui for the construction of the drillship and $19 million of other capital expenditures. The capital lease agreement has a 20-year term, after which we will have the right and obligation to acquire the drillship for one dollar.

(c)

The costs for Dhirubhai Deepwater KG1 and Dhirubhai Deepwater KG2 represent 100 percent of expenditures incurred prior to our investment in the joint venture ($277 million and $178 million, respectively) and 100 percent of expenditures incurred since our investment in the joint venture. Transocean Pacific Drilling Inc. (“TPDI”) is responsible for these costs. We hold a 50 percent interest in TPDI, and Pacific Drilling Limited (“Pacific Drilling”) holds the remaining 50 percent interest.

(d)	These costs include our initial investments in Development Driller III and Deepwater Champion of $350 million and $109 million, respectively, representing the estimated fair values of the rigs at the time of our merger with GlobalSantaFe Corporation (“GlobalSantaFe”) in November 2007.

(e)	The costs for Discoverer Luanda represent 100 percent of expenditures incurred since inception. Angola Deepwater Drilling Company Limited (“ADDCL”) is responsible for these costs. We hold a 65 percent interest in ADDCL, and Angco Cayman Limited holds the remaining 35 percent interest.

During 2010, we expect capital expenditures to be approximately $1.3 billion, including approximately $750 million of cash capital costs for our major construction and conversion projects. The level of our capital expenditures is partly dependent upon financial market conditions, the actual level of operational and contracting activity and the level of capital expenditures for which our customers agree to reimburse us.

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

We intend to fund the cash requirements relating to our capital expenditures through available cash balances, cash generated from operations and asset sales. We also have available credit under the Five-Year Revolving Credit Facility (see “—Sources and Uses of Liquidity”) and may utilize other commercial bank or capital market financings. We intend to fund the cash requirements of our joint ventures for capital expenditures in connection with newbuild construction through their respective credit facilities. The

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continued economic downturn and related instability in the global financial system could impact the availability of these sources of funding. See “Item 1A. Risk Factors—The worldwide financial and economic downturn could have a material adverse effect on our revenue, profitability and financial position” and “Item 1A. Risk Factors—The worldwide financial and economic downturn may continue to negatively impact our business and financial condition.”

Dispositions—From time to time, we may also review possible dispositions of drilling units. During the year ended December 31, 2009, we received net proceeds of $18 million and recognized a net loss of $9 million in connection with our sales of Sedco 135-D and other unrelated property and equipment. Additionally, in connection with the sales of our ownership interests in Caspian Drilling Company Limited and in Arab Drilling & Workover Company, we received net proceeds of $42 million and recognized a net gain of $30 million, recorded in other, net on our consolidated statements of operations.

In January 2010, we completed the sale of two Midwater Floaters, GSF Arctic II and GSF Arctic IV, in connection with our previously announced undertakings to the Office of Fair Trading in the U.K. (“OFT”). In connection with the sale, we received net cash proceeds of $40 million and non-cash proceeds in the form of two notes receivable, in the aggregate amount of $165 million. We continue to operate GSF Arctic IV under a short-term bareboat charter with the new owner of the vessel through October 2010.

Sources and Uses of Liquidity

Overview—We expect to use existing cash balances, internally generated cash flows, bank credit agreements and proceeds from asset sales to fulfill anticipated obligations such as scheduled debt maturities or other payment events, repayment of short-term debt, capital expenditures and working capital needs. We may also use a portion of such sources of cash to reduce debt (including convertible debt) prior to scheduled maturity through repurchases (in the open market or in privately negotiated transactions), redemptions or tender offers, to make distributions to our shareholders, or to repurchase our shares, subject in each case to then existing market conditions and to our then expected liquidity needs and subject to a shareholder approval with respect to distributions. From time to time, we may also borrow under our bank credit agreement or our commercial paper program to maintain liquidity for short-term cash needs.

During the year ended December 31, 2009, we repaid the borrowings under the Term Loan and repurchased $901 million aggregate principal amount of the 1.625% Series A Convertible Senior Notes for an aggregate cash purchase price of $865 million.

On February 16, 2010, we announced that our board of directors has decided to recommend that shareholders at our May 2010 annual general meeting approve a distribution in the form of a par value reduction denominated in Swiss francs for an amount equivalent to approximately U.S. $1.0 billion, or approximately U.S. $3.11 per share based on the current number of issued shares, in four installments. If approved, we intend to fund such distributions using cash flows from operations. See “—Distribution recommendation.”

In May 2009, at our annual general meeting, our shareholders approved and authorized our board of directors, at its discretion, to repurchase shares for cancellation with an aggregate purchase price of up to 3.5 billion Swiss francs. On February 12, 2010, our board of directors authorized our management to implement the share repurchase program. We intend to fund any such repurchases using cash flows from operations. See “—Share repurchase program.”

Our access to debt and equity markets may be reduced or closed to us due to a variety of events, including among others, general economic conditions, industry conditions, credit rating agency downgrades of our debt, market conditions or market perceptions of us and our industry. The economic downturn and related financial market instability has had, and may continue to have, an impact on our business and our financial condition. Our ability to access the capital markets may be severely restricted at a time when we would like, or need, to access the financial markets, which could have an impact on our flexibility to react to changing economic and business conditions. The economic downturn could have an impact on the lenders participating in our credit facilities or on our customers, causing them to fail to meet their obligations to us.

Our internally generated cash flow is directly related to our business and the market sectors in which we operate. Should the drilling market deteriorate, or should we experience poor results of 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.

Notes receivable—In connection with our disposal of GSF Arctic II and GSF Arctic IV in January 2010, we received two notes in the aggregate amount of $165 million. The notes bear a fixed interest rate of nine percent and require scheduled quarterly installments of principal and interest with a final payment in 2015. The vessels are pledged as security for the payment and performance of obligations under the notes. See “—Fleet Expansion and Dispositions—Dispositions.”

Bank credit agreements—We have a revolving credit facility subject to the Five-Year Revolving Credit Facility Agreement dated November 27, 2007 (“Five-Year Revolving Credit Facility”). We may borrow under the Five-Year Revolving Credit Facility at either (1) the adjusted London Interbank Offer Rate (“LIBOR”) plus a margin (the “Five-Year Revolving Credit Facility Margin”) based on our Debt Rating (based on our current Debt Rating, a margin of 1.1 percent) or (2) the Base Rate plus the Five-Year Revolving Credit Facility Margin, less one percent per annum. Throughout the term of the Five-Year Revolving Credit Facility, we pay a facility fee on the daily amount of the underlying commitment, whether used or unused, which ranges from 0.10 percent to

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0.30 percent (based on our Debt Rating) and was 0.15 percent at February 19, 2010. The Five-Year Revolving Credit Facility, which may be prepaid in whole or in part without premium or penalty, includes limitations on creating liens, incurring subsidiary debt, transactions with affiliates, sale/leaseback transactions, mergers and the sale of substantially all assets. The Five-Year Revolving Credit Facility also includes covenants imposing a maximum debt to tangible capitalization ratio of 0.6 to 1.0. As of December 31, 2009, our debt to tangible capitalization ratio was 0.49 to 1.0. Borrowings under the Five-Year Revolving Credit Facility are subject to acceleration upon the occurrence of events of default. 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 the Five-Year Revolving Credit Facility and, if not waived by the lenders, could cause us to lose access to the Five-Year Revolving Credit Facility. At February 19, 2010, we had $81 million in letters of credit issued and outstanding and no borrowings outstanding under the Five-Year Revolving Credit Facility.

During the year ended December 31, 2009, we repaid the outstanding borrowings under the Term Loan and terminated the facility. In November 2009, the 364-Day Revolving Credit Agreement, dated November 25, 2008, which established our $1.08 billion 364-day revolving credit facility, expired with no borrowings outstanding.

Commercial paper program—We maintain a commercial paper program (the “Program”), which is supported by the Five-Year Revolving Credit Facility and under which we may, from time to time, issue privately placed, unsecured commercial paper notes up to a maximum aggregate outstanding amount of $1.5 billion. Proceeds from commercial paper issuance under the Program may be used for general corporate purposes. At February 19, 2010, $472 million was outstanding under the Program at a weighted-average interest rate of 0.3 percent.

TPDI Credit Facilities—TPDI has a bank credit agreement for a $1.265 billion secured credit facility (the “TPDI Credit Facilities”), comprised of a $1.0 billion senior term loan, a $190 million junior term loan and a $75 million revolving credit facility, which was established to finance the construction of Dhirubhai Deepwater KG1 and Dhirubhai Deepwater KG2. One of our subsidiaries participates in the senior and junior term loans with a 50 percent commitment totaling $595 million in the aggregate. The TPDI Credit Facilities bear interest at LIBOR plus the applicable margin of 1.60 percent until acceptance of Dhirubhai Deepwater KG2, which is expected to occur in the first quarter of 2010. Subsequently, the TPDI Credit Facilities will bear interest at a rate of 1.45 percent for the senior term loan and the revolving credit facility and 2.25 percent for the junior term loan. The senior term loan requires quarterly payments with a final payment on the earlier of (1) June 2015 and (2) the fifth anniversary of the acceptance date of the Dhirubhai Deepwater KG2. The junior term loan is due in full on the earlier of (1) June 2015 and (2) the fifth anniversary of the acceptance date of the Dhirubhai Deepwater KG2. The TPDI Credit Facilities may be prepaid in whole or in part without premium or penalty. The TPDI Credit Facilities have covenants that require TPDI to maintain a minimum cash balance and available liquidity, a minimum debt service ratio and a maximum leverage ratio. At February 19, 2010, $1.2 billion was outstanding under the TPDI Credit Facilities, of which $595 million was due to one of our subsidiaries and was eliminated in consolidation. The weighted-average interest rate of the TPDI Credit Facilities on February 19, 2010 was 3.9 percent.

TPDI Notes—TPDI has issued promissory notes payable to Pacific Drilling and one of our subsidiaries (the “TPDI Notes”). The TPDI Notes bear interest at LIBOR plus the applicable margin of 2 percent and have maturities through October 2019. As of February 19, 2010, $296 million in promissory notes remained outstanding, $148 million of which was due to one of our subsidiaries and has been eliminated in consolidation, bearing interest at a weighted-average interest rate of 2.8 percent.

ADDCL Credit Facilities—ADDCL has a senior secured bank credit agreement for a credit facility (the “ADDCL Primary Loan Facility”) comprised of Tranche A, Tranche B and Tranche C for $215 million, $270 million and $399 million, respectively, which was established to finance the construction of Discoverer Luanda. Tranche A and Tranche B are provided by external lenders, and the borrowings under these tranches bear interest at LIBOR plus the applicable margin of 0.425 percent until the first well commencement date, currently expected to be in the third quarter of 2010, following which the borrowings outstanding under Tranche A will bear interest at LIBOR plus the applicable margin of 0.725 percent. Tranche A requires semi-annual payments beginning six months after the rig’s first well commencement date, and matures in December 2017. Tranche B matures upon customer acceptance of the rig and is expected to be repaid with borrowings under Tranche C. Tranche C will be provided by one of our subsidiaries that has also agreed to provide financial security for borrowings under Tranche A and Tranche B until customer acceptance of Discoverer Luanda. Tranche C is subordinate to Tranche A and Tranche B and will be eliminated in consolidation. The ADDCL Primary Loan Facility contains covenants that require ADDCL to maintain certain cash balances to service the debt and also limits ADDCL’s ability to incur additional indebtedness, to acquire assets, or to make distributions or other payments. At February 19, 2010, $193 million and $235 million were outstanding under Tranche A and Tranche B, respectively, both at a weighted-average interest rate of 0.7 percent.

Additionally, ADDCL has a secondary bank credit agreement for a $90 million credit facility (the “ADDCL Secondary Loan Facility”), for which one of our subsidiaries provides 65 percent of the total commitment. The facility bears interest at LIBOR plus the applicable margin, ranging from 3.125 percent to 5.125 percent, depending on certain milestones. The ADDCL Secondary Loan Facility is payable in full on the earlier of (1) 90 days after the fifth anniversary of the first well commencement or (2) December 2015, and it may be prepaid in whole or in part without premium or penalty. At February 19, 2010, $74 million was outstanding under the ADDCL Secondary Loan Facility, of which $48 million was provided by one of our subsidiaries and has been eliminated in consolidation. At February 19, 2010, the weighted-average interest rate was 3.4 percent.

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Convertible Senior Notes—In December 2007, we issued $6.6 billion aggregate principal amount of Convertible Senior Notes. The Convertible Senior Notes may be converted at a rate of 5.9310 shares per $1,000 note, subject to adjustment upon the occurrence of certain events. Upon conversion, we will deliver, in lieu of shares, cash up to the aggregate principal amount of notes to be converted and shares in respect of the remainder, if any, of our conversion obligation. If certain fundamental changes occur on or before specified dates, we will, in some cases, increase the conversion rate for a holder electing to convert notes in connection with such fundamental change; provided that in no event will the total number of shares issuable upon conversion of a note exceed 7.8585 per $1,000 principal amount of notes, subject to adjustment in the same manner as the conversion rate.

Share repurchase program—In May 2009, at our annual general meeting, our shareholders approved and authorized our board of directors, at its discretion, to repurchase an amount of our shares for cancellation with an aggregate purchase price of up to 3.5 billion Swiss francs, which is equivalent to approximately U.S. $3.2 billion at an exchange rate as of the close of trading on February 19, 2010 of U.S. $1.00 to 1.08 Swiss francs. On February 12, 2010, our board of directors authorized our management to implement the share repurchase program. We intend to fund any repurchases using cash from operating activities.

We may decide, based upon our ongoing capital requirements, the price of our shares, regulatory and tax considerations, cash flow generation, the relationship between our contract backlog and our debt, general market conditions and other factors, that we should retain cash, reduce debt, make capital investments or otherwise use cash for general corporate purposes, and consequently, repurchase fewer or no shares under this program. Decisions regarding the amount, if any, and timing of any share repurchases would be made from time to time based upon these factors.

Any shares repurchased under this program are expected to be purchased from time to time from market participants that have acquired those shares on the open market and that can fully recover Swiss withholding tax resulting from the share repurchase. Repurchases could also be made by tender offer, in privately negotiated transactions or by any other share repurchase method. Any repurchased shares would be held by us for cancellation by the shareholders at a future annual general meeting. The share repurchase program could be suspended or discontinued by our board of directors or company management, as applicable, at any time.

Under Swiss corporate law, the right of a company and its subsidiaries to repurchase and hold its own shares is limited. A company may repurchase such company’s shares to the extent it has freely distributable reserves as shown on its Swiss statutory balance sheet in the amount of the purchase price and the aggregate par value of all shares held by the company as treasury shares does not exceed 10 percent of the company’s share capital recorded in the Swiss commercial register, whereby for purposes of determining whether the 10 percent threshold has been reached, shares repurchased under a share repurchase program for cancellation purposes authorized by the company’s shareholders are disregarded. As of December 31, 2009, Transocean Inc., our wholly owned subsidiary, held as treasury shares approximately four percent of our issued shares. At the annual general meeting in May 2009, the shareholders approved the release of 3.5 billion Swiss francs of additional paid-in capital to other reserves, or freely available reserves as presented on our Swiss statutory balance sheet, to create the freely available reserve necessary for the 3.5 billion Swiss franc share repurchase program for the purpose of the cancellation of shares (the “Currently Approved Program”). We may only repurchase shares to the extent freely distributable reserves are available. Our board of directors could, to the extent freely distributable reserves are available, authorize the repurchase of additional shares for purposes other than cancellation, such as to retain treasury shares for use in satisfying our obligations in connection with incentive plans or other rights to acquire our shares. Based on the current amount of shares held as treasury shares, approximately six percent of our issued shares could be repurchased for purposes of retention as additional treasury shares. Although our board of directors has not approved such a share repurchase program for the purpose of retaining repurchased shares as treasury shares, if it did so, any such shares repurchased would be in addition to any shares repurchased under the Currently Approved Program.

Distribution recommendation—On February 16, 2010, we announced that our board of directors has decided to recommend that shareholders at our May 2010 annual general meeting approve a distribution in the form of a par value reduction denominated in Swiss francs for an amount equivalent to approximately U.S. $1.0 billion, or approximately U.S. $3.11 per share based on the current number of issued shares. The Swiss franc equivalent will be determined based on the exchange rate determined by us approximately two business days prior to the date of the 2010 annual general meeting. The distribution will, if approved, be paid in four installments with expected payment dates in July 2010, October 2010, January 2011 and April 2011. Distributions to shareholders in the form of a reduction in par value of our shares are not subject to the 35 percent Swiss withholding tax. Shareholders will be paid in U.S. dollars converted using an exchange rate determined by us approximately two business days prior to the payment date, unless shareholders elect to receive the payment in Swiss francs. If approved, we intend to fund such distributions using our cash flows from operations.

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Index

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

	For the years ending December 31,
	Total		2010		2011-2012		2013-2014		Thereafter
	(in millions)
Contractual obligations
Debt (a)	$	11,392	$	1,890	$	4,759	$	951	$	3,792
Capital leases		1,454		74		148		148		1,084
Interest on debt		4,487		365		631		478		3,013
Operating leases		174		40		56		33		45
Purchase obligations		902		902		—		—		—
Total (b)	$	18,409	$	3,271	$	5,594	$	1,610	$	7,934

______________________________

(a)

Noteholders may, at their option, require Transocean Inc. to repurchase the Series A Convertible Senior Notes and the Series B Convertible Senior Notes in December 2010 and 2011, respectively. In addition, holders of any series of the Convertible Senior Notes may, at their option, require Transocean Inc. to repurchase their notes in December 2012, 2017, 2022, 2027 and 2032. In preparing the table above, we have assumed that the holders of our notes exercise the options at the first available date.

(b)

As of December 31, 2009, our defined benefit pension and other postretirement plans represented an aggregate liability of $514 million, representing the aggregate projected benefit obligation, net of the aggregate fair value of plan assets. The carrying amount of this liability is affected by net periodic benefit costs, funding contributions, participant demographics, plan amendments, significant current and future assumptions, and returns on plan assets. Due to the uncertainties resulting from these factors and since the carrying amount is not representative of future liquidity requirements, we have excluded this amount from the contractual obligations presented in the table above. See “—Retirement Pension Plans and Other Postretirement Benefit Plans” and Notes to Consolidated Financial Statements—Note 15—Postemployment Benefit Plans.

As of December 31, 2009, our unrecognized tax benefits related to uncertain tax positions, net of prepayments, represented a liability of $648 million. Due to the high degree of uncertainty regarding the timing of future cash outflows associated with the liabilities recognized in this balance, we are unable to make reasonably reliable estimates of the period of cash settlement with the respective taxing authorities. See Notes to Consolidated Financial Statements—Note 7—Income Taxes.

Other commercial commitments—At December 31, 2009, we had other commercial commitments that we are contractually obligated to fulfill with cash under certain circumstances. These commercial commitments 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. Standby letters of credit are issued under a number of committed and uncommitted bank credit facilities. The obligations that are the subject of these standby letters of credit and surety bonds are geographically concentrated in Nigeria and India. Obligations under these standby letters of credit and surety bonds are not normally called, as we typically comply with the underlying performance requirement. The following table presents these obligations in U.S. dollar equivalents and their time to expiration.

	For the years ending December 31,
	Total		2010		2011-2012		2013-2014		Thereafter
	(in millions)
Other commercial commitments
Standby letters of credit	$	567	$	469	$	71	$	24	$	3
Surety bonds		31		29		2		—		—
Total	$	598	$	498	$	73	$	24	$	3

We have established a wholly owned captive insurance company, which insures various risks of our operating subsidiaries. Access to the cash investments of the captive insurance company may be limited due to local regulatory restrictions. The cash investments totaled $201 million at December 31, 2009. The cash investments are expected to range from $150 million to $250 million by December 31, 2010, depending on the amount of claims that may be incurred, the timing of claim payments, the amount of dividends paid by the captive insurance company, and the amount of premiums paid to the captive insurance company.

Derivative Instruments

We have established policies and procedures for derivative instruments approved by our board of directors that provide for the approval of our Chief Financial Officer prior to entering into any derivative instruments. From time to time, we may enter into a variety of derivative instruments in connection with the management of our exposure to fluctuations in interest rates and foreign exchange rates. We do not enter into derivative transactions for speculative purposes; however, we may enter into certain transactions that do not meet the criteria for hedge accounting. See Notes to Consolidated Financial Statements—Note 12—Derivatives and Hedging.

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Results of Operations

Historical 2009 compared to 2008

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,
	2009			2008			Change			% Change
	(In millions, except day amounts and percentages)
				(As adjusted)
Revenue earning days		39,085			44,761			(5,676	)	(13)	%
Utilization		80	%		90	%		n/a		n/m
Average daily revenue	$	271,400		$	240,300		$	31,100		13	%

Contract drilling revenues	$	10,607		$	10,756		$	(149	)	(1)	%
Contract drilling intangible revenues		281			690			(409	)	(59)	%
Other revenues		668			1,228			(560	)	(46)	%
		11,556			12,674			(1,118	)	(9)	%
Operating and maintenance expense		(5,140	)		(5,355	)		215		(4)	%
Depreciation, depletion and amortization		(1,464	)		(1,436	)		(28	)	2	%
General and administrative expense		(209	)		(199	)		(10	)	5	%
Loss on impairment		(334	)		(320	)		(14	)	4	%
Loss on disposal of assets, net		(9	)		(7	)		(2	)	29	%
Operating income		4,400			5,357			(957	)	(18)	%
Other income (expense), net
Interest income		5			32			(27	)	(84)	%
Interest expense, net of amounts capitalized		(484	)		(640	)		156		(24)	%
Loss on retirement of debt		(29	)		(3	)		(26	)	n/m
Other, net		32			26			6		23	%
Income tax expense		(754	)		(743	)		(11	)	1	%
Net income		3,170			4,029			(859	)	(21)	%
Net loss attributable to noncontrolling interest		(11	)		(2	)		(9	)	n/m
Net income attributable to controlling interest	$	3,181		$	4,031		$	(850	)	(21)	%

______________________________

“n/a” means not applicable.

“n/m” means not meaningful.

Operating revenues—Contract drilling revenues decreased primarily due to lower utilization, partly offset by higher average daily revenue. The lower utilization was primarily due to reduced activity resulting from the stacking of 36 rigs, including one held for sale as of December 31, 2009, compared to two stacked rigs, including one held for sale as of December 31, 2008. This reduced activity was partially offset by the commencement of operations of our newbuilds and by lower out of service time for shipyard, mobilization, maintenance and repair projects during the year ended December 31, 2009 relative to the same period in 2008. Our average daily revenue increases as we commence operations under new contracts that offer higher dayrates and as our newbuilds commence operations. In addition, our average daily revenue increases as we stack rigs in our Midwater Floaters, High-Specification Jackups and Standard Jackups fleets since rigs in these classes are typically contracted at lower dayrates compared to those in our High-Specification Floaters fleet.

Contract drilling intangible revenues declined $409 million for the year ended December 31, 2009, compared to the year ended December 31, 2008, due to timing of the respective executory contracts with which they were associated. Contract drilling intangible revenues represent the amortization of the fair value of drilling contracts in effect at the time of the Merger. We recognize contract drilling intangible revenues over the respective contract period using the straight-line method of amortization.

Other revenues for the year ended December 31, 2009 decreased primarily due to reduced activity in our other operations segment.

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Costs and expenses—Operating and maintenance expenses decreased primarily due to reduced activity in our other operations segment, the reduced activity in contract drilling services resulting from a greater number of stacked rigs in 2009 and the sale of our interest in a joint venture that previously operated two rigs under bareboat charter. These decreases were partially offset by increases in shipyard and maintenance projects, the commencement of operations of our newbuilds and provisions associated with litigation matters.

Depreciation, depletion and amortization increased primarily due to $21 million of expense related to the commencement of operations of four newbuilds and $14 million related to a life-enhancement project on the Sedco 706 upgrade. Partly offsetting the increase was $14 million of reduced depreciation expense related to the extension of the useful lives of four rigs in 2009.

In the year ended December 31, 2009, we recognized losses on impairment of $334 million, including $279 million and $55 million related to assets held for sale and other intangible assets, respectively. In the year ended December 31, 2008, we recognized losses on impairment of $320 million, including $176 million, $97 million and $47 million related to goodwill, assets held for sale and other intangible assets, respectively.

Other income and expense—Interest income decreased by $27 million, in the year ended December 31, 2009 compared to 2008, primarily due to reduced average cash balances and reduced interest rates on cash investments.

Interest expense decreased $156 million in the year ended December 31, 2009 compared to 2008, primarily attributable to $131 million associated with debt repaid or repurchased, $34 million associated with reduced borrowings under our commercial paper program and $35 million associated with increased interest capitalized. Partially offsetting the decrease was $40 million of interest expense associated with the commencement of the Petrobras 10000 capital lease and additional borrowings under our TPDI Credit Facilities and ADDCL Credit Facilities in 2009.

In the year ended December 31, 2009, we recognized losses on retirement of debt of $29 million primarily related to repurchases of the Series A Convertible Notes. In the year ended December 31, 2008, we recognized a loss on retirement of debt of $3 million related to the early termination of the Bridge Loan Facility.

Income tax expense—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. The countries in which we operate have taxation regimes with varying nominal rates, deductions, credits and other tax attributes. Consequently, there is little to no expected relationship between income tax expense and net income before income tax expense. The annual effective tax rate for the years ended December 31, 2009 and 2008 was 16.0 percent and 14.4 percent, respectively, based on income before income tax expense after adjusting for certain items such as losses on impairment, losses on litigation matters, losses on retirement of debt and merger-related costs. The tax effect, if any, of the excluded items as well as settlements of prior year tax liabilities and changes in prior year tax estimates are all treated as discrete period tax expenses or benefits. In the year ended December 31, 2009, the various discrete items represented income tax expense of $54 million, resulting in an effective tax rate of 19.2 percent on net income before income tax expense, including $74 million primarily resulting from changes in prior year estimates, offset by benefits of $18 million and $2 million resulting from losses on impairment and merger-related costs, respectively. In the year ended December 31, 2008, the various discrete items represented a net tax benefit of $2 million including $24 million primarily resulting from changes in prior year estimates, offset by benefits of $17 million and $9 million resulting from losses on impairment and other charges, respectively.

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Index

Historical 2008 compared to 2007

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

	Years ended December 31,
	2008			2007			Change			% Change
	(In millions, except day amounts and percentages)
	(As adjusted)
Revenue earning days		44,761			28,074			16,687		59	%
Utilization		90	%		90	%		n/a		n/m
Average daily revenue	$	240,300		$	211,900		$	28,400		13	%

Contract drilling revenues	$	10,756		$	5,948		$	4,808		81	%
Contract drilling intangible revenues		690			88			602		n/m
Other revenues		1,228			341			887		n/m
		12,674			6,377			6,297		99	%
Operating and maintenance expense		(5,355	)		(2,781	)		(2,574	)	93	%
Depreciation, depletion and amortization		(1,436	)		(499	)		(937	)	n/m
General and administrative expense		(199	)		(142	)		(57	)	40	%
Loss on impairment		(320	)		—			(320	)	n/m
Gain (loss) on disposal of assets, net		(7	)		284			(291	)	n/m
Operating income		5,357			3,239			2,118		65	%
Other income (expense), net
Interest income		32			30			2		7	%
Interest expense, net of amounts capitalized		(640	)		(182	)		(458	)	n/m
Loss on retirement of debt		(3	)		(8	)		5		63	%
Other, net		26			295			(269	)	(91)	%
Income tax expense		(743	)		(253	)		(490	)	n/m
Net income		4,029			3,121			908		29	%
Net loss attributable to noncontrolling interest		(2	)		—			2		n/m
Net income attributable to controlling interest	$	4,031		$	3,121		$	910		29	%

______________________________

“n/a” means not applicable.

“n/m” means not meaningful.

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

Contract drilling intangible revenues were $690 million for the year ended December 31, 2008, compared to $88 million for the year ended December 31, 2007, due to timing of the respective executory contracts with which they were associated. Contract drilling intangible revenues represent the amortization of the fair value of drilling contracts in effect at the time of our merger with GlobalSantaFe. We recognize contract drilling intangible revenues over the respective contract period using the straight-line method of amortization.

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

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

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

The increase in general and administrative expenses was due primarily to $28 million related to the inclusion of GlobalSantaFe’s operations and a $29 million net increase in general operating costs.

During the year ended December 31, 2008, we recognized losses on impairment of $320 million including $176 million, $97 million and $47 million related to goodwill, assets held for sale and other intangible assets, respectively. There was no comparable activity in 2007.

During the year ended December 31, 2008, we recognized a net loss on disposal of $7 million related to sales of rigs and other property and equipment. During 2007, we recognized net gain on disposal of $284 million related to sales of rigs and other property and equipment.

Other income and expense—Interest income increased was primarily due to higher average cash balances in 2008 compared to 2007.

The increase in interest expense was primarily attributable to $467 million of interest expense on additional borrowings under our credit facilities and $104 million of interest expense resulting from the issuance of new debt during 2008. In addition, $32 million of the increase was from debt assumed in the Merger, including $15 million from debt due to affiliates. Partially offsetting this increase were reductions of $72 million due to debt repaid during 2008 and $70 million related to increased capitalized interest during 2008.

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

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

Income tax expense—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. The countries in which we operated have taxation regimes with varying nominal rates, deductions, credits and other tax attributes. Consequently, there is little to no expected relationship between the income tax expense and net income before income tax expense. The annual effective tax rate for the years ended December 31, 2008 and 2007 was 14.4 percent and 12.5 percent, respectively, based on net income before income tax expense after adjusting for certain items, such as a portion of net gains on disposal of assets, losses on impairment, losses on retirement of debt and merger-related costs. The tax effect, if any, of the excluded items as well as settlements of prior year tax liabilities and changes in prior year tax estimates are all treated as discrete period tax expenses or benefits. In the year ended December 31, 2008, the various discrete items represented a net tax benefit of $2 million, resulting in an effective tax rate of 15.6 percent on net income before income tax expense, including $24 million primarily resulting from changes in prior year estimates, offset by benefits of $17 million and $9 million resulting from losses on impairment and other charges, respectively. In the year ended December 31, 2007, the various discrete items represented a tax benefit of $43 million resulting from changes in prior year estimates, $58 million for the reduction of a valuation allowance related to U.S. foreign tax credits and $15 million from merger-related costs.

Business Combination

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

Our historical financial operating results for 2007 include approximately one month of operating results for the combined company. Although the Merger did not materially impact 2007 results, it had a significant impact on our 2008 results and is expected to have a significant impact on our future results of operations and financial condition. See Notes to Consolidated Financial Statements—Note 5―Business Combinations.

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Critical Accounting Policies and Estimates

We have prepared our consolidated financial statements in accordance with accounting principles generally accepted in the U.S., which require us to make estimates, judgments and assumptions that affect the amounts reported on the consolidated financial statements and disclosed in the accompanying notes. 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 amounts of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates.

We consider the following to be our critical accounting policies and estimates, and we have discussed the development, selection and disclosure of these critical accounting policies and estimates with the audit committee of our board of directors. For a discussion of our significant accounting policies, refer to our Notes to Consolidated Financial Statements—Note 2—Significant Accounting Policies.

Income taxes—We are a Swiss corporation, operating through our various subsidiaries in a number of countries throughout the world. We have provided for income taxes based upon the tax laws and rates in the countries in which we operate and earn income. There is little to no expected relationship between the provision for or benefit from income taxes and income or loss before income taxes because the countries have taxation regimes that vary with respect to the nominal tax rate and 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 of our annual tax provision and evaluation of our tax positions involves interpretation of tax laws in the various jurisdictions 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. Our tax liability in any given year could be affected by changes in tax laws, regulations, agreements, and treaties, foreign currency exchange restrictions or our level of operations or profitability in each jurisdiction. Additionally, we operate in many jurisdictions where the tax laws relating to the offshore drilling industry are not well developed. Although our annual tax provision is based on the best information available at the time, a number of years may elapse before the ultimate tax liabilities in the various jurisdictions are determined.

We maintain liabilities for estimated tax exposures in our jurisdictions of operation, and the provisions and benefits resulting from changes to those liabilities are included in our annual tax provision along with related interest. Tax exposure items include potential challenges to permanent establishment positions, intercompany pricing, disposition transactions, and withholding tax rates and their applicability. 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 revise past estimates.

We are currently undergoing examinations in a number of taxing jurisdictions for various fiscal years. We review our liabilities on an ongoing basis and, to the extent audits or other events cause us to adjust the liabilities accrued in prior periods, we recognize those adjustments in the period of the event. We do not believe it is possible to reasonably estimate the future impact of changes to the assumptions and estimates related to our annual tax provision because changes to our tax liabilities are dependent on numerous factors that cannot be reasonably projected. These factors 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 taxes paid to one country that either produce, or fail to produce, offsetting tax changes in other countries.

We consider the earnings of certain of our subsidiaries to be indefinitely reinvested. As such, we have not provided for taxes on these unremitted earnings. At December 31, 2009, the amount of indefinitely reinvested earnings was approximately $1.8 billion. Should we make a distribution from the unremitted earnings of these subsidiaries, we would be subject to taxes payable to various jurisdictions. We estimate taxes in the range of $150 million to $200 million would be payable upon distribution of all previously unremitted earnings at December 31, 2009.

We have recognized deferred taxes related to the earnings of certain subsidiaries that are not permanently reinvested or that will not be permanently reinvested in the future. If facts and circumstances cause us to change our expectations regarding future tax consequences, the resulting adjustments to our deferred tax balances could have a material effect on our consolidated statement of financial position, results of operations or cash flows.

Estimates, judgments and assumptions are required in determining whether deferred tax assets will be fully or partially realized. When it is estimated to be more likely than not that all or some portion of certain deferred tax assets, such as foreign tax credit carryovers or net operating loss carryforwards, will not be realized, we establish a valuation allowance for the amount of the deferred tax assets that is considered to be unrealizable. We continually evaluate strategies that could allow for the future utilization of our deferred tax assets. Resulting from a change in circumstances in the year ended December 31, 2007, we believe that we will realize the benefits of our foreign tax credits in the U.S. and appropriately released the respective valuation allowance of approximately $58 million. We did not make any significant changes to our valuation allowance against deferred tax assets during the years ended December 31, 2008 and 2009.

See Notes to Consolidated Financial Statements—Note 7—Income Taxes.

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Goodwill—The carrying amount of goodwill was $8.1 billion, representing 22 percent of our total assets, as of December 31, 2009. We conduct impairment testing for our goodwill annually as of October 1 and more frequently when an event occurs or circumstances change that may indicate a reduction in the fair value of a reporting unit below its carrying amount. We test goodwill at the reporting unit level, which is defined as an operating segment or a component of an operating segment that constitutes a business for which financial information is available and is regularly reviewed by management. We have determined that our reporting units for this purpose are as follows: (1) contract drilling services, (2) drilling management services and (3) oil and gas properties.

To determine the fair value of each reporting unit, we use a combination of valuation methodologies, including both income and market approaches. For our contract drilling services reporting unit, we estimate fair value using discounted cash flows and publicly traded company multiples. To develop the projected cash flows associated with our contract drilling services reporting unit, which are based on estimated future utilization and dayrates, we consider key factors that include assumptions regarding future commodity prices, credit market conditions and the effect these factors may have on our contract drilling operations and the capital expenditure budgets of our customers. We discount projected cash flows using a long-term weighted-average cost of capital, which is based on our estimate of the investment returns that market participants would require for each of our reporting units. To develop the publicly traded company multiples, we gather available market data for companies with operations similar to our reporting units and publicly available information for recent acquisitions in the marketplace.

Because our business is cyclical in nature, the results of our impairment testing are expected to vary significantly depending on the timing of the assessment relative to the business cycle. Altering either the timing of or the assumptions used in a reporting unit’s fair value calculations could result in an estimate that is significantly below its carrying amount, which may indicate its goodwill is impaired.

In calculating the fair values of our reporting units for our annual impairment test performed as of October 1, 2009, we applied a discount rate of 10 percent and a terminal growth rate of three percent to our contract drilling services reporting unit. Applying a hypothetical three percent increase in the discount rate and a hypothetical 10 percent decrease in our projected cash flows for our 2009 annual impairment test would not have resulted in the impairment of goodwill associated with our contract drilling services reporting unit.

Property and equipment—The carrying amount of our property and equipment was $23 billion as of December 31, 2009, representing 63 percent of our total assets. The carrying amount of these assets is subject to our estimates, assumptions, and judgments related to capitalized costs, useful lives and salvage values.

Capitalized costs—We capitalize costs incurred to enhance, improve and extend the useful lives of our assets and expense costs incurred to repair and maintain the existing condition of our rigs. Capitalized costs increase the carrying amounts and depreciation expense of the related assets, which would also impact our results of operations.

Useful lives—We depreciate our assets over their estimated useful lives, which we determine by applying judgments and assumptions that reflect both historical experience and expectations regarding future operations, utilization and asset performance. Useful lives of rigs are difficult to estimate due to a variety of factors, including (a) technological advances that impact the methods or cost of oil and gas exploration and development, (b) changes in market or economic conditions, and (c) changes in laws or regulations affecting the drilling industry. Applying different judgments and assumptions in establishing the useful lives would likely result in materially different net carrying amounts and depreciation expense for our assets. We evaluate the remaining useful lives of our rigs when certain events occur that directly impact the useful lives of the rigs, including changes in operating condition, functional capability and market and economic factors. When evaluating the remaining useful lives of rigs, we also consider major capital upgrades required to perform certain contracts and the long-term impact of those upgrades on future marketability. A hypothetical one-year increase in the useful lives of all of our rigs would cause a decrease in our annual depreciation expense of approximately $184 million. A hypothetical one-year decrease would cause an increase in our annual depreciation expense of approximately $264 million.

Impairment of long-lived assets—We review our property and equipment for impairment when events or changes in circumstances indicate that the carrying amounts of our assets held and used may not be recoverable or when carrying amounts of assets held for sale exceed fair value less cost to sell. Potential impairment indicators include rapid declines in commodity prices and related market conditions, actual or expected declines in rig utilization or increases in idle time, cancellations of contracts or credit concerns of multiple customers. During periods of oversupply, we may idle or stack rigs for extended periods of time, which could be an indication that an asset group may be impaired since supply and demand are the key drivers of rig utilization and our ability to contract our rigs at economical rates. Our rigs are mobile units, equipped to operate in geographic regions throughout the world and, consequently, we may move rigs from an oversupplied market sector to a more lucrative and undersupplied market sector when it is economical to do so. Many of our contracts generally allow our customers to relocate our rigs from one geographic region to another, subject to certain conditions, and our customers utilize this capability to meet their worldwide drilling requirements. Accordingly, our rigs are considered to be interchangeable within classes or asset groups, and we evaluate impairment by asset group. We consider our asset groups to be Ultra-Deepwater Floaters, Deepwater Floaters, Harsh Environment Floaters, Midwater Floaters, High-Specification Jackups, Standard Jackups and Other Rigs.

We assess recoverability of assets held and used by projecting undiscounted cash flows for the asset group being evaluated. When the carrying amount of the asset group is determined to be unrecoverable, we recognize an impairment loss, measured as the amount by which the carrying amount of the asset group exceeds its estimated fair value. The evaluation requires us to make judgments about long-term projections for future revenues and costs, dayrates, rig utilization and idle time. These projections involve

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uncertainties that rely on assumptions about demand for our services, future market conditions and technological developments. Significant and unanticipated changes to these assumptions could materially alter an outcome that could otherwise result in an impairment loss. Given the nature of these evaluations and their application to specific asset groups and specific time periods, it is not possible to reasonably quantify the impact of changes in these assumptions.

Pension and other postretirement benefits—We use a January 1 measurement date for net periodic benefit costs and a December 31 measurement date for projected benefit obligations and plan assets. We measure our pension liabilities and related net periodic benefit costs using actuarial assumptions based on a market-related valuation of assets that reduces year-to-year volatility. In applying this approach, we recognize investment gains or losses over a five-year period beginning with the year in which they occur. Investment gains or losses for this purpose are measured as the difference between the expected and actual returns calculated using the market-related value of assets. Actual results may differ from these measurements under different conditions or assumptions. Future changes in plan asset returns, assumed discount rates and various other factors related to the pension plans will impact our future pension obligations and net periodic benefit costs.

Additionally, the pension obligations and related net periodic benefit costs for our defined benefit pension and other postretirement benefit plans, including retiree life insurance and medical benefits, are actuarially determined and are affected by assumptions, including long-term rate of return, discount rates, compensation increases, employee turnover rates and health care cost trend rates. The two most critical assumptions are the long-term rate of return and the discount rate. We periodically evaluate our assumptions and, when appropriate, adjust the recorded liabilities and expense. Changes in these and other assumptions used in the actuarial computations could impact our projected benefit obligations, pension liabilities, net periodic benefit costs and other comprehensive income. See “―Retirement Pension Plans and Other Postretirement Benefit Plans.”

Long-term rate of return—We develop our assumptions regarding the estimated rate of return on plan assets based on historical experience and projected long-term investment returns, considering each plan’s target asset allocation and long-term asset class expected returns. We regularly review our actual asset allocation and periodically rebalance plan assets as appropriate. For each percentage point the expected long-term rate of return assumption is lowered, pension expense would increase by approximately $9 million.

Discount rate—As a basis for determining the discount rate, we utilize a yield curve approach based on Aa-rated corporate bonds and the expected timing of future benefit payments. For each one-half percentage point the discount rate is lowered, net periodic benefit costs would increase by approximately $17 million.

Contingent liabilities—We establish reserves for estimated loss contingencies when we believe a loss is probable and the amount of the probable loss can be reasonably estimated. Once established, we adjust reserves upon the occurrence of a recognizable event when facts and circumstances change, altering our previous assumptions with respect to the likelihood or amount of loss.

Retirement Pension Plans and Other Postretirement Benefit Plans

Overview—Effective January 1, 2009, following mergers of existing plans with similar characteristics, we maintain a single qualified defined benefit pension plan in the U.S. (the “U.S. Plan”) and a single funded supplemental benefit plan (the “Supplemental Plan”). The U.S. Plan covers substantially all U.S. employees, and the Supplemental Plan, along with two unfunded supplemental benefit plans (the “Other Supplemental Plans”), provide certain eligible employees with benefits in excess of those allowed under the U.S. Plan. Additionally, we maintain two funded and two unfunded defined benefit plans (collectively, the “Frozen Plans”) that we assumed in connection with our mergers with GlobalSantaFe and R&B Falcon, all of which were frozen prior to the respective merger and for which benefits no longer accrue but the pension obligations have not been fully distributed. We refer to the U.S. Plan, the Supplemental Plan, the Other Supplemental Plans and the Frozen Plans, collectively, as the “U.S. Plans.”

We maintain a defined benefit plan in the U.K. covering certain current and former employees in the U.K. (the “U.K. Plan”). We also provide four funded defined benefit plans, primarily group pension schemes with life insurance companies, and two unfunded plans, covering certain current and former employees in Norway (the “Norway Plans”). Additionally, we maintain unfunded defined benefit plans that provide retirement and severance benefits for certain of our Indonesian, Nigerian and Egyptian employees (the “Other Plans”). We refer to the U.K. Plan, the Norway Plans and the Other Plans, collectively, as the “Non-U.S. Plans.”

We refer to the U.S. Plans and the Non-U.S. Plans, collectively, as the “Transocean Plans.” Additionally, we have several unfunded contributory and noncontributory other postretirement benefit plans (the “OPEB Plans”) covering substantially all of our U.S. employees.

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The following table presents the amounts and weighted-average assumptions associated with the U.S. Plans, the Non-U.S. Plans and the OPEB Plans.

	Year ended December 31, 2009												Year ended December 31, 2008
	U.S. Plans			Non-U.S. Plans			OPEB Plans			Total			U.S. Plans			Non-U.S. Plans			OPEB Plans			Total
Net periodic benefit costs (a)	$	60		$	24		$	3		$	87		$	30		$	14		$	3		$	47
Other comprehensive income		(117	)		67			(10	)		(60	)		338			41			10			389
Employer contributions		50			20			3			73			60			14			4			78

At end of period:
Accumulated benefit obligation	$	789		$	344		$	54		$	1,187		$	763		$	220		$	64		$	1,047
Projected benefit obligation		932			403			54			1,389			900			250			64			1,214
Fair value of plan assets		594			281			—			875			455			208			—			663
Funded status		(338	)		(122	)		(54	)		(514	)		(445	)		(42	)		(64	)		(551	)

Weighted-Average Assumptions
– Net Periodic Benefit costs
Discount rate (b)		5.41	%		6.06	%		5.34	%		5.57	%		6.14	%		5.97	%		5.96	%		6.09	%
Long-term rate of return (c)		8.50	%		6.59	%		n/a			7.90	%		8.50	%		7.16	%		n/a			8.08	%
Compensation trend rate (b)		4.21	%		4.55	%		n/a			4.30	%		4.57	%		4.64	%		n/a			4.59	%
Health care cost trend rate – initial		n/a			n/a			8.99	%		8.99	%		n/a			n/a			8.55	%		8.55	%
Health care cost trend rate – ultimate		n/a			n/a			5.00	%		5.00	%		n/a			n/a			5.00	%		5.00	%
– Benefit Obligations
Discount rate (b)		5.84	%		5.59	%		5.52	%		5.76	%		5.40	%		6.06	%		5.35	%		5.56	%
Compensation trend rate (b)		4.21	%		4.73	%		n/a			4.37	%		4.21	%		4.54	%		n/a			4.28	%

_______________________________

“n/a” means not applicable.

(a)	Net periodic benefit costs were reduced by expected returns on plan assets of $71 million and $74 million for the years ended December 31, 2009 and 2008, 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.

Net periodic benefit costs—In the year ended December 31, 2009, net periodic benefit costs increased by $40 million primarily due to the significant decline in the aggregate fair value of plan assets held by the trusts in 2008 and higher service costs, partly offset by a change in the demographic assumptions for future periods. For the year ending December 31, 2010, we expect net periodic benefit costs to increase by less than $1 million compared to the net periodic benefit costs recognized in the year ended December 31, 2009.

Plan assets—We review our investment policies at least annually and our plan assets and asset allocations at least quarterly to evaluate performance relative to specified objectives. To develop our asset allocation strategy, we review models presenting many different asset allocation scenarios to assess an appropriate target allocation that is expected to produce long-term gains without accepting undue risk.

In the year ended December 31, 2009, plan assets of the funded Transocean Plans benefited from the favorable impact of improvements in world equity markets since December 31, 2008, as a result of the 69.8 percent allocation of plan assets to equity securities. To a lesser extent, plan assets allocated to debt securities and other investments also experienced improved values. In 2009, the fair value of the investments in the funded Transocean Plans increased by $213 million, or 32.1 percent, due to net investment gains of $151 million, primarily in the funded U.S. Plans, resulting from the favorable performance of equity markets supplemented by company contributions of $70 million.

Funding contributions—We review the funded status of our plans at least annually and contribute an amount at least equal to the minimum amount required. For the funded U.S. Plans, we contribute an amount at least equal to that required by the Employee Retirement Income Security Act of 1974 (“ERISA”) and the Pension Protection Act of 2006 (“PPA”). Actuarial computations are used to establish the minimum contribution required under ERISA and PPA and the maximum deductible contribution allowed for income tax purposes. For the funded U.K. Plan, we contribute an amount, as mutually agreed with the plan trustees, based on actuarial recommendations. For the funded Norway Plans, we contribute an amount determined by the plan trustee based on Norwegian pension laws. For the unfunded Transocean Plans and OPEB Plans, we generally fund benefit payments for plan participants as incurred. We fund our contributions to the Transocean Plans and the OPEB Plans using cash flows from operations.

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For the year ended December 31, 2009, we contributed $73 million and participants contributed $2 million to the Transocean Plans. Our contributions in 2009 included $44 million, $20 million, $6 million, and $3 million to the funded U.S. Plans, the Non-U.S. Plans, the unfunded U.S. Plans and the OPEB Plans, respectively. For the year ended December 31, 2008, we contributed $78 million and participants contributed $3 million to the Transocean Plans. Our contributions in 2008 included $11 million, $14 million, $50 million, and $4 million to the funded U.S. Plans, the Non-U.S. Plans, and the unfunded U.S. Plans and the OPEB Plans, respectively.

For the year ending December 31, 2010, we expect to contribute $76 million to the Transocean Plans. These estimated contributions are comprised of $53 million to meet minimum funding requirements for the funded U.S. Plans and $16 million to meet the funding requirements for the funded non-U.S. Plans. Additionally, we expect to contribute an estimated $7 million to fund expected benefit payments for the unfunded U.S. Plans and Other Plans.

Benefit payments—Our projected benefit payments for the Transocean Plans and the OPEB Plans are as follows (in millions):

Years ending December 31,		U.S. Plans	Non-U.S. Plans			OPEB Plans	Total
2010	$	35	$	6	$	3	$	44
2011		42		6		3		51
2012		39		7		4		50
2013		41		8		4		53
2014		42		8		4		54
2015-2019		256		54		21		331

Off-Balance Sheet Arrangements

We had no off-balance sheet arrangements as of December 31, 2009.

Related Party Transactions

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

At February 19, 2010, TPDI had outstanding promissory notes in the aggregate amount of $296 million, of which $148 million is due to Pacific Drilling and is included in long-term debt on our consolidated balance sheet.

Angco Cayman Limited—We hold a 65 percent interest in ADDCL, a Cayman Islands joint venture company formed to construct, own and operate an ultra-deepwater drillship to be named Discoverer Luanda. Angco Cayman Limited, a Cayman Islands company, holds the remaining 35 percent interest in ADDCL. Under a management services agreement with ADDCL, we provide construction management services and have agreed to provide operating management services once the drillship begins operations. Beginning on the fifth anniversary of the first well commencement date, Angco Cayman Limited will have the right to exchange its interest in the joint venture for cash in an amount based on the appraised fair value of the drillship, subject to various adjustments.

New Accounting Pronouncements

For a discussion of the new accounting pronouncements that have had or are expected to have an effect on our consolidated financial statements, see Notes to Consolidated Financial Statements—Note 3—New Accounting Pronouncements.

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ITEM 7A. Quantitative and Qualitative Disclosures About Market Risk

Interest Rate Risk

We are exposed to interest rate risk, primarily associated with our long-term and short-term debt. For our debt obligations as of December 31, 2009, the following table presents our scheduled debt maturities in U.S. dollars and related weighted-average stated interest rates for the years ending December 31 (in millions, except interest rate percentages):

	Scheduled Maturity Date (a) (b)																					Fair Value
	2010			2011			2012			2013			2014			Thereafter			Total			12/31/09
Total debt
Fixed rate	$	1,377		$	2,453		$	2,289		$	91		$	92		$	4,165		$	10,467		$	10,701
Average interest rate		1.7	%		1.9	%		1.6	%		3.6	%		3.7	%		6.7	%		3.7	%
Variable rate	$	529		$	26		$	28		$	779		$	32		$	257		$	1,651		$	1,695
Average interest rate		0.7	%		4.8	%		4.5	%		3.5	%		4.1	%		3.8	%		2.7	%

______________________________

(a)

In preparing the scheduled maturities of our debt, we assume the noteholders will exercise their options to require us to repurchase the 1.625% Series A Convertible Senior Notes, 1.50% Series B Convertible Senior Notes, and 1.50% Series C Convertible Senior Notes in December 2010, 2011 and 2012, respectively.

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

At December 31, 2009, the face value of our variable-rate debt was approximately $1.7 billion, which represented 14 percent of the face value of our total debt, and primarily consisted of notes issued under our commercial paper program and borrowings under the ADDCL Credit Facilities and the TPDI Credit Facilities. At December 31, 2008, the face value of our variable-rate debt was approximately $3.0 billion, which represented 24 percent of the face value of our total debt, and primarily consisted of notes issued under our commercial paper program and borrowings under the Term Loan. Based upon variable-rate debt amounts outstanding as of December 31, 2009 and 2008, a one percentage point change in annual interest rates would result in a corresponding change in annual interest expense of approximately $17 million and $33 million, respectively. We have engaged in certain hedging activities to reduce our exposure to interest rate risk resulting from our fixed-rate debt. The effect of our derivative instruments is included in the table above. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Derivative Instruments.”

The fair value of our debt was $12.4 billion and $12.8 billion at December 31, 2009 and 2008, respectively. The $400 million decrease was primarily due to our repayment of debt during the year ended December 31, 2009 and changes in corporate bond rates.

A large portion of our cash investments is subject to variable interest rates and would earn commensurately higher rates of return if interest rates increase. Based upon cash investments as of December 31, 2009 and 2008, a one percentage point change in interest rates would result in a corresponding change in annual interest income of approximately $11 million and $4 million, respectively.

GSF Jack Ryan is subject to a fully defeased financing lease arrangement through November 2020, under which we are required to make additional payments if the associated defeasance deposit does not earn an annual rate of return of at least 8.0 percent, the interest rate expected at the inception of the agreement. The defeasance deposit earns interest based on the British pound three-month LIBOR, which was 0.6 percent as of December 31, 2009. If the interest rate were to remain fixed at this rate through January 2013, we would be required to make additional payments totaling approximately $19 million during that period. We do not expect that, if required, any additional payments made under this defeasance arrangement would be material to our statement of financial position, results of operations or cash flows.

Foreign Exchange Risk

We are exposed to foreign exchange risk associated with our international operations. 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 our anticipated local currency needs 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 local currency needs may vary from those anticipated in the customer contracts, resulting in partial exposure to foreign exchange risk. Fluctuations in foreign currencies generally have not had a material impact on our overall operating results. In situations where local currency receipts do not equal local currency requirements, we may use foreign exchange derivative instruments, including forward exchange contracts, or spot purchases, to mitigate foreign currency risk. A forward exchange contract obligates us to exchange predetermined amounts of specified currencies at a stated exchange rate on a stated date or to make a U.S. dollar payment equal to the value of such exchange. At December 31, 2009 and 2008, we had no outstanding foreign exchange derivative instruments. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Derivative Instruments.”

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ITEM 8. Financial Statements and Supplementary Data

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

Management of Transocean Ltd. (the “Company” or “our”) is responsible for establishing and maintaining adequate internal control over financial reporting for the Company as defined in Rules 13a-15(e) and 15d-15(e) 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, 2009. 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, 2009, the Company’s internal control over financial reporting was effective.

The Company’s independent auditors, Ernst & Young LLP, a registered public accounting firm, are appointed by the Audit Committee of the Company’s Board of Directors, subject to ratification by our shareholders. Ernst & Young LLP has audited and reported on the consolidated financial statements of Transocean Ltd. and Subsidiaries, and the Company’s internal control over financial reporting. The reports of the independent auditors are contained in this annual report.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Shareholders of Transocean Ltd. and Subsidiaries

We have audited Transocean Ltd. and Subsidiaries’ internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Transocean Ltd. and Subsidiaries’ management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the company’s internal control over financial reporting based on our audit.

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

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

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

In our opinion, Transocean Ltd. and Subsidiaries maintained, in all material respects, effective internal control over financial reporting as of December 31, 2009, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Transocean Ltd. and Subsidiaries as of December 31, 2009 and 2008, 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, 2009 and our report dated February 24, 2010 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

Houston, Texas

February 24, 2010

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Shareholders of Transocean Ltd.

We have audited the accompanying consolidated balance sheets of Transocean Ltd. and Subsidiaries as of December 31, 2009 and 2008, 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, 2009. 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 Board of Directors and management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits.

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

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Transocean Ltd. and Subsidiaries at December 31, 2009 and 2008, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2009, 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 3 to the consolidated financial statements, the consolidated financial statements have been retrospectively adjusted to reflect the application of new accounting standards and updates related to (i) convertible debt instruments, (ii) noncontrolling interests, and (iii) participating securities and earnings per share.

As discussed in Note 7 to the consolidated financial statements, effective January 1, 2007, the Company adopted amendments to the accounting standards related to accounting for uncertainty in income taxes.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Transocean Ltd.’s internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 24, 2010 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

Houston, Texas

February 24, 2010

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TRANSOCEAN LTD. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(In millions, except per share data)

	Years ended December 31,
	2009			2008			2007
				(As adjusted)
Operating revenues
Contract drilling revenues	$	10,607		$	10,756		$	5,948
Contract drilling intangible revenues		281			690			88
Other revenues		668			1,228			341
		11,556			12,674			6,377
Costs and expenses
Operating and maintenance		5,140			5,355			2,781
Depreciation, depletion and amortization		1,464			1,436			499
General and administrative		209			199			142
		6,813			6,990			3,422
Loss on impairment		(334	)		(320	)		—
Gain (loss) on disposal of assets, net		(9	)		(7	)		284
Operating income		4,400			5,357			3,239

Other income (expense), net
Interest income		5			32			30
Interest expense, net of amounts capitalized		(484	)		(640	)		(182	)
Loss on retirement of debt		(29	)		(3	)		(8	)
Other, net		32			26			295
		(476	)		(585	)		135

Income before income tax expense		3,924			4,772			3,374
Income tax expense		754			743			253

Net income		3,170			4,029			3,121
Net loss attributable to noncontrolling interest		(11	)		(2	)		—

Net income attributable to controlling interest	$	3,181		$	4,031		$	3,121

Earnings per share
Basic	$	9.87		$	12.63		$	14.58
Diluted	$	9.84		$	12.53		$	14.08

Weighted-average shares outstanding
Basic		320			318			214
Diluted		321			321			222

See accompanying notes.

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TRANSOCEAN LTD. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(In millions)

	Years ended December 31,
	2009			2008			2007
				(As adjusted)

Net income	$	3,170		$	4,029		$	3,121

Other comprehensive income (loss) before income taxes
Unrecognized components of net periodic benefit costs		37			(388	)		(27	)
Recognized components of net periodic benefit costs		24			5			13
Unrealized gain (loss) on derivative instruments		4			(1	)		—
Other, net		1			(3	)		—

Other comprehensive income (loss) before income taxes		66			(387	)		(14	)
Income taxes related to other comprehensive income (loss)		24			9			2
Other comprehensive income (loss), net of income taxes		90			(378	)		(12	)

Total comprehensive income		3,260			3,651			3,109
Total comprehensive loss attributable to noncontrolling interest		(6	)		(2	)		—

Total comprehensive income attributable to controlling interest	$	3,266		$	3,653		$	3,109

See accompanying notes.

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TRANSOCEAN LTD. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(In millions, except share data)

	December 31,
	2009			2008
				(As adjusted)
Assets
Cash and cash equivalents	$	1,130		$	963
Short-term investments		38			333
Accounts receivable, net
Trade		2,330			2,798
Other		55			66
Materials and supplies, net		462			432
Deferred income taxes, net		104			63
Assets held for sale		186			464
Other current assets		171			230
Total current assets		4,476			5,349

Property and equipment		29,351			25,836
Less accumulated depreciation		6,333			4,975
Property and equipment, net		23,018			20,861
Goodwill		8,134			8,128
Other assets		808			844
Total assets	$	36,436		$	35,182

Liabilities and equity
Accounts payable	$	780		$	914
Accrued income taxes		240			317
Debt due within one year		1,868			664
Other current liabilities		730			806
Total current liabilities		3,618			2,701

Long-term debt		9,849			12,893
Deferred income taxes, net		726			666
Other long-term liabilities		1,684			1,755
Total long-term liabilities		12,259			15,314

Commitments and contingencies

Shares, CHF 15.00 par value, 502,852,947 authorized, 167,617,649 conditionally authorized, 335,235,298 issued at December 31, 2009 and 2008; 321,223,882 and 319,262,113 outstanding at December 31, 2009 and 2008, respectively		4,472			4,444
Additional paid-in capital		7,407			7,313
Retained earnings		9,008			5,827
Accumulated other comprehensive loss		(335	)		(420	)
Total controlling interest shareholders’ equity		20,552			17,164
Noncontrolling interest		7			3
Total equity		20,559			17,167
Total liabilities and equity	$	36,436		$	35,182

See accompanying notes.

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TRANSOCEAN LTD. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF EQUITY

(In millions)

	Years ended December 31,				Years ended December 31,
	2009	2008		2007	2009			2008			2007
								(As adjusted)
Shares	Shares				Amount
Balance, beginning of period	319	317		205	$	4,444		$	3		$	2
Cancellation of shares for redomestication	—	(317	)	—		—			(3	)		—
Issuance of shares for redomestication	—	317		—		—			4,444			—
Business combination	—	—		108		—			—			1
Issuance of shares under share-based compensation plans	2	2		4		28			—			—
Balance, end of period	321	319		317	$	4,472		$	4,444		$	3
Additional paid-in capital
Balance, beginning of period					$	7,313		$	11,619		$	8,045
Issuance of shares under share-based compensation plans						7			62			65
Share-based compensation expense						81			64			78
Excess tax benefit for share-based compensation plans						2			10			70
Repurchase of convertible notes						22			—			—
Redomestication						—			(4,441	)		—
Repurchase of shares						—			—			(400	)
Reclassification of shares						—			(1	)		(9,859	)
Business combination						—			—			12,385
Issuance of shares upon conversion of convertible notes						—			—			414
Equity component of convertible notes						—			—			820
Changes in ownership of noncontrolling interest and other, net						(18	)		—			1
Balance, end of period					$	7,407		$	7,313		$	11,619
Retained earnings (accumulated deficit)
Balance, beginning of period					$	5,827		$	1,796		$	(1,181	)
Net income attributable to controlling interest						3,181			4,031			3,121
Adjustments to initially apply accounting standards updates						—			—			(144	)
Balance, end of period					$	9,008		$	5,827		$	1,796
Accumulated other comprehensive loss
Balance, beginning of period					$	(420	)	$	(42	)	$	(30	)
Other comprehensive income (loss) attributable to controlling interest						85			(378	)		(12	)
Balance, end of period					$	(335	)	$	(420	)	$	(42	)
Total controlling interest shareholders’ equity
Balance, beginning of period					$	17,164		$	13,376		$	6,836
Total comprehensive income attributable to controlling interest						3,266			3,653			3,109
Issuance of shares under share-based compensation plans						35			62			65
Share-based compensation expense						81			64			78
Repurchase of convertible notes						22			—			—
Repurchase of shares						—			—			(400	)
Reclassification of shares						—			(1	)		(9,859	)
Business combination						—			—			12,386
Issuance of shares upon conversion of convertible notes						—			—			414
Equity component of convertible notes						—			—			820
Adjustments to initially apply accounting standards updates						—			—			(144	)
Other, net						(16	)		10			71
Balance, end of period					$	20,552		$	17,164		$	13,376
Total noncontrolling interest
Balance, beginning of period					$	3		$	5		$	4
Total comprehensive loss attributable to noncontrolling interest						(6	)		(2	)		—
Changes in ownership of noncontrolling interest						10			—			1
Balance, end of period					$	7		$	3		$	5
Total equity
Balance, beginning of period					$	17,167		$	13,381		$	6,840
Total comprehensive income						3,260			3,651			3,109
Issuance of shares under share-based compensation plans						35			62			65
Share-based compensation expense						81			64			78
Repurchase of convertible notes						22			—			—
Repurchase of shares						—			—			(400	)
Reclassification of shares						—			(1	)		(9,859	)
Business combination						—			—			12,386
Issuance of shares upon conversion of convertible notes						—			—			414
Equity component of convertible notes						—			—			820
Adjustments to initially apply accounting standards updates						—			—			(144	)
Other, net						(6	)		10			72
Balance, end of period					$	20,559		$	17,167		$	13,381

See accompanying notes.

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TRANSOCEAN LTD. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In millions)

	Years ended December 31,
	2009			2008			2007
				(As adjusted)
Cash flows from operating activities
Net income	$	3,170		$	4,029		$	3,121
Adjustments to reconcile net income to net cash provided by operating activities:
Amortization of drilling contract intangibles		(281	)		(690	)		(88	)
Depreciation, depletion and amortization		1,464			1,436			499
Share-based compensation expense		81			64			78
Excess tax benefit from share-based compensation plans		(2	)		(10	)		(70	)
Loss on impairment		334			320			—
(Gain) loss on disposal of assets, net		9			7			(284	)
Loss on retirement of debt		29			3			8
Amortization of debt issue costs, discounts and premiums, net		209			176			18
Deferred income taxes		13			8			(40	)
Other, net		7			41			6
Deferred revenue, net		169			11			52
Deferred expenses, net		(38	)		(115	)		(55	)
Changes in operating assets and liabilities		434			(321	)		(172	)
Net cash provided by operating activities		5,598			4,959			3,073

Cash flows from investing activities
Capital expenditures		(3,052	)		(2,208	)		(1,380	)
Proceeds from disposal of assets, net		18			348			379
Proceeds from short-term investments		564			59			—
Purchases of short-term investments		(269	)		(408	)		—
Business combination		—			—			(5,129	)
Cash balances acquired in business combination		—			—			695
Joint ventures and other investments, net		45			13			(242	)
Net cash used in investing activities		(2,694	)		(2,196	)		(5,677	)

Cash flows from financing activities
Change in short-term borrowings, net		(382	)		(837	)		1,500
Proceeds from debt		514			2,661			24,095
Repayments of debt		(2,871	)		(4,893	)		(12,033	)
Financing costs		(2	)		(24	)		(106	)
Repurchase of shares		—			—			(400	)
Payment to shareholders for Reclassification		—			(1	)		(9,859	)
Payments for warrant exercises, net		(13	)		(7	)		40
Proceeds from share-based compensation plans, net		17			51			72
Excess tax benefit from share-based compensation plans		2			10			70
Other, net		(2	)		(1	)		(1	)
Net cash provided by (used in) financing activities		(2,737	)		(3,041	)		3,378

Net increase (decrease) in cash and cash equivalents		167			(278	)		774
Cash and cash equivalents at beginning of period		963			1,241			467
Cash and cash equivalents at end of period	$	1,130		$	963		$	1,241

See accompanying notes.

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TRANSOCEAN LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1—Nature of Business

Transocean Ltd. (together with its subsidiaries and predecessors, unless the context requires otherwise, “Transocean,” the “Company,” “we,” “us” or “our”) is a leading international provider of offshore contract drilling services for oil and gas wells. Our mobile offshore drilling fleet is considered one of the most modern and versatile fleets in the world. Specializing in technically demanding sectors of the offshore drilling business with a particular focus on deepwater and harsh environment drilling services, we contract our drilling rigs, related equipment and work crews predominantly on a dayrate basis to drill oil and gas wells. At December 31, 2009, we owned, had partial ownership interests in or operated 138 mobile offshore drilling units. As of this date, our fleet consisted of 44 High-Specification Floaters (Ultra-Deepwater, Deepwater and Harsh Environment semisubmersibles and drillships), 26 Midwater Floaters, 10 High-Specification Jackups, 55 Standard Jackups and three Other Rigs. We also have five Ultra-Deepwater Floaters under construction (see Note 9—Drilling Fleet Expansion and Dispositions).

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

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

Note 2—Significant Accounting Policies

Accounting estimates—The preparation of financial statements in accordance with accounting principles generally accepted in the United States (“U.S.”) requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, and expenses and the disclosures of contingent assets and liabilities. On an ongoing basis, we evaluate our estimates and assumptions, including those related to our allowance for doubtful accounts, materials and supplies obsolescence, property and equipment, investments, goodwill and other intangible assets, income taxes, share-based compensation, defined benefit pension plans and other postretirement benefits, and contingencies. We base our estimates and assumptions on historical experience and on various other factors we believe are reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results could differ from such estimates.

Fair value measurements—We estimate fair value at a price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants in the principal market for the asset or liability. Our valuation techniques require inputs that we categorize using a three-level hierarchy as follows: (1) unadjusted quoted prices for identical assets or liabilities in active markets (“Level 1”), (2) direct or indirect observable inputs, including quoted prices or other market data, for similar assets or liabilities in active markets or identical assets or liabilities in less active markets (“Level 2”) and (3) unobservable inputs that require significant judgment for which there is little or no market data (“Level 3”). When multiple input levels are required for a valuation, we categorize the entire fair value measurement according to the lowest level input that is significant to the measurement even though we may have also utilized significant inputs that are more readily observable.

Principles of consolidation—We consolidate those investments that meet the criteria of a variable interest entity where we are deemed to be the primary beneficiary for accounting purposes and for entities in which we have a majority voting interest. Intercompany transactions and accounts are eliminated in consolidation. For investments in joint ventures and other entities that do not meet the criteria of a variable interest entity or where we are not deemed to be the primary beneficiary for accounting

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

purposes of those entities that meet the variable interest entity criteria, we use the equity method of accounting if we have the ability to exercise significant influence over the unconsolidated affiliate. We use the cost method of accounting for investments in joint ventures and other entities if we do not have the ability to exercise significant influence over the unconsolidated affiliate. See Note 4—Variable Interest Entities.

We had investments in and advances to unconsolidated affiliates of $11 million and $17 million at December 31, 2009 and 2008, respectively, and reported these amounts in other assets on our consolidated balance sheet. We recognized equity in earnings (losses) of unconsolidated affiliates of $2 million, $2 million and $(2) million for the years ended December 31, 2009, 2008 and 2007, respectively, and reported these amounts in other, net on our consolidated statement of operations.

Cash and cash equivalents—Cash equivalents are highly liquid debt instruments with an original maturity of three months or less that may include time deposits with a number of commercial banks with high credit ratings, U.S. Treasury and government securities, Eurodollar time deposits, certificates of deposit and commercial paper. We may also invest excess funds in no-load, open-end, management investment trusts (“management trusts”). The management trusts invest exclusively in high quality money market instruments. Cash equivalents are stated at cost plus accrued interest, which approximates fair value.

Allowance for doubtful accounts—We establish reserves for doubtful accounts on a case-by-case basis, considering changes in the financial position of a major customer, when we believe the required payment of specific amounts owed is unlikely to occur. We derive a majority of our revenues from services to international oil companies and government-owned or government-controlled oil companies. We do not generally require collateral or other security to support customer receivables. The allowance for doubtful accounts was $65 million and $114 million at December 31, 2009 and 2008, respectively.

Materials and supplies—Materials and supplies are carried at average cost less an allowance for obsolescence. Such allowance was $66 million and $49 million at December 31, 2009 and 2008, respectively.

Property and equipment—Property and equipment, consisting primarily of offshore drilling rigs and related equipment, represented approximately 63 percent of our total assets at December 31, 2009. 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 expensed as incurred. Upon sale or other disposition, the applicable carrying amounts of asset cost and accumulated depreciation are removed from the accounts and the net amount, less net proceeds from disposal, is recognized in gain (loss) from disposal of assets, net.

Estimated original useful lives of our drilling units range from 18 to 35 years, 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 we may extend the useful life when events and circumstances indicate a drilling unit can operate beyond its remaining useful life. During 2009, we adjusted the useful lives for 10 rigs, extending the estimated useful lives from between 30 and 35 years to between 33 and 50 years. During 2008, we adjusted the useful lives for five rigs, extending the estimated useful lives from between 30 and 35 years to between 34 and 50 years. During 2007, we adjusted the useful lives for six rigs, extending the estimated useful lives from between 30 and 35 years to between 35 and 45 years. We deemed the life extensions appropriate for each of these rigs based on the respective contracts under which the rigs were operating and the additional life-extending work, upgrades and inspections we performed on the rigs. For each of the years ended December 31, 2009, 2008 and 2007, the changes in estimated useful lives of these rigs resulted in a reduction in depreciation expense of $23 million ($0.07 per diluted share), $6 million ($0.02 per diluted share) and $25 million ($0.11 per diluted share), respectively, which had no tax effect for any period.

During 2008, we also adjusted the useful lives for four rigs that we acquired in the Merger, reducing the estimated useful lives from between eight and 16 years to between three and nine years. We determined the appropriate useful lives for each of these rigs based on our review of technical specifications of the rigs and comparisons to the remaining useful lives of comparable rigs in our fleet. In 2008, the change in estimated useful life of these rigs resulted in an increase in depreciation expense of $46 million ($0.14 per diluted share), which had no tax effect.

Assets held for sale—We classify an asset as held for sale when the facts and circumstances meet the required criteria for such classification, including the following: (a) we have committed to a plan to sell the asset, (b) the asset is available for immediate sale, (c) we have initiated actions to complete the sale, including locating a buyer, (d) the sale is expected to be completed within one year, (e) the asset is being actively marketed at a price that is reasonable relative to its fair value, and (f) the plan to sell is unlikely to be subject to significant changes or termination. At December 31, 2009 and 2008, we had assets held for sale, included in current assets, in the amount of $186 million and $464 million, respectively. See Note 26—Subsequent Events.

Long-lived assets and definite-lived intangible assets—We review the carrying values of long-lived assets and definite-lived intangible assets, principally property and equipment and a drilling management services customer relationships asset, for potential impairment when events occur or circumstances change that indicate that the carrying value of such assets may not be recoverable. For assets classified as held and used, we determine recoverability by evaluating the undiscounted estimated future net cash flows of the related asset or asset group under review. We consider our asset groups to be Ultra-Deepwater Floaters, Deepwater Floaters, Harsh Environment Floaters, Midwater Floaters, High-Specification Jackups, Standard Jackups and Other Rigs. The

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TRANSOCEAN LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

estimated future net cash flows are based upon projected utilization and dayrates. For our drilling management services customer relationships asset, we estimate fair value using the excess earnings method, which applies the income approach. For an asset classified as held for sale, we measure the asset at the lower of its carrying amount or fair value less cost to sell. For the years ended December 31, 2009 and 2008, we concluded that our customer relationships asset and our assets held for sale were impaired. See Note 6—Impairments and Note 10—Goodwill and Other Intangible Assets.

Goodwill and other indefinite-lived intangible assets—We conduct impairment testing for our goodwill and other indefinite-lived intangible assets annually as of October 1 and more frequently when an event occurs or circumstances change that may indicate a reduction in the fair value of a reporting unit or the intangible asset is below its carrying value. We test goodwill at the reporting unit level, which is defined as an operating segment or a component of an operating segment that constitutes a business for which financial information is available and is regularly reviewed by management. We test goodwill for impairment by comparing the carrying amount of the reporting unit, including goodwill, to the fair value of the reporting unit. If the reporting unit’s carrying amount exceeds its fair value, we consider goodwill impaired and perform a second step to measure the amount of the impairment loss, if any. We have identified three reporting units for this purpose: (1) contract drilling services, (2) drilling management services and (3) oil and gas properties. As a result of our testing in each of the years ended December 31, 2009 and 2007, we concluded that goodwill was not impaired. For the year ended December 31, 2008, we concluded that the goodwill of drilling management services was impaired. See Note 6—Impairments and Note 10—Goodwill and Other Intangible Assets.

For our contract drilling services reporting unit, we estimate fair value using projected discounted cash flows and publicly traded company multiples. To develop the projected cash flows associated with our contract drilling services reporting unit, which are based on estimated future utilization and dayrates, we consider key factors that include assumptions regarding future commodity prices, credit market conditions and the effect these factors may have on our contract drilling operations and the capital expenditure budgets of our customers. We discount the projected cash flows using a long-term weighted-average cost of capital, which is based on our estimate of the investment returns that market participants would require for each of our reporting units. We derive publicly traded company multiples for companies with operations similar to our reporting units using observable information related to shares traded on stock exchanges and, when available, observable information related to recent acquisitions.

For our trade name asset, an indefinite-lived intangible asset, we estimate fair value using the relief from royalty method, which applies the income approach. For the years ended December 31, 2009 and 2008, we concluded that the trade name asset for our drilling management services reporting unit was impaired. See Note 6—Impairments and Note 10—Goodwill and Other Intangible Assets.

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

Contract drilling intangible revenues—In connection with the Merger, we acquired drilling contracts for future contract drilling services of GlobalSantaFe. The terms of these contracts include fixed dayrates that were above or below the market dayrates available for similar contracts as of the date of the Merger. We recognized the fair value adjustments as contract intangible assets and liabilities, recorded in other assets and other long-term liabilities, respectively. We amortize the resulting contract drilling intangible revenues on a straight-line basis over the respective contract period. During the years ended December 31, 2009 and 2008, we recognized $281 million and $690 million, respectively, in contract intangible revenues on our consolidated statements of operations. See Note 10—Goodwill and Other Intangible Assets.

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

Share-based compensation—For time-based awards, we recognize compensation expense on a straight-line basis through the date the employee is no longer required to provide service to earn the award (the “service period”). For market-based awards that vest at the end of the service period, we recognize compensation expense on a straight-line basis through the end of the service period. For performance-based awards with graded vesting conditions, we recognize compensation expense on a straight-line basis over the service period for each separately vesting portion of the award as if the award was, in substance, multiple awards. Share-based compensation expense is recognized, net of a forfeiture rate, estimated at the time of grant based on historical experience and adjusted, if necessary, in subsequent periods based on actual forfeitures.

To measure the fair values of time-based restricted shares and deferred units granted or modified, we use the market price of our shares on the grant date or modification date. To measure the fair values of stock options and stock appreciation rights (“SARs”) granted or modified, we use the Black-Scholes-Merton option-pricing model and apply assumptions for the expected life, risk-free interest rate, dividend yield and expected volatility. The expected life is based on historical information of past employee behavior regarding exercises and forfeitures of options. The risk-free interest rate is based upon the published U.S. Treasury yield curve in effect at the time of grant or modification for instruments with a similar life. The dividend yield is based on our history and expectation of dividend payouts. The expected volatility is based on a blended rate with an equal weighting of the (a) historical volatility based on historical data for an amount of time approximately equal to the expected life and (b) implied volatility derived from our at-the-money long-dated call options. To measure the fair values of market-based deferred units granted or modified, we use a Monte Carlo simulation model and, in addition to the assumptions applied for the Black-Scholes-Merton option-pricing model, we apply assumptions using a risk neutral model and an average price at the performance start date. The risk neutral model assumes that all peer group stocks grow at the risk-free rate. The average price at the performance start date is based on the average stock price for the preceding 30 trading days.

We recognize share-based compensation expense in the same financial statement line item as cash compensation paid to the respective employees. Tax deduction benefits for awards in excess of recognized compensation costs are reported as a financing cash flow. Share-based compensation expense was $81 million, $64 million, and $78 million in the years ended December 31, 2009, 2008 and 2007, respectively. Income tax benefit on share-based compensation expense was $8 million, $8 million, and $9 million in the years ended December 31, 2009, 2008 and 2007, respectively. See Note 17—Share-Based Compensation Plans.

Pension and other postretirement benefits—We use a January 1 measurement date for determining net periodic benefit costs and a December 31 measurement date for determining benefit obligations and the fair value of plan assets. We determine our net periodic benefit costs based on a market-related valuation of assets that reduces year-to-year volatility by recognizing investment gains or losses over a five-year period from the year in which they occur. Investment gains or losses for this purpose are measured as 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 obligations and related costs for our defined benefit pension and other postretirement benefit plans, retiree life insurance and medical benefits, are actuarially determined by applying assumptions, including long-term rate of return on plan assets, discount rates, compensation increases, employee turnover rates and health care cost trend rates. The two most critical assumptions are the long-term rate of return on plan assets and the discount rate.

For the long-term rate of return, we develop our assumptions regarding the expected rate of return on plan assets based on historical experience and projected long-term investment returns, which consider each plan’s target asset allocation and long-term asset class return expectations. For the discount rate, we base our assumptions on a yield curve approach based on Aa-rated corporate bonds and the expected timing of future benefit payments. For the projected compensation trend rate, we consider short-term and long-term compensation expectations for participants, including salary increases and performance bonus payments. For the health care cost trend rate for other postretirement benefits, we establish our assumptions for health care cost trends, applying an initial trend rate that reflects both our recent historical experience and broader national statistics with an ultimate trend rate that assumes that the portion of gross domestic product devoted to health care eventually becomes constant.

Pension and other postretirement benefit plan obligations represented a total liability of $514 million and $551 million, at December 31, 2009 and 2008, respectively. Net periodic benefit costs were $84 million, $44 million and $26 million for the years ended December 31, 2009, 2008, and 2007, respectively. See Note 15—Postemployment Benefit Plans.

Capitalized interest—We capitalize interest costs for qualifying construction and upgrade projects. We capitalized interest costs on construction work in progress of $182 million, $147 million and $77 million for the years ended December 31, 2009, 2008 and 2007, respectively.

Derivatives and hedging—From time to time, we may enter into a variety of derivative financial instruments in connection with the management of our exposure to variability in foreign exchange rates and interest rates. We record derivatives on our consolidated balance sheet, measured at fair value. For derivatives that do not qualify for hedge accounting, we recognize the gains and losses associated with changes in the fair value in current period earnings. See Note 12—Derivatives and Hedging and Note 14—Financial Instruments and Risk Concentration.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

We may enter into cash flow hedges to manage our exposure to variability of the expected future cash flows of recognized assets or liabilities or of unrecognized forecasted transactions. For a derivative that is designated and qualifies as a cash flow hedge, we initially recognize the effective portion of the gains or losses in other comprehensive income and subsequently recognize the gains and losses in earnings in the period in which the hedged forecasted transaction affects earnings. We recognize the gains and losses associated with the ineffective portion of the hedges in interest expense in the period in which they are realized.

We may enter into fair value hedges to manage our exposure to changes in fair value of recognized assets or liabilities, such as fixed-rate debt, or of unrecognized firm commitments. For a derivative that is designated and qualifies as a fair value hedge, we simultaneously recognize in current period earnings the gains or losses on the derivative along with the offsetting losses or gains on the hedged item attributable to the hedged risk. The resulting ineffective portion, which is measured as the difference between the change in fair value of the derivative and the hedged item, is recognized in current period earnings.

Foreign currency—The majority of our revenues and expenditures are denominated in U.S. dollars to limit our exposure to foreign currency fluctuations, resulting in the use of the U.S. dollar as the functional currency for all of our operations. Foreign currency exchange gains and losses are primarily included in other income (expense) as incurred. We had net foreign currency exchange losses of $34 million, $3 million and $10 million for the years ended December 31, 2009, 2008 and 2007, respectively.

Income taxes—Income taxes have been provided based upon the tax laws and rates in effect in the countries in which operations are conducted and income is earned. There is little or 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. We recognize deferred tax assets and liabilities for the anticipated future tax effects of temporary differences between the financial statement basis and the tax basis of our assets and liabilities using the applicable jurisdictional tax rates in effect at year end. We record a valuation allowance for deferred tax assets when it is more likely than not that some or all of the benefit from the deferred tax asset will not be realized. See Note 7—Income Taxes.

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

Subsequent events—We evaluate subsequent events through the time of our filing on the date we issue our financial statements. For the year ended December 31, 2009, we have evaluated subsequent events through the time of our filing on February 24, 2010, the date on which we issued our financial statements. See Note 26—Subsequent Events.

Note 3—New Accounting Pronouncements

Recently Adopted Accounting Standards

Earnings per share—Effective January 1, 2009, we adopted the accounting standards update related to participating securities, which clarified that all outstanding unvested share-based payment awards containing rights to nonforfeitable dividends are considered participating securities and the holders of the unvested awards, therefore, participate in undistributed earnings with common shareholders. Accordingly, the two-class method of computing basic and diluted earnings per share must be applied to the unvested awards. As a result of our adoption, we adjusted our earnings per share for each period presented by deducting the proportionate amount of our undistributed earnings allocable to the participating securities from net income to arrive at net income attributable to shareholders. Our adoption did not have a material effect on basic or diluted earnings per share for the years ended December 31, 2008 or 2007. See Note 8—Earnings per Share.

Debt—Effective January 1, 2009, we adopted the accounting standards update regarding convertible debt instruments that may be settled in cash upon conversion, which required the issuer of certain convertible debt instruments to separately account for the liability and equity components of the instrument and reflect interest expense at the issuer’s market rate of borrowing for non-convertible debt instruments. We applied these provisions in accounting and reporting for our convertible senior notes. In addition to the reduction of debt balances and increase of shareholders’ equity on our consolidated balance sheets for each period presented, the retrospective application resulted in a non-cash increase to our annual historical interest expense, net of amounts capitalized, of $171 million and $10 million for the years ended December 31, 2008 and 2007, respectively. See Note 11—Debt.

Compensation – retirement benefits—Effective for the year ended December 31, 2009, we adopted the accounting standards update regarding employers’ disclosures about postretirement benefit plan assets, which provided additional requirements for enhanced disclosures related to plan assets of a defined benefit pension or other postretirement plan. Our adoption did not have a material effect on the disclosures contained within our notes to consolidated financial statements. See Note 15—Postemployment Benefit Plans.

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TRANSOCEAN LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

Business combinations—Effective January 1, 2009, we adopted the accounting standards update regarding business combinations, which required (a) primarily all acquired assets, liabilities, noncontrolling interest and certain contingencies be measured at fair value, (b) broader scope of business combinations to include all transactions in which one entity gains control over one or more other businesses and (c) acquisition-related costs and anticipated restructuring costs of the acquired company to be recognized separately from the acquisition. Assets and liabilities arising from contingencies related to a business combination must be recognized at their acquisition-date fair values if the fair values can be determined during the measurement period. If the fair values of such contingencies cannot be determined during the measurement period, they must be recognized at the acquisition date if the contingencies are probable and an amount can be reasonably estimated. We will apply such principles with respect to any business combinations occurring after January 1, 2009 and with respect to certain income tax matters related to business combinations that occurred prior to our adoption. Because of the prospective application requirement, our adoption did not have an effect on our historical consolidated statement of financial position, results of operations or cash flows.

Consolidation—Effective January 1, 2009, we adopted the accounting standards update related to noncontrolling interest that established accounting and reporting requirements for (a) noncontrolling interest in a subsidiary and (b) the deconsolidation of a subsidiary. The update required that noncontrolling interest be reported as equity on the consolidated balance sheet and required that net income attributable to controlling interest and to noncontrolling interest be shown separately on the face of the statement of operations. As a result of our adoption, on our consolidated statements of operations, we have separately presented net income (loss) attributable to noncontrolling interest and net income attributable to controlling interest. Additionally, on our consolidated balance sheet, presented as of December 31, 2008, we reclassified to equity the balance of $3 million associated with noncontrolling interest.

Derivatives and hedging—Effective January 1, 2009, we adopted the accounting standards update related to derivative instruments and hedging activities, which required enhanced disclosures about (a) how and why an entity uses derivative instruments, (b) how an entity accounts for derivative instruments and related hedged items and (c) how derivative instruments and related hedged items affect an entity’s financial position, financial performance and cash flows. Our adoption did not have a material effect on the disclosures contained within our notes to consolidated financial statements. See Note 12—Derivatives and Hedging.

Fair value measurements and disclosures—Effective January 1, 2008, we adopted the accounting standards update related to fair value measurement of financial instruments that (a) defined fair value, thereby offering a single source of guidance for the application of fair value measurement, (b) established a framework for measuring fair value that contains a three-level hierarchy for the inputs to valuation techniques, and (c) required enhanced disclosures about fair value measurements. Our adoption did not have a material effect on our consolidated statement of financial position, results of operations or cash flows.

Effective January 1, 2009, we adopted the remaining provisions of the accounting standards update for fair value measurement of nonfinancial assets and nonfinancial liabilities that are recognized or disclosed at fair value in the financial statements on a nonrecurring basis, which we applied in estimating the fair value of our intangible assets, reporting units and assets held for sale (see Note 6—Impairments). Our adoption did not have a material effect on our consolidated statement of financial position, results of operations or cash flows.

Effective April 1, 2009, we adopted the accounting standards update related to measuring fair value when the volume and level of activity for the assets or liability have significantly decreased and identifying transactions that are not orderly, which provided additional guidance for estimating fair value when there is no active market or where the activity represents distressed sales on an interim and annual reporting basis. Our adoption did not have a material effect on our consolidated statement of financial position, results of operations or cash flows.

Subsequent events—Effective for events occurring subsequent to June 30, 2009, we adopted the accounting standards update regarding subsequent events, which established (a) the period after the balance sheet date during which management should evaluate events or transactions that may occur for potential recognition or disclosure in the financial statements, (b) the circumstances under which an entity should recognize events or transactions occurring after the balance sheet date in its financial statements, and (c) the disclosures that an entity should make about events or transactions that occurred after the balance sheet date. Our adoption did not have a material impact on the disclosures contained within our notes to consolidated financial statements. See Note 2—Significant Accounting Policies and Note 26—Subsequent Events.

Recently Issued Accounting Standards

Consolidation—Effective January 1, 2010, we will adopt the accounting standards update that requires enhanced transparency of our involvement with variable interest entities, which (a) amends certain guidance for determining whether an enterprise is a variable interest entity, (b) requires a qualitative rather than a quantitative analysis to determine the primary beneficiary, and (c) requires continuous assessments of whether an enterprise is the primary beneficiary of a variable interest entity. The update is effective as of the first annual reporting period that begins after November 15, 2009, for interim periods within that first annual reporting period and for interim and annual reporting periods thereafter. We are evaluating these requirements, particularly with regard to our interests in Transocean Pacific Drilling Inc. (“TPDI”) and Angola Deepwater Drilling Company Limited (“ADDCL”), and continue to evaluate the effect that our adoption will have on our consolidated statements of financial position, results of operations or cash flows. See Note 4—Variable Interest Entities.

Fair value measurements and disclosures—Effective January 1, 2010, we will adopt the effective provisions of the accounting standards update that clarifies existing disclosure requirements and introduces additional disclosure requirements for fair value measurements. The update requires entities to disclose the amounts of and reasons for significant transfers between Level 1 and Level 2, the reasons for any transfers into or out of Level 3, and information about recurring Level 3 measurements of purchases, sales, issuances and settlements on a gross basis. The update also clarifies that entities must provide (a) fair value measurement disclosures for each class of assets and liabilities and (b) information about both the valuation techniques and inputs used in estimating Level 2

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

and Level 3 fair value measurements. Except for the requirement to disclose information about purchases, sales, issuances, and settlements in the reconciliation of recurring Level 3 measurements on a gross basis, the update is effective for interim and annual periods beginning after December 15, 2009. The requirement to separately disclose purchases, sales, issuances, and settlements of recurring Level 3 measurements is effective for interim and annual periods beginning after December 15, 2010. We do not expect that our adoption will have a material effect on the disclosures contained in our notes to consolidated financial statements.

Note 4—Variable Interest Entities

In October 2007, we acquired a 50 percent interest in TPDI, a British Virgin Islands joint venture company formed by us and Pacific Drilling Limited (“Pacific Drilling”), a Liberian company, to own and operate two ultra-deepwater drillships named Dhirubhai Deepwater KG1 and Dhirubhai Deepwater KG2, the latter of which is currently under construction. Since TPDI’s equity at risk is insufficient to permit TPDI to carry on its activities without additional subordinated financial support, TPDI meets the criteria for a variable interest entity, and we have determined that we are the primary beneficiary for accounting purposes. As a result, we consolidate TPDI in our consolidated financial statements, intercompany transactions are eliminated and the interest that is not owned by us is presented as noncontrolling interest on our consolidated balance sheet. Under a management services agreement, we currently provide construction management services for the Dhirubhai Deepwater KG2 and operating management services for the Dhirubhai Deepwater KG1, and we have agreed to provide operating management services for the Dhirubhai Deepwater KG2 after the drillship commences operations. Beginning on October 18, 2010, Pacific Drilling will have the right to exchange its interest in the joint venture for our shares or cash at a purchase price based on an appraisal of the fair value of the drillships, subject to various adjustments.

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

The carrying amounts associated with these two joint ventures, after eliminating the effect of intercompany transactions, were as follows (in millions):

	December 31, 2009						December 31, 2008
	Assets		Liabilities		Net carrying amount		Assets		Liabilities		Net carrying amount
Variable interest entity
TPDI	$	1,500	$	763	$	737	$	803	$	413	$	390
ADDCL		582		482		100		354		307		47
Total	$	2,082	$	1,245	$	837	$	1,157	$	720	$	437

Note 5—Business Combination

In connection with the Merger, Transocean Inc. issued approximately 107,752,000 ordinary shares and paid approximately $5 billion in cash. We accounted for the Merger using the purchase method of accounting with Transocean treated as the accounting acquirer. As a result, the assets and liabilities of Transocean remained at historical amounts. We recorded the assets and liabilities of GlobalSantaFe at their estimated fair values at November 27, 2007, the date of completion of the GSF Transactions, with the excess of the purchase price over the sum of these fair values recorded as goodwill, and we included the results of operations and cash flows for approximately one month of 2007 in our consolidated financial statements for the year ended December 31, 2007.

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

In the fourth quarter of 2008, we completed our evaluation of the purchase price allocation. As a result, during 2008, we made adjustments to the estimated fair value of certain assets and liabilities with a corresponding net adjustment to goodwill amounting to $123 million, which are reflected in the amounts noted above. Our adjustments to the allocation of the fair value of assets acquired and liabilities assumed were primarily related to property and equipment, accrued pension liabilities, severance liabilities and income taxes, including deferred taxes, uncertain tax positions and other tax accruals. See Note 10—Goodwill and Other Intangible Assets.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

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

	Year ended December 31, 2007
	(As adjusted)
Operating revenues	$	11,066
Operating income		4,870
Income from continuing operations		3,678
Earnings per share
Basic	$	17.19
Diluted	$	16.57

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

Note 6—Impairments

Assets held for sale—During the year ended December 31, 2009, we determined that GSF Arctic II and GSF Arctic IV, both classified as assets held for sale, were impaired due to the continued global economic downturn and depressed commodity prices, both of which have had an adverse effect on our industry. We estimated the fair values of these rigs based on an exchange price that would be received for the assets in the principal or most advantageous market for the assets in an orderly transaction between market participants as of the measurement date and considering our undertakings to the Office of Fair Trading in the U.K. (“OFT”) that require the sale of the rigs with certain limitations and in a limited amount of time. We based our estimates on unobservable inputs that require significant judgment, for which there is little or no market data, including non-binding price quotes from unaffiliated parties, considering existing market conditions and restrictions imposed by the OFT. As a result of our evaluation, during the year ended December 31, 2009, we recognized an impairment loss of $279 million ($0.87 per diluted share), which had no tax effect. See Note 26—Subsequent Events. During the year ended December 31, 2008, we recognized an impairment loss of $97 million ($0.30 per diluted share), which had no tax effect.

Goodwill and other intangible assets—During the year ended December 31, 2009, we determined that the customer relationships and trade name intangible assets associated with our drilling management services reporting unit were impaired due to market conditions resulting from the continued global economic downturn and depressed commodity prices. We estimated the fair value of the customer relationships intangible asset using the multi-period excess earnings method, and we estimated the fair value of the trade name using the relief from royalty method, both valuation methodologies that apply the income approach. Our valuations were based on projections of the future performance of the drilling management services reporting unit using unobservable inputs that require significant judgment, for which there is little or no market data, including assumptions about future commodity prices, projected demand for our services, rig availability and dayrates. As a result of our impairment testing, we determined that the carrying amount of the customer relationships intangible asset exceeded its fair value, and we recognized impairment losses of $49 million ($33 million, or $0.10 per diluted share, net of tax) for the year ended December 31, 2009. Additionally, we determined that the carrying amount of the trade name intangible asset exceeded its fair value, and we recognized an impairment loss of $6 million ($4 million, or $0.01 per diluted share, net of tax).

In the fourth quarter of 2009, we performed our annual impairment testing for indefinite-lived intangible assets. Based on the results of our tests, we determined that the goodwill associated with our contract drilling services reporting unit and our oil and gas properties reporting unit was not impaired. We also concluded that the carrying value of the trade name intangible asset associated with our drilling management services reporting unit did not require additional impairment.

In the fourth quarter of 2008, we performed our annual impairment testing for indefinite-lived intangible assets. We identified interim indicators that resulted in testing our long-lived assets, goodwill and other intangible assets as of December 31, 2008. As a result of our impairment testing, we determined that the goodwill and other intangible assets associated with our drilling management services reporting unit were impaired. Accordingly, we recognized an impairment loss on full carrying amount of goodwill associated with this reporting unit in the amount of $176 million ($0.55 per diluted share), which had no tax effect. We also impaired both the trade name and customer relationship intangible assets associated with this reporting unit and recorded impairments of $31 million ($20 million, or $0.06 per diluted share, net of tax) and $16 million ($11 million, or $0.04 per diluted share, net of tax), respectively.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

Note 7—Income Taxes

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

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

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

	Years ended December 31,
	2009			2008			2007
				(As adjusted)
Current tax expense	$	740		$	735		$	293
Deferred tax expense (benefit)		14			8			(40	)
Income tax expense	$	754		$	743		$	253

Effective tax rate		19.2	%		15.6	%		7.5	%

A reconciliation of the differences between our income tax expense computed at the Swiss holding company statutory rate of 7.83 percent and our reported provision for income taxes for the year ended December 31, 2009 is as follows (in millions):

	Year ended December 31, 2009
Income tax expense at the federal statutory rate	$	307
Taxes on earnings subject to rates greater than the Swiss rate		321
Changes in unrecognized tax benefits		135
Change in valuation allowance		46
Benefit from foreign tax credits		(49	)
Other, net		(6	)
Income tax expense	$	754

For the years ended December 31, 2008 and 2007, our parent holding company was a Cayman Islands company and our earnings were not subject to income tax in the Cayman Islands because the country does not levy tax on corporate income. As a result, we have not presented a reconciliation of the differences between the income tax provision computed at the statutory rate and the reported provision for income taxes for these periods.

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

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TRANSOCEAN LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

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

	December 31,
	2009			2008
Deferred tax assets
Drilling contract intangibles	$	14		$	46
Net operating loss carryforwards		135			75
Tax credit carryforwards		29			40
Accrued payroll expenses not currently deductible		74			62
Deferred income		74			53
Other		29			13
Valuation allowance		(69	)		(23	)
Total deferred tax assets		286			266

Deferred tax liabilities
Depreciation and amortization		(863	)		(795	)
Drilling management services intangibles		(27	)		(55	)
Other		(18	)		(19	)
Total deferred tax liabilities		(908	)		(869	)

Net deferred tax liabilities	$	(622	)	$	(603	)

We have recognized deferred taxes related to the earnings of certain subsidiaries that are not permanently reinvested or that will not be permanently reinvested in the future. Should our expectations change regarding the expected future tax consequences, we may be required to record additional deferred taxes that could have a material adverse effect on our consolidated statement of financial position, results of operations or cash flows.

A valuation allowance for deferred tax assets is recorded when it is more likely than not that some or all of the benefit from the deferred tax asset will not be realized. We provide a valuation allowance to offset deferred tax assets for net operating losses (“NOL”) incurred during the year in certain jurisdictions and for other deferred tax assets where, in our opinion, it is more likely than not that the financial statement benefit of these losses will not be realized. We provide a valuation allowance for foreign tax credit carryforwards to reflect the possible expiration of these benefits prior to their utilization. As of December 31, 2009, the valuation allowance for non-current deferred tax assets increased from $23 million to $69 million. The increase resulted primarily from reassessments of valuation allowances against future operations in Brazil. Our Brazilian NOL carryforwards do not expire. As of December 31, 2008, the valuation allowance for non-current deferred tax assets decreased from $29 million to $23 million. The decrease resulted primarily from reassessments of valuation allowances against deferred tax assets acquired in connection with the Merger, which did not impact the statement of operations.

Our U.K. NOL carryforwards do not expire. The tax effect of the U.K. NOL carryforwards was $19 million at December 31, 2009 and $27 million at December 31, 2008. We have generated additional NOL carryforwards in various worldwide tax jurisdictions. Our U.S. foreign tax credit carryforwards of $29 million will expire between 2015 and 2019.

On December 31, 2009, our unrecognized U.S. capital loss carryforward expired. We did not recognize a deferred tax asset for the capital loss carryforward as it was not probable that we would realize the benefit of this tax attribute. Our operations do not normally generate capital gain income, which is the only type of income that may be offset by capital losses. Certain activities related to the TODCO tax sharing agreement also serve to increase or decrease the capital loss carryforward.

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TRANSOCEAN LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

Tax returns—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. On January 1, 2007, we adopted amendments to the accounting standards related to accounting for uncertainty in income taxes which require us to accrue for income tax contingencies that we believe are more likely than not exposures.

The following is a reconciliation of our unrecognized tax benefits, excluding interest and penalties (in millions):

	Years ended December 31,
		2009			2008			2007
Balance, beginning of period	$	372		$	299		$	219
Additions for current year tax positions		64			46			48
Additions for prior year tax positions		62			67			22
Unrecognized tax benefits assumed in connection with the Merger		—			—			42
Reductions for prior year tax positions		(22	)		(36	)		(6	)
Settlements		(3	)		(3	)		(26	)
Reductions related to statute of limitation expirations		(13	)		(1	)		—
Balance, end of period	$	460		$	372		$	299

The liabilities related to our unrecognized tax benefits were comprised of the following (in millions):

	December 31,
		2009		2008
Unrecognized tax benefits, excluding interest and penalties	$	460	$	372
Interest and penalties		200		149
Unrecognized tax benefits, including interest and penalties	$	660	$	521

For the years ended December 31, 2009, 2008 and 2007, as a component of income tax expense, we recognized interest and penalties related to our unrecognized tax benefits of $51 million, $24 million and $41 million, respectively. If recognized, $628 million of our unrecognized tax benefits, including interest and penalties, at December 31, 2009 would favorably impact our effective tax rate.

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

We, or one of our subsidiaries, file federal and local tax returns in several jurisdictions throughout the world. With few exceptions, we are no longer subject to examinations of our U.S. and non-U.S. tax matters for years prior to 1999. The amount of current tax benefit recognized during the years ended December 31, 2009 and December 31, 2008 from the settlement of disputes with tax authorities and the expiration of statute of limitations was insignificant.

Tax positions—With respect to our 2004 and 2005 U.S. federal income tax returns, the U.S. taxing authorities have withdrawn all of their previously proposed tax adjustments, except a claim regarding transfer pricing for certain charters of drilling rigs between our subsidiaries, reducing the total proposed adjustments to approximately $79 million. Such tax treatment with respect to 2004, 2005 or subsequent years’ activities would not result in a material adverse effect on our consolidated statement of financial position, results of operations or cash flows. Although we believe our returns are materially correct, we have been unable to reach a resolution with the tax authorities and we expect the matter to proceed to litigation.

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TRANSOCEAN LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

Certain of our Brazilian income tax returns for the years 2000 through 2004 are currently under examination. The Brazilian tax authorities have issued tax assessments totaling $114 million, plus a 75 percent penalty of $86 million and $99 million of interest through December 31, 2009. The U.S. dollar amount of the assessments decreased during 2008 due to foreign currency exchange rate fluctuations. We believe our returns are materially correct as filed, and we are vigorously contesting these assessments. We filed a protest letter with the Brazilian tax authorities on January 25, 2008, and we are currently engaged in the appeals process.

Note 8—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,
	2009						2008						2007
	Basic			Diluted			Basic			Diluted			Basic			Diluted
Numerator for earnings per share							(As adjusted)
Net income attributable to controlling interest	$	3,181		$	3,181		$	4,031		$	4,031		$	3,121		$	3,121
Add back interest expense on convertible debentures		—			—			—			—			—			6
Undistributed net income allocable to participating securities		(18	)		(18	)		(10	)		(10	)		(7	)		(7	)
Net income attributable to shareholders	$	3,163		$	3,163		$	4,021		$	4,021		$	3,114		$	3,120

Denominator for earnings per share
Weighted-average shares outstanding		320			320			318			318			214			214
Effect of dilutive securities:
Stock options and other share-based awards		—			1			—			2			—			3
Stock warrants and 1.5% convertible debentures		—			—			—			1			—			5
Weighted-average shares for per share calculation		320			321			318			321			214			222

Earnings per share	$	9.87		$	9.84		$	12.63		$	12.53		$	14.58		$	14.08

Shares subject to issuance pursuant to the conversion features of the 1.625% Series A, 1.50% Series B and 1.50% Series C Convertible Senior Notes did not have an effect on the dilution calculation for the periods presented.

Historical amounts have been adjusted to reflect our retrospective application of the accounting standards updates related to (a) convertible debt instruments that may be settled in cash upon conversion, (b) noncontrolling interests in subsidiaries and (c) earnings per share calculations considering participating securities. See Note 3—New Accounting Pronouncements and Note 11—Debt.

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TRANSOCEAN LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

Note 9—Drilling Fleet Expansion and Dispositions

Drilling fleet expansion—Construction work in progress, recorded in property and equipment, was $3.7 billion and $4.5 billion at December 31, 2009 and 2008, respectively. The following table presents actual capital expenditures and other capital additions, including capitalized interest, for our major construction and conversion projects for the four years ended December 31, 2009 (in millions):

	Years ended December 31,
	2009		2008		2007			2006	Total
			(As adjusted)
Petrobras 10000 (a) (b)	$	735	$	—	$	—	$	—	$	735
Dhirubhai Deepwater KG2 (c)		371		91		179		—		641
Dhirubhai Deepwater KG1 (a) (c)		295		105		279		—		679
Discoverer India		291		250		—		—		541
Deepwater Champion (d)		263		155		109		—		527
Discoverer Inspiration		224		205		120		118		667
Discoverer Luanda (e)		220		208		107		—		535
Discoverer Americas (a)		148		167		195		116		626
Development Driller III (a) (d)		117		133		350		—		600
Discoverer Clear Leader (a)		115		107		195		214		631
Sedco 700-series upgrades (a)		71		124		250		146		591
Capitalized interest		182		147		77		16		422
Mobilization costs		155		—		—		—		155
Total	$	3,187	$	1,692	$	1,861	$	610	$	7,350

______________________________

(a)	The accumulated construction costs of these rigs are no longer included in construction work in progress, as their construction or conversion projects had been completed as of December 31, 2009.

(b)

(c)

The costs for Dhirubhai Deepwater KG1 and Dhirubhai Deepwater KG2 represent 100 percent of expenditures incurred prior to our investment in the joint venture ($277 million and $178 million, respectively) and 100 percent of expenditures incurred since our investment in the joint venture. TPDI is responsible for these costs. We hold a 50 percent interest in TPDI, and Pacific Drilling Limited holds the remaining 50 percent interest.

(d)	These costs include our initial investments in Development Driller III and Deepwater Champion of $350 million and $109 million, respectively, representing the estimated fair values of the rigs at the time of the Merger.

(e)	The costs for Discoverer Luanda represent 100 percent of expenditures incurred since inception. ADDCL is responsible for these costs. We hold a 65 percent interest in ADDCL, and Angco Cayman Limited holds the remaining 35 percent interest.

Dispositions—During the year ended December 31, 2009, we received net proceeds of $18 million and recognized a net loss of $9 million in connection with our sale of the Sedco 135-D and other unrelated property and equipment. Additionally, in connection with the sales of our ownership interests in Caspian Drilling Company Limited and in Arab Drilling & Workover Company, we received net proceeds of $42 million and recognized a net gain of $30 million, recorded in other, net on our consolidated statements of operations. See Note 26—Subsequent Events.

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

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

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TRANSOCEAN LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

Note 10—Goodwill and Other Intangible Assets

Goodwill and other indefinite-lived intangible assets—The gross carrying amount of goodwill and accumulated impairment losses are as follows (in millions):

	December 31, 2009							December 31, 2008
	Gross carrying amount		Accumulated impairment			Net carrying amount		Gross carrying amount		Accumulated impairment			Net carrying amount
Contract drilling services	$	10,626	$	(2,494	)	$	8,132	$	10,620	$	(2,494	)	$	8,126
Drilling management services		176		(176	)		—		176		(176	)		—
Oil and gas properties		2		—			2		2		—			2
Total	$	10,804	$	(2,670	)	$	8,134	$	10,798	$	(2,670	)	$	8,128

The changes in carrying amount of our goodwill balance are as follows (in millions):

	Year ended December 31, 2009						Year ended December 31, 2008
	Balance at January 1		Net adjustment		Balance at December 31		Balance at January 1		Net adjustment (a)			Balance at December 31
Contract drilling services	$	8,126	$	6	$	8,132	$	8,020	$	106		$	8,126
Drilling management services		—		—		—		176		(176	)		—
Oil and gas properties		2		—		2		23		(21	)		2
Total	$	8,128	$	6	$	8,134	$	8,219	$	(91	)	$	8,128

______________________________

(a)	The net adjustment represents an impairment of goodwill partially offset by additional goodwill recognized in connection with the completion of our purchase price allocation related to the Merger. See Note 5—Business Combination and Note 6—Impairments.

In the Merger, we acquired the ADTI trade name, which we consider to be an indefinite-lived intangible asset. The carrying value of the trade name is as follows (in millions):

	December 31, 2009							December 31, 2008
	Gross carrying amount		Accumulated impairment			Net carrying amount		Gross carrying amount		Accumulated impairment)			Net carrying amount
Trade name	$	76	$	(37	)	$	39	$	76	$	(31	)	$	45

Other definite-lived intangible assets—In connection with the Merger, we acquired certain definite-lived intangible assets, including drilling contract intangibles, drilling management customer relationships and drilling management contract backlog. The carrying amount of definite-lived intangible assets and intangible liabilities are comprised of the following (in millions):

	December 31, 2009							December 31, 2008
	Gross carrying amount		Accumulated amortization			Net carrying amount		Gross carrying amount		Accumulated amortization			Net carrying amount
Drilling contract intangible assets	$	191	$	(168	)	$	23	$	191	$	(123	)	$	68
Customer relationships (a)		83		(19	)		64		132		(11	)		121
Contract backlog		—		—			—		16		(16	)		—
Total intangible assets	$	274	$	(187	)	$	87	$	339	$	(150	)	$	189

Drilling contract intangible liabilities	$	1,494	$	(1,226	)	$	268	$	1,494	$	(901	)	$	593

______________________________

(a) Gross carrying amount includes impairment losses of $49 million and $16 million in the years ended December 31, 2009 and 2008, respectively. See Note 6—Impairments.

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Index

TRANSOCEAN LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

We recognize contract intangible revenues over nine years and amortize the balances using the straight-line method over the respective contract periods. The customer relationships and contract backlog have definite lifespans over which we amortize using the straight-line method. The customer relationships will be amortized over their useful lives of 15 years and recognized in operating and maintenance in our consolidated statements of operations. The contract backlog was amortized over its useful life of three months and was fully amortized during the three months ended March 31, 2008. The estimated net future amortization expense (income) related to intangible assets and liabilities as of December 31, 2009 is as follows (in millions):

	Drilling contract intangibles			Customer relationships		Amortization expense (income), net
Years ending December 31,
2010	$	(98	)	$	5	$	(93	)
2011		(45	)		5		(40	)
2012		(42	)		5		(37	)
2013		(25	)		5		(20	)
2014		(15	)		5		(10	)
Thereafter		(20	)		39		19
Total intangible assets and liabilities, net	$	(245	)	$	64	$	(181	)

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Index

TRANSOCEAN LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

Note 11—Debt

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

	December 31,
	2009		2008
			(As adjusted)
ODL Loan Facility (a)	$	10	$	—
Commercial paper program (a) (b)		281		663
Term Loan due March 2010 (b)		—		2,000
6.625% Notes due April 2011 (b)		170		174
5% Notes due February 2013		247		248
5.25% Senior Notes due March 2013 (b)		496		499
TPDI Credit Facilities due June 2015 (a)		581		288
TPDI Notes due October 2017		148		111
ADDCL Credit Facilities due December 2017 (a)		454		280
6.00% Senior Notes due March 2018 (b)		997		997
7.375% Senior Notes due April 2018 (b)		247		247
GSF Explorer capital lease obligation due July 2026 (a)		15		16
8% Debentures due April 2027 (b)		57		57
7.45% Notes due April 2027 (b)		96		96
7% Senior Notes due June 2028		313		313
Petrobras 10000 capital lease obligation due August 2029 (a)		711		—
7.5% Notes due April 2031 (b)		598		598
1.625% Series A Convertible Senior Notes due December 2037 (a) (b)		1,261		2,070
1.50% Series B Convertible Senior Notes due December 2037 (b)		2,057		1,990
1.50% Series C Convertible Senior Notes due December 2037 (b)		1,979		1,911
6.80% Senior Notes due March 2038 (b)		999		999
Total debt		11,717		13,557
Less debt due within one year (a)		1,868		664
Total long-term debt	$	9,849	$	12,893

______________________________

(a)

The Overseas Drilling Limited (“ODL”) Loan Facility is classified as debt due within one year at December 31, 2009. The commercial paper program is classified as debt due within one year at both December 31, 2009 and December 31, 2008. The TPDI Credit Facilities and the ADDCL Credit Facilities had $52 million and $248 million, respectively, classified as debt due within one year at December 31, 2009. The 1.625% Series A Convertible Senior Notes had $1.3 billion classified as debt due within one year at December 31, 2009 since the holders have the option to require us to repurchase the notes in December 2010. The GSF Explorer capital lease obligation had less than $1 million classified as debt due within one year at both December 31, 2009 and December 31, 2008. The Petrobras 10000 capital lease obligation had $16 million classified as debt due within one year at December 31, 2009.

(b)

Transocean Inc., a wholly owned subsidiary of Transocean Ltd., is the issuer of the notes and debentures, which have been guaranteed by Transocean Ltd. Transocean Ltd. has also guaranteed borrowings under the commercial paper program, the Term Loan and the Five-Year Revolving Credit Facility. Transocean Ltd. has no independent assets or operations, its guarantee of debt securities of Transocean Inc. is full and unconditional and its only other subsidiaries not owned indirectly through Transocean Inc. are minor. Transocean Ltd. is not subject to any significant restrictions on its ability to obtain funds from its consolidated subsidiaries or entities accounted for under the equity method by dividends, loans or return of capital distributions.

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Index

TRANSOCEAN LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

Scheduled maturities—In preparing the scheduled maturities of our debt, we assume the bondholders exercise their options to require us to repurchase the 1.625% Series A, 1.50% Series B and 1.50% Series C Convertible Senior Notes in December 2010, 2011 and 2012, respectively. At December 31, 2009, the scheduled maturities of our debt were as follows (in millions):

Years ending December 31,
2010	$	1,906
2011		2,479
2012		2,317
2013		870
2014		124
Thereafter		4,422
Total debt, excluding unamortized discounts, premiums and fair value adjustments		12,118
Total unamortized discounts, premiums and fair value adjustments		(401	)
Total debt	$	11,717

ODL Loan Facility—In December 2009, we amended our existing loan agreement with ODL, increasing the maximum borrowing amount from $8 million to $10 million. ODL may demand repayment of the borrowings at any time upon written notice, five business days in advance. Any amounts due to us from ODL may be offset against the borrowings at the time of repayment. As of December 31, 2009, $10 million was outstanding under the ODL Loan Facility.

Commercial paper program—We maintain a commercial paper program (the “Program”), which is supported by the Five-Year Revolving Credit Facility and under which we may, from time to time, issue privately placed, unsecured commercial paper notes up to a maximum aggregate outstanding amount of $1.5 billion. Proceeds from commercial paper issuance under the Program may be used for general corporate purposes. At December 31, 2009, $281 million was outstanding under the Program at a weighted-average interest rate of 0.4 percent.

Term Loan—In March 2008, Transocean Inc. entered into a term credit facility under the Term Credit Agreement dated March 13, 2008, as amended. In 2008, Transocean Inc. borrowed $2.0 billion under this facility, the maximum allowed under the Term Loan. During the year ended December 31, 2009, Transocean Inc. repaid the borrowings under the Term Loan, terminated the facility and recognized a loss on retirement of debt in the amount of $1 million. See Note 12—Derivatives and Hedging.

6.625% Notes and 7.5% Notes—In April 2001, Transocean Inc. 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. The indenture pursuant to which the notes were issued contains restrictions on creating liens, engaging in sale/leaseback transactions and engaging in merger, consolidation or reorganization transactions. At December 31, 2009, $166 million and $600 million principal amount of the 6.625% Notes and 7.5% Notes, respectively, were outstanding.

Five-Year Revolving Credit Facility—We have a revolving credit facility subject to the Five-Year Revolving Credit Facility Agreement dated November 27, 2007, as amended (“Five-Year Revolving Credit Facility”). We may borrow under the Five-Year Revolving Credit Facility at either (1) the adjusted London Interbank Offered Rate (“LIBOR”) plus a margin (the “Five-Year Revolving Credit Facility Margin”) based on our Debt Rating (based on our current Debt Rating, a margin of 1.1 percent) or (2) the Base Rate plus the Five-Year Revolving Credit Facility Margin, less one percent per annum. Throughout the term of the Five-Year Revolving Credit Facility, we pay a facility fee on the daily amount of the underlying commitment, whether used or unused, which ranges from 0.10 percent to 0.30 percent (based on our Debt Rating) and was 0.15 percent at December 31, 2009. The Five-Year Revolving Credit Facility may be prepaid in whole or in part without premium or penalty. The Five-Year Revolving Credit Facility includes limitations on creating liens, incurring subsidiary debt, transactions with affiliates, sale/leaseback transactions, mergers and the sale of substantially all assets. The Five-Year Revolving Credit Facility also includes covenants imposing a maximum debt to tangible capitalization ratio of 0.6 to 1.0. Borrowings under the Five-Year Revolving Credit Facility are subject to acceleration upon the occurrence of events of default. At December 31, 2009, we had $81 million in letters of credit issued and outstanding and no borrowings outstanding under the Five-Year Revolving Credit Facility.

5% Notes and 7% Notes—Two of our wholly-owned subsidiaries are the obligors on the 5% Notes due 2013 (the “5% Notes”) and the 7% Notes due 2028 (the “7% Notes”), and we have not guaranteed either obligation. The respective obligor may redeem the 5% Notes and the 7% Notes in whole or in part at a price equal to 100 percent of the principal amount plus accrued and unpaid interest, if any, and a make-whole premium. The indentures related to the 5% Notes and the 7% Notes contain limitations on creating liens and sale/leaseback transactions. At December 31, 2009, $250 million and $300 million aggregate principal amount of the 5% Notes and the 7% Notes, respectively, remained outstanding. See Note 12—Derivatives and Hedging.

5.25%, 6.00% and 6.80% Senior Notes—In December 2007, Transocean Inc. issued $500 million aggregate principal amount of 5.25% Senior Notes due March 2013 (the “5.25% Senior Notes”), $1.0 billion aggregate principal amount of 6.00% Senior Notes due March 2018 (the “6.00% Senior Notes”) and $1.0 billion aggregate principal amount of 6.80% Senior Notes due March 2038 (the “6.80% Senior Notes”). Transocean Inc. may redeem some or all of the notes at any time, at a redemption price equal to 100 percent of the principal amount plus accrued and unpaid interest, if any, and a make-whole premium. The indenture pursuant to which the notes were issued contains restrictions on creating liens, engaging in sale/leaseback transactions and engaging in merger, consolidation or reorganization transactions. At December 31, 2009, $500 million, $1 billion and $1 billion principal amount of the 5.25% Senior Notes, the 6.00% Senior Notes and the 6.80% Senior Notes, respectively, were outstanding. See Note 12—Derivatives and Hedging.

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Index

TRANSOCEAN LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

TPDI Credit Facilities—TPDI has a bank credit agreement for a $1.265 billion secured credit facility (the “TPDI Credit Facilities”), comprised of a $1.0 billion senior term loan, a $190 million junior term loan and a $75 million revolving credit facility, which was established to finance the construction of and is secured by Dhirubhai Deepwater KG1 and Dhirubhai Deepwater KG2. One of our subsidiaries participates in the senior and junior term loans with a 50 percent commitment totaling $595 million in the aggregate. The TPDI Credit Facilities bear interest at LIBOR plus the applicable margin of 1.60 percent until acceptance of Dhirubhai Deepwater KG2, which is expected to be in the first quarter of 2010. Subsequently, the TPDI Credit Facilities will bear interest at a rate of 1.45 percent for the senior term loan and the revolving credit facility and 2.25 percent for the junior term loan. The senior term loan requires quarterly payments with a final payment on the earlier of (1) June 2015 or (2) the fifth anniversary of the acceptance date of the Dhirubhai Deepwater KG2. The junior term loan is due in full on the earlier of (1) June 2015 and (2) the fifth anniversary of the acceptance date of the Dhirubhai Deepwater KG2. The TPDI Credit Facilities may be prepaid in whole or in part without premium or penalty. The TPDI Credit Facilities have covenants that require TPDI to maintain a minimum cash balance and available liquidity, a minimum debt service ratio and a maximum leverage ratio. At December 31, 2009, $1.1 billion was outstanding under the TPDI Credit Facilities, of which $564 million was due to one of our subsidiaries and was eliminated in consolidation. The weighted-average interest rate of the TPDI Credit Facilities on December 31, 2009 was 3.9 percent.

TPDI Notes—TPDI has issued promissory notes payable to Pacific Drilling and one of our subsidiaries (the “TPDI Notes”). The TPDI Notes bear interest at LIBOR plus the applicable margin of 2 percent and have maturities through October 2019. As of December 31, 2009, $296 million in promissory notes remained outstanding, $148 million of which was due to one of our subsidiaries and has been eliminated in consolidation, bearing interest at a weighted-average interest rate of 2.8 percent.

ADDCL Credit Facilities—ADDCL has a senior secured bank credit agreement for a credit facility (the “ADDCL Primary Loan Facility”) comprised of Tranche A, Tranche B and Tranche C for $215 million, $270 million and $399 million, respectively, which was established to finance the construction of and is secured by Discoverer Luanda. Tranche A and Tranche B are provided by external lenders, and borrowings under these tranches bear interest at LIBOR plus the applicable margin of 0.425 percent until the first well commencement date, currently expected to be in the third quarter of 2010, following which the borrowings outstanding under Tranche A will bear interest at LIBOR plus the applicable margin of 0.725 percent. Tranche A requires semi-annual payments beginning six months after the rig’s first well commencement date and matures in December 2017. Tranche B matures upon customer acceptance of the rig and is expected to be repaid with borrowings under Tranche C. Tranche C is provided by one of our subsidiaries that has also agreed to provide financial security for borrowings under Tranche A and Tranche B until customer acceptance of Discoverer Luanda. Tranche C is subordinate to Tranche A and Tranche B, and borrowings under Tranche C will be eliminated in consolidation. The ADDCL Primary Loan Facility contains covenants that require ADDCL to maintain certain cash balances to service the debt and also limits ADDCL’s ability to incur additional indebtedness, to acquire assets, or to make distributions or other payments. At December 31, 2009, $193 million and $235 million were outstanding under Tranche A and Tranche B, respectively, both at a weighted-average interest rate of 0.7 percent.

Additionally, ADDCL has a secondary bank credit agreement for a $90 million credit facility (the “ADDCL Secondary Loan Facility”), for which one of our subsidiaries provides 65 percent of the total commitment. The facility bears interest at LIBOR plus the applicable margin, ranging from 3.125 percent to 5.125 percent, depending on certain milestones. The ADDCL Secondary Loan Facility is payable in full on the earlier of (1) 90 days after the fifth anniversary of the first well commencement or (2) December 2015, and it may be prepaid in whole or in part without premium or penalty. At December 31, 2009, $74 million was outstanding under the ADDCL Secondary Loan Facility, of which $48 million was provided by one of our subsidiaries and has been eliminated in consolidation. At December 31, 2009, the weighted average interest rate was 3.4 percent.

7.375% Senior Notes—In March 2002, we completed an exchange offer and consent solicitation for TODCO’s 7.375% Senior Notes (the “Exchange Offer”). As a result of the Exchange Offer, we issued $247 million principal amount of our 7.375% Senior Notes. The indenture pursuant to which the 7.375% Senior Notes were issued contains restrictions on creating liens, engaging in sale/leaseback transactions and engaging in merger, consolidation or reorganization transactions. At December 31, 2009, $247 million principal amount of the 7.375% Senior Notes were outstanding.

Petrobras 10000 capital lease obligation—On August 4, 2009, we accepted delivery of Petrobras 10000 and recorded non-cash additions of $716 million to property and equipment, net along with a corresponding increase to long-term debt. Total capital costs incurred by the lessor, Petrobras and Mitsui, for the construction of the drillship were $716 million. The capital lease agreement has an implicit interest rate of 7.8 percent with scheduled monthly payments of $6 million through August 2029, after which we will have the right and obligation to acquire the drillship from the lessor for one dollar. See Note 9—Drilling Fleet Expansion and Dispositions and Note 16—Commitments and Contingencies.

GSF Explorer capital lease obligation—GSF Explorer is subject to a capital lease agreement, which has an implicit interest rate of 9.8 percent with scheduled monthly payments totaling $2 million annually through July 2026. See Note 16—Commitments and Contingencies.

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Index

TRANSOCEAN LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

7.45% Notes and 8% Debentures—In April 1997, a predecessor of Transocean Inc. issued $100 million aggregate principal amount of 7.45% Notes due April 2027 (the “7.45% Notes”) and $200 million aggregate principal amount of 8% Debentures due April 2027 (the “8% Debentures”). The 7.45% Notes and the 8% Debentures are redeemable at any time at Transocean Inc.’s option subject to a make-whole premium. The indenture pursuant to which the 7.45% Notes and the 8% Debentures were issued contains restrictions on creating liens, engaging in sale/leaseback transactions and engaging in merger, consolidation or reorganization transactions. At December 31, 2009, $100 million and $57 million principal amount of the 7.45% Notes and the 8% Debentures, respectively, were outstanding.

1.625% Series A, 1.50% Series B and 1.50% Series C Convertible Senior Notes—In December 2007, we issued $2.2 billion aggregate principal amount of 1.625% Series A Convertible Senior Notes due December 2037 (the “Series A Notes”), $2.2 billion aggregate principal amount of 1.50% Series B Convertible Senior Notes due December 2037 (the “Series B Notes”) and $2.2 billion aggregate principal amount of 1.50% Series C Convertible Senior Notes due December 2037 (the “Series C Notes,” and together with the Series A and Series B Notes, the “Convertible Senior Notes”). The Convertible Senior Notes may be converted under the circumstances specified below at a rate of 5.9310 shares per $1,000 note, subject to adjustments upon the occurrence of certain events. Upon conversion, we will deliver, in lieu of shares, cash up to the aggregate principal amount of notes to be converted and shares in respect of the remainder, if any, of our conversion obligation. In addition, if certain fundamental changes occur on or before December 20, 2010, with respect to Series A Notes, December 20, 2011, with respect to Series B Notes or December 20, 2012, with respect to Series C Notes, we will, in some cases, increase the conversion rate for a holder electing to convert notes in connection with such fundamental change. We may redeem some or all of the notes at any time after December 20, 2010, in the case of the Series A Notes, December 20, 2011, in the case of the Series B Notes and December 20, 2012, in the case of the Series C Notes, in each case at a redemption price equal to 100 percent of the principal amount plus accrued and unpaid interest, if any. Holders of the Series A Notes and Series B Notes have the right to require us to repurchase their notes on December 15, 2010 and December 15, 2011, respectively. In addition, holders of any series of notes will have the right to require us to repurchase their notes on December 14, 2012, December 15, 2017, December 15, 2022, December 15, 2027 and December 15, 2032, and upon the occurrence of a fundamental change, at a repurchase price in cash equal to 100 percent of the principal amount of the notes to be repurchased plus accrued and unpaid interest, if any. At December 31, 2009, $1.3 billion, $2.2 billion and $2.2 billion principal amount of each of the Series A Notes, Series B Notes and Series C Notes were outstanding, respectively.

Holders may convert their notes only under the following circumstances: (1) during any calendar quarter after March 31, 2008 if the last reported sale price of our shares for at least 20 trading days in a period of 30 consecutive trading days ending on the last trading day of the preceding calendar quarter is more than 130 percent of the conversion price, (2) during the five business days after the average trading price per $1,000 principal amount of the notes is equal to or less than 98 percent of the average conversion value of such notes during the preceding five trading-day period as described herein, (3) during specified periods if specified distributions to holders of our shares are made or specified corporate transactions occur, (4) prior to the close of business on the business day preceding the redemption date if the notes are called for redemption or (5) on or after September 15, 2037 and prior to the close of business on the business day prior to the stated maturity of the notes. As of December 31, 2009, no shares were issuable upon conversion of any series of the Convertible Senior Notes since the closing price per share did not exceed the conversion price of $168.61 during the previous 30 trading days.

The carrying amounts of the liability components of the Convertible Senior Notes were as follows (in millions):

	December 31, 2009							December 31, 2008
	Principal amount		Unamortized discount			Carrying amount		Principal amount		Unamortized discount			Carrying amount
Carrying amount of liability component
Series A Convertible Senior Notes due 2037	$	1,299	$	(38	)	$	1,261	$	2,200	$	(130	)	$	2,070
Series B Convertible Senior Notes due 2037		2,200		(143	)		2,057		2,200		(210	)		1,990
Series C Convertible Senior Notes due 2037		2,200		(221	)		1,979		2,200		(289	)		1,911

The carrying amounts of the equity components of the Convertible Senior Notes were as follows (in millions):

	December 31,
	2009		2008
Carrying amount of equity component
Series A Convertible Senior Notes due 2037	$	215	$	193
Series B Convertible Senior Notes due 2037		275		275
Series C Convertible Senior Notes due 2037		352		352

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Index

TRANSOCEAN LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

Including the amortization of the unamortized discount, the effective interest rates were 4.88 percent for the Series A Notes, 5.08 percent for the Series B Notes, and 5.28 percent for the Series C Notes. At December 31, 2009, the remaining period over which the discount will be amortized is 0.9 years for the Series A Notes, 1.9 years for the Series B Notes and 2.9 years for the Series C Notes. Interest expense, excluding amortization of debt issue costs, was as follows (in millions):

	Years ended December 31,
		2009	2008		2007
Interest expense
Series A Convertible Senior Notes due 2037	$	85	$	97	$	5
Series B Convertible Senior Notes due 2037		100		97		5
Series C Convertible Senior Notes due 2037		100		97		5

During the year ended December 31, 2009, we repurchased an aggregate principal amount of $901 million of the 1.625% Series A Notes for an aggregate cash payment of $865 million. We recognized a loss of $28 million associated with the debt component of the instrument and recorded additional paid-in capital of $22 million associated with the equity component of the instrument.

Transition accounting—The following presents the incremental effect on our consolidated statement of operations upon our adoption of an accounting standards update, effective January 1, 2009 (see Note 3—New Accounting Pronouncements), related to convertible debt instruments that may be settled in cash upon conversion on our consolidated statement of operations for the years ended December 31, 2008 and 2007 (in millions, except per share data):

	Year ended December 31, 2008									Year ended December 31, 2007
	Prior to adoption			Effect of adoption			As adjusted			Prior to adoption			Effect of adoption			As adjusted
Interest expense, net of amounts capitalized	$	(469	)	$	(171	)	$	(640	)	$	(172	)	$	(10	)	$	(182	)
Income before income tax expense		4,943			(171	)		4,772			3,384			(10	)		3,374
Net income (a)		4,200			(171	)		4,029			3,131			(10	)		3,121
Net income attributable to controlling interest (a)	$	4,202		$	(171	)	$	4,031		$	3,131		$	(10	)	$	3,121
Earnings per share (b)
Basic	$	13.20		$	(0.54	)	$	12.66		$	14.65		$	(0.04	)	$	14.61
Diluted	$	13.09		$	(0.53	)	$	12.56		$	14.14		$	(0.04	)	$	14.10

______________________________

(a)	As adjusted for our adoption of the accounting standards update related to noncontrolling interest. See Note 3—New Accounting Pronouncements.

(b)	Excludes the effect of our adoption of the accounting standards update related to participating securities. See Note 3—New Accounting Pronouncements.

The following table presents the incremental effect on our consolidated balance sheet upon our adoption of the accounting standards update regarding convertible debt instruments on our consolidated balance sheet as of December 31, 2008 (in millions):

	December 31, 2008
	Prior to adoption		Effect of adoption			As adjusted
Property and equipment	$	25,802	$	34		$	25,836
Property and equipment, net		20,827		34			20,861
Other assets		867		(23	)		844
Total assets	$	35,171	$	11		$	35,182

Long-term debt	$	13,522	$	(629	)	$	12,893
Total long-term liabilities		15,943		(629	)		15,314
Additional paid-in capital		6,492		821			7,313
Retained earnings		6,008		(181	)		5,827
Total controlling interest shareholders’ equity (a)		16,524		640			17,164
Total equity (a)		16,527		640			17,167
Total liabilities and equity	$	35,171	$	11		$	35,182

______________________________

(a)	As adjusted for our adoption of the accounting standards update related to noncontrolling interest. See Note 3—New Accounting Pronouncements.

Property and equipment increased $34 million due to increased capitalization of interest related to our construction in progress, which resulted from the higher effective interest rates on the Convertible Senior Notes following our adoption of the accounting standards update regarding convertible debt instruments.

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Index

TRANSOCEAN LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

Debt issue costs, recorded in other assets, decreased $23 million, representing the cumulative adjustment caused by increased amortization recognized in interest expense for the two years ended December 31, 2008 due to the reduced recognition period required by the accounting standards update regarding convertible debt instruments and the portion of debt issue costs reclassified to additional paid-in capital.

Note 12—Derivatives and Hedging

Cash flow hedges—We recognize the gains and losses associated with the ineffective portion of the hedges in interest expense in the period in which they are realized. During the year ended December 31, 2009, TPDI entered into interest rate swaps, which have been designated and have qualified as a cash flow hedge, to reduce the variability of cash interest payments associated with the variable-rate borrowings under the TPDI Credit Facilities. The notional value increased proportionately with the forecasted borrowings under the TPDI Credit Facilities to a maximum amount of $1.190 billion, of which $595 million is attributable to one of our subsidiaries. As of December 31, 2009, the aggregate notional value had increased to its maximum amount and the intercompany balances attributable to our subsidiary have been eliminated in consolidation. Under the interest rate swaps, TPDI receives interest at three-month LIBOR and pays interest at a weighted-average fixed rate of 2.3 percent during the expected term of the TPDI Credit Facilities. At December 31, 2009, the weighted-average variable interest rate was 3.9 percent, and the carrying value represented an asset measured at a fair value of $4 million, with $5 million recorded in other assets and less than $1 million recorded in other long-term liabilities, with a corresponding decrease to accumulated other comprehensive loss on our consolidated balance sheet. During the year ended December 31, 2009, the ineffective portion recorded in interest expense was less than $1 million.

In February 2009, Transocean Inc. entered into interest rate swaps with an aggregate notional value of $1 billion, which were designated and qualified as a cash flow hedge, to reduce the variability of our cash interest payments on the borrowings under the Term Loan. Under the interest rate swaps, Transocean Inc. received interest at one-month LIBOR and paid interest at a fixed rate of 0.768 percent over the six-month period ended August 6, 2009. Upon their stated maturity, Transocean Inc. settled these interest rate swaps with no gain or loss recognized. No ineffectiveness was recorded in interest expense.

Fair value hedges—In September 2009, Transocean Inc. and Transocean Worldwide Inc. entered into interest rate swaps, which are designated and have qualified as a fair value hedge, to reduce our exposure to changes in the fair values of our 5.25% Senior Notes and our 5.00% Notes, respectively. The interest rate swaps have aggregate notional values of $500 million and $250 million, respectively, equal to the face values of the hedged instruments. The hedging relationship qualifies for and we have applied the shortcut method of accounting, under which the interest rate swaps are considered to have no ineffectiveness and no ongoing assessment of effectiveness is required. Through the stated maturities of the interest rate swaps, which coincide with those of the hedged instruments, we receive semi-annual interest at a fixed rate equal to that of the underlying debt instrument and pay variable interest semi-annually at three-month LIBOR plus a margin. At December 31, 2009, the weighted-average variable interest rate was 3.43 percent and the carrying value of the interest rate swaps represented a liability measured at a fair value of $4 million, recorded in other long-term liabilities on our consolidated balance sheet, with a corresponding decrease in the carrying value of the underlying debt instrument.

In June 2001, we entered into interest rate swaps, which were designated and qualified as a fair value hedge, to reduce our exposure to changes in the fair value of our 6.625% Notes. The interest rate swaps had an aggregate notional value of $700 million, equal to the face value of the hedge instrument. In January 2003, we terminated the outstanding interest rate swaps and recorded a fair value adjustment of $174 million to the carrying value of the 6.625% Notes. We amortize this amount as a reduction to interest expense over the remaining life of the underlying debt. During the years ended December 31, 2009, 2008 and 2007 such reduction amounted to $4 million ($0.01 per diluted share) for each year. At December 31, 2009 and 2008, the remaining unamortized balance was $5 million and $8 million, respectively.

We did not have any outstanding fair value hedges during the year ended December 31, 2008.

Note 13—Fair Value of Financial Instruments

We estimate the fair value of each class of financial instruments, for which estimating fair value is practicable, by applying the following methods and assumptions:

Cash and cash equivalents—The carrying amount approximates fair value because of the short maturities of those instruments.

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

Short-term investments—The carrying amount represents the estimated fair value, measured using (a) quoted prices for identical instruments in active markets and (b) pricing data that are representative of quoted prices for similar instruments in active markets or identical instruments in less active markets. Our short-term investments include investments in The Reserve International Liquidity Fund Ltd. and The Reserve Primary Fund. As of December 31, 2009, the carrying value of our short-term investments was $38 million.

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Index

TRANSOCEAN LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

Debt—The fair value of our fixed-rate debt is measured using quoted prices for identical instruments in active markets. Our variable-rate debt is included in the fair values stated below at its carrying value since the short-term interest rates cause the face value to approximate its fair value. The TPDI Notes and ODL Loan Facility are included in the fair values stated below at their aggregate carrying value of $158 million and $111 million at December 31, 2009 and 2008, respectively, since there is no available market price for such related-party debts (see Note 24—Related Party Transactions). The carrying values and estimated fair values of our long-term debt, including debt due within one year, were as follows (in millions):

	December 31, 2009				December 31, 2008
	Carrying value		Fair value		Carrying value		Fair value
					(As adjusted)
Long-term debt, including current maturities	$	11,717	$	12,396	$	13,557	$	12,838

Derivative instruments—The carrying amount of our derivative instruments represents the estimated fair value, measured using pricing data, including quoted prices and other observable market data, for the instruments. As of December 31, 2009, the carrying value of our derivative instruments was $5 million recorded in other assets and in other long-term liabilities on our consolidated balance sheet. We did not have any derivative instruments outstanding as of December 31, 2008.

Note 14—Financial Instruments and Risk Concentration

Interest rate risk—Financial instruments that potentially subject us to concentrations of interest rate risk include our cash equivalents, short-term investments, debt and capital lease obligations. We are exposed to interest rate risk related to our cash equivalents and short-term investments, as the interest income earned on these investments changes with market interest rates. Floating rate debt, where the interest rate can be adjusted 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 when we refinance maturing debt with new debt.

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.

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, from time to time, the 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, we may use foreign exchange derivative instruments, specifically foreign exchange forward contracts, or spot purchases, 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 that 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 that 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, 2009 and 2008, we had no outstanding foreign exchange derivative instruments.

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

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

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Index

TRANSOCEAN LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

Labor agreements—We require highly skilled personnel to operate our drilling units. We conduct extensive personnel recruiting, training and safety programs. At December 31, 2009, we had approximately 19,300 employees, and we had engaged approximately 2,200 persons through contract labor providers. Some of our employees working in Angola, the U.K. and Norway, are represented by, and some of our contracted labor work under, collective bargaining agreements. Many of these represented individuals are working under agreements that are subject to ongoing salary negotiation in 2010. These negotiations could result in higher personnel expenses, other increased costs or increased operation restrictions as the outcome of such negotiations apply to all offshore employees not just the union members.

Additionally, the unions in the U.K. sought an interpretation of the application of the Working Time Regulations to the offshore sector. The Employment Tribunal issued its decision in favor of the unions and held, in part, that offshore workers are entitled to 28 days of annual leave. Such decision has been overturned on appeal by the Employment Appeal Tribunal, but the unions have appealed this decision to the Court of Session for a hearing in June 2010. The application of the Working Time Regulations to the offshore sector could result in higher labor costs and could undermine our ability to obtain a sufficient number of skilled workers in the U.K. Legislation has been introduced in the U.S. Congress that could encourage additional unionization efforts in the U.S., as well as increase the chances that such efforts succeed. Additional unionization efforts, if successful, new collective bargaining agreements or work stoppages could materially increase our labor costs and operating restrictions.

Note 15—Postemployment Benefit Plans

Defined benefit pension plans and other postretirement benefit plans

Overview—Effective January 1, 2009, following mergers of existing plans with similar characteristics, we maintain a single qualified defined benefit pension plan in the U.S. (the “U.S. Plan”) and a single funded supplemental benefit plan (the “Supplemental Plan”). The U.S. Plan covers substantially all U.S. employees, and the Supplemental Plan, along with two other unfunded supplemental benefit plans (the “Other Supplemental Plans”), provide certain eligible employees with benefits in excess of those allowed under the U.S. Plan. Additionally, we maintain two funded and two unfunded defined benefit plans (collectively, the “Frozen Plans”) that we assumed in connection with our mergers with GlobalSantaFe and R&B Falcon, all of which were frozen prior to the respective mergers and for which benefits no longer accrue but the pension obligations have not been fully distributed. We refer to the U.S. Plan, the Supplemental Plan, the Other Supplemental Plans and the Frozen Plans, collectively, as the “U.S. Plans.”

We maintain a defined benefit plan in the U.K. (the “U.K. Plan”) covering certain current and former employees in the U.K. We also provide several funded defined benefit plans, primarily group pension schemes with life insurance companies, and two unfunded plans, covering our eligible Norway employees and former employees (the “Norway Plans”). We also maintain unfunded defined benefit plans (the “Other Plans”) that provide retirement and severance benefits for certain of our Indonesian, Nigerian and Egyptian employees. We refer to the U.K. Plan, the Norway Plans and the Other Plans, collectively, as the “Non-U.S. Plans.”

We refer to the U.S. Plans and the Non-U.S. Plans, collectively, as the “Transocean Plans”. Additionally, we have several unfunded contributory and noncontributory other postretirement employee benefits plans (the “OPEB Plans”) covering substantially all of our U.S. employees.

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

	December 31, 2009									December 31, 2008
	U.S. Plans			Non-U.S. Plans			OPEB Plans			U.S. Plans			Non-U.S. Plans			OPEB Plans
Discount rate		5.84	%		5.59	%		5.52	%		5.40	%		6.06	%		5.35	%
Compensation trend rate		4.21	%		4.73	%		n/a			4.21	%		4.54	%		n/a

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

	December 31, 2009									December 31, 2008									December 31, 2007
	U.S. Plans			Non-U.S. Plans			OPEB Plans			U.S. Plans			Non-U.S. Plans			OPEB Plans			U.S. Plans			Non-U.S. Plans			OPEB Plans
Discount rate		5.41	%		6.06	%		5.34	%		6.14	%		5.97	%		5.96	%		5.95	%		5.83	%		5.80	%
Expected rate of return		8.50	%		6.59	%		n/a			8.50	%		7.16	%		n/a			9.00	%		7.12	%		n/a
Compensation trend rate		4.21	%		4.55	%		n/a			4.57	%		4.64	%		n/a			4.58	%		4.47	%		n/a
Health care cost trend rate
–initial		n/a			n/a			8.99	%		n/a			n/a			8.55	%		n/a			n/a			9.73	%
–ultimate		n/a			n/a			5.00	%		n/a			n/a			5.00	%		n/a			n/a			5.00	%

______________________________

“n/a” means not applicable.

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Index

TRANSOCEAN LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

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

	Year ended December 31, 2009												Year ended December 31, 2008
	U.S. Plans			Non-U.S. Plans			OPEB Plans			Total			U.S. Plans			Non-U.S. Plans			OPEB Plans			Total
Change in projected benefit obligation
Projected benefit obligation, beginning of period	$	900		$	250		$	64		$	1,214		$	758		$	307		$	55		$	1,120
Plan amendments		—			—			5			5			(11	)		—			—			(11	)
Actuarial (gains) losses, net		(31	)		86			(16	)		39			148			—			9			157
Service cost		44			18			1			63			30			16			1			47
Interest cost		50			17			3			70			47			17			3			67
Foreign currency exchange rate		—			40			—			40			—			(85	)		—			(85	)
Benefits paid		(32	)		(11	)		(4	)		(47	)		(74	)		(8	)		(5	)		(87	)
Participant contributions		—			2			1			3			—			3			1			4
Special termination benefits		—			—			—			—			3			—			—			3
Settlements and curtailments		1			1			—			2			(1	)		—			—			(1	)
Projected benefit obligation, end of period	$	932		$	403		$	54		$	1,389		$	900		$	250		$	64		$	1,214

Change in plan assets
Fair value of plan assets, beginning of period	$	455		$	208		$	—		$	663		$	632		$	307		$	—		$	939
Actual return on plan assets		121			31			—			152			(163	)		(33	)		—			(196	)
Foreign currency exchange rate changes		—			31			—			31			—			(75	)		—			(75	)
Employer contributions		50			20			3			73			60			14			4			78
Participant contributions		—			2			1			3			—			3			1			4
Benefits paid		(32	)		(11	)		(4	)		(47	)		(74	)		(8)			(5	)		(87	)
Fair value of plan assets, end of period	$	594		$	281		$	—		$	875		$	455		$	208		$	—		$	663

Funded status, end of period	$	(338	)	$	(122	)	$	(54	)	$	(514	)	$	(445	)	$	(42	)	$	(64	)	$	(551	)

Balance sheet classification, end of period:
Accrued pension liability, current	$	5		$	2		$	3		$	10		$	7		$	—		$	3		$	10
Accrued pension liability, non-current		333			120			51			504			438			42			61			541
Accumulated other comprehensive income (loss) (a)		(264	)		(117	)		2			(379	)		(390	)		(42	)		(8	)		(440	)

______________________________

(a)	Amounts are before income tax effect.

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, 2009								December 31, 2008
	U.S. Plans		Non-U.S. Plans		OPEB Plans		Total		U.S. Plans		Non-U.S. Plans		OPEB Plans		Total
Projected benefit obligation	$	932	$	403	$	54	$	1,389	$	900	$	250	$	64	$	1,214
Fair value of plan assets		594		281		—		875		455		208		—		663

The accumulated benefit obligation for all defined benefit pension plans was $1.1 billion and $983 million at December 31, 2009 and 2008, respectively. The aggregate accumulated benefit obligation and fair value of plan assets for plans with an accumulated benefit obligation in excess of plan assets are as follows (in millions):

	December 31, 2009								December 31, 2008
	U.S. Plans		Non-U.S. Plans		OPEB Plans		Total		U.S. Plans		Non-U.S. Plans		OPEB Plans		Total
Accumulated benefit obligation	$	789	$	344	$	54	$	1,187	$	763	$	164	$	64	$	991
Fair value of plan assets		594		281		—		875		455		152		—		607

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Index

TRANSOCEAN LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

Plan assets—We periodically review our investment policies, plan assets and asset allocation strategies to evaluate performance relative to specified objectives. In determining our asset allocation strategies, we review models presenting many different asset allocation scenarios to assess the most appropriate target allocation expected to produce long-term gains without taking on undue risk. As of December 31, 2009, our actual and targeted weighted-average asset allocations for funded Transocean Plans by asset category were as follows (in millions):

	December 31, 2009
	U.S. Plans								Non-U.S. Plans
Asset category	Value (a)		Allocation			Target			Value (a)		Allocation			Target
Equity securities :
U.S. large-cap	$	286							$	34
U.S. small-cap		55								—
Non-U.S. developed markets		70								146
Non-U.S. emerging markets		20								—
Total equity securities	$	431		72	%		65	%	$	180		64	%		56	%

Fixed income securities:
U.S. Treasury		48								—
Non-U.S. government		12								53
U.S. government agencies		12								—
U.S. corporate (b)		33								—
U.S. government, collateralized		49								—
U.S. corporate, collateralized		5								—
Total fixed income securities	$	159		27	%		35	%	$	53		19	%		30	%

Other investments:
Cash	$	4							$	15
Property		—								24
Other		—								9
Total other investments	$	4		1	%		—	%	$	48		17	%		14	%

Total	$	594		100	%		100	%	$	281		100	%		100	%

______________________________

(a)	Fair value amounts are measured using quoted prices and other observable market data.

(b)	This asset category comprises investments in the industrial, finance and utility industries.

Investment managers are given established ranges within which the investments may deviate from the target allocations. As of December 31, 2009, the target allocation for the U.S. Plans was 65 percent equity securities and 35 percent fixed income securities, having recently been adjusted to reduce exposure to the equity markets. The U.S. Plans invest in low-cost passively managed funds that reference market indices. The Non-U.S. Plans invest in actively managed funds that measure performance against relevant index benchmarks. The Non-U.S. Plans invest a small portion of funds in other investments to participate in strategies that include arbitrage, short-selling, risk management and merger and acquisition opportunities.

The plan assets for our funded Transocean Plans are invested in indexed and actively managed investment funds managed by plan investment managers that have discretion to select the securities held within each asset category. Given this discretion, the managers may occasionally invest in our debt or equity securities, and may hold either long or short positions in such securities. As these managers are required to maintain well diversified portfolios, the actual investment in our securities would be immaterial relative to asset categories and the overall plan assets.

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Index

TRANSOCEAN LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

Net periodic benefit costs—Net periodic benefit costs, before tax, included the following components (in millions):

	Year ended December 31, 2009									Year ended December 31, 2008									Year ended December 31, 2007
	U.S. Plans			Non-U.S. Plans			Transocean Plans			U.S. Plans			Non-U.S. Plans			Transocean Plans			U.S. Plans			Non-U.S. Plans			Transocean Plans
Service cost	$	44		$	18		$	62		$	30		$	16		$	46		$	15		$	6		$	21
Interest cost		50			17			67			47			17			64			19			5			24
Expected return on plan assets		(55	)		(16	)		(71	)		(53	)		(21	)		(74	)		(22	)		(4	)		(26	)
Settlements and curtailments		4			2			6			(1	)		—			(1	)		—			—			—
Special termination benefits		—			—			—			3			—			3			—			—			—
Actuarial losses, net		18			2			20			4			—			4			4			1			5
Prior service cost, net		(1	)		1			—			—			1			1			—			1			1
Transition obligation, net		—			—			—			—			1			1			—			1			1
Net periodic benefit costs	$	60		$	24		$	84		$	30		$	14		$	44		$	16		$	10		$	26

For the OPEB Plans, the combined components of net periodic benefit costs, including service cost, interest cost, amortization of prior service cost and recognized net actuarial losses were $3 million for each of the years ended December 31, 2009 and 2008 and less than $2 million for the year ended December 31, 2007, respectively.

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

	December 31, 2009												December 31, 2008
	U.S. Plans			Non-U.S. Plans			OPEB Plans			Total			U.S. Plans			Non-U.S. Plans			OPEB Plans			Total
Actuarial loss, net	$	277		$	117		$	5		$	399		$	404		$	42		$	22		$	468
Prior service credit, net		(13	)		(2	)		(7	)		(22	)		(14	)		(1	)		(14	)		(29	)
Transition obligation, net		—			2			—			2			—			1			—			1
Total	$	264		$	117		$	(2	)	$	379		$	390		$	42		$	8		$	440

The following table presents the amounts in accumulated other comprehensive income expected to be recognized as components of net periodic benefit costs during the year ending December 31, 2010 (in millions):

	Year ending December 31, 2010
	U.S. Plans			Non-U.S. Plans		OPEB Plans			Total
Actuarial loss, net	$	12		$	6	$	—		$	18
Prior service credit, net		(1	)		—		(2	)		(3	)
Transition obligation, net		—			—		—			—
Total amount expected to be recognized	$	11		$	6	$	(2	)	$	15

Funding contributions—During the year ended December 31, 2009, we contributed $73 million to the Transocean Plans and the OPEB Plans which was funded from our cash flows from operations. Our 2009 contributions included $44 million to the funded U.S. Plans, $11 million to the funded Norway Plans, $5 million to the funded U.K. Plans, $10 million to the unfunded U.S. Plans and the Other Plans, and $3 million to the OPEB Plans.

We expect to contribute a total of $76 million to the Transocean Plans in 2010. These contributions are comprised of an estimated $53 million to meet the minimum funding requirements for the funded U.S. Plans, $7 million to fund expected benefit payments for the unfunded U.S. Plans and the Other Plans, $11 million to fund expected benefit payments for the funded Norway Plans and $5 million to fund expected benefit payments for the U.K. Plan. For the OPEB Plans, we expect to fund the benefit payments of $3 million as costs are incurred. The postretirement health care plans include a limit on our share of costs for recent and future retirees.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

Benefit payments—The following are the projected pension benefits payments (in millions):

Years ending December 31,		U.S. Plans	Non-U.S. Plans			OPEB Plans	Total
2010	$	35	$	6	$	3	$	44
2011		42		6		3		51
2012		39		7		4		50
2013		41		8		4		53
2014		42		8		4		54
2015-2018		256		54		21		331

Defined contribution plans

In 2009, we sponsored three defined contribution plans, including (1) one qualified defined contribution savings plans covering certain employees working in the U.S. (the “U.S. Savings Plan”), (2) one defined contribution savings plans covering certain employees working outside the U.S. and U.K. (the “Non-U.S. Savings Plan”), and (3) one defined contribution pension plan that covers certain employees working outside the U.S. (the “Non-U.S. Pension Plan”).

For the U.S. Savings Plan and the Non-U.S. Savings Plan, we make a matching contribution of up to 6.0 percent of each covered employee’s base salary, based on the employee’s contribution to the plan. For the Non-U.S. Pension Plan, we contribute between 4.5 percent and 6.5 percent of each covered employee’s base salary, based on the employee’s years of eligible service. We recorded approximately $67 million, $51 million and $33 million of expense related to our defined contribution plans for the years ended December 31, 2009, 2008 and 2007, respectively.

Severance plan

Following our merger with GlobalSantaFe in 2007, we established a plan to consolidate operations and administrative functions. As of December 31, 2009, we had identified 336 employees who had been involuntarily terminated pursuant to this plan. We recognized $17 million, $5 million and $4 million of severance expense for the years ended December 31, 2009, 2008 and 2007, respectively, in either operating and maintenance expense or general and administrative expense. The liability associated with the severance plan, recorded in accrued liabilities, was $17 million and $21 million at December 31, 2009 and December 31, 2008, respectively. Since the severance plan’s inception in 2007, we have paid $53 million in termination benefits under the plan, including $18 million, $33 million and $2 million paid during the years ended December 31, 2009, 2008 and 2007, respectively. We expect to accrue all remaining amounts in the three months ended March 31, 2009, and we expect such remaining amounts to be immaterial.

Note 16—Commitments and Contingencies

Lease obligations

We have operating lease commitments expiring at various dates, principally for real estate, office space and office equipment. In August 2009, we accepted delivery of Petrobras 10000, an asset held under a capital lease through August 2029. Additionally, GSF Explorer is held under a capital lease through July 2026. Rental expenses for all leases, including leases with terms of less than one year, was approximately $99 million, $89 million and $51 million for the years ended December 31, 2009, 2008 and 2007, respectively. As of December 31, 2009, future minimum rental payments related to noncancellable operating leases and the capital leases were as follows (in millions):

Years ending December 31,	Capital Leases			Operating Leases
2010	$	74		$	40
2011		74			33
2012		74			23
2013		74			19
2014		74			14
Thereafter		1,084			45
Total future minimum rental payment	$	1,454		$	174
Less amount representing imputed interest		(728	)
Present value of future minimum rental payments under capital leases		726
Less current portion included in debt due within one year		(16	)
Long-term capital lease obligation	$	710

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

The following is the aggregate carrying amount of GSF Explorer and Petrobras 10000, assets held under capital lease, as of December 31, 2009 and 2008, respectively (in millions):

	December 31,
		2009		2008
Property and equipment, cost	$	976		$	224
Accumulated depreciation		(27	)		(13	)
Property and equipment, net	$	949		$	211

Depreciation expense for GSF Explorer and Petrobras 10000 was $14 million, $12 million and $1 million for the years ended December 31, 2009, 2008 and 2007, respectively. Having acquired the GSF Explorer in the Merger, only one month of depreciation expense is included in the year ended December 31, 2007.

Legal proceedings

One of our subsidiaries was involved in lawsuits arising out of the subsidiary’s involvement in the design, construction and refurbishment of major industrial complexes. The operating assets of the subsidiary were sold and its operations discontinued in 1989, and the subsidiary has no remaining assets other than the insurance policies involved in its litigation, fundings from settlements with the primary insurers and funds received from the cancellation of certain insurance policies. The subsidiary has been named as a defendant, along with numerous other companies, in lawsuits alleging personal injury as a result of exposure to asbestos. As of December 31, 2009, the subsidiary was a defendant in approximately 1,041 lawsuits. Some of these lawsuits include multiple plaintiffs and we estimate that there are approximately 2,623 plaintiffs in these lawsuits. For many of these lawsuits, we have not been provided with sufficient information from the plaintiffs to determine whether all or some of the plaintiffs have claims against the subsidiary, the basis of any such claims, or the nature of their alleged injuries. The first of the asbestos-related lawsuits was filed against this subsidiary in 1990. Through December 31, 2009, the amounts expended to resolve claims (including both attorneys’ fees and expenses, and settlement costs) have not been material, and all deductibles with respect to the primary insurance have been satisfied. The subsidiary continues to be named as a defendant in additional lawsuits and we cannot predict the number of additional cases in which it may be named a defendant nor can we predict the potential costs to resolve such additional cases or to resolve the pending cases. However, the subsidiary has in excess of $1 billion in insurance limits potentially available to the subsidiary. Although not all of the policies may be fully available due to the insolvency of certain insurers, we believe that the subsidiary will have sufficient insurance and funds from the settlements of litigation with insurance carriers available to respond to these claims. While we cannot predict or provide assurance as to the final outcome of these matters, we do not believe that the current value of the claims where we have been identified will have a material impact on our consolidated statement of financial position, results of operations or cash flows.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

Sedco 710 litigation—One of our subsidiaries was involved in an action with respect to a customs matter relating to the Sedco 710 semisubmersible drilling rig. Prior to our merger with Sedco Forex, this drilling rig, which was working for Petrobras in Brazil at the time, had been admitted into the country on a temporary basis under authority granted to a Schlumberger entity. When the drilling contract with Petrobras was transferred from Schlumberger to us in the merger, the temporary import permit was not transferred. When the temporary import permit granted to Schlumberger expired in 2000, renewal filings were not immediately made and the Brazilian authorities threatened to cancel the temporary import permit and to collect customs duties as if the rig had been nationalized in Brazil. Together with Schlumberger, we jointly filed an action for the purpose of avoiding cancellation of, and extending, the temporary import permit and to avoid collection of any customs duty. Other proceedings were also initiated to secure the transfer of the temporary import permit to us. The court initially permitted the transfer of the temporary import permit but did not rule on whether the temporary admission could be extended without the payment of a financial penalty in the form of Brazilian customs duties. In 2004, the Brazilian authorities issued an assessment totaling approximately $167 million (based on the initial assessment amount, accrued interest and current exchange rate) against our subsidiary based on the expiration of the temporary import permit. This amount continued to grow as a result of interest and changes in the exchange rate. The first level Brazilian court also ruled in 2007 that the financial penalties were appropriate and this ruling was subsequently upheld at the next level. We continued to contest this decision but ultimately decided to participate in November 2009 in a Brazilian tax amnesty program and paid $142 million to settle all tax claims by the Brazilian authorities in this matter. In addition, we reached a settlement with Schlumberger with respect to our allegation that Schlumberger should be responsible for the assessment.

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

Environmental matters

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

Superfund site, which includes this property. Testing has been completed at the property but no contaminants of concern were detected. In discussions with CRWQCB staff we were advised of their intent to issue us a “no further action” letter but it has not yet been received. Based on the test results, we would contest any potential liability. We have no knowledge at this time of the potential cost of any remediation, who else will be named as PRPs, and whether in fact any of our subsidiaries is a responsible party. The subsidiaries in question do not own any operating assets and have limited ability to respond to any liabilities.

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

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

§	appropriate investigatory and/or remedial actions; and

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

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

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

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

§	the remediation methods and technology to be used.

Contamination litigation

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

Retained risk

Our insurance program consists of commercial market and captive insurance policies primarily with 12-month policy periods beginning May 1, 2009. Under the program, we generally maintain a $125 million per occurrence deductible on our hull and machinery, which is subject to an aggregate deductible of $250 million. However, in the event of a total loss or a constructive total loss of a drilling unit, such loss would be subject to a deductible ranging from $500,000 to $1.5 million. Additionally, we maintain a $10 million per occurrence deductible on crew personal injury liability and collision liability claims and $5 million per occurrence deductible on other third-party non-crew claims, which together are subject to an aggregate deductible of $50 million that is applied to any occurrence in excess of the per occurrence deductible until the aggregate deductible is exhausted. We also carry $950 million of third-party liability coverage exclusive of the personal injury liability deductibles, third-party property liability deductibles and retention amounts described above. We retain the risk for any liability losses in excess of the $950 million limit. We have elected to self-insure operators extra expense coverage for our subsidiaries ADTI and CMI. This coverage provides protection against expenses related to well control and redrill liability associated with blowouts. Generally, ADTI’s customers assume, and indemnify ADTI for, liability associated with blowouts in excess of $50 million.

At present, the insured value of our drilling rig fleet is approximately $39 billion in aggregate. We generally do not have commercial market insurance coverage for physical damage losses to our fleet due to named windstorms in the U.S. Gulf of Mexico and war perils worldwide. Except with respect to Dhirubhai Deepwater KG1 and Dhirubhai Deepwater KG2, we generally do not carry insurance for loss of revenue unless contractually required. In the opinion of management, adequate accruals have been made based on known and estimable losses related to such exposures.

Letters of credit and surety bonds

We had letters of credit outstanding totaling $567 million and $751 million at December 31, 2009 and 2008, 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 $31 million and $37 million at December 31, 2009 and 2008, respectively.

Note 17—Share-Based Compensation Plans

Overview—We have (i) a long-term incentive plan (the “Long-Term Incentive Plan”) for executives, key employees and outside directors under which awards can be granted in the form of stock options, restricted shares, deferred units, SARs and cash performance awards and (ii) other incentive plans under which awards are currently outstanding. Awards that may be granted under the Long-Term Incentive Plan include traditional time-vesting awards (“time-based awards”) and awards that are earned based on the achievement of certain performance criteria (“performance-based awards”) or market factors (“market-based awards”). Our executive compensation committee of our board of directors determines the terms and conditions of the awards granted under the Long-Term Incentive Plan. At the 2009 annual shareholder’s meeting, the board of directors approved an increase of authorized shares for employee grants from 22.9 million to 35.9 million shares. As of December 31, 2009, we had 35.9 million shares authorized for all future employee grants.

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

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

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

All Transocean deferred units and restricted shares were exchanged for the same consideration for which each outstanding Transocean Inc. ordinary share was exchanged in the Reclassification. As a result, holders of deferred units and restricted shares received $33.03 in cash and 0.6996 Transocean Inc. ordinary shares for each deferred unit or restricted share they held immediately prior to the Reclassification. With respect to time-based deferred unit and restricted share awards made prior to July 21, 2007, all such consideration was fully vested as of the Merger date. However, with respect to those awards made on or after July 21, 2007, only the cash component of the consideration vested as of the Merger date, and the share consideration remained subject to the vesting restrictions set forth in the applicable award agreement. All performance-based awards for which the performance determination occurred prior to the Merger date became fully vested at that time. All unvested performance-based shares for which the performance determination had not yet occurred as of the Merger date became vested at 50 percent on the Merger date. The remaining shares not vested were forfeited in 2007. As a result, there were no performance-based shares outstanding at December 31, 2007. The numbers of restricted shares and deferred units in the tables and discussions below have been retroactively restated for all periods presented to give effect to reduction in shares that occurred in connection with the Reclassification. Weighted-average grant-date fair values per share for deferred units and restricted shares have not been restated.

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

In connection with the Redomestication Transaction, we adopted and assumed the Long-Term Incentive Plan and other employee benefit plans and arrangements of Transocean Inc., and those plans and arrangements were amended as necessary to give effect to the Redomestication Transaction, including to provide (1) that our shares will be issued, held, available or used to measure benefits as appropriate under the plans and arrangements, in lieu of Transocean Inc. ordinary shares, including upon exercise of any options or SARs issued under those plans and arrangements; and (2) for the appropriate substitution of us for Transocean Inc. in those plans and arrangements. Additionally, we issued 16 million of our shares to Transocean Inc., 14 million of which remained available as of December 31, 2009, for future use to satisfy our obligations to deliver shares in connection with awards granted under incentive plans, warrants or other rights to acquire our shares.

As of December 31, 2009, total unrecognized compensation costs related to all unvested share-based awards totaled $100 million, which is expected to be recognized over a weighted-average period of 1.8 years. There were modifications totaling $8 million during the year ended December 31, 2009. There were no significant modifications during the years ended December 31, 2008 and 2007.

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

	Years ended December 31,
	2009		2008		2007
Dividend yield		—		—		—
Expected price volatility		49%		36%		31%
Risk-free interest rate		1.80%		3.00%		4.88%-5.09%
Expected life of options		4.8 years		4.4 years		3.2 years
Weighted-average fair value of options granted		$26.07		$49.32		$40.69

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

	Years ended December 31,
	2009 (a)		2008		2007
Dividend yield		—		—		—
Expected price volatility		—		31%		33%
Risk-free interest rate		—		3.15%		4.91%
Expected life of options		—		1.0 year		1.0 year
Weighted-average fair value of options granted		—		$41.39		$23.01

______________________________

(a)	As of January 1, 2009, we discontinued offering the ESPP.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

Time-Based Awards

Stock options—The following table summarizes vested and unvested time-based vesting stock option (“time-based options”) activity under our incentive plans during the year ended December 31, 2009:

	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, 2009	2,358,743		$	44.50	2.90	$	6
Granted	597,898			60.41
Exercised	(980,105	)		19.97
Forfeited	(147,881	)		71.19
Outstanding at December 31, 2009	1,828,655		$	60.69	4.96	$	40

Vested and exercisable at December 31, 2009	1,171,865		$	50.05	2.70	$	38

The weighted-average grant-date fair value of time-based options granted during the year ended December 31, 2009 was $26.07 per share. There were time-based options to purchase 276,281 and 3,073 shares granted during the years ended December 31, 2008 and 2007, respectively, with weighted-average grant-date fair values of $49.32 and $40.69 per share, respectively.

The total pretax intrinsic value of time-based options exercised during the year ended December 31, 2009 was $43 million. There were 1,066,173 and 2,112,853 time-based options exercised during the years ended December 31, 2008 and 2007, respectively. The total pretax intrinsic value of time-based options exercised was $101 million and $156 million during the years ended December 31, 2008 and 2007, respectively.

There were 656,790 and 273,314 unvested time-based options outstanding as of December 31, 2009 and 2008, respectively. There were no unvested time-based options outstanding at December 31, 2007.

Restricted shares—The following table summarizes unvested share activity for time-based vesting restricted shares (“time-based shares”) granted under our incentive plans during the year ended December 31, 2009:

	Number of shares		Weighted-average grant-date fair value per share
Unvested at January 1, 2009	427,465		$	126.01
Vested	(320,782	)		120.60
Forfeited	(8,297	)		116.55
Unvested at December 31, 2009	98,386		$	112.14

We did not grant any time-based shares during the year ended December 31, 2009. There were 259,057 and 380,653 time-based shares granted during the years ended December 31, 2008 and 2007, respectively. The weighted-average grant-date fair value of time-based shares granted was $126.26 and $109.92 per share for the years ended December 31, 2008 and 2007, respectively. There were 129,979 and 261,330 time-based shares that vested during the years ended December 31, 2008 and 2007, respectively. The total grant-date fair value of time-based shares that vested was $14 million and $20 million for the years ended December 31, 2008 and 2007, respectively.

Deferred units—A deferred unit is a unit that is equal to one share but has no voting rights until the underlying shares are issued. The following table summarizes unvested activity for time-based vesting deferred units (“time-based units”) granted under our incentive plans during the year ended December 31, 2009:

	Number of units		Weighted-average grant-date fair value per share
Unvested at January 1, 2009	504,949		$	141.72
Granted	1,287,893			60.53
Vested	(282,543	)		118.20
Forfeited	(54,852	)		85.01
Unvested at December 31, 2009	1,455,447		$	76.58

The total grant-date fair value of the time-based units vested during the year ended December 31, 2009 was $33 million. There were 498,216 and 64,676 time-based units granted during the years ended December 31, 2008 and 2007, respectively. The weighted-average grant-date fair value of time-based units granted was $143.85 and $105.99 per share for the years ended December 31, 2008 and 2007, respectively. There were 25,740 and 53,086 time-based units that vested during the years ended December 31, 2008 and 2007, respectively. The total grant-date fair value of deferred units that vested was $3 million and $4 million for the years ended December 31, 2008 and 2007, respectively.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

SARs—Under an incentive plan assumed in connection with the Merger, we assumed share-settled SARs granted to key employees and to non-employee directors of GlobalSantaFe at no cost to the grantee. The grantee receives a number of shares upon exercise equal in value to the difference between the market value of our shares at the exercise date and the Merger-adjusted exercise price. The following table summarizes share-settled SARs activity under our incentive plans during the year ended December 31, 2009:

	Number of awards		Weighted-average exercise price per share		Weighted-average remaining contractual term (years)	Aggregate intrinsic value (in millions)
Outstanding at January 1, 2009	189,363		$	93.26	7.75	$	—
Exercised	(224	)		77.73
Outstanding at December 31, 2009	189,139		$	93.28	6.76	$	—

Vested and exercisable at December 31, 2009	189,139		$	93.28	6.76	$	—

At December 31, 2009, we have presented the aggregate intrinsic value as zero since the weighted-average exercise price per share exceeded the market price of our shares on that date.

We did not grant share-settled SARs during the years ended December 31, 2009, 2008, and 2007. The total pretax intrinsic value of share-settled SARs exercised during the period ended December 31, 2009 was zero. There were 315,408 and 110,355 share-settled SARs exercised, with a total pretax intrinsic value of zero, during the years ended December 31, 2008 and 2007, respectively, after we assumed them in the Merger.

There were no unvested share-settled SARs outstanding as of December 31, 2009, 2008 and 2007.

Performance-Based Awards

Stock options—We grant performance-based stock options (“performance-based options”) that can be earned depending on the achievement of certain performance targets. The number of options earned is quantified upon completion of the performance period at the determination date. The following table summarizes vested and unvested performance-based option activity under our incentive plans during the year ended December 31, 2009:

	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, 2009	179,262	$	75.30	8.38	$	—

Outstanding at December 31, 2009	179,262	$	75.30	6.22	$	1

Vested and exercisable at December 31, 2009	179,262	$	75.30	6.22	$	1

We did not grant performance-based options during the years ended December 31, 2009, 2008 and 2007. The total pretax intrinsic value of performance-based options exercised during the year ended December 31, 2009 was zero. There were 212,840 and 661,988 performance-based options exercised, with a total pretax intrinsic value of $22 million and $52 million, during the years ended December 31, 2008 and 2007, respectively.

There were no unvested performance-based stock options outstanding as of December 31, 2009, 2008 and 2007.

Restricted shares—We have previously granted performance-based restricted shares (“performance-based shares”) that could be earned depending on the achievement of certain performance targets. The number of shares earned was quantified upon completion of the performance period at the determination date. We did not grant performance-based shares during the years ended December 31, 2009, 2008 and 2007. No performance-based shares vested in the years ended December 31, 2009 and 2008 and none remain outstanding. There were 357,544 performance-based shares that vested with a total grant-date fair value of $14 million for the year ended December 31, 2007.

Deferred units—We have previously granted performance-based deferred units (“performance-based units”) that could be earned depending on the achievement of certain performance targets. The number of units earned was quantified upon completion of the performance period at the determination date. We did not grant performance-based units during the years ended December 31, 2009, 2008 and 2007. No performance-based units vested in the years ended December 31, 2009 and 2008 and none remain outstanding. There were 150,762 performance-based units that vested with a total grant-date fair value of $7 million for the year ended December 31, 2007.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

Market-Based Awards

Deferred units—We grant market-based deferred units (“market-based units”) that can be earned depending on the achievement of certain market conditions. The number of units earned is quantified upon completion of the specified period at the determination date. The following table summarizes unvested activity for market-based units granted under our incentive plans during the year ended December 31, 2009:

	Number of units		Weighted-average grant-date fair value per share
Unvested at January 1, 2009	98,540		$	144.32
Granted	285,012			75.98
Vested	—			—
Forfeited	(52,682	)		92.55
Unvested at December 31, 2009	330,870		$	93.70

There were 99,464 market-based units granted with a weighted-average grant-date fair value of $144.32 per share during the year ended December 31, 2008. We did not grant market-based units during the year ended December 31, 2007. No market-based units vested in the years ended December 31, 2008 and 2007.

ESPP—Through December 31, 2008, we offered an ESPP under which certain full-time employees could choose to have between two and 20 percent of their annual base earnings withheld to purchase up to $21,150 of our shares each year. The purchase price of the shares was 85 percent of the lower of the beginning-of-year or end-of-year market price of our shares. At December 31, 2008, 577,537 shares were available for issuance. As of January 1, 2009, we discontinued offering the ESPP.

Note 18—Stock Warrants

We assumed stock warrants in connection with our merger with R&B Falcon Corporation in January 2001. Under the amended warrant agreement, each warrant holder could elect to receive 12.243 shares and $578.025 in cash upon exercise at a price of $332.50. During the year ended December 31, 2008, Transocean Inc. issued 363,492 of its ordinary shares and paid $7 million, net of a $10 million aggregate exercise price. At December 31, 2008, the cash payment feature, reclassified from permanent equity, represented an aggregate obligation of $31 million, recorded in other current liabilities.

During the year ended December 31, 2009, we issued 651,570 shares and paid $13 million, net of an $18 million aggregate exercise price, upon the exercise of 53,220 warrants. No warrants remained outstanding and the cash payment feature had been fully satisfied as of the stated expiration date of May 1, 2009.

Note 19—Share Repurchase Program

In May 2006, Transocean Inc.’s board of directors authorized an increase in the overall amount of ordinary shares that could be repurchased under its share repurchase program to $4.0 billion from $2.0 billion, which was previously authorized and announced in October 2005. The repurchase program did not have an established expiration date and could be suspended or discontinued at any time. Under the program, repurchased shares were constructively retired and returned to unissued status. During 2007, Transocean Inc. repurchased and retired 5.2 million aggregate ordinary shares for $400 million at an average purchase price of $77.39 per share. There were no repurchases under the repurchase program during 2009 and 2008.

Total consideration paid to repurchase the shares was recorded in shareholders’ equity as a reduction in shares and additional paid-in capital. Such consideration was funded with existing cash balances and borrowings under a former revolving credit facility. As a result of the Redomestication, the Transocean Inc. share repurchase program was terminated.

In May 2009, at our annual general meeting, our shareholders approved and authorized our board of directors, at its discretion, to repurchase an amount of our shares for cancellation with an aggregate purchase price of up to 3.5 billion Swiss francs, which is equivalent to approximately U.S. $3.2 billion at an exchange rate as of the close of trading on February 19, 2010 of U.S. $1.00 to 1.08 Swiss francs. See Note 26—Subsequent Events.

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Index

TRANSOCEAN LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

Note 20—Other Comprehensive Income

The allocation of other comprehensive income (loss) attributable to controlling interest and to non-controlling interest was as follows (in millions):

		Years ended December 31,
		2009							2008								2007
		Controlling interest			Non-controlling interest		Total		Controlling interest			Non-controlling interest		Total			Controlling interest			Non-controlling interest		Total
Unrecognized components of net periodic benefit costs	$	37		$	—	$	37	$	(388	)	$	—	$	(388	)	$	(27	)	$	—	$	(27	)
Recognized components of net periodic benefit costs		24			—		24		5			—		5			13			—		13
Unrealized gain (loss) on derivative instruments		(1	)		5		4		(1	)		—		(1	)		—			—		—
Other, net		1			—		1		(3	)		—		(3	)		—			—		—

Other comprehensive income (loss) before income taxes		61			5		66		(387	)		—		(387	)		(14	)		—		(14	)
Income taxes related to other comprehensive income		24			—		24		9			—		9			2			—		2
Other comprehensive income (loss), net of tax	$	85		$	5	$	90	$	(378	)	$	—	$	(378	)	$	(12	)	$	—	$	(12	)

The components of accumulated other comprehensive income (loss), net of tax, were as follows (in millions):

	December 31, 2009					December 31, 2008					December 31, 2007
		Controlling interest			Non-controlling interest		Controlling interest			Non-controlling interest		Controlling interest			Non-controlling interest
Unrecognized components of net period benefit costs (a)	$	(334	)	$	—	$	(419	)	$	—	$	(45	)	$	—
Unrecognized gain on derivative investments		1			5		2			—		3			—
Unrealized loss on securities held for sale		(2	)		—		(3	)		—		—			—
Accumulated other comprehensive income (loss)	$	(335	)	$	5	$	(420	)	$	—	$	(42	)	$	—

______________________________

(a)	Amounts are net of income tax effect of $45 million, $21 million and $12 million for December 31, 2009, 2008 and 2007, respectively.

Note 21—Supplemental Balance Sheet Information

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

	December 31,
	2009		2008
Other current liabilities
Accrued payroll and employee benefits	$	308	$	363
Deferred revenue		139		112
Accrued taxes, other than income		80		112
Accrued interest		83		100
Stock warrant consideration payable		—		31
Unearned income		23		18
Other		97		70
Total other current liabilities	$	730	$	806

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

	December 31,
	2009		2008
Other long-term liabilities
Drilling contract intangibles	$	268	$	593
Accrued pension liabilities		453		480
Long-term income taxes payable		594		460
Accrued retiree life insurance and medical benefits		51		61
Deferred revenue		214		54
Other		104		107
Total other long-term liabilities	$	1,684	$	1,755

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Index

TRANSOCEAN LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

Note 22—Supplemental Cash Flow Information

We include investments in highly liquid debt instruments with an original maturity of three months or less in cash and cash equivalents. In September 2008, The Reserve announced that certain funds, including The Reserve Primary Fund and The Reserve International Liquidity Fund Ltd., had lost the ability to maintain a net asset value of $1.00 per share due to losses in connection with the bankruptcy of Lehman Brothers Holdings, Inc. (“Lehman Holdings”). According to its public disclosures, The Reserve stopped processing redemption requests in order to develop an orderly plan of liquidation that would protect all of the funds’ shareholders. Based on statements made by the funds, we recognized an impairment loss of $16 million, recorded in other, net in the quarter ended September 30, 2008, associated with our proportional interest in the debt instruments of Lehman Holdings held by the funds. During the year ended December 31, 2009, we received distributions of $10 million and $286 million from The Reserve Primary Fund and the Reserve International Liquidity Fund Ltd., respectively. As of December 31, 2009, the carrying values of our investments in The Reserve Primary Fund and The Reserve International Liquidity Fund Ltd. were $5 million and $33 million, respectively. The timing of our ability to access the remaining funds is uncertain.

Shortly following the Lehman Holdings bankruptcy, the funds announced that all redemption requests received by the funds prior to a cut-off time on the day following the bankruptcy of Lehman Holdings would be redeemed at a net asset value of $1.00 per share. Some investors in the funds that submitted redemption requests prior to this cut-off time are seeking redemption of their interests at this amount, which would reduce funds available for distribution to other investors, including us. We have filed a motion to intervene in pending litigation against The Reserve International Liquidity Fund Ltd. and related parties seeking a declaration that we are entitled to a pro rata distribution with respect to the redemption of our remaining interest in the fund, damages and other relief. Potential rulings or decisions by courts or regulators relating to this litigation or otherwise relating to the funds may impact further distributions by the funds and could result in additional losses.

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

	Years ended December 31,
	2009			2008			2007
Changes in operating assets and liabilities
Decrease (increase) in accounts receivable	$	504		$	(501	)	$	(274	)
Increase in other current assets		(50	)		(118	)		(43	)
Increase in other assets		(30	)		(8	)		(4	)
Increase (decrease) in accounts payable and other current liabilities		(60	)		75			73
Increase (decrease) in other long-term liabilities		(7	)		(43	)		8
Change in income taxes receivable / payable, net		77			274			68
	$	434		$	(321	)	$	(172	)

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

	Years ended December 31,
	2009		2008		2007
Certain cash operating activities
Cash payments for interest	$	683	$	545	$	208
Cash payments for income taxes		663		461		225

Non-cash investing and financing activities
Capital expenditures, accrued at end of period (a)	$	139	$	268	$	233
Asset capitalized under capital leases (b)		716		—		—
Business combination (c)		—		—		12,386
Joint ventures and other investments (d)		—		—		238

______________________________

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

(b)	On August 4, 2009, we accepted delivery of Petrobras 10000 and recorded non-cash additions of $716 million to property and equipment, net along with a corresponding increase to long-term debt. See Note 11—Debt and Note 16—Commitments and Contingencies.

(c)	In connection with the Merger, Transocean Inc. issued $12.4 billion of its ordinary shares to GlobalSantaFe shareholders, acquired $20.6 billion in assets and assumed $575 million of debt and $2.5 billion of other liabilities. See Note 5—Business Combination.

(d)	In connection with our investment in and consolidation of TPDI, we recorded additions to property and equipment of $457 million, of which $238 million was in exchange for a note payable to Pacific Drilling. See Note 4—Variable Interest Entities and Note 11—Debt.

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Index

TRANSOCEAN LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

Note 23—Segments, Geographical Analysis and Major Customers

We have established two reportable segments: (1) contract drilling services and (2) other operations. The drilling management services and oil and gas properties businesses do not meet the quantitative thresholds for determining reportable segments and are combined for reporting purposes in the other operations segment.

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

	Years ended December 31,
	2009		2008		2007
Operating revenues
U.S.	$	2,239	$	2,578	$	1,259
U.K.		1,563		2,012		848
India		1,084		890		761
Other countries (a)		6,670		7,194		3,509
Total operating revenues	$	11,556	$	12,674	$	6,377

	December 31,
	2009		2008
Long-lived assets			(As adjusted)
U.S.	$	6,203	$	4,128
South Korea		3,128		3,218
Other countries (a)		13,687		13,515
Total long-lived assets	$	23,018	$	20,861

______________________________

(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 Switzerland, we do not conduct any operations and do not have operating revenues in Switzerland. At December 31, 2009, we had $1 million of long-lived assets in Switzerland.

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

For the year ended December 31, 2009, BP accounted for approximately 12 percent of our operating revenues. For the year ended December 31, 2008, BP accounted for approximately 11 percent of our operating revenues. For the year ended December 31, 2007, Chevron, Shell and BP accounted for approximately 12 percent, 11 percent and 10 percent, respectively, of our operating revenues. The loss of these or other significant customers could have a material adverse effect on our results of operations.

Note 24—Related Party Transactions

At December 31, 2009, TPDI had outstanding promissory notes in the aggregate amount of $296 million, of which $148 million is due to Pacific Drilling and is included in long-term debt on our consolidated balance sheet. At December 31, 2008, TPDI had outstanding promissory notes in the aggregate amount of $222 million, of which $111 million was due to Pacific Drilling and was included in long-term debt on our consolidated balance sheet.

Angco Cayman Limited—We hold a 65 percent interest in ADDCL, a Cayman Islands joint venture company formed to construct, own and operate an ultra-deepwater drillship to be named Discoverer Luanda. Angco Cayman Limited, a Cayman Islands company, holds the remaining 35 percent interest in ADDCL. Beginning on the fifth anniversary of the first well commencement date, Angco Cayman Limited will have the right to exchange its interest in the joint venture for cash at a purchase price based on an appraisal of the fair value of the drillship, subject to various adjustments.

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Index

TRANSOCEAN LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

Overseas Drilling Limited—We own a 50 percent interest in ODL, an unconsolidated Cayman Islands joint venture company. Siem Offshore Invest AS owns the other 50 percent interest in ODL. ODL owns the Joides Resolution, for which we provide certain operational and management services. We earned $2 million for these services in the year ended December 31, 2009.

In December 2009, we amended our existing loan agreement with ODL, increasing the maximum borrowing amount from $8 million to $10 million. ODL may demand repayment of the borrowings at any time upon five business days prior written notice, and any amounts due to us from ODL may be offset against the borrowings at the time of repayment. As of December 31, 2009, $10 million was outstanding under this loan agreement.

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)
2009
Operating revenues	$	3,118	$	2,882	$	2,823	$	2,733
Operating income (a)		1,319		1,121		957		1,003
Net income attributable to controlling interest (a)		942		806		710		723
Earnings per share
Basic	$	2.94	$	2.50	$	2.20	$	2.24
Diluted	$	2.93	$	2.49	$	2.19	$	2.24
Weighted-average shares outstanding
Basic		319		320		321		321
Diluted		320		321		322		322

2008 (As adjusted)
Operating revenues	$	3,110	$	3,102	$	3,192	$	3,270
Operating income (b)		1,540		1,350		1,383		1,084
Net income attributable to controlling interest (b)		1,149		1,065		1,063		754
Earnings per share
Basic	$	3.62	$	3.34	$	3.32	$	2.36
Diluted	$	3.58	$	3.31	$	3.30	$	2.35
Weighted-average shares outstanding
Basic		317		318		319		319
Diluted		321		321		321		320

______________________________

(a)	First quarter included loss on impairment of $221 million. Second quarter included loss on impairment of $67 million. Third quarter included loss on impairment of $46 million and settlement charges related to litigation matters of $132 million. See Note 6—Impairments.

(b)	Fourth quarter included a loss on impairment of $320 million. See Note 6—Impairments.

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Index

TRANSOCEAN LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

Note 26—Subsequent Events (Unaudited)

Dispositions—In January 2010, we completed the sale of two Midwater Floaters, GSF Arctic II and GSF Arctic IV, in connection with our previously announced undertakings to the Office of Fair Trading in the U.K. In connection with the sale, we received net cash proceeds of $40 million and non-cash proceeds in the form of two notes receivable, in the aggregate amount of $165 million. We continue to operate GSF Arctic IV under a short-term bareboat charter with the new owner of the vessel through August 2010.

Share repurchase program—In May 2009, at our annual general meeting, our shareholders approved and authorized our board of directors, at its discretion, to repurchase an amount of our shares for cancellation with an aggregate purchase price of up to 3.5 billion Swiss francs, which is equivalent to approximately U.S. $3.2 billion at an exchange rate as of the close of trading on February 19, 2010 of U.S. $1.00 to 1.08 Swiss francs. On February 12, 2010, our board of directors authorized our management to implement the share repurchase program, as approved by our shareholders at our annual general meeting in May 2009.

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Index

ITEM 9.

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

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

ITEM 9A.

Controls and Procedures

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, as defined in Exchange Act Rules 13a-15(e) and 15d-15(e), were effective as of December 31, 2009 and provide reasonable assurance that information required to be disclosed in our reports filed or submitted under the Exchange Act is (1) accumulated and communicated to our management, including our Chief Executive Officer and our Chief Financial Officer, to allow timely decisions regarding required disclosure and (2) recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms.

There were no changes in these internal controls during the quarter ended December 31, 2009 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” included in Item 8 of this Annual Report.

ITEM 9B.

Other Information

None

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Index

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 2010 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, 2009. 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.”

PART IV

ITEM 15.

Exhibits and Financial Statement Schedules

(a) Index to Financial Statements, Financial Statement Schedules and Exhibits

(1) Financial Statements

Included in Part II of this report:		Page
Management’s Report on Internal Control Over Financial Reporting		56
Report of Independent Registered Public Accounting Firm		57
Consolidated Statements of Operations		59
Consolidated Statements of Comprehensive Income		60
Consolidated Balance Sheets		61
Consolidated Statements of Equity		62
Consolidated Statements of Cash Flows		63
Notes to Consolidated Financial Statements		64

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

(2) Financial Statement Schedules

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Index

Transocean Ltd. and Subsidiaries

Schedule II - Valuation and Qualifying Accounts

(In millions)

			Additions
	Balance at beginning of period		Charge to cost and expenses		Charge to other accounts -describe			Deductions -describe			Balance at end of period

Year ended December 31, 2007
Reserves and allowances deducted from asset accounts:
Allowance for doubtful accounts receivable	$	26	$	57	$	—		$	33	(a)	$	50
Allowance for obsolete materials and supplies		19		4		—			1	(b)		22
Valuation allowance on deferred tax assets		59		—		28	(c)		58	(d)		29

Year ended December 31, 2008
Reserves and allowances deducted from asset accounts:
Allowance for doubtful accounts receivable	$	50	$	95	$	—		$	31	(a)	$	114
Allowance for obsolete materials and supplies		22		27		—			—			49
Valuation allowance on deferred tax assets		29		4		—			10	(c)		23

Year ended December 31, 2009
Reserves and allowances deducted from asset accounts:
Allowance for doubtful accounts receivable	$	114	$	27	$	—		$	76	(a)	$	65
Allowance for obsolete materials and supplies		49		17		—			—			66
Valuation allowance on deferred tax assets		23		46		—			—			69

______________________________

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

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

(c)	Amount represents the valuation allowances established in connection with the tax assets acquired and the liabilities assumed in connection with the merger with GlobalSantaFe Corporation.

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

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

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Index

(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 Sedco Forex 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 (Registration No. 333-46374) filed by Transocean Sedco Forex Inc. 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, 2000 included in a 424(b)(3) prospectus (Registration No. 333-46374) filed by Transocean Sedco Forex Inc. 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, 2000 included in a 424(b)(3) prospectus (Registration No. 333-46374) filed by Transocean Sedco Forex Inc. on November 1, 2000)

2.4

Agreement and Plan of Merger, dated as of July 21, 2007, among Transocean Inc., GlobalSantaFe Corporation and Transocean Worldwide Inc. (incorporated by reference to Exhibit 2.1 to Transocean Inc.’s Current Report on Form 8-K (Commission File No. 333-75899) filed on July 23, 2007)

2.5

Agreement and Plan of Merger, dated as of October 9, 2008, among Transocean Inc., Transocean Ltd. and Transocean Cayman Ltd. (incorporated by reference to Exhibit 2.1 to Transocean Inc.’s Current Report on Form 8-K (Commission File No. 333-75899) filed on October 10, 2008)

2.6

Amendment No. 1 to Agreement and Plan of Merger, dated as of October 31, 2008, among Transocean Inc., Transocean Ltd. and Transocean Cayman Ltd. (incorporated by reference to Exhibit 2.2 to Transocean Inc.’s Current Report on Form 8-K (Commission File No. 333-75899) filed on November 3, 2008)

3.1

Articles of Association of Transocean Ltd. (incorporated by reference to Exhibit 3.1 to Transocean Ltd.’s Current Report on Form 8-K filed on December 19, 2008)

3.2

Organizational Regulations of Transocean Ltd. (incorporated by reference to Annex G to Transocean Inc.’s Proxy Statement (Commission File No. 333-75899) filed on November 3, 2008)

4.1

Indenture dated as of April 15, 1997 between Transocean Offshore Inc. and Texas Commerce Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to Transocean Offshore Inc.’s Current Report on Form 8-K (Commission File No. 001-07746) filed on April 30, 1997)

4.2

First Supplemental Indenture dated as of April 15, 1997 between Transocean Offshore Inc. 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 Transocean Offshore Inc.’s Current Report on Form 8-K (Commission File No. 001-07746) filed on April 30, 1997)

4.3

Second Supplemental Indenture dated as of May 14, 1999 between Transocean Offshore (Texas) Inc., Transocean Offshore Inc. and Chase Bank of Texas, National Association, as trustee (incorporated by reference to Exhibit 4.5 to Transocean Offshore Inc.’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 Transocean Sedco Forex Inc. and Chase Bank of Texas, National Association, as trustee (incorporated by reference to Exhibit 4.1 to Transocean Sedco Forex Inc.’s Current Report on Form 8-K (Commission File No. 333-75899) filed on May 24, 2000)

4.5

Fourth Supplemental Indenture dated as of May 11, 2001 between Transocean Sedco Forex Inc. and The Chase Manhattan Bank (incorporated by reference to Exhibit 4.3 to Transocean Sedco Forex Inc.’s Quarterly Report on Form 10-Q (Commission File No. 333-75899) for the quarter ended March 31, 2001)

4.6

Fifth Supplemental Indenture, dated as of December 18, 2008, among Transocean Ltd., Transocean Inc. and The Bank of New York Mellon Trust Company, N.A., as trustee (incorporated by reference to Exhibit 4.4 to Transocean Ltd.’s Current Report on Form 8-K filed on December 19, 2008)

4.7

Form of 7.45% Notes due April 15, 2027 (incorporated by reference to Exhibit 4.3 to Transocean Offshore Inc.’s Current Report on Form 8-K (Commission File No. 001-07746) filed on April 30, 1997)

4.8

Form of 8.00% Debentures due April 15, 2027 (incorporated by reference to Exhibit 4.4 to Transocean Offshore Inc.’s Current Report on Form 8-K (Commission File No. 001-07746) filed on April 30, 1997)

4.9

Form of 6.625% Note due April 15, 2011 (incorporated by reference to Exhibit 4.3 to Transocean Sedco Forex Inc.’s Current Report on Form 8-K (Commission File No. 333-75899) filed on April 9, 2001)

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Index

4.10

Form of 7.5% Note due April 15, 2031 (incorporated by reference to Exhibit 4.3 to Transocean Sedco Forex Inc.’s Current Report on Form 8-K (Commission File No. 333-75899) filed on April 9, 2001)

4.11

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 Transocean Sedco Forex Inc.’s Annual Report on Form 10-K (Commission File No. 333-75899) for the fiscal year ended December 31, 2001)

4.12

Officers’ Certificate establishing the terms of the 7.375% Notes due 2018 (incorporated by reference to Exhibit 4.14 to Transocean Sedco Forex Inc.’s Annual Report on Form 10-K (Commission File No. 333-75899) for the fiscal year ended December 31, 2001)

4.13

Warrant Agreement, including form of Warrant, dated April 22, 1999 between R&B Falcon Corporation 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)

4.14

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 Transocean Sedco Forex Inc.’s Annual Report on Form 10-K (Commission File No. 333-75899) for the year ended December 31, 2000)

4.15

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 Transocean Inc.’s Post-Effective Amendment No. 3 on Form S-3 to Form S-4 filed on November 18, 2005)

4.16

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

4.17

Supplement to Warrant Agreement, dated as of December 18, 2008, by and among Transocean Ltd., Transocean Inc. and The Bank of New York (incorporated by reference to Exhibit 4.1 to Transocean Ltd.’s Current Report on Form 8-K filed on December 19, 2008)

4.18

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

4.19

Supplement to Registration Rights Agreement dated January 31, 2001 between Transocean Sedco Forex Inc. and R&B Falcon Corporation (incorporated by reference to Exhibit 4.30 to Transocean Sedco Forex Inc.’s Annual Report on Form 10-K (Commission File No. 333-75899) for the year ended December 31, 2000)

4.20

Supplement to Warrant Registration Rights Agreement, dated as of December 18, 2008, by Transocean Ltd. and Transocean Inc. (incorporated by reference to Exhibit 4.2 to Transocean Ltd.’s Current Report on Form 8-K filed on December 19, 2008)

4.21

Five-Year Revolving Credit Agreement dated November 27, 2007 among Transocean Inc., as borrower, the lenders from time to time parties thereto, JPMorgan Chase Bank, N.A., as administrative agent for the lenders and as issuing bank of letters of credit, Citibank, N.A., as syndication agent for the lenders and as an issuing bank of letters of credit, Calyon Corporate and Investment Bank, as co-syndication agent, and Credit Suisse, Cayman Islands Branch and The Bank of Tokyo-Mitsubishi UFJ, Ltd., as co-documentation agents for the lenders (incorporated by reference to Exhibit 4.1 to Transocean Inc.’s Current Report on Form 8-K (Commission File No. 333-75899) filed on December 3, 2007)

4.22

Agreement for First Amendment of Five-Year Revolving Credit Agreement dated as of November 25, 2008 among Transocean Inc., as borrower, the lenders parties thereto and JPMorgan Chase Bank, N.A., as administrative agent for the lenders (incorporated by reference to Exhibit 4.2 to Transocean Inc.’s Current Report on Form 8-K (Commission File No. 333-75899) filed on November 26, 2008)

4.23

Guaranty Agreement, dated as of December 19, 2008, among Transocean Ltd., Transocean Inc. and JPMorgan Chase Bank, N.A., as administrative agent under the Five-Year Revolving Credit Agreement (incorporated by reference to Exhibit 4.9 to Transocean Ltd.’s Current Report on Form 8-K filed on December 19, 2008)

4.24

Indenture dated as of February 1, 2003, between GlobalSantaFe Corporation and Wilmington Trust Company, as trustee, relating to debt securities of GlobalSantaFe Corporation (incorporated by reference to Exhibit 4.9 to GlobalSantaFe Corporation’s Annual Report on Form 10-K (Commission File No. 001-14634) for the year ended December 31, 2002)

4.25

Supplemental Indenture dated November 27, 2007 among Transocean Worldwide Inc., GlobalSantaFe Corporation and Wilmington Trust Company, as trustee, to the Indenture dated as of February 1, 2003 between GlobalSantaFe Corporation and Wilmington Trust Company (incorporated by reference to Exhibit 4.4 to Transocean Inc.’s Current Report on Form 8-K (Commission File No. 333-75899) filed on December 3, 2007)

4.26

Form of 7% Note Due 2028 (incorporated by reference to Exhibit 4.2 of Global Marine Inc.’s Current Report on Form 8-K (Commission File No. 1-5471) filed on May 22, 1998)

4.27

Terms of 7% Note Due 2028 (incorporated by reference to Exhibit 4.1 of Global Marine Inc.’s Current Report on Form 8-K (Commission File No. 1-5471) filed on May 22, 1998)

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Index

4.28

Indenture dated as of September 1, 1997, between Global Marine Inc. and Wilmington Trust Company, as Trustee, relating to Debt Securities of Global Marine Inc. (incorporated by reference to Exhibit 4.1 of Global Marine Inc.’s Registration Statement on Form S-4 (No. 333-39033) filed with the Commission on October 30, 1997); First Supplemental Indenture dated as of June 23, 2000 (incorporated by reference to Exhibit 4.2 of Global Marine Inc.’s Quarterly Report on Form 10-Q (Commission File No. 1-5471) for the quarter ended June 30, 2000); Second Supplemental Indenture dated as of November 20, 2001 (incorporated by reference to Exhibit 4.2 to GlobalSantaFe Corporation’s Annual Report on Form 10-K (Commission File No. 001-14634) for the year ended December 31, 2004)

4.29

Form of 5% Note due 2013 (incorporated by reference to Exhibit 4.10 to GlobalSantaFe Corporation’s Annual Report on Form 10-K (Commission File No. 001-14634) for the year ended December 31, 2002)

4.30

Terms of 5% Note due 2013 (incorporated by reference to Exhibit 4.11 to GlobalSantaFe Corporation’s Annual Report on Form 10-K (Commission File No. 001-14634) for the year ended December 31, 2002)

4.31

364-Day Revolving Credit Agreement dated December 3, 2007 among Transocean Inc. and the lenders from time to time parties thereto, JPMorgan Chase Bank, N.A., as administrative agent for the lenders, Citibank, N.A., as syndication agent for the lenders, Calyon New York Branch, as co-syndication agent, and Credit Suisse, Cayman Islands Branch and The Bank of Tokyo-Mitsubishi UFJ, Ltd., as co-documentation agents for the lenders (incorporated by reference to Exhibit 4.1 to Transocean Inc.’s Current Report on Form 8-K (Commission File No. 333-75899) filed on December 5, 2007)

4.32

364-Day Revolving Credit Agreement dated as of November 25, 2008 among Transocean Inc., the lenders parties thereto, JPMorgan Chase Bank, N.A., as administrative agent for the lenders, Citibank, N.A. and Calyon New York Branch, as co-syndication agents for the lenders, and Wells Fargo Bank, N.A., as documentation agent for the lenders (incorporated by reference to Exhibit 4.1 to Transocean Inc.’s Current Report on Form 8-K (Commission File No. 333-75899) filed on November 26, 2008)

4.33

Guaranty Agreement, dated as of December 19, 2008, among Transocean Ltd., Transocean Inc. and JPMorgan Chase Bank, N.A., as administrative agent under the 364-Day Revolving Credit Agreement (incorporated by reference to Exhibit 4.8 to Transocean Ltd.’s Current Report on Form 8-K (Commission File No. 333-75899) filed on December 19, 2008)

4.34

Senior Indenture, dated as of December 11, 2007, between Transocean Inc. and Wells Fargo Bank, National Association (incorporated by reference to Exhibit 4.36 to Transocean Inc.’s Annual Report on Form 10-K (Commission File No. 333-75899) for the year ended December 31, 2007)

4.35

First Supplemental Indenture, dated as of December 11, 2007, between Transocean Inc. and Wells Fargo Bank, National Association (incorporated by reference to Exhibit 4.37 to Transocean Inc.’s Annual Report on Form 10-K (Commission File No. 333-75899) for the year ended December 31, 2007)

4.36

Second Supplemental Indenture, dated as of December 11, 2007, between Transocean Inc. and Wells Fargo Bank, National Association (incorporated by reference to Exhibit 4.38 to Transocean Inc.’s Annual Report on Form 10-K (Commission File No. 333-75899) for the year ended December 31, 2007)

4.37

Third Supplemental Indenture, dated as of December 18, 2008, among Transocean Ltd., Transocean Inc. and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.3 to Transocean Ltd.’s Current Report on Form 8-K (Commission File No. 333-75899) filed on December 19, 2008)

4.38

Term Credit Agreement dated as of March 13, 2008 among Transocean Inc., the lenders parties thereto and Citibank, N.A., as Administrative Agent, Calyon New York Branch and JP Morgan Chase Bank, N.A., as Co-Syndication Agents, The Bank of Tokyo-Mitsubishi UFJ, Ltd. and Fortis Bank SA/NV, New York Branch, as Co-Documentation Agents, and Citigroup Global Markets, Inc., Calyon New York Branch and J.P. Morgan Securities Inc., as Joint Lead Arrangers and Bookrunners (incorporated by reference to Exhibit 4.1 to Transocean Inc.’s Current Report on Form 8-K (Commission File No. 333-75899) filed on March 18, 2008)

4.39

Agreement for First Amendment of Term Credit Agreement dated as of November 25, 2008 among Transocean Inc., the lenders parties thereto and Citibank, N.A., as administrative agent for the lenders (incorporated by reference to Exhibit 4.3 to Transocean Inc.’s Current Report on Form 8-K (Commission File No. 333-75899) filed on November 26, 2008)

4.40

Guaranty Agreement, dated as of December 19, 2008, among Transocean Ltd., Transocean Inc. and Citibank, N.A., as administrative agent under the Term Credit Agreement (incorporated by reference to Exhibit 4.10 to Transocean Ltd.’s Current Report on Form 8-K (Commission File No. 333-75899) filed on December 19, 2008)

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 Sonat Offshore Drilling Inc.’s Form 10-Q (Commission File No. 001-07746) for the quarter ended June 30, 1993)

10.2

Amended and Restated Employee Stock Purchase Plan of Transocean Inc. (incorporated by reference to Exhibit 10.1 to Transocean Inc.’s Current Report on Form 8-K (Commission File No. 333-75899) filed on May 16, 2005)

10.3

Long-Term Incentive Plan of Transocean Ltd. (as amended and restated as of February 12, 2009) (incorporated by reference to Exhibit 10.5 to Transocean Ltd.’s Annual Report on Form 10-K (Commission File No. 000-53533) for the year ended December 31, 2008)

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Index

10.4

Deferred Compensation Plan of Transocean Offshore Inc., as amended and restated effective January 1, 2000 (incorporated by reference to Exhibit 10.10 to Transocean Sedco Forex Inc.’s Annual Report on Form 10-K (Commission File No. 333-75899) for the year ended December 31, 1999)

10.5

GlobalSantaFe Corporation Key Employee Deferred Compensation Plan effective January 1, 2001; and Amendment to GlobalSantaFe Corporation Key Employee Deferred Compensation Plan effective November 20, 2001 (incorporated by reference to Exhibit 10.33 to the GlobalSantaFe Corporation Annual Report on Form 10-K for the year ended December 31, 2004)

10.6

Amendment to Transocean Inc. Deferred Compensation Plan (incorporate by reference to Exhibit 10.1 to Transocean Inc.’s Current Report on Form 8-K (Commission File No. 333-75899) filed on December 29, 2005)

10.7

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

10.8

1997 Long-Term Incentive Plan of Reading & Bates Corporation (incorporated by reference to Exhibit 99.A to Reading & Bates’ Proxy Statement (Commission File No. 001-05587) dated March 28, 1997)

10.9

1998 Employee Long-Term Incentive Plan of R&B Falcon Corporation (incorporated by reference to Exhibit 99.A to R&B Falcon Corporation’s Proxy Statement (Commission File No. 001-13729) dated April 23, 1998)

10.10

1998 Director Long-Term Incentive Plan of R&B Falcon Corporation (incorporated by reference to Exhibit 99.B to R&B Falcon Corporation’s Proxy Statement (Commission File No. 001-13729) dated April 23, 1998)

10.11

1999 Employee Long-Term Incentive Plan of R&B Falcon Corporation (incorporated by reference to Exhibit 99.A to R&B Falcon Corporation’s Proxy Statement (Commission File No. 001-13729) dated April 13, 1999)

10.12

1999 Director Long-Term Incentive Plan of R&B Falcon Corporation (incorporated by reference to Exhibit 99.B to R&B Falcon Corporation’s Proxy Statement (Commission File No. 001-13729) dated April 13, 1999)

10.13

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 Transocean Inc.’s Current Report on Form 8-K (Commission File No. 333-75899) filed on March 3, 2004)

10.14

Tax Sharing Agreement dated February 4, 2004 between Transocean Holdings Inc. and TODCO (incorporated by reference to Exhibit 99.3 to Transocean Inc.’s Current Report on Form 8-K (Commission File No. 333-75899) filed on March 3, 2004)

10.15

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 Transocean Inc.’s Current Report on Form 8-K (Commission File No. 333-75899) filed on November 30, 2006)

10.16

Form of 2004 Performance-Based Nonqualified Share Option Award Letter (incorporated by reference to Exhibit 10.2 to Transocean Inc.’s Current Report on Form 8-K (Commission File No. 333-75899) filed on February 15, 2005)

10.17

Form of 2004 Director Deferred Unit Award (incorporated by reference to Exhibit 10.5 to Transocean Inc.’s Current Report on Form 8-K (Commission File No. 333-75899) filed on February 15, 2005)

10.18

Form of 2008 Director Deferred Unit Award (incorporated by reference to Exhibit 10.20 to Transocean Ltd.’s Annual Report on Form 10-K (Commission File No. 000-53533) for the year ended December 31, 2008)

† *

10.19

Form of 2009 Director Deferred Unit Award

10.20

Performance Award and Cash Bonus Plan of Transocean Ltd. (incorporated by reference to Exhibit 10.21 to Transocean Ltd.’s Annual Report on Form 10-K (Commission File No. 000-53533) for the year ended December 31, 2008)

† *

10.21

Description of Base Salaries of Named Executive Officers

10.22

Executive Change of Control Severance Benefit (incorporated by reference to Exhibit 10.1 to Transocean Inc.’s Current Report on Form 8-K (Commission File No. 333-75899) filed on July 19, 2005)

10.23

Terms of July 2007 Employee Restricted Stock Awards (incorporated by reference to Exhibit 10.2 to Transocean Inc.’s Form 10-Q (Commission File No. 333-75899) for the quarter ended June 30, 2007)

10.24

Terms of July 2007 Employee Deferred Unit Awards (incorporated by reference to Exhibit 10.3 to Transocean Inc.’s Form 10-Q (Commission File No. 333-75899) for the quarter ended June 30, 2007)

10.25

Terms and Conditions of the July 2008 Employee Contingent Deferred Unit Award (incorporated by reference to Exhibit 10.2 to Transocean Inc.’s Form 10-Q (Commission File No. 333-75899) for the quarter ended June 30, 2008)

10.26

Terms and Conditions of the July 2008 Nonqualified Share Option Award (incorporated by reference to Exhibit 10.2 to Transocean Inc.’s Form 10-Q (Commission File No. 333-75899) for the quarter ended June 30, 2008)

10.27

Terms and Conditions of the February 2009 Employee Deferred Unit Award (incorporated by reference to Exhibit 10.28 to Transocean Ltd.’s Annual Report on Form 10-K (Commission File No. 000-53533) for the year ended December 31, 2008)

10.28

Terms and Conditions of the February 2009 Employee Contingent Deferred Unit Award (incorporated by reference to Exhibit 10.29 to Transocean Ltd.’s Annual Report on Form 10-K (Commission File No. 000-53533) for the year ended December 31, 2008)

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Index

10.29

Terms and Conditions of the February 2009 Nonqualified Share Option Award (incorporated by reference to Exhibit 10.30 to Transocean Ltd.’s Annual Report on Form 10-K (Commission File No. 000-53533) for the year ended December 31, 2008)

10.30

Put Option and Registration Rights Agreement, dated as of October 18, 2007, among Pacific Drilling Limited, Transocean Pacific Drilling Inc., Transocean Inc. and Transocean Offshore International Ventures Limited (incorporated by reference to Exhibit 10.1 to Transocean Inc.’s Current Report on Form 8-K (Commission File No. 333-75899) filed on October 24, 2007)

10.31

Form of Novation Agreement dated as of November 27, 2007 by and among GlobalSantaFe Corporation, Transocean Offshore Deepwater Drilling Inc. and certain executives (incorporated by reference to Exhibit 10.1 to Transocean Inc.’s Current Report on Form 8-K (Commission File No. 333-75899) filed on December 3, 2007)

10.32

Form of Severance Agreement with GlobalSantaFe Corporation Executive Officers (incorporated by reference to Exhibit 10.1 to GlobalSantaFe Corporation’s Current Report on Form 8-K/A (Commission File No. 001-14634) filed on July 26, 2005)

10.33

Transocean Special Transition Severance Plan for Shore-Based Employees (incorporated by reference to Exhibit 10.3 to Transocean Inc.’s Current Report on Form 8-K (Commission File No. 333-75899) filed on December 3, 2007)

10.34

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

10.35

1997 Long-Term Incentive Plan (incorporated by reference to GlobalSantaFe Corporation’s Registration Statement on Form S-8 (No. 333-7070) filed June 13, 1997); Amendment to 1997 Long Term Incentive Plan (incorporated by reference to GlobalSantaFe Corporation’s Annual Report on Form 20-F (Commission File No. 001-14634) for the calendar year ended December 31, 1998); Amendment to 1997 Long Term Incentive Plan dated December 1, 1999 (incorporated by reference to GlobalSantaFe Corporation’s Annual Report on Form 20-F (Commission File No. 001-14634) for the calendar year ended December 31, 1999)

10.36

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

10.37

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

10.38

GlobalSantaFe Corporation 2001 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.1 to GlobalSantaFe Corporation’s Quarterly Report on Form 10-Q (Commission File No. 001-14634) for the quarter ended June 30, 2001)

10.39

GlobalSantaFe 2003 Long-Term Incentive Plan (as Amended and Restated Effective June 7, 2005) (incorporated by reference to Exhibit 10.4 to GlobalSantaFe Corporation’s Quarterly Report on Form 10-Q (Commission File No. 001-14634) for the quarter ended June 30, 2005)

10.40

Transocean Ltd. Pension Equalization Plan, as amended and restated, effective January 1, 2009 (incorporated by reference to Exhibit 10.41 to Transocean Ltd.’s Annual Report on Form 10-K (Commission File No. 000-53533) for the year ended December 31, 2008)

10.41

Transocean U.S. Supplemental Retirement Benefit Plan, as amended and restated, effective as of November 27, 2007 (incorporated by reference to Exhibit 10.11 to Transocean Inc.’s Current Report on Form 8-K (Commission File No. 333-75899) filed on December 3, 2007)

10.42

GlobalSantaFe Corporation Supplemental Executive Retirement Plan (incorporated by reference to Exhibit 10.1 to the GlobalSantaFe Corporation Quarterly Report on Form 10-Q for the quarter ended September 30, 2002)

10.43

Transocean U.S. Supplemental Savings Plan (incorporated by reference to Exhibit 10.44 to Transocean Ltd.’s Annual Report on Form 10-K (Commission File No. 000-53533) for the year ended December 31, 2008)

10.44

Commercial Paper Dealer Agreement between Transocean Inc. and Lehman Brothers Inc., dated as of December 20, 2007 (incorporated by reference to Exhibit 10.1 to Transocean Inc.’s Current Report on Form 8-K (Commission File No. 333-75899) filed on December 21, 2007)

10.45

Amended and Restated Commercial Paper Dealer Agreement between Transocean Inc. and Barclays Capital Inc., dated as of December 3, 2008 (including form of Accession Agreement) (incorporated by reference to Exhibit 10.1 to Transocean Inc.’s Current Report on Form 8-K (Commission File No. 333-75899) filed on December 9, 2008)

10.46

Commercial Paper Dealer Agreement between Transocean Inc. and Morgan Stanley & Co. Incorporated, dated as of December 20, 2007 (incorporated by reference to Exhibit 10.2 to Transocean Inc.’s Current Report on Form 8-K (Commission File No. 333-75899) filed on December 21, 2007)

- 111 - -

Index

10.47

Amended and Restated Commercial Paper Dealer Agreement between Transocean Inc. and Morgan Stanley & Co. Incorporated, dated as of December 3, 2008 (including form of Accession Agreement) (incorporated by reference to Exhibit 10.3 to Transocean Inc.’s Current Report on Form 8-K (Commission File No. 333-75899) filed on December 9, 2008)

10.48

Commercial Paper Dealer Agreement between Transocean Inc. and J.P. Morgan Securities Inc., dated as of December 20, 2007 (incorporated by reference to Exhibit 10.3 to Transocean Inc.’s Current Report on Form 8-K (Commission File No. 333-75899) filed on December 21, 2007)

10.49

Amended and Restated Commercial Paper Dealer Agreement between Transocean Inc. and J.P. Morgan Securities Inc., dated as of December 3, 2008 (including form of Accession Agreement) (incorporated by reference to Exhibit 10.2 to Transocean Inc.’s Current Report on Form 8-K (Commission File No. 333-75899) filed on December 9, 2008)

10.50

Amended and Restated Commercial Paper Dealer Agreement between Transocean Inc. and Goldman, Sachs & Co., dated as of December 3, 2008 (including form of Accession Agreement) (incorporated by reference to Exhibit 10.4 to Transocean Inc.’s Current Report on Form 8-K (Commission File No. 333-75899) filed on December 9, 2008)

10.51

Guarantee, dated as of December 19, 2008, of Transocean Ltd. pursuant to the Issuing and Paying Agent Agreement, dated as of December 20, 2007 (incorporated by reference to Exhibit 10.5 to Transocean Ltd.’s Current Report on Form 8-K filed on December 19, 2008)

10.52

Form of Indemnification Agreement entered into between Transocean Ltd. and each of its Directors and Executive Officers (incorporated by reference to Exhibit 10.1 to Transocean Inc.’s Current Report on Form 8-K (Commission File No. 333-75899) filed on October 10, 2008)

10.53

Form of Assignment Memorandum for Executive Officers (incorporated by reference to Exhibit 10.5 to Transocean Ltd.’s Current Report on Form 8-K filed on December 19, 2008)

10.54

Consulting Arrangement with Gregory L. Cauthen (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on May 21, 2009)

†

Subsidiaries of Transocean Ltd.

†

23.1

Consent of Ernst & Young LLP

†

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

†

101.ins

XBRL Instance Document

†

101.sch

XBRL Taxonomy Extension Schema

†

101.cal

XBRL Taxonomy Extension Calculation Linkbase

†

101.def

XBRL Taxonomy Extension Definition Linkbase

†

101.lab

XBRL Taxonomy Extension Label Linkbase

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101.pre

XBRL Taxonomy Extension Presentation Linkbase

______________________________

† Filed herewith.

* Compensatory plan or arrangement.

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

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

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

- 112 - -

Index

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned; thereunto duly authorized, on February 24, 2010.

TRANSOCEAN LTD.

By /s/ Ricardo H. Rosa

Ricardo H. Rosa

Senior Vice President and Chief Financial Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant in the capacities indicated on February 24, 2010.

Signature Title

_________*_________ Chairman of the Board of Directors

Robert E. Rose

/s/ Robert L. Long Chief Executive Officer

Robert L. Long (Principal Executive Officer)

/s/ Ricardo H. Rosa Senior Vice President and Chief Financial Officer

Ricardo H. Rosa (Principal Financial Officer)

/s/ John H. Briscoe Vice President and Controller

John H. Briscoe (Principal Accounting Officer)

_________*_________ Director

W. Richard Anderson

_________*_________ Director

Thomas W. Cason

_________*_________ Director

Richard L. George

_________*_________ Director

Victor E. Grijalva

_________*_________ Director

Martin B. McNamara

_________*_________ Director

Edward R. Muller

- 113 - -

Index

Signature Title

_________*_________ Director

Robert M. Sprague

_________*_________ Director

Ian C. Strachan

_________*_________ Director

J. Michael Talbert

_________*_________ Director

John L. Whitmire

/s/ Philippe Huber Secretary and Associate General Counsel

Philippe Huber

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Litigous
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Transocean (RIG) 10-K2009 FY Annual report

Content analysis