Edgar Filing: Transocean Ltd.

form10_k2011.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

______________________________

FORM 10-K

(Mark one)

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

For the fiscal year ended December 31, 2011

¨ 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 of incorporation or organization)	(I.R.S. Employer Identification No.)

Chemin de Blandonnet 10 Vernier, Switzerland	1214
(Address of principal executive offices)	(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 SIX Swiss 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. ¨

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, 2011, 319,639,362 shares were outstanding and the aggregate market value of shares held by non-affiliates was approximately $20.6 billion (based on the reported closing market price of the shares of Transocean Ltd. on such date of $64.56 and assuming that all directors and executive officers of the Company are “affiliates,” although the Company does not acknowledge that any such person is actually an “affiliate” within the meaning of the federal securities laws). As of February 22, 2012, 350,424,694 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, 2011, for its 2012 annual general meeting of shareholders, are incorporated by reference into Part III of this Form 10-K.

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TRANSOCEAN LTD. AND SUBSIDIARIES

INDEX TO ANNUAL REPORT ON FORM 10-K

FOR THE YEAR ENDED DECEMBER 31, 2011

Item		Page

PART I
Item 1.	Business	4
Item 1A.	Risk Factors	14
Item 1B.	Unresolved Staff Comments	27
Item 2.	Properties	27
Item 3.	Legal Proceedings	27
Item 4.	Mine Safety Disclosures	35

PART II
Item 5.	Market for Registrant’s Common Equity, Related Shareholder Matters and Issuer Purchases of Equity Securities	36
Item 6.	Selected Financial Data	39
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	40
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	72
Item 8.	Financial Statements and Supplementary Data	74
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	135
Item 9A.	Controls and Procedures	135
Item 9B.	Other Information	135

PART III
Item 10.	Directors, Executive Officers and Corporate Governance	136
Item 11.	Executive Compensation	136
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters	136
Item 13.	Certain Relationships and Related Transactions, and Director Independence	136
Item 14.	Principal Accountant Fees and Services	136

PART IV
Item 15.	Exhibits and Financial Statement Schedules	136

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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 impact of the Macondo well incident and related matters,

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

the offshore drilling market, including the impact of enhanced regulations in the jurisdictions in which we operate, 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, force majeure provisions, contract commencements, contract extensions, contract terminations, contract option exercises, contract revenues, contract awards and rig mobilizations,

§	liquidity and adequacy of cash flows for our obligations,

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

§	uses of excess cash, including the payment of dividends and other distributions and debt retirement,

§	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,

§	the cost and timing of acquisitions and the proceeds and timing 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 U.S.,

§	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, renewal of insurance, insurance proceeds and cash investments of our wholly owned captive insurance company,

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

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 and access to sources of liquidity,

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

§	our inability to renew contracts at comparable dayrates,

§	operational performance,

§	the impact of regulatory changes,

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

§	increased political and civil unrest,

§	the effect and results of litigation, regulatory matters, settlements, audits, assessments 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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PART I

Item 1.

Business

Overview

Transocean Ltd. (together with its subsidiaries and predecessors unless the context requires otherwise, “Transocean,” the “Company,” “we,” “us” or “our”) is a leading international provider of offshore contract drilling services for oil and gas wells. As of February 14, 2012, we owned or had partial ownership interests in and operated 134 mobile offshore drilling units. As of this date, our fleet consisted of 50 High-Specification Floaters (Ultra-Deepwater, Deepwater and Harsh Environment semisubmersibles and drillships), 25 Midwater Floaters, nine High-Specification Jackups, 49 Standard Jackups and one swamp barge. In addition, we had two Ultra-Deepwater Floaters and four High-Specification Jackups under construction.

We specialize in technically demanding sectors of the global offshore drilling business with a particular focus on deepwater and harsh environment drilling services. We believe our mobile offshore drilling fleet is one of the most 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 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.

Transocean Ltd. is a Swiss corporation with its registered office in Steinhausen, Canton of Zug and with principal executive offices located at Chemin de Blandonnet 10, 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” and on the SIX Swiss Exchange under the symbol “RIGN.” 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 25—Segments, Geographical Analysis and Major Customers.

Recent Developments

In February 2011, we sold the subsidiary that owns the High-Specification Jackup, Trident 20, located in the Caspian Sea. In March 2011, we engaged an unaffiliated advisor to coordinate the sale of the assets of our oil and gas properties reporting unit, a component of our other operations segment, which comprises the exploration, development and production activities performed by Challenger Minerals Inc. and Challenger Minerals (North Sea) Limited (together, “CMI”). As a result of these actions, we reclassified to discontinued operations the operating results and the assets and liabilities associated with our Caspian Sea operations and our oil and gas operations. In October 2011, we completed the sale of Challenger Minerals (North Sea) Limited, and in February 2012, entered into an agreement to sell the assets of Challenger Minerals Inc.

In October 2011, we completed our acquisition of Aker Drilling ASA (“Aker Drilling”), a Norwegian company formerly listed on the Oslo Stock Exchange. In connection with the acquisition, we acquired two Harsh Environment, Ultra-Deepwater semisubmersibles currently operating on long-term contracts in Norway. Additionally, we acquired two Ultra-Deepwater drillships currently under construction at the Daewoo Shipbuilding & Marine Engineering Co. Ltd. shipyard in Korea, which have expected deliveries in 2014.

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Drilling Fleet

Fleet overview—Most of our drilling equipment is suitable for both exploration and development drilling, and we normally engage in both types of drilling activity. Likewise, all 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 have living quarters for the crews, a helicopter landing deck and storage space for pipe and drilling supplies. Our drilling fleet can be generally characterized as follows: (1) floaters, including drillships and semisubmersibles, and (2) jackups. Also included in our fleet is a swamp barge drilling unit.

Drillships are generally self-propelled vessels, shaped like conventional ships, and are the most mobile of the major rig types. All of our high-specification drillships are equipped with a computer-controlled dynamic positioning thruster system, 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 generally limited to operations in calmer water conditions than those in which semisubmersibles can operate. We have three Enterprise-class and five Enhanced Enterprise-class drillships, which are all equipped with our patented dual-activity technology. Dual-activity technology employs structures, equipment and techniques using two drilling stations within a single derrick to allow these drillships to perform simultaneous drilling tasks in a parallel rather than sequential manner, reducing critical path activity, to improve efficiency in both exploration and development drilling. Our Enhanced Enterprise-class drillships offer improved reliability, increased pipe handling capacity, dual well control systems and flexible fluid capabilities and increased water depth and drilling depth.

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 a well through the use of an anchoring system or a computer-controlled dynamic positioning thruster system. Although most semisubmersible rigs are relocated with the assistance of tugs, some units are self-propelled and move between locations under their own power when afloat on pontoons. Typically, semisubmersibles are better suited than drillships for operations in rougher water conditions. We have three Express-class semisubmersibles, which are designed for mild environments and are equipped with the unique tri-act derrick. The tri-act derrick was designed to reduce overall well construction costs, as it 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.

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.

Fleet categories—We categorize the drilling units of 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) a swamp barge. As of February 14, 2012, our fleet of 134 rigs, excluding rigs under construction, was as follows:

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

§	27 Ultra-Deepwater Floaters;

§	16 Deepwater Floaters; and

§	Seven Harsh Environment Floaters;

§	25 Midwater Floaters;

§	Nine High-Specification Jackups;

§	49 Standard Jackups; and

§	one swamp barge

High-Specification Floaters are specialized offshore drilling units that we categorize into three sub-classifications based on their capabilities. Ultra-Deepwater Floaters are equipped with high-pressure mud pumps and are capable of drilling in water depths of 7,500 feet or greater. Deepwater Floaters are generally those other semisubmersible rigs and drillships capable of drilling in water depths between 7,500 and 4,500 feet. Harsh Environment Floaters are capable of drilling in harsh environments in water depths between 10,000 and 1,500 feet and have greater displacement, which offers larger variable load capacity, more useable deck space and better motion characteristics. Midwater Floaters are generally comprised of those non-high-specification semisubmersibles that have a water depth capacity of less than 4,500 feet. High-Specification Jackups have greater operational capabilities than Standard Jackups and are able to operate in harsh environments, and have higher capacity derricks, drawworks, mud systems and storage. Typically, High-Specification Jackups also have deeper water depth capacity than Standard Jackups.

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Fleet status—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 staffed by a reduced crew or has no crew 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. Stacked rigs will continue to incur operating costs at or above normal operating levels for 30 to 60 days following initiation of stacking. Some idle rigs and all stacked rigs require additional costs to return to service. The actual cost to return to service, which in many instances could be significant and 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. We consider these factors, together with market conditions, length of contract, dayrate and other contract terms, when deciding whether to return a stacked rig to service. We may, from time to time, consider marketing stacked rigs as accommodation units or for other alternative uses until drilling activity increases and we obtain drilling contracts for these units.

Drilling units—The following tables, presented as of February 14, 2012, provide certain specifications for our rigs. Unless otherwise noted, the stated location of each rig indicates either the current drilling location, if the rig is operating, or the next operating location, if the rig is in shipyard with a follow-on contract. As of February 14, 2012, 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 through our interests in joint venture companies and (2) Petrobras 10000, which is subject to a capital lease through August 2029. In addition to the rigs presented below, we also own and operate one swamp barge.

Rigs Under Construction (6)

			Water	Drilling
			depth	depth
		Expected	capacity	capacity	Contracted
Name	Type	completion	(in feet)	(in feet)	location
Ultra-Deepwater Floaters
DSME 12000 Drillship TBN1	HSD	1Q 2014	12,000	40,000	To be determined
DSME 12000 Drillship TBN2	HSD	2Q 2014	12,000	40,000	To be determined
High-Specification Jackups
Transocean Honor	Jackup	1Q 2012	400	30,000	Angola
Transocean Siam Driller	Jackup	1Q 2013	350	35,000	Thailand
Transocean Andaman	Jackup	1Q 2013	350	35,000	Thailand
Transocean Ao Thai	Jackup	3Q 2013	350	35,000	Thailand

______________________________

“HSD” means high-specification drillship.

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High-Specification Floaters (50)

		Year	Water	Drilling
		entered	depth	depth
		service/	capacity	capacity
Name	Type	upgraded (a)	(in feet)	(in feet)	Location
Ultra-Deepwater Floaters (27)
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
Discoverer Inspiration (b) (c) (d)	HSD	2010	12,000	40,000	U.S. Gulf
Deepwater Champion (b) (c)	HSD	2011	12,000	40,000	Romania/Black Sea
Petrobras 10000 (b) (c)	HSD	2009	12,000	37,500	Brazil
Dhirubhai Deepwater KG1 (b) (e)	HSD	2009	12,000	35,000	India
Dhirubhai Deepwater KG2 (b) (e)	HSD	2010	12,000	35,000	India
Discoverer India (b) (c) (d)	HSD	2010	12,000	40,000	U.S. Gulf
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	Sierra Leone
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 Frontier (b)	HSD	1999	10,000	30,000	Australia
Deepwater Millennium (b)	HSD	1999	10,000	30,000	Mozambique
Deepwater Pathfinder (b)	HSD	1998	10,000	30,000	U.S. Gulf
Deepwater Expedition (b)	HSD	1999	8,500	30,000	To be determined
Cajun Express (b) (f)	HSS	2001	8,500	35,000	Brazil
Deepwater Nautilus (g)	HSS	2000	8,000	30,000	U.S. Gulf
GSF Explorer (b)	HSD	1972/1998	7,800	30,000	Indonesia
Discoverer Luanda (b) (c) (d) (h)	HSD	2010	7,500	40,000	Angola
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	Ghana
Sedco Express (b) (f)	HSS	2001	7,500	35,000	Israel
Deepwater Floaters (16)
Deepwater Navigator (b)	HSD	1971/2000	7,200	25,000	Brazil
Discoverer 534 (b)	HSD	1975/1991	7,000	25,000	Stacked
Discoverer Seven Seas (b)	HSD	1976/1997	7,000	25,000	India
Transocean Marianas (g)	HSS	1979/1998	7,000	30,000	Nigeria/Ghana
Sedco 702 (b)	HSS	1973/2007	6,500	25,000	Nigeria
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	Angola
Jack Bates (g)	HSS	1986/1997	5,400	30,000	Australia
M.G. Hulme, Jr. (g)	HSS	1983/1996	5,000	25,000	India
Sedco 709 (b)	HSS	1977/1999	5,000	25,000	Stacked
Transocean Richardson (g)	HSS	1988	5,000	25,000	Stacked
Jim Cunningham (g)	HSS	1982/1995	4,600	25,000	Stacked
Sedco 710 (b)	HSS	1983/2001	4,500	25,000	Brazil
Sovereign Explorer (g)	HSS	1984	4,500	25,000	Stacked
Transocean Rather (g)	HSS	1988	4,500	25,000	Angola
Harsh Environment Floaters (7)
Transocean Spitsbergen (b) (c)	HSS	2010	10,000	30,000	Norwegian N. Sea
Transocean Barents (b) (c)	HSS	2009	10,000	30,000	Norwegian N. Sea
Henry Goodrich (g)	HSS	1985/2007	5,000	30,000	Canada
Transocean Leader (g)	HSS	1987/1997	4,500	25,000	Norwegian N. Sea
Paul B. Loyd, Jr.(g)	HSS	1990	2,000	25,000	U.K. N. Sea
Transocean Arctic (g)	HSS	1986	1,650	25,000	Norwegian N. Sea
Polar Pioneer (g)	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)	Enterprise-class or Enhanced Enterprise-class rig.

(e) Owned through our 50 percent interest in Transocean Pacific Drilling Inc. and pledged as collateral for debt of the joint venture company.

(f)	Express-class rig.

(g)	Moored floaters.

(h)	Owned through our 65 percent interest in Angola Deepwater Drilling Company Limited and pledged as collateral for the debt of the joint venture company.

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Midwater Floaters (25)

		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	Egypt
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	Nigeria
GSF Rig 140	OS	1983	2,800	25,000	India
Falcon 100	OS	1974/1999	2,400	25,000	Brazil
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	U.K. N. Sea
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	Malaysia
GSF Grand Banks	OS	1984	1,500	25,000	Canada
Sedco 601	OS	1983	1,500	25,000	Stacked
Sedneth 701	OS	1972/1993	1,500	25,000	Congo
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	Stacked
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.

High-Specification Jackups (9)

	Year	Water	Drilling
	entered	depth	depth
	service/	capacity	capacity
Name	upgraded (a)	(in feet)	(in feet)	Location
GSF Constellation I	2003	400	30,000	Gabon
GSF Constellation II	2004	400	30,000	Egypt
GSF Galaxy I	1991/2001	400	30,000	Stacked
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	Nigeria
GSF Monarch	1986	350	30,000	Denmark
GSF Monitor	1989	350	30,000	Nigeria

______________________________

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

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Standard Jackups (49)

	Year	Water	Drilling
	entered	depth	depth
	service/	capacity	capacity
Name	upgraded (a)	(in feet)	(in feet)	Location
Trident IX	1982	400	21,000	Malaysia
GSF Adriatic II	1981	350	25,000	Stacked
GSF Adriatic IX	1981	350	25,000	Nigeria
GSF Adriatic X	1982	350	30,000	Nigeria
GSF Key Manhattan	1980	350	25,000	Italy
GSF Key Singapore	1982	350	25,000	Stacked
GSF Adriatic VI	1981	328	25,000	Stacked
GSF Adriatic VIII	1983	328	25,000	Stacked
C. E. Thornton	1974	300	25,000	India
D. R. Stewart	1980	300	25,000	Stacked
F. G. McClintock	1975	300	25,000	India
GSF Adriatic I	1981	300	25,000	Stacked
GSF Adriatic V	1979	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	Thailand
GSF Key Hawaii	1982	300	25,000	Vietnam
GSF Main Pass I	1982	300	25,000	Arabian Gulf
GSF Main Pass IV	1982	300	25,000	Arabian Gulf
Harvey H. Ward	1981	300	25,000	Indonesia
J. T. Angel	1982	300	25,000	India
Randolph Yost	1979	300	25,000	Stacked
Roger W. Mowell	1982	300	25,000	Stacked
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	Thailand
Trident VIII	1981	300	21,000	Gabon
GSF Parameswara	1983	300	20,000	Indonesia
GSF Rig 134	1982	300	20,000	Stacked
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	Nigeria
GSF High Island IX	1983	250	20,000	Arabian Gulf
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
Trident VI	1981	220	21,000	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.

As of February 14, 2012, our fleet was located in the Far East (27 units), Middle East (16 units), West African countries other than Nigeria and Angola (14 units), United States (“U.S.”) Gulf of Mexico (13 units), U.K. North Sea (12 units), India (12 units), Brazil (10 units), Nigeria (10 units), Norway (eight units), Angola (four units), Australia (three units), the Mediterranean (two units), Canada (two units), and Romania (one unit).

In recent years, oil companies have placed increased emphasis 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.

We categorize the market sectors in which we operate as follows: (1) deepwater, (2) midwater, (3) jackup and (4) transition zone. 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 market sector 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 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 only operate in this sector using our swamp barge drilling rig located in Southeast Asia.

Financial Information about Geographic Areas

The following table presents the geographic areas in which our operating revenues were earned and our long-lived assets were located (in millions):

	Years ended December 31,
	2011		2010		2009
Operating revenues
U.S.	$	1,975	$	2,087	$	2,209
U.K.		1,211		1,183		1,563
Brazil		1,019		1,288		1,108
Other countries (a)		4,937		4,908		6,561
Total operating revenues	$	9,142	$	9,466	$	11,441

______________________________

(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.

	December 31,
	2011		2010
Long-lived assets
U.S.	$	6,549	$	5,519
Brazil		2,185		2,472
India		1,593		2,632
Other countries (a)		12,202		10,696
Total long-lived assets	$	22,529	$	21,319

______________________________

(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 Backlog

Our contract backlog at December 31, 2011 was approximately $22.5 billion, representing an 8.5 percent and 27.7 percent decrease compared to our contract backlog of $24.6 billion and $31.1 billion at December 31, 2010 and 2009, 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.”

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 or zero 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, however, may not 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 results of operations or cash flows. See “Item 1A. Risk Factors—Risks related to our business—Our drilling contracts may be terminated due to a number of events.”

Consistent with standard industry practice, our customers generally assume, and indemnify us against, well control and subsurface risks under dayrate contracts. Under all of our current drilling contracts, the operator indemnifies us for pollution damages in connection with reservoir fluids stemming from operations under the contract and we indemnify the operator for pollution from substances in our control that originate from the rig (e.g., diesel used onboard the rig or other fluids stored onboard the rig and above the water surface). Also, under all of our current drilling contracts, the operator indemnifies us against damage to the well or reservoir and loss of subsurface oil and gas and the cost of bringing the well under control. However, our drilling contracts are individually negotiated, and the degree of indemnification we receive from the operator against the liabilities discussed above can vary from contract to contract, based on market conditions and customer requirements existing when the contract was negotiated. In some instances, we have contractually agreed upon certain limits to our indemnification rights and can be responsible for damages up to a specified maximum dollar amount, which amount is usually $5 million or less, although the amount can be greater depending on the nature of our liability. In most instances in which we are indemnified for damages to the well, we have the responsibility to redrill the well at a reduced dayrate. Notwithstanding a contractual indemnity from a customer, there can be no assurance that our customers will be financially able to indemnify us or will otherwise honor their contractual indemnity obligations.

The interpretation and enforceability of a contractual indemnity depends upon the specific facts and circumstances involved, as governed by applicable laws, and may ultimately need to be decided by a court or other proceeding which will need to consider the specific contract language, the facts and applicable laws. In connection with the Macondo well incident, a court refused to enforce an indemnity in respect of certain penalties and punitive damages under the Clean Water Act and the enforceability of an indemnity as to other matters may be limited. The inability or other failure of our customers to fulfill their indemnification obligations to us could have a material adverse effect on our consolidated statement of financial position, results of operations and cash flows. See “Item 3. Legal Proceedings—Macondo well incident—Contractual indemnity.”

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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.

Revenues from these drilling management services represented less than six percent of our consolidated revenues for the year ended December 31, 2011. In the course of providing drilling management services, ADTI may either 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 14, 2012, we were only performing such services in India. Revenues from these integrated services represented less than one percent of our consolidated revenues for the year ended December 31, 2011.

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. We may or may not control these joint ventures. 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.

We hold a 50 percent interest in Transocean Pacific Drilling Inc. (“TPDI”), a consolidated British Virgin Islands joint venture company formed by us and Quantum Pacific Management Limited, a Cypriot company and successor in interest to Pacific Drilling Limited (“Quantum”), to own and operate two ultra-deepwater drillships named Dhirubhai Deepwater KG1 and Dhirubhai Deepwater KG2. Under a management services agreement with TPDI, we provide operating management services for Dhirubhai Deepwater KG1 and Dhirubhai Deepwater KG2. Quantum has the unilateral right to exchange its interest in the joint venture for our shares or cash, at an amount based on an appraisal of the fair value of the drillships, subject to certain adjustments, but it has not exercised this right.

We hold a 65 percent interest in Angola Deepwater Drilling Company Limited (“ADDCL”), a consolidated Cayman Islands joint venture company formed to own and operate 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 operating management services for Discoverer Luanda. Beginning January 31, 2016, Angco Cayman Limited will have the right to exchange its interest in the joint venture for cash at an amount based on an appraisal of the fair value of the drillship, subject to certain adjustments.

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 2011 was BP plc (together with its affiliates, “BP”), accounting for approximately 10 percent of our operating revenues. No other customer accounted for 10 percent or more of our 2011 operating revenues.

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Employees

We require highly skilled personnel to operate our drilling units. Consequently, we conduct extensive personnel recruiting, training and safety programs. At December 31, 2011, we had approximately 18,700 employees, including approximately 1,850 persons engaged through contract labor providers. Some of our employees working in Angola, the U.K., Norway and Australia 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 annual salary negotiation. These negotiations could result in higher personnel expenses, other increased costs or increased operational 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 a leading international provider of offshore contract drilling services and drilling management services for oil and gas wells. We specialize in technically demanding sectors of the global offshore drilling business. Our fleet is considered one of the most versatile in the world with a particular focus on deepwater and harsh environment drilling capabilities. 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. Fifteen rigs in our existing fleet are 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. Additionally, three rigs in our existing fleet are equipped with the unique tri-act derrick, which we have patented in certain market sectors in which we operate. The tri-act derrick was designed to reduce overall well construction costs, as it 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. The effective use of and continued improvements in technology are critical to maintaining our competitive position within the drilling services industry. We expect to continue to develop technology internally or to acquire technology through strategic acquisitions.

Environmental Regulation

For a discussion of the effects of environmental regulation, see “Item 1A. Risk Factors—Risks related to our business—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. Our actions are designed to reduce risk in our current and future operations, to promote sound environmental management and to create a proactive environmental program. From a global perspective, we continue to assess further projects designed to reduce our overall emissions. To date, we have not incurred significant costs in order to comply with recent legislation, and we do not believe that our compliance with such requirements will have a material adverse effect on our competitive position, consolidated results of operations or cash flows.

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 Integrity and any waiver from any provision of our Code of Integrity by posting such information in the Corporate Governance section of our website at www.deepwater.com.

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Item 1A. Risk Factors

Risks related to our business

The Macondo well incident could result in increased expenses and decreased revenues, which could ultimately have a material adverse effect on us.

Numerous lawsuits have been filed against us and unaffiliated defendants related to the Macondo well incident. We are subject to claims alleging that we are jointly and severally liable, along with BP and others, for damages arising from the Macondo well incident. We have incurred and expect to continue to incur significant legal fees and costs in responding to these matters. We may also be subject to governmental fines or penalties. Although we have excess liability insurance coverage, our personal injury and other third party liability insurance coverage is subject to deductibles and overall aggregate policy limits. There can be no assurance that our insurance will ultimately be adequate to cover all of our potential liabilities in connection with these matters. For a discussion of the potential impact of the failure of the Macondo well operator to honor its indemnification obligations to us, see “We could experience a material adverse effect on our consolidated statement of financial position, results of operations and cash flows to the extent any of the operator’s indemnification obligations to us are not enforceable or the operator does not indemnify us” below. If we ultimately incur substantial liabilities in connection with these matters with respect to which we are neither insured nor indemnified, those liabilities could have a material adverse effect on us.

The incident has had and could continue to have a material adverse effect on our consolidated statement of financial position, results of operations and cash flows. Our business has been negatively impacted by the loss of revenue from Deepwater Horizon. The backlog associated with the Deepwater Horizon drilling contract was approximately $590 million through the end of the contract term in 2013. We do not carry insurance for business interruption or loss of hire. In the two years ended December 31, 2011, we estimate that the Macondo well incident had a direct and indirect effect of greater than $1.0 billion in lost revenues and incremental costs and expenses associated with extended shipyard projects and increased downtime, both as a result of complying with the enhanced regulations and our customers’ requirements. In one case, the increased downtime has resulted in the recent termination of one of our contracts, which represented backlog of approximately $470 million. In the three months ended December 31, 2011, we recognized an estimated loss of $1.0 billion in connection with loss contingencies associated with the Macondo well incident that we believe are probable and for which a reasonable estimate can be made. Additionally, in the years ended December 31, 2011 and 2010, we incurred incremental costs, primarily associated with legal expenses for lawsuits and investigations, net of expected insurance recoveries, in the amount of $71 million and $139 million, respectively. Collectively, the lost contract backlog from the incident and from the recent termination, lost revenues and incremental expenses from extended shipyard projects and increased downtime, loss contingencies associated with the incident and other incremental costs have had an effect of greater than $3.0 billion.

We are currently unable to estimate the full impact the Macondo well incident will have on us. We have recognized a liability for estimated loss contingencies that we believe are probable and for which a reasonable estimate can be made. As of December 31, 2011, we have recognized a liability for such loss contingencies in the amount of $1.2 billion. This liability takes into account certain events related to the litigation and investigations arising out of the incident. There are loss contingencies related to the Macondo well incident that we believe are reasonably possible and for which we do not believe a reasonable estimate can be made. These contingencies could increase the liabilities we ultimately recognize. Our estimates involve a significant amount of judgment. As a result of new information or future developments, some of which could occur very soon, we may adjust our estimated loss contingencies arising out of the Macondo well incident, and the resulting liabilities could have a material adverse effect on our consolidated statement of financial position, results of operations and cash flows.

Our business may also be adversely impacted by any negative publicity relating to the incident and us, any negative perceptions about us by customers, the skilled personnel that we require to support our operations or others, any further increases in premiums for insurance or difficulty in obtaining coverage and the diversion of management’s attention from our other operations to focus on matters relating to the incident. In addition, the Macondo well incident could negatively impact our ongoing business relationship with BP, which accounted for approximately 10 percent of our consolidated operating revenues for the year ended December 31, 2011. Ultimately, these factors could have a material adverse effect on our statement of financial position, results of operations or cash flows.

We could experience a material adverse effect on our consolidated statement of financial position, results of operations and cash flows to the extent any of the Macondo well operator’s indemnification obligations to us are not enforceable or the operator does not indemnify us.

The combined response team to the Macondo well incident was unable to stem the flow of hydrocarbons from the well prior to the sinking of Deepwater Horizon. The resulting spill of hydrocarbons was the most extensive in U.S. history. According to its public filings, the operator has recognized cumulative pre-tax losses of $44.6 billion in relation to the spill. As described under “Part I. Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Contingencies—Macondo well incident—Contractual indemnity,” under the Deepwater Horizon drilling contract, BP agreed to indemnify us with respect to certain matters, and we agreed to indemnify BP with respect to certain matters. We could ultimately experience a material adverse effect on our consolidated statement of financial position, results of operations and cash flows to the extent that BP does not honor its indemnification obligations, including by reason of financial or legal restrictions, or our insurance policies do not fully cover these amounts. In April 2011, BP filed a claim seeking a declaration that it is not liable to us in contribution, indemnification, or otherwise, and further, BP has brought claims

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against us seeking indemnification and contribution. On November 1, 2011, we filed a motion for partial summary judgment regarding the scope and enforceability of the indemnity obligations in the drilling contract. On January 26, 2012, the court ruled that the drilling contract requires BP to indemnify us for compensatory damages asserted by third parties against us related to pollution that did not originate on or above the surface of the water, even if the claim is the result of our strict liability, negligence, or gross negligence. The court also held that BP does not owe us indemnity to the extent that we are held liable for punitive damages or civil penalties under the Clean Water Act. The court deferred ruling on BP’s argument that we breached the drilling contract or materially increased BP’s risk or prejudiced its rights so as to impair BP’s indemnity obligations. The law generally considers contractual indemnity for criminal fines and penalties to be against public policy.

Investigations are ongoing in connection with the Macondo well incident, the outcome of which are unknown and could have a material adverse effect on us.

On June 28, 2010, we received a letter from the U.S. Department of Justice (“DOJ”) asking us to meet with them to discuss our financial responsibilities in connection with the Macondo well incident and requesting that we provide them certain financial and organizational information. The letter also requested that we provide the DOJ advance notice of certain corporate actions involving the transfer of cash or other assets outside the ordinary course of business. We have engaged in discussions with the DOJ and have responded to their document requests, and we expect these discussions to continue. In addition, on December 15, 2010, the DOJ filed a civil lawsuit against us and other unaffiliated defendants. The complaint alleges claims under the Oil Pollution Act of 1990 (“OPA”) and the Clean Water Act, including claims for per barrel civil penalties of up to $1,100 per barrel or up to $4,300 per barrel if gross negligence or willful misconduct is established, and the DOJ reserved its rights to amend the complaint to add new claims and defendants. The complaint asserts that all defendants are jointly and severally liable for all removal costs and damages resulting from the Macondo well incident. On December 6, 2011, the DOJ filed a motion for partial summary judgment seeking a ruling that we were jointly and severally liable under OPA, and liable for civil penalties under the Clean Water Act, for all discharges from the Macondo well on the theory that the discharges not only came from the well, but also came from the blowout preventer and riser, appurtenances of Deepwater Horizon. On February 22, 2012, the U.S. District Court, Eastern District of Louisiana ("The MDL Court") ruled that we are not liable as a responsible party for damages under OPA with respect to the below surface discharges from the Macondo well. The court also ruled that the below surface discharge was discharged from the well facility, and not from the Deepwater Horizon vessel, within the meaning of the Clean Water Act, and that we therefore are not liable for such discharges as an owner of the vessel under the Clean Water Act. However, the court ruled that the issue of whether we could be held liable for such discharge under the Clean Water Act as an “operator” of the well facility could not be resolved on summary judgment. The court did not determine whether we could be liable for removal costs under OPA, or the extent of such removal costs.

In addition to the civil complaint, the DOJ served us with civil investigative demands on December 8, 2010. These demands were part of an investigation by the DOJ to determine if we made false claims, or false statements in support of claims, in connection with the operator’s acquisition of the leasehold interest in the Mississippi Canyon Block 252, Gulf of Mexico and drilling operations on Deepwater Horizon.

The DOJ is also conducting a criminal investigation into the Macondo well incident. The DOJ task force is investigating possible violations, by us and certain unaffiliated parties, of the Clean Water Act, the Migratory Bird Treaty Act, the Refuse Act, the Endangered Species Act, and the Seaman's Manslaughter Act, among other federal statutes, and possible criminal liabilities including fines under those statutes and under the Alternative Fines Act. Under the Alternative Fines Act, a corporate defendant convicted of a criminal offense may be subject to a fine in the amount of twice the gross pecuniary loss suffered by third parties as a result of the offense.

In addition, a number of other governmental and regulatory bodies as well as we and other companies have conducted investigations into the Macondo well incident. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Contingencies—Macondo well incident—Investigations.”

We cannot predict the ultimate outcome of the DOJ’s lawsuit or any of the investigations, including any impact on the litigation related to the Macondo well incident, the extent to which we could be subject to fines, sanctions or other penalties, the potential impact of implementing measures that may result from the investigations or the costs to be incurred in completing the investigations.

The continuing effects of the enhanced regulations enacted following the Macondo well incident could materially and adversely affect our worldwide operations.

New governmental safety and environmental requirements applicable to both deepwater and shallow water operations have been adopted for drilling in the U.S. Gulf of Mexico following the Macondo well incident. In order to obtain drilling permits, operators must submit applications that demonstrate compliance with the enhanced regulations, which require independent third-party inspections, certification of well design and well control equipment and emergency response plans in the event of a blowout, among other requirements. Operators have, and may continue to have, difficulties obtaining drilling permits in the U.S. Gulf of Mexico. In addition, the oil and gas industry has adopted new equipment and operating standards such as the American Petroleum Institute recommended practice 53 relating to the installation and testing of well control equipment. These new safety and environmental guidelines and standards and any further new guidelines or standards the U.S. government or industry may issue or any other steps the U.S. government or industry may take, could disrupt or delay operations, increase the cost of operations, increase out-of-service time or reduce the area of operations for drilling rigs in U.S. and non-U.S. offshore areas.

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Other governments could take similar actions relating to implementing new safety and environmental regulations in the future. Additionally, some of our customers have elected to voluntarily comply with some or all of the new inspections, certification requirements and safety and environmental guidelines on rigs operating outside of the U.S. Gulf of Mexico. Additional governmental regulations and requirements concerning licensing, taxation, equipment specifications and training requirements or the voluntary adoption of such requirements or guidelines by our customers could increase the costs of our operations, increase certification and permitting requirements, increase review periods and impose increased liability on offshore operations.

The continuing effects of the enhanced regulations may also decrease the demand for drilling services, negatively affect dayrates and increase out-of-service time, which could ultimately have a material adverse affect on our revenue and profitability. We are unable to predict the full impact that the continuing effects of the enhanced regulations will have on our operations.

The Frade Field incident in Brazil could result in increased expenses and decreased revenues, which could ultimately have a material impact on us.

On or about November 7, 2011, oil was released from fissures in the ocean floor in the vicinity of a development well being drilled by Chevron off the coast of Rio de Janeiro in the Campo de Frade field with our Deepwater Floater Sedco 706. In connection with the incident, authorities in Brazil have filed a civil action against Chevron and us, and a Brazilian federal police marshal has filed a report recommending the criminal indictment of Chevron and us. We may be subject to liability for civil damage and governmental fines or penalties. If we ultimately incur substantial liabilities in connection with these matters for which we are neither insured nor indemnified, those liabilities could adversely affect our consolidated statement of financial position, results of operations or cash flow. In addition, there is a risk that Brazilian authorities could temporarily or permanently enjoin us from further operations in Brazil. For the year ended December 31, 2011, our operations in Brazil accounted for 11 percent of our consolidated operating revenues. If we are enjoined from operating in Brazil for a substantial period of time, the resulting decrease in demand for our drilling services could ultimately have a material adverse effect on our consolidated statement of financial position, results of operations or cash flows.

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 approximately $13.5 billion and $11.2 billion at December 31, 2011 and 2010, 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 or satisfy certain other conditions included in our bank credit agreements, which could result in our inability to meet requirements for borrowings under our bank credit agreements or 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.

Credit rating agencies may lower our corporate credit ratings below investment grade.

Credit rating agencies may downgrade our credit ratings to non-investment grade levels. Such ratings levels could limit our ability to refinance our existing debt, could cause us to refinance or issue debt with less favorable terms and conditions and could increase certain fees under our credit facilities and interest rates under agreements governing certain of our senior notes and cause indebtedness of approximately $30 million to become due. In addition, such ratings levels could negatively impact current and prospective customers’ willingness to transact business with us and could impose additional insurance requirements. Suppliers and financial institutions may lower or eliminate the level of credit provided through payment terms or intraday funding when dealing with us thereby increasing the need for higher levels of cash on hand, which would decrease our ability to repay debt balances. Since the Macondo well incident, Moody’s Investors Service, Standard & Poor’s and Fitch have each downgraded their ratings of our senior unsecured debt on more than one occasion, and Moody’s Investors Service currently has such debt on review for further downgrade. Any further downgrade by any of the rating agencies could have the effect described above. We cannot provide assurance that our credit ratings will not be downgraded to a non-investment grade rating in the near future. See “The Macondo well incident could result in increased expenses and decreased revenues, which could ultimately have a material adverse effect on us.”

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.

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Laws and regulations protecting the environment have become more stringent in recent years, and may in some cases impose strict liability, rendering a person liable for environmental damage without regard to negligence. These laws and regulations may expose us to liability for the conduct of or conditions caused by others or for acts that were in compliance with all applicable laws at the time they were performed. The application of these requirements or the adoption of new requirements could have a material adverse effect on our consolidated statement of financial position, results of operations or cash flows. Numerous lawsuits, including one brought by the DOJ, allege that we may have liability under the environmental laws relating to the Macondo well incident. If we are charged with or convicted of certain criminal environmental offenses, we may be subject to suspension or debarment as a contractor or subcontractor on certain government contracts, including leases. See “The Macondo well incident could result in increased expenses and decreased revenues, which could ultimately have a material adverse effect on us.”

There is no assurance that we can obtain enforceable indemnities against liability for pollution, well and environmental damages 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 indemnity obligations to us. A court in the litigation related to the Macondo well incident has refused to enforce all aspects of our indemnity with respect to certain environmental-related liabilities.

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. 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. 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, civil unrest 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 market sectors. We have idled and stacked rigs, and may in the future idle or stack additional rigs or enter into lower dayrate contracts in response to market conditions. We cannot predict when any idled or stacked rigs will return to service.

During prior periods of high dayrates and utilization, industry participants have increased the supply of rigs by ordering the construction of new units. This has typically resulted in an oversupply of rigs and has caused a subsequent decline in dayrates and utilization, sometimes for extended periods of time. Presently, there are numerous recently constructed high-specification floaters and jackups that have entered the market, and there are more that are under contract for construction.

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The entry into service of these new units has increased and will continue to increase supply and could curtail a strengthening, or trigger a reduction, in dayrates as rigs are absorbed into the active fleet. Additionally, as a result of the Aker Drilling acquisition we are expected to take delivery, in 2014, of two Ultra-Deepwater drillships currently under construction. We have not yet secured a drilling contract for either drillship. Our failure to secure a drilling contract for either rig prior to its deployment could adversely affect our results of operations. Any further increase in construction of new units would likely exacerbate the negative impact on dayrates and utilization. Lower dayrates and utilization could adversely affect our revenues and profitability.

We rely heavily on a relatively small number of customers and the loss of a significant customer 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 2011 was BP, accounting for 10 percent of our operating revenues for the year ended December 31, 2011. As of February 14, 2012, the contract backlog associated with our contracts with BP and its affiliates was $2.7 billion. Our relationship with BP, whose affiliate was the operator of the Macondo well, has been and could continue to be negatively impacted by the Macondo well incident. 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 and cash flows.

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 unplanned downtime while on contract or 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. 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, and these expenses could increase for short or extended periods as a result of regulatory or customer requirements that raise maintenance standards above historical levels. 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 14, 2012, we had two Ultra-Deepwater Floater and four High-Specification Jackup 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:

§	availability of suppliers to recertify equipment for enhanced regulations;

§	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;

§	civil unrest;

§	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 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.

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During periods of depressed market conditions, 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 14, 2012 was approximately $21.4 billion. This amount represents the firm term of the contract multiplied by the contractual operating rate, which may be higher than the actual dayrate we receive or we may receive other dayrates included in the contract such as waiting on weather rate, repair rate, standby rate or force majeure rate. The contractual operating dayrate may also be higher than the actual dayrate we receive because of a number of factors, including rig downtime or suspension of operations. In certain contracts, the dayrate may be reduced to zero or result in customer credit against future dayrate if, for example, repairs extend beyond a stated period of time. 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.

The global nature of our operations involves additional risks.

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;

§	changes in law and regulatory requirements, including changes in interpretation and enforcement;

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

§	civil unrest resulting in suspension of operations;

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

§	the inability to move income or capital; and

§	currency exchange fluctuations.

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. 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 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Contingencies—Regulatory matters.” We have also operated rigs in Myanmar, a country that is subject to some U.S. trading sanctions. We have received and responded to an administrative subpoena from OFAC concerning our operations in Myanmar and a follow up administrative subpoena from OFAC with questions relating to the previous Myanmar operations subpoena response and the self-reported shipment through Iran matter. 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, including local content requirements for participating in tenders for certain drilling contracts. 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. 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 by major oil companies and may continue to do so.

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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 global economic downturn 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.

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. For example, in the past few years, we have 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 affect our consolidated statement of financial position, results of operations or cash flows.

Failure to comply with the U.S. Foreign Corrupt Practices Act and the Bribery Act 2010 recently enacted by the U.K. could result in fines, criminal penalties, drilling contract terminations and an adverse effect on our business.

The U.S. Foreign Corrupt Practices Act (“FCPA”) and similar anti-bribery laws in other jurisdictions, including the Bribery Act 2010 which became effective in the U.K. on July 1, 2011, generally prohibit companies and their intermediaries from making improper payments for the purpose of obtaining or retaining business. We operate in many parts of the world that have experienced corruption to some degree and, in certain circumstances, strict compliance with anti-bribery laws may conflict with local customs and practices. If we are found to be liable for FCPA violations or violations under the Bribery Act 2010, either due to our own acts or our omissions or due to the acts or omissions of others, including our partners in our various joint ventures, we could suffer from civil and criminal penalties or other sanctions, which could have a material adverse effect on our business, financial condition, and results of operations.

Civil penalties under the anti-bribery provisions of the FCPA could range up to $10,000 per violation, with a criminal fine up to the greater of $2 million per violation or twice the gross pecuniary gain to us or twice the gross pecuniary loss to others, if larger. Civil penalties under the accounting provisions of the FCPA can range up to $500,000 per violation and a company that knowingly commits a violation can be fined up to $25 million per violation. In addition, both the SEC and the DOJ could assert that conduct extending over a period of time may constitute multiple violations for purposes of assessing the penalty amounts. Often, dispositions for these types of matters result in modifications to business practices and compliance programs and possibly the appointment of a monitor to review future business and practices with the goal of ensuring compliance with the FCPA. On November 4, 2010, we reached a settlement with the SEC and the DOJ with respect to certain charges relating to the anti-bribery and books and records provisions of the FCPA. In November 2010, under the terms of the settlements, we paid a total of approximately $27 million in penalties, interest and disgorgement of profits. We have also consented to the entry of a civil injunction in two SEC actions and have entered into a three-year deferred prosecution agreement with the DOJ (the “DPA”). In connection with the DPA, we have agreed to implement and maintain certain internal controls, policies and procedures. For the duration of the DPA, we are also obligated to provide an annual written report to the DOJ of our efforts and progress in maintaining and enhancing our compliance policies and procedures. In the event the DOJ determines that we have knowingly violated the terms of the DPA, the DOJ may impose an extension of the term of the agreement or, if the DOJ determines we have breached the DPA, the DOJ may pursue criminal charges or a civil or administrative action against us. The DOJ may also find, in its sole discretion, that a change in circumstances has eliminated the need for the corporate compliance reporting obligations of the DPA and may terminate the DPA prior to the three-year term. Failure to comply with the terms of the DPA may impact our operations and any resulting fines may have a material adverse effect on our results of operations or cash flows.

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We could also face fines, sanctions and other penalties from authorities in the relevant foreign jurisdictions, including prohibition of our participating in or curtailment of business operations in those jurisdictions and the seizure of rigs or other assets. Our customers in those jurisdictions could seek to impose penalties or take other actions adverse to our interests. We could also face other third-party claims by agents, stockholders, debt holders, or other interest holders or constituents of our company. In addition, disclosure of the subject matter of the investigation could adversely affect our reputation and our ability to obtain new business or retain existing business from our current customers and potential customers, to attract and retain employees and to access the capital markets. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Contingencies-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., Norway and Australia, 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 annual salary negotiation. These negotiations could result in higher personnel expenses, other increased costs or increased operational 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.

Worldwide financial and economic conditions 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. 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. Recent worldwide economic conditions impacted lenders participating in our credit facilities and our customers, and another economic shock could cause them to fail to meet their obligations to us. The slowdown in economic activity caused by the recession also reduced worldwide demand for energy and resulted in an extended period of lower oil and natural gas prices. Crude oil prices, although rebounded from the low levels experienced in early 2009, 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.

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. We may also be subject to property, environmental and other damage claims by oil and gas companies. Our insurance policies and contractual rights to indemnity may not adequately cover losses, and we do not have insurance coverage or rights to indemnity for all risks. There are also risks following the loss of control of a well, such as a blowout or cratering, including the cost to regain control of or redrill the well and associated pollution. Damage to the environment could also result from our operations, particularly through oil spillage or extensive uncontrolled fires.

The South China Sea, the Northwest Coast of Australia and the U.S. 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.

We have two main types of insurance coverage: (1) hull and machinery coverage for property damage and (2) excess liability coverage, which generally covers offshore risks, such as personal injury, third-party property claims, and third-party non-crew claims, including wreck removal and pollution. We generally have no coverage for hull and machinery exposure for named storms in the U.S. Gulf of Mexico and war perils worldwide. We also generally self-insure coverage on our Standard Jackup fleet and our swamp barge for expenses incurred by ADTI and CMI related to well control and redrill liability for well blowouts. As of December 31, 2011 the aggregate net carrying amount of the Standard Jackup fleet and swamp barge is approximately $1.6 billion.

With respect to our hull and machinery coverage, we maintain a $125 million per occurrence deductible for damage to our rigs and offshore drilling equipment included in the coverage. However, in the event of a total loss of such a drilling unit there is no deductible. We also maintain per occurrence deductibles on such rigs that generally range up to $10 million for various third-party liabilities and an additional aggregate annual self-insured retention of $50 million.

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With respect to the remaining $950 million excess liability coverage, we generally retain the risk for any liability in excess of this coverage; however, our wholly-owned captive insurance company has underwritten $132 million of this policy in addition to the $50 million self-insured retention noted above, and we re-insured $25 million of this amount in 2011. There is no guarantee that we will be successful in re-insuring any or all of this amount, and we may retain the risks associated with this portion of our excess liability coverage.

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 generally retain the risk 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 have decided to generally retain the risk associated with our Standard Jackup and barge fleets and we could decide to retain substantially more risk 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.

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.

Legislation to regulate emissions of GHGs has been introduced in the U.S. Congress, and there has been a wide-ranging policy debate, both in the U.S. and internationally, regarding the impact of these gases and possible means for their regulation. Some of the proposals would require industries to meet stringent new standards that would require substantial reductions in carbon emissions. Those reductions could be costly and difficult to implement. In addition, efforts have been made and continue to be made in the international community toward the adoption of international treaties or protocols that would address global climate change issues, such as the United Nations Climate Change Conference in Copenhagen in 2009. Also, the U.S. Environmental Protection Agency (“EPA”) has undertaken new efforts to collect information regarding GHG emissions and their effects. Following a finding by the EPA that certain GHGs represent an endangerment to human health, EPA finalized motor vehicle GHG standards, the effect of which could reduce demand for motor fuels refined from crude oil, and a final rule to address permitting of GHG emissions from stationary sources under the Clean Air Act’s Prevention of Significant Deterioration and Title V programs. Additionally, EPA has issued a “Mandatory Reporting of Greenhouse Gases” final rule, which establishes a new comprehensive scheme requiring operators of stationary sources in the U.S. emitting more than established annual thresholds of carbon dioxide-equivalent GHGs to inventory and report their GHG emissions annually. In late 2010, EPA finalized new GHG reporting requirements for upstream petroleum and natural gas systems, which will be added to EPA’s GHG Reporting Rule, and will require facilities containing petroleum and natural gas systems that emit 25,000 metric tons or more of CO2 equivalent per year to report annual GHG emissions, with the first report due on March 31, 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. Historically, competition for the labor required for drilling operations, including for turnkey drilling and drilling management services businesses and construction projects, has intensified as the number of rigs activated, added to worldwide fleets or under construction increased, leading to shortages of qualified personnel in the industry and creating upward pressure on wages and higher turnover. We may experience a reduction in the experience level of our personnel as a result of any increased turnover, which could lead to higher downtime and more operating incidents, which in turn could decrease revenues and increase costs. If increased competition for labor were to intensify in the future we may experience increases in costs or limits on operations.

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.

In addition to the litigation surrounding the Macondo well incident and the Frade field incident, we are subject to a variety of other litigation. 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. Further, 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.

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Insurance may not be applicable or sufficient in all cases, insurers may not remain solvent, and policies may not be located, and liabilities associated to the Macondo well incident may exhaust some or all of the insurance available to cover certain claims. 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. We are also subject to a number of significant tax disputes. 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.

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.

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, however, are generally not insured against risk of loss due to perils such as terrorist acts, civil unrest, expropriation, nationalization and acts of war.

Other risks

We have significant carrying amounts of goodwill and long-lived assets that are subject to impairment testing.

At December 31, 2011, the carrying amount of our property and equipment was $22.5 billion, representing 64 percent of our total assets, and the carrying amount of our goodwill was $3.2 billion, representing nine percent of our total assets. In accordance with our critical accounting policies, we review our property and equipment for impairment when events or changes in circumstances indicate that carrying amounts of our assets held and used may not be recoverable, and we conduct impairment testing for our goodwill when events and circumstances indicate that the fair value of a reporting unit may have fallen below its carrying amount.

As of October 1, 2011, we recognized an estimated loss of $5.2 billion on the impairment of goodwill associated with our contract drilling services reporting unit due to a decline in projected cash flows and market valuations for this reporting unit. In the fourth quarter of 2010, we recognized a loss of $1.0 billion on the impairment of our Standard Jackup asset group due to projected declines in dayrates and utilization, and we have previously recognized other losses on impairment of goodwill and other intangible assets. Continued or future expectations of low dayrates and utilization could result in the recognition of additional losses on impairment of our long-lived asset groups, particularly with respect to our High-Specification Jackups, or our goodwill or other intangible assets if future cash flow expectations, based upon information available to management at the time of measurement, indicate that the carrying amount of our asset groups, goodwill or other intangible assets may be impaired.

A change in tax laws, treaties or regulations, or their interpretation, of any country in which we have operations, are incorporated or are resident 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, including the use of “management and control” provisions to determine corporate residency, and proposals that could override certain tax treaties and limit treaty benefits on certain payments by U.S. subsidiaries to non-U.S. affiliates. Additionally, the U.S. Congress has recently introduced a proposal which would disallow any deduction for otherwise tax deductible payments relating to any incident resulting in the discharge of oil into navigable waters, such as the Macondo well incident.

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Any material change in tax laws or policies, or their interpretation, resulting from such legislative proposals or inquiries could result in a higher effective tax rate on our worldwide earnings and such change could have a material adverse effect on our statement of financial position, results of operations and cash flows.

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

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

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

The Norwegian authorities have issued criminal indictments against two of our subsidiaries alleging misleading or incomplete disclosures in Norwegian tax returns for the years of 1999 through 2002, as well as civil actions based upon inaccuracies in Norwegian statutory financial statements for the periods of 1996 through 2001. We cannot be certain that the Norwegian authorities will not be successful in proving their allegations in a Norwegian court of law. If they are successful, our earnings and cash flows from operations could be adversely affected.

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. 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.

There is significant legal authority supporting this position, including statutory provisions, legislative history, case law and 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, the IRS subsequently has formally announced that it does not agree with the decision in that case. Moreover, 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.

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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.

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 non-U.S. NOL carryforwards, and we could be required to record an additional valuation allowance against our non-U.S. 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. At the annual general meeting on May 13, 2011, our shareholders approved our current authorized share capital, which expires on May 13, 2013 and was limited to 19.99 percent of our existing share capital. In connection with our December 2011 issuance of shares, our available authorized share capital decreased to 10.17 percent of our existing share capital. 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 CHF 15, equivalent to $16.48 based on a foreign exchange rate of USD 1.00 to CHF 0.91 on February 22, 2012), 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.

Distributions to shareholders in the form of a par value reduction and dividend distributions out of qualifying additional paid-in capital are not currently subject to the 35 percent Swiss federal withholding tax. Dividend distributions out of qualifying additional paid-in capital do not require registration with the Commercial Register of the Canton of Zug. However, the Swiss withholding tax rules could also be changed in the future. Due to the continuing debate in the Swiss political arena, we cannot provide assurance that the current Swiss law with respect to distributions out of additional paid-in capital will not be changed or that a change in Swiss law will not adversely affect us or our shareholders, in particular as a result of distributions out of additional paid-in capital becoming subject to Swiss federal withholding tax or subject to additional corporate law restrictions. 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 is limited. If we are unable to make a distribution through a reduction in par value, or 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 repurchase price less the par value, and since January 1, 2011, to the extent attributable to qualifying additional paid-in capital, if any. At our 2009 annual general meeting, our shareholders approved the repurchase of up to CHF 3.5 billion of our shares for cancellation (the “Share Repurchase Program”). On February 12, 2010, our board of directors authorized our management to implement the Share Repurchase Program. 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. 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, our ability to use the “virtual second trading line” is 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 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.

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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, subject to obtaining shareholder approval every two years, at any time during a maximum two-year period, which is currently scheduled to expire on May 13, 2013, to issue up to a specified number of shares, currently approximately 10.17 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 for a conditional share capital that authorizes the issuance of additional shares up to a maximum amount of 50 percent of the share capital registered in the commercial register without obtaining additional shareholder approval through: (1) the exercise of conversion, exchange, option, warrant or similar rights for the subscription of shares granted in connection with bonds, options, warrants or other securities newly or already issued in national or international capital markets or new or already existing contractual obligations by or of any of our subsidiaries; or (2) in connection with the issuance of shares, options or other share-based awards;

§	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 company;

§	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.

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 the following:

§	principal executive offices in Vernier, Switzerland;

§	corporate offices in Zug, Switzerland; Houston, Texas; Cayman Islands, Barbados and Luxembourg; and

§	a 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

Macondo well incident

Overview—On April 22, 2010, the Ultra-Deepwater Floater Deepwater Horizon sank after a blowout of the Macondo well caused a fire and explosion on the rig. Eleven persons were declared dead and others were injured as a result of the incident. At the time of the explosion, Deepwater Horizon was located approximately 41 miles off the coast of Louisiana in Mississippi Canyon Block 252 and was contracted to BP America Production Co.

The MDL Court has issued an order outlining the trial plan, which will proceed in three phases. The first phase will focus on issues arising out of the conduct of various parties, relevant to the loss of well control at the Macondo well, the ensuing fire and explosion on Deepwater Horizon on April 20, 2010, the sinking of Deepwater Horizon on April 22, 2010, and the initiation of the release of oil during those time periods. The second phase will address conduct relating to stopping the release of hydrocarbons between April 22, 2010 and approximately September 19, 2010, and seek to determine the amount of oil actually released during that time period.

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The third, and final, phase will involve consideration of issues relating to containing oil discharged by controlled burning, application of dispersants, use of booms, skimming and other methods, as well as issues pertaining to the migration paths and end locations of oil released.

Trial is currently scheduled to commence on March 5, 2012. There can be no assurance as to the outcome of the trial, that the trial will proceed according to the proposed schedule, that we will not enter into a settlement as to some or all of the matters related to the Macondo well incident, including those to be determined at the trial, or as to the timing or terms of any such settlement.

We are currently unable to estimate the full impact the Macondo well incident will have on us. We have recognized a liability for estimated loss contingencies that we believe are probable and for which a reasonable estimate can be made. As of December 31, 2011, we have recognized a liability for such loss contingencies in the amount of $1.2 billion. This liability takes into account certain events related to the litigation and investigations arising out of the incident. There are loss contingencies related to the Macondo well incident that we believe are reasonably possible and for which we do not believe a reasonable estimate can be made. These contingencies could increase the liabilities we ultimately recognize. As of December 31, 2011, we have also recognized an asset of $220 million associated with the portion of our estimated losses that we believe is recoverable from insurance. Although we have available policy limits that could result in additional amounts recoverable from insurance, we are not currently able to estimate the amount of such additional recoverable amounts. Our estimates involve a significant amount of judgment. As a result of new information or future developments, some of which could occur very soon, we may adjust our estimated loss contingencies arising out of the Macondo well incident, and the resulting liabilities could have a material adverse effect on our consolidated statement of financial position, results of operations and cash flows. See “—Contractual indemnity.”

Litigation—As of December 31, 2011, 349 actions or claims were pending against us and certain of our subsidiaries, along with other unaffiliated defendants, in state and federal courts. Additionally, government agencies have initiated investigations into the Macondo well incident. We have categorized below the nature of the legal actions or claims. We are evaluating all claims and intend to vigorously defend any claims and pursue any and all defenses available. In addition, we believe we are entitled to contractual defense and indemnity for all wrongful death and personal injury claims made by non-employees and third-party subcontractors’ employees as well as all liabilities for pollution or contamination, other than for pollution or contamination originating on or above the surface of the water. See “—Contractual indemnity.”

Wrongful death and personal injury—As of December 31, 2011, we and one or more of our subsidiaries have been named, along with other unaffiliated defendants, in 34 complaints that were pending in state and federal courts in Louisiana and Texas involving multiple plaintiffs that allege wrongful death and other personal injuries arising out of the Macondo well incident. Per the order of the Multi-District Litigation Panel (the “MDL”), these claims have been centralized for discovery purposes in the MDL Court. The complaints generally allege, among other things, negligence and seek awards of unspecified economic damages and punitive damages. BP, MI-SWACO, Weatherford Ltd. and Cameron International Corporation and certain of its affiliates, have, based on contractual arrangements, also made indemnity demands upon us with respect to personal injury and wrongful death claims asserted by our employees or representatives of our employees against these entities. See “—Contractual indemnity.”

Economic loss—As of December 31, 2011, we and one or more of our subsidiaries were named, along with other unaffiliated defendants, in 114 individual complaints as well as 184 putative class-action complaints that were pending in the federal and state courts in Louisiana, Texas, Mississippi, Alabama, Georgia, Kentucky, South Carolina, Tennessee, Florida and possibly other courts. The complaints generally allege, among other things, economic losses as a result of environmental pollution arising out of the Macondo well incident and are based primarily on OPA and state OPA analogues. Certain claims were dismissed in a court ruling on August 26, 2011. See “—Environmental matters.” The plaintiffs are generally seeking awards of unspecified economic, compensatory and punitive damages, as well as injunctive relief. See “—Contractual indemnity.”

Federal securities claims—Two federal securities law class actions are currently pending in the U.S. District Court, Southern District of New York, naming us and certain of our officers and directors as defendants. One of these actions generally allege violations of Section 10(b) of the Securities Exchange Act of 1934 (the “Exchange Act”), Rule 10b-5 promulgated under the Exchange Act and Section 20(a) of the Exchange Act in connection with the Macondo well incident. The plaintiffs are generally seeking awards of unspecified economic damages, including damages resulting from the decline in our stock price after the Macondo well incident. The other action was filed by a former GlobalSantaFe Corporation (“GlobalSantaFe”) shareholder, alleging that the proxy statement related to our shareholder meeting in connection with our merger with GlobalSantaFe violated Section 14(a) of the Exchange Act, Rule 14a-9 promulgated thereunder and Section 20(a) of the Exchange Act. The plaintiff claims that GlobalSantaFe shareholders received inadequate consideration for their shares as a result of the alleged violations and seeks rescission and compensatory damages. The defendants have filed motions to dismiss each of these claims, and the plaintiffs have responded. The motions have been fully briefed and are pending rulings by the courts.

Shareholder derivative claims—In June 2010, two shareholder derivative suits were filed by our shareholders naming us as a nominal defendant and certain of our officers and directors as defendants in the District Courts of the State of Texas. The first case generally alleges breach of fiduciary duty, unjust enrichment, abuse of control, gross mismanagement and waste of corporate assets in connection with the Macondo well incident and the other generally alleges breach of fiduciary duty, unjust enrichment and waste of corporate assets in connection with the Macondo well incident.

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The plaintiffs are generally seeking, on behalf of us, restitution and disgorgement of all profits, benefits and other compensation from the defendants. Under current schedule orders, an amended consolidated complaint must be filed by the plaintiffs by March 5, 2012.

Limitation of liability action—At the instruction of our insurers and to preserve our insurance coverage, pursuant to the federal Limitation of a Shipowner’s Liability Act (the “Limitation Act”), we filed a complaint in the Houston Division of the Southern District of Texas on May 13, 2010 regarding the casualty of the Deepwater Horizon rig. The action has been transferred to the U.S. District Court, Eastern District of Louisiana for further proceedings. Under the Limitation Act, a vessel owner is generally liable only for the post-accident value of the vessel and cargo as long as the vessel owner can show that it had no knowledge of or privity of knowledge with entities that were negligent. Claims limited under the Limitation Act include personal injury, wrongful death, and damage to property contained on the rig.

Pursuant to the Limitation Act, we are seeking an injunction staying certain lawsuits underway in jurisdictions other than the Eastern District of Louisiana. In addition, we are seeking to limit our liability for personal injury, wrongful death and damage to property contained on the rig to $27 million, the value of the rig and its freight, including the accounts receivable and accrued accounts receivable, as of April 28, 2010. One objective of the filing is to consolidate lawsuits relating to the Deepwater Horizon casualty and to process these lawsuits and claims in an orderly fashion, before a single federal judge. The filing also seeks to establish a single fund from which legitimate claims may be paid.

Environmental matters—Environmental claims under two different schemes, statutory and common law, and in two different regimes, federal and state, have been asserted against us. See “—Litigation—Economic loss.” Liability under many statutes is imposed without fault, but such statutes often allow the amount of damages to be limited. In contrast, common law liability requires proof of fault and causation, but generally has no readily defined limitation on damages, other than the type of damages that may be redressed. We have described below certain significant applicable environmental statutes and matters relating to the Macondo well incident.

OPA imposes strict liability on responsible parties of vessels or facilities from which oil is discharged into or upon navigable waters or adjoining shore lines. OPA defines the responsible parties with respect to the source of discharge. Responsible parties for discharges are liable for: (1) removal and cleanup costs, (2) damages that result from the discharge, including natural resources damages, generally up to a statutorily defined limit, (3) reimbursement for government efforts and (4) certain other specified damages. For responsible parties of MODUs, the limitation on liability is determined based on the gross tonnage of the vessel. The statutory limits are not applicable, however, if the discharge is the result of gross negligence, willful misconduct, or violation of federal construction or permitting regulations by the responsible party or a party in a contractual relationship with the responsible party.

The National Pollution Funds Center (“NPFC”), a division of the U.S. Coast Guard, is charged with administering the Oil Spill Liability Trust Fund (“OSLTF”). The NPFC collects fines and civil penalties under OPA from responsible parties, as defined in the statute. The payments are directed to the OSLTF. To date, the NPFC has issued twelve invoices to BP, Anadarko Petroleum Corporation (together with its affiliates, “Anadarko”) and MOEX Offshore LLC (together with its affiliates, “MOEX”), as the operator and leasehold owners of the well and, thus, the statutorily defined responsible parties for discharges from the well and wellhead. To date, BP has paid eleven of the twelve invoices. Invoices have also been sent to us, and we have acknowledged responsible party status only with respect to discharges from the vessel on or above the surface of the water, if any.

On December 15, 2010, the DOJ filed a civil lawsuit against us and other unaffiliated defendants. The complaint alleges claims under OPA and the Clean Water Act, including claims for per barrel civil penalties of up to $1,100 per barrel, or up to $4,300 per barrel if gross negligence or willful misconduct is established. The U.S. government has estimated that up to 4.1 million barrels of oil were discharged and subject to penalties. The DOJ reserved its rights to amend the complaint to add new claims and defendants. The complaint asserts that all defendants named are jointly and severally liable for all removal costs and damages resulting from the Macondo well incident. On December 6, 2011, the DOJ filed a motion for partial summary judgment seeking a ruling that we were jointly and severally liable under OPA, and liable for civil penalties under the Clean Water Act, for all of the discharges from the Macondo well on the theory that the discharges not only came from the well, but also came from the blowout preventer and riser, appurtenances of Deepwater Horizon. We believe that the owner or operator of a mobile offshore drilling unit (“MODU”), such as Deepwater Horizon, is only a responsible party with respect to discharges from the vessel that occur on or above the surface of the water. As the responsible party for Deepwater Horizon, we believe we are responsible only for the discharges of oil emanating from the rig above the surface of the water. Therefore, we believe we are not responsible for the discharged hydrocarbons from the Macondo well. On January 9, 2012, we filed our opposition to the motion and filed a cross-motion for partial summary judgment seeking a ruling that we are not liable or the subsurface discharge of hydrocarbons. On February 22, 2012, the MDL Court ruled that we are not liable as a responsible party for damages under OPA with respect to the below surface discharges from the Macondo well. The court also ruled that the below surface discharge was discharged from the well facility, and not from the Deepwater Horizon vessel, within the meaning of the Clean Water Act, and that we therefore are not liable for such discharges as an owner of the vessel under the Clean Water Act. However, the court ruled that the issue of whether we could be held liable for such discharge under the Clean Water Act as an “operator” of the well facility could not be resolved on summary judgment. The court did not determine whether we could be liable for removal costs under OPA, or the extent of such removal costs.

In addition to the civil complaint, the DOJ served us with Civil Investigative Demands (“CIDs”) on December 8, 2010. These demands were part of an investigation by the DOJ to determine if we made false claims, or false statements in support of claims, in connection with the operator’s acquisition of the leasehold interest in the Mississippi Canyon Block 252, Gulf of Mexico and the drilling operations on Deepwater Horizon.

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The DOJ is also conducting a criminal investigation of the Macondo well incident. Other investigations are pending or have been concluded in connection with the incident. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Contingencies—Macondo well incident.”

We have also received claims directly from individuals, pursuant to OPA, requesting compensation for loss of income as a result of the Macondo well incident. BP has accepted responsible party status with the U.S. Coast Guard for the release of hydrocarbons from the Macondo well and has stated its intent to pay all legitimate claims, and we have not paid any of these claims.

Other federal statutes—Several of the claimants have made assertions under other statutes, including the Clean Water Act, the Endangered Species Act, the Migratory Bird Treaty Act, the Clean Air Act, the Comprehensive Environmental Response Compensation and Liability Act and the Emergency Planning and Community Right-to-Know Act.

State environmental laws—As of December 31, 2011, claims had been asserted by private claimants under state environmental statutes in Florida, Louisiana, Mississippi and Texas. As described below, claims asserted by various state and local governments are pending in Alabama, Florida, Louisiana and Texas.

In June 2010, the Louisiana Department of Environmental Quality (the “LDEQ”) issued a consolidated compliance order and notice of potential penalty to us and certain of our subsidiaries asking us to eliminate and remediate discharges of oil and other pollutants into waters and property located in the State of Louisiana, and to submit a plan and report in response to the order. We requested that the LDEQ rescind the enforcement actions against us and our subsidiaries because the remediation actions that are the subject of such orders are actions that do not involve us or our subsidiaries, as we are not involved in the remediation or clean-up activities. Alternatively, if the LDEQ would not rescind the enforcement actions altogether, we requested the LDEQ to dismiss the enforcement actions against us and certain of our subsidiaries as these entities are not proper parties to the enforcement actions and were improperly served. In October 2010, the LDEQ rescinded its enforcement actions against us and our subsidiaries but reserved its rights to seek civil penalties for future violations of the Louisiana Environmental Quality Act.

In September 2010, the State of Louisiana filed a declaratory judgment seeking to designate us as a responsible party under OPA and the Louisiana Oil Spill Prevention and Response Act (“LOSPRA”) for the discharges emanating from the Macondo well. Specifically the declaratory judgment claims (1) that we are a responsible party under OPA for all hydrocarbons discharged from the Macondo well, including underwater discharges of oil from the well head; (2) that we, as a responsible party, are jointly, severally, and strictly liable for the spill from the Macondo well in accordance with OPA; (3) that we are a responsible party under the Louisiana Oil Spill Prevention and Response Act for all hydrocarbons discharged from the Macondo well, including underwater discharges of oil from the well head; (4) that we, as a responsible party, are jointly, severally, and strictly liable for the spill from the Macondo well in accordance with the LOSPRA; and (5) seeks an award Plaintiff’s costs incurred in pursuing this action as allowed by law.

Additionally, suits have been filed by the State of Alabama and the cities of Greenville, Evergreen, Georgiana and McKenzie, Alabama in the U.S. District Court, Middle District of Alabama; the Mexican States of Veracruz, Quintana Roo and Tamaulipas in the U.S. District Court, Western District of Texas; and the City of Panama City Beach, Florida in the U.S. District Court, Northern District of Florida. Suits were also filed by the City of New Orleans, by and on behalf of multiple Parishes, and by or on behalf of the Town of Grand Isle, Grand Isle Independent Levee District, the Town of Jean Lafitte, the Lafitte Area Independent Levee District, The City of Gretna, the City of Westwego, and the City of Harahan in the U.S. District Court, Eastern District of Louisiana. Additional suits were filed by or on behalf of other Parishes in the respective Parish courts and were removed to federal court. A local government master complaint also was filed in which cities, municipalities, and other local government entities can and have joined. Generally, these governmental entities allege economic losses under OPA and other statutory environmental state claims and also assert various common law state claims. The claims have been centralized in the MDL Court and will proceed in accordance with the MDL scheduling order, and the City of Panama City Beach’s claim was voluntarily dismissed.

On August 26, 2011, the MDL Court ruled on the motion to dismiss certain economic loss claims. The court ruled that state law, both statutory and common law, is preempted by maritime law, notwithstanding OPA’s savings provisions. Accordingly, all claims brought under state law were dismissed. Secondly, general maritime law claims that do not allege physical damage to a proprietary interest were dismissed, unless the claim falls into the commercial fisherman exception. The court ruled that OPA claims for economic loss do not require physical damage to a proprietary interest. Third, the MDL Court ruled that presentment under OPA is a mandatory condition precedent to filing suit against a responsible party. Finally, the MDL Court ruled that claims for punitive damages may be available under general maritime law in claims against responsible parties and non-responsible parties. The State of Louisiana and BP each have appealed portions of this ruling.

The Mexican States’ OPA claims were dismissed for failure to demonstrate that recovery under OPA was authorized by treaty or executive agreement. This ruling may be appealed.

By letter dated May 5, 2010, the Attorneys General of the five Gulf Coast states of Alabama, Florida, Louisiana, Mississippi and Texas informed us that they intend to seek recovery of pollution clean-up costs and related damages arising from the Macondo well incident. In addition, by letter dated June 21, 2010, the Attorneys General of the 11 Atlantic Coast states of Connecticut, Delaware, Georgia, Maine, Maryland, Massachusetts, New Hampshire, New York, North Carolina, Rhode Island and South Carolina informed us that their states have not sustained any damage from the Macondo well incident but they would like assurances that we will be responsible financially if damages are sustained.

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We responded to each letter from the Attorneys General and indicated that we intend to fulfill our obligations as a responsible party for any discharge of oil from Deepwater Horizon on or above the surface of the water, and we assume that the operator will similarly fulfill its obligations under OPA for discharges from the undersea well. Other than the lawsuits filed by the states discussed above, no further requests have been made or actions taken subsequent to the initial communication.

Wreck removal—By letter dated December 6, 2010, the Coast Guard requested us to formulate and submit a comprehensive oil removal plan to remove any diesel fuel contained in the sponsons and fuel tanks that can be recovered from Deepwater Horizon. We have conducted a survey of the rig wreckage and have confirmed that no diesel fuel remains on the rig. We have insurance coverage for wreck removal for up to 25 percent of Deepwater Horizon’s insured value, or $140 million, with any excess wreck removal liability generally covered to the extent of our remaining excess liability limits.

Contractual indemnity—Under our drilling contract for Deepwater Horizon, the operator has agreed, among other things, to assume full responsibility for and defend, release and indemnify us from any loss, expense, claim, fine, penalty or liability for pollution or contamination, including control and removal thereof, arising out of or connected with operations under the contract other than for pollution or contamination originating on or above the surface of the water from hydrocarbons or other specified substances within the control and possession of the contractor, as to which we agreed to assume responsibility and protect, release and indemnify the operator. Although we do not believe it is applicable to the Macondo well incident, we also agreed to indemnify and defend the operator up to a limit of $15 million for claims for loss or damage to third parties arising from pollution caused by the rig while it is off the drilling location, while the rig is underway or during drive off or drift off of the rig from the drilling location. The operator has also agreed, among other things, (1) to defend, release and indemnify us against loss or damage to the reservoir, and loss of property rights to oil, gas and minerals below the surface of the earth and (2) to defend, release and indemnify us and bear the cost of bringing the well under control in the event of a blowout or other loss of control. We agreed to defend, release and indemnify the operator for personal injury and death of our employees, invitees and the employees of our subcontractors while the operator agreed to defend, release and indemnify us for personal injury and death of its employees, invitees and the employees of its subcontractors, other than us. We have also agreed to defend, release and indemnify the operator for damages to the rig and equipment, including salvage or removal costs.

Although we believe we are entitled to contractual defense and indemnity, given the potential amounts involved in connection with the Macondo well incident, the operator has sought to avoid its indemnification obligations. In particular, the operator, in response to our request for indemnification, has generally reserved all of its rights and stated that it could not at this time conclude that it is obligated to indemnify us. In doing so, the operator has asserted that the facts are not sufficiently developed to determine who is responsible and has cited a variety of possible legal theories based upon the contract and facts still to be developed. We believe this reservation of rights is without justification and that the operator is required to honor its indemnification obligations contained in our contract and described above.

In April 2011, BP filed a claim seeking a declaration that it is not liable to us in contribution, indemnification, or otherwise. On November 1, 2011, we filed a motion for partial summary judgment, seeking enforcement of the indemnity obligations for pollution and civil fines and penalties contained in the drilling contract with BP. On January 26, 2012, the court ruled that the drilling contract requires BP to indemnify us for compensatory damages asserted by third parties against us related to pollution that did not originate on or above the surface of the water, even if the claim is the result of our strict liability, negligence, or gross negligence. The court also held that BP does not owe us indemnity to the extent that we are held liable for civil penalties under the Clean Water Act or for punitive damages. The court deferred ruling on BP’s argument that we breached the drilling contract or materially increased BP’s risk or prejudiced its rights so as to vitiate BP’s indemnity obligations. Our motion for partial summary judgment and the court’s ruling did not address the issue of contractual indemnity for criminal fines and penalties. The law generally considers contractual indemnity for criminal fines and penalties to be against public policy.

Other legal proceedings

Brazil Frade field incident—On or about November 7, 2011, oil was released from fissures in the ocean floor in the vicinity of a development well being drilled by Chevron off the coast of Rio de Janeiro in the Frade field with Sedco 706. The release was ultimately controlled and the well was plugged. The oil released is in the process of being contained by Chevron.

On or about December 13, 2011, a federal prosecutor in the town of Campos in Rio de Janeiro State filed a civil public action against Chevron and us seeking 20.0 billion Brazilian reals, equivalent to approximately $11.0 billion, and seeking a preliminary and permanent injunction preventing Chevron and us from operating in Brazil. The prosecutor amended the requested injunction on December 15, 2011, to seek to prevent Chevron and us from conducting extraction or transportation activities in Brazil and to seek to require Chevron to stop the release and remediate its effects. The complaint has not been served on us. On January 11, 2012, a judge of the federal court in Campos issued an order finding that the case should be transferred to the federal court in Rio de Janeiro.

On December 21, 2011, a federal police marshal investigating the release filed a report with the federal court in Rio de Janeiro State recommending the indictment of Chevron, us, and 17 individuals, five of which are our employees. The report recommended indictment on four counts, three alleging environmental offenses and one alleging false statements by Chevron in connection with its cleanup efforts. The federal court in Rio de Janeiro State has forwarded the report to the federal court in Campos for a decision on the proper jurisdiction for the matter. In addition, there is a risk that Brazilian authorities could temporarily or permanently enjoin us from further operations in Brazil.

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The drilling services and charter contracts between us and Chevron provides, among other things, for Chevron to indemnify and defend us for claims based on pollution or contamination originating from below the surface of the water, including claims for control or removal or property loss or damage, including but not limited to third-party claims and liabilities, with an excludable amount of $250,000 per occurrence if the claim arises from our negligence.

We believe that we have valid defenses to the threatened civil and criminal claims by the federal prosecutor and intend to defend vigorously against any claims that are brought based on the incident. We also intend to pursue indemnity rights under our contracts with Chevron.

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. Each individual plaintiff was subsequently required to 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 12 cases. The complaints generally allege that the defendants used or manufactured asbestos-containing drilling mud additives for use 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. All of these cases are being governed for discovery and trial setting by a single Case Management Order entered by a Special Master appointed by the Court to reside over all the cases, and none of the seven cases in which we are a named defendant have been scheduled for trial or pre-trial discovery. 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. 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 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, with its insurers and, either directly or indirectly as the beneficiary of a qualified settlement fund, funding from settlements with insurers, assigned rights from insurers and “coverage-in-place” settlement agreements with insurers, and funds received from the communication of certain insurance policies. The subsidiary has been named as a defendant, along with numerous other companies, in lawsuits alleging bodily injury or personal injury as a result of exposure to asbestos. As of December 31, 2011, the subsidiary was a defendant in approximately 950 lawsuits. Some of these lawsuits include multiple plaintiffs and we estimate that there are approximately 2,114 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, 2011, the amounts expended to resolve claims, including both defense fees and expenses and settlement costs, have not been material, all known deductibles have been satisfied or are inapplicable, and the subsidiary’s defense fees and expenses and costs of settlement have been met by insurance made available to the subsidiary. 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 $1.0 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 funding from settlements and claims payments from insurers, assigned rights from insurers and “coverage-in-place” settlement agreements with insurers 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.

Rio de Janeiro tax assessment—In the third quarter of 2006, we received tax assessments of approximately $187 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.

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Brazilian import license assessment—In the fourth quarter of 2010, one of our Brazilian subsidiaries received an assessment from the Brazilian federal tax authorities in Rio de Janeiro of approximately $235 million based upon the alleged failure to timely apply for import licenses for certain equipment and for allegedly providing improper information on import license applications. We responded to the assessment on December 22, 2010, and we currently believe that a substantial majority of the assessment is without merit. 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.

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, as of December 31, 2011, we were 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.

Other environmental matters

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

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

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 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 number 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 statement of financial position, or results of operations. Estimated costs of future expenditures for environmental remediation obligations are not discounted to their present value.

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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 further claimed to receive a right to continue to pursue the original plaintiff’s claims.

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 denial of the motion to dismiss the bankruptcies was appealed. On appeal the bankruptcy cases were ordered to be dismissed, and the bankruptcies were dismissed on June 14, 2010.

On March 10, 2010, GlobalSantaFe and the two subsidiaries filed a declaratory judgment action in State District Court in Houston, Texas against the codefendant and the debtors seeking a declaration that GlobalSantaFe and the two subsidiaries had no liability under legal theories advanced by the codefendant. This action is currently stayed.

On March 11, 2010, the codefendant filed a motion for leave to amend the pending litigation in Avoyelles Parish to add GlobalSantaFe, Transocean Worldwide Inc., its successor and our wholly owned subsidiary, and one of the subsidiaries as well as various additional insurers. Leave to amend was granted and the amended petition was filed. An extension to respond for all purposes was agreed until April 28, 2010 for the debtors, GlobalSantaFe, Transocean Worldwide Inc. and the subsidiary. On April 28, 2010, GlobalSantaFe and its two subsidiaries filed various exceptions seeking dismissal of the Avoyelles Parish lawsuit, which have been denied. Subsequent to denial, GlobalSantaFe and its two subsidiaries filed supervisory writs with the Third Circuit Court of Appeals for the State of Louisiana.

On December 15, 2010, as permitted under the existing Case Management Order, GlobalSantaFe and various subsidiaries served third-party demands joining various insurers in the Avoyelles Parish lawsuit seeking insurance coverage for the claims brought against GlobalSantaFe and such subsidiaries. On January 27, 2011, one of the insurers filed pleadings removing the Avoyelles Parish lawsuit to the United States District Court for the Western District of Louisiana, Alexandria Division (the “Western District Action”). On February 3, 2011, GlobalSantaFe and the two subsidiaries filed motions to dismiss the Western District Action, which are now pending. A motion to remand was filed by the codefendant and a hearing on the motion was held on April 5, 2011. A report and recommendations were issued on April 25, 2011 by the magistrate in favor of granting the motion to remand. Objections to this report were filed with the district court. On September 27, 2011 the district court adopted the report and recommendations and remanded the matter to the state court in Avoyelles Parish. Separately, the removing insurer has filed an appeal of the United States Court of Appeals for the Fifth Circuit challenging the remand order and seeking to stay or enjoin the state court from proceeding until a determination of the appeal. The appeal is currently pending in the initial briefing state.

Subsequent to the remand, a scheduling order has been entered in the Avoyelles Parish lawsuit and a jury trial is set for September 17, 2012. In the interim, discovery is ongoing.

We believe that these legal theories advanced by the codefendant should not be applied against GlobalSantaFe or Transocean Worldwide Inc. 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.

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Item 4.

Mine Safety Disclosures

Not applicable.

Executive Officers of the Registrant

We have included the following information, presented as of February 22, 2012, on our executive officers in Part I of this report in reliance on General Instruction (3) to Form 10-K. The board of directors elects the officers of the Company, generally on an annual basis. There is no family relationship between any of the executive officers named below.

		Age as of
Officer	Office	February 22, 2012
Steven L. Newman	President and Chief Executive Officer	47
Gregory L. Cauthen	Executive Vice President and Chief Financial Officer	54
Nick Deeming	Senior Vice President, General Counsel and Assistant Corporate Secretary	57
Ihab Toma	Executive Vice President, Operations	49

Steven L. Newman is President and Chief Executive Officer and a member of the board of directors of the Company. Before being named as Chief Executive Officer in March 2010, Mr. Newman served as President and Chief Operating Officer from May 2008 to November 2009 and subsequently as President. Mr. Newman’s prior senior management roles included Executive Vice President, Performance from November 2007 to May 2008, 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 to May 2006, and Vice President of Performance and Technology from August 2003 to 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. Mr. Newman received his Bachelor of Science degree in Petroleum Engineering in 1989 from the Colorado School of Mines and his MBA in 1992 from the Harvard University Graduate School of Business. Mr. Newman is also a member of the Society of Petroleum Engineers.

Gregory L. Cauthen is the Company’s interim Executive Vice President and Chief Financial Officer under an employment agreement through June 2012. Mr. Cauthen also assumed the responsibilities of Principal Accounting Officer in January 2012. Mr. Cauthen served as a consultant to the Company from September 2009 to August 2010. Since August 2010, Mr. Cauthen has pursued personal interests. Prior to his retirement in August 2009, Mr. Cauthen was Chief Financial Officer of the Company from December 2001 to August 2009. He was also Treasurer of the Company from March 2001 until July 2003 and served as Vice President, Finance from March 2001 to December 2001. Mr. Cauthen holds a Masters in Accounting degree from the University of Florida, Gainesville.

Nick Deeming is Senior Vice President, General Counsel and Assistant Corporate Secretary of the Company. Before being named to this position in February 2011, Mr. Deeming most recently served as Group General Counsel and Company Secretary of Christie’s International Plc, from 2007 to 2010. Prior to Christie’s, from 2001 to 2007, Mr. Deeming served as Chief Legal Officer of Linde Group AG, formerly BOC Group Plc. He served as the Chief Legal Officer of Sema Group Plc from 1999 to 2001; the Group Legal Director of PPP Healthcare Group Plc from 1990 to 1998, Group Legal Director of the financial services company Target Group Plc from 1986 to 1990, and Head of Legal Services of Burmah Oil Exploration from 1983 to 1986. Mr. Deeming received his law degree in 1977 from Guildhall University, subsequently qualified as a solicitor in 1981 and received his MBA in 1996 from Cranfield University.

Ihab Toma is Executive Vice President, Operations of the Company. Before being named to his current position in August 2011, Mr. Toma served as Executive Vice President, Global Business of the Company from August 2010 to August 2011 and as Senior Vice President, Marketing and Planning of the Company from August 2009 to August 2010. Before joining the Company, Mr. Toma served as Vice President, Sales and Marketing for Europe, Africa and Caspian for Schlumberger Oilfield Services from April 2006 to August 2009. 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. Mr. Toma received his Bachelor’s degree in Electrical Engineering in 1985 from Cairo University.

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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 New York Stock Exchange (“NYSE”) under the symbol “RIG” and on the SIX Swiss Exchange (“SIX”) under the symbol “RIGN.” The following table presents the high and low sales prices of our shares as reported on the NYSE and the SIX for the periods indicated.

	NYSE Stock Price								SIX Stock Price
	2011				2010				2011				2010
	High		Low		High		Low		High		Low		High		Low
First quarter	$	85.98	$	68.89	$	94.88	$	76.96	CHF	79.95	CHF	64.60	CHF	—	CHF	—
Second quarter		83.05		59.30		92.67		41.88		75.80		49.58		101.10		49.90
Third quarter		65.39		47.70		65.98		44.30		55.25		36.52		64.45		46.54
Fourth quarter		60.09		38.21		73.94		61.60		51.70		36.02		72.00		59.15

On February 22, 2012, the last reported sales price of our shares on the NYSE and the SIX was $48.99 per share and CHF 45.06 per share, respectively. On such date, there were 8,915 holders of record of our shares and 350,424,694 shares outstanding.

Shareholder matters—In May 2011, at our annual general meeting, our shareholders approved the distribution of additional paid-in capital in the form of a U.S. dollar denominated dividend of $3.16 per outstanding share, payable in four equal installments of $0.79 per outstanding share, subject to certain limitations. On June 15, 2011, September 21, 2011 and December 21, 2011 we paid the first three installments, in the aggregate amount of $763 million, to shareholders of record as of May 20, 2011, August 26, 2011 and November 25, 2011, respectively.

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 2011, we completed a public offering of 29.9 million shares at a share price of $40.50, equivalent to CHF 37.19 using an exchange rate of $1.00 to CHF 0.9183. On December 5, 2011, we received proceeds from the offering of $1.2 billion, net of underwriting discounts and commissions, estimated issuance costs and the Swiss Federal Issuance Stamp Tax.

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”, subject to certain exceptions. See “—Swiss Withholding Tax—Distributions to Shareholders” and “—Exemption from 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.

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.

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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. See “—Refund of Swiss Withholding Tax on Dividends and Other Distributions.”

Exemption from Swiss Withholding Tax—Distributions to Shareholders

Distributions to shareholders in relation to a reduction of par value are exempt from Swiss withholding tax. Since January 1, 2011, distributions to shareholders out of qualifying additional paid-in capital for Swiss statutory purposes are also exempt from the Swiss withholding tax. On December 31, 2011, the aggregate amount of par value of our outstanding shares was CHF 5.5 billion, equivalent to $5.9 billion, and the aggregate amount of qualifying additional paid-in capital of our outstanding shares was at least CHF 9.8 billion, equivalent to at least $10.4 billion, at an exchange rate of $1.00 to CHF 0.94 on December 31, 2011. Consequently, we expect that a substantial amount of any potential future distributions may be exempt from Swiss withholding tax.

Repurchases of Shares

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. Since January 1, 2011, the portion of the repurchase price that is according to Swiss tax law and practice 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, since January 2011, the related amount of qualifying additional paid-in capital, if any. 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. Because our shares are listed on the SIX, we may repurchase our 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. 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 relation to the U.S. market, we may therefore repurchase such shares using an alternative procedure pursuant to which we repurchase our shares via a "virtual second trading line" from market players, such as banks and institutional investors, who are generally entitled to receive a full refund of the Swiss withholding tax. Currently, 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 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.

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.

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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 Bern, 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 or can be downloaded from the webpage of the Swiss federal tax administration. 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 2011	645	$	46.76	—	$	3,560
November 2011	14,286		50.36	—		3,560
December 2011	2,022		43.26	—		3,560
Total	16,953	$	49.38	—	$	3,560

______________________________

(1)	Total number of shares purchased in the fourth quarter of 2011 includes 16,953 shares withheld by us through a broker arrangement and limited to statutory tax in satisfaction of withholding taxes due upon the vesting of restricted shares 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 CHF 3.5 billion (which is equivalent to approximately $3.7 billion at an exchange rate as of the close of trading on December 31, 2011 of USD 1.00 to CHF 0.94). On February 12, 2010, our board of directors authorized our management to implement the share repurchase program. We may decide, based upon our ongoing capital requirements, the price of our shares, matters relating to the Macondo well incident, 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. Through December 31, 2011, we have repurchased a total of 2,863,267 of our shares under this share repurchase program at a total cost of $240 million ($83.74 per share). See “Part I. Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Sources and Uses of Liquidity—Overview.”

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Item 6. Selected Financial Data

The selected financial data as of December 31, 2011 and 2010 and for each of the three years in the period ended December 31, 2011 have been derived from the audited consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data.” The selected financial data as of December 31, 2009, 2008 and 2007, and for each of the two years in the period ended December 31, 2008 have been derived from our accounting records. 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,
	2011 (a)			2010			2009			2008			2007 (b)
	(In millions, except per share data)

Statement of operations data
Operating revenues	$	9,142		$	9,466		$	11,441		$	12,462		$	6,309
Operating income (loss)		(4,776	)		1,857			4,390			5,298			3,207
Income (loss) from continuing operations		(5,829	)		954			3,196			3,981			3,093
Net income (loss)		(5,632	)		988			3,170			4,029			3,121
Net income (loss) attributable to controlling interest		(5,725	)		961			3,181			4,031			3,121

Per share earnings (loss) from continuing operations
Basic	$	(18.40	)	$	2.88		$	9.95		$	12.48		$	14.44
Diluted	$	(18.40	)	$	2.88		$	9.92		$	12.38		$	13.95

Balance sheet data (at end of period)
Total assets	$	35,088		$	36,811		$	36,436		$	35,182		$	34,356
Debt due within one year		2,039			2,012			1,868			664			6,172
Long-term debt		11,497			9,209			9,849			12,893			10,266
Total equity		15,691			21,375			20,559			17,167			13,382

Other financial data
Cash provided by operating activities	$	1,785		$	3,946		$	5,598		$	4,959		$	3,073
Cash used in investing activities		(1,896	)		(721	)		(2,694	)		(2,196	)		(5,677	)
Cash provided by (used in) financing activities		734			(961	)		(2,737	)		(3,041	)		3,378
Capital expenditures		1,020			1,391			3,041			2,184			1,377
Distributions of qualifying additional paid-in capital		763			—			—			—			—

Per share distributions of qualifying additional paid-in capital	$	2.37		$	—		$	—		$	—		$	—

______________________________

(a)

In October 2011, we completed our acquisition of Aker Drilling ASA and applied the acquisition method of accounting for the business combination. The balance sheet data as of December 31, 2011 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, 2011 include approximately three months of operating results and cash flows for the combined company. In December 2011, we completed a public offering of 29.9 million shares for aggregate net proceeds of $1.2 billion.

(b)

In November 2007, Transocean Inc., a wholly owned subsidiary and our former parent holding company, completed its merger with GlobalSantaFe Corporation (the “Merger”) and applied the acquisition method of accounting for the Merger. 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 Merger with borrowings under a $15.0 billion bridge loan facility.

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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.

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. As of February 14, 2012, we owned or had partial ownership interests in and operated 134 mobile offshore drilling units. As of this date, our fleet consisted of 50 High-Specification Floaters (Ultra-Deepwater, Deepwater and Harsh Environment semisubmersibles and drillships), 25 Midwater Floaters, nine High-Specification Jackups, 49 Standard Jackups and one swamp barge. In addition, we had two Ultra-Deepwater Floater and four High-Specification Jackups under construction.

We have two reportable segments: (1) contract drilling services and (2) drilling management services, formerly a component of our other operations segment. 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 specialize in technically demanding regions of the offshore drilling business with a particular focus on deepwater and harsh environment drilling services. We believe our drilling fleet is one of the most 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.

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.

Our drilling management services segment 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. We provide drilling management services through Applied Drilling Technology Inc., our wholly owned subsidiary, and through ADT International, a division of one of our U.K. subsidiaries (together, “ADTI”).

Significant Events

Business combination—In October 2011, we completed our acquisition of Aker Drilling ASA (“Aker Drilling”), a Norwegian company formerly listed on the Oslo Stock Exchange. In connection with the acquisition, we acquired two Harsh Environment, Ultra-Deepwater semisubmersibles currently operating on long-term contracts in Norway. Additionally, we acquired two Ultra-Deepwater drillships currently under construction at the Daewoo Shipbuilding & Marine Engineering Co. Ltd. shipyard in Korea, which have expected deliveries in 2014. See “—Liquidity and Capital Resources—Sources and Uses of Liquidity.”

Discontinued operations—In February 2011, we sold the subsidiary that owns the High-Specification Jackup Trident 20, located in the Caspian Sea. In March 2011, we engaged an unaffiliated advisor to coordinate the sale of the assets of our oil and gas properties reporting unit, a component of our other operations segment, which comprises the exploration, development and production activities performed by Challenger Minerals Inc. and Challenger Minerals (North Sea) Limited (together, “CMI”). As a result of these actions, we reclassified to discontinued operations the operating results and the assets and liabilities associated with our Caspian Sea operations and our oil and gas operations. In October 2011, we completed the sale of Challenger Minerals (North Sea) Limited, and in February 2012, we entered into an agreement to sell the assets of Challenger Minerals Inc. See “—Results of Operations—Discontinued Operations.”

Bank credit agreement—In November 2011, we entered into the Five-Year Revolving Credit Facility Agreement dated November 1, 2011, which established a $2.0 billion five-year revolving credit facility that is scheduled to expire on November 1, 2016 (the “Five-Year Revolving Credit Facility”). See “—Liquidity and Capital Resources—Sources and Uses of Liquidity.”

Debt issuance—In December 2011, we issued in a public offering $1.0 billion aggregate principal amount of 5.05% Senior Notes due December 2016 (the “5.05% Senior Notes”), $1.2 billion aggregate principal amount of 6.375% Senior Notes due December 2021 (the “6.375% Senior Notes”) and $300 million aggregate principal amount of 7.35% Senior Notes due December 2041 (the “7.35% Senior Notes,” and collectively with the 5.05% Senior Notes and the 6.375% Senior Notes, the “2011 Senior Notes”). We received net proceeds of $2.5 billion from this offering. See “—Liquidity and Capital Resources—Sources and Uses of Liquidity.”

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Debt repurchase—Holders of the 1.50% Series B Convertible Senior Notes due 2037 (“Series B Convertible Senior Notes”) had the option to require Transocean Inc., our wholly owned subsidiary and the issuer of the Series B Convertible Senior Notes, to repurchase all or any part of such holder’s notes on December 15, 2011. As a result, we were required to repurchase an aggregate principal amount of $1.7 billion of our Series B Convertible Senior Notes for an aggregate cash payment of $1.7 billion. On February 15, 2012, we redeemed the remaining $30 million of aggregate principal amount of our Series B Convertible Senior Notes for an aggregate cash payment of $30 million. See “—Liquidity and Capital Resources—Sources and Uses of Liquidity.”

Share issuance—In December 2011, we completed a public offering of 29.9 million shares at a price per share of $40.50, equivalent to CHF 37.19 using an exchange rate of USD 1.00 to CHF 0.9183. We received net proceeds of $1.2 billion from this offering. See “—Liquidity and Capital Resources—Sources and Uses of Liquidity.”

Distribution of qualifying additional paid-in capital—In May 2011, at our annual general meeting, our shareholders approved the distribution of additional paid-in capital in the form of a U.S. dollar denominated dividend of $3.16 per outstanding share, payable in four equal installments of $0.79 per outstanding share, subject to certain limitations. On December 21, 2011, we paid the third installment to shareholders of record as of November 25, 2011. At February 22, 2012, the carrying amount of the unpaid distribution payable was $278 million. See “—Liquidity and Capital Resources—Sources and Uses of Liquidity.”

Impairment of goodwill—As of October 1, 2011, we determined that the goodwill associated with our contract drilling services reporting unit was impaired, and we recognized an estimated loss on impairment of goodwill in the amount of $5.2 billion. See “—Results of Operations—Historical 2011 compared to 2010” and —Critical Accounting Policies and Estimates.”

Contingent liability—In the three months ended December 31, 2011, we recognized an estimated loss of $1.0 billion, recorded in operating and maintenance expense, in connection with the loss contingencies associated with the Macondo well incident that we believe are probable and for which a reasonable estimate can be made. As of December 31, 2011, we have recognized a liability for estimated loss contingencies in the amount of $1.2 billion. See “—Results of Operations—Historical 2011 to compared to 2010”, “—Contingencies—Macondo well incident” and “—Critical Accounting Policies and Estimates—Contingencies.”

Outlook

Drilling market—We expect commodity pricing to remain at levels that continue to support the ongoing exploration and production programs of our customers, resulting in contracting opportunities for all classes within our drilling fleet for the remainder of 2012 and into 2013. Oil price stability and exploration success during 2010 and 2011 have prompted our customers to increase budgets for exploration and production. Utilization and dayrates are improving for most of the asset classes within our drilling fleet, and we expect this trend to continue over the next 18 months. As of February 14, 2012, our contract backlog was $21.4 billion compared to $23.5 billion as of October 17, 2011.

Following the Macondo well incident, the U.S. government implemented enhanced regulations related to offshore drilling in the U.S. Gulf of Mexico. In order to obtain new drilling permits and pursue drilling activities, operators must submit applications that demonstrate compliance with enhanced regulations that require independent third-party inspection, certification of well design and well control equipment and emergency response plans in the event of a blowout, among other requirements. In the first quarter of 2011, the U.S. government began issuing new drilling permits under these enhanced regulations. As of February 14, 2012, authorities approved 37 new drilling permits and 27 new exploration plans under these enhanced regulations to customers utilizing our rigs in the U.S. Gulf of Mexico. Some customers have also elected to voluntarily apply the requirement for third-party inspections and certification to well control equipment operating outside the U.S. Gulf of Mexico, and the application of and compliance with these enhanced requirements has caused and may continue to cause us to experience additional out of service time and incur additional maintenance costs. As a result of the enhanced requirements for third-party inspections and certification of well control equipment, we updated our guidelines under our existing periodic survey and drydock cost policy to include these new inspections and certification costs. Although the enhanced regulations have affected our revenues, costs and out of service time, we are unable to predict, with certainty, the ongoing effect that the enhanced regulations will have on our operations. The backlog associated with the contracts for our remaining rigs in the U.S. Gulf of Mexico was $5.8 billion as of February 14, 2012.

Fleet status—As of February 14, 2012, the uncommitted fleet rates for the remainder of 2012, 2013, 2014 and 2015 are as follows:

	Years ending December 31,
	2012		2013		2014		2015
Uncommitted fleet rate (a)
High-Specification Floaters	18	%	37	%	64	%	79	%
Midwater Floaters	43	%	73	%	84	%	90	%
High-Specification Jackups	24	%	57	%	69	%	75	%
Standard Jackups	45	%	70	%	84	%	97	%

______________________________

(a)	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.

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As of February 14, 2012, we had 17 existing contracts with fixed-price or capped options to extend the contract terms that are exercisable, at the customer’s discretion, any time through their expiration dates. Customers are more likely to exercise fixed-price options when dayrates are higher on new contracts relative to existing contracts, and customers are less likely to exercise fixed-price options when dayrates are lower on new contracts relative to existing contracts. Given current market conditions, we expect that a number of these options will not be exercised by our customers in 2012. Additionally, well-in-progress or similar provisions of our existing contracts may delay the start of higher or lower dayrates in subsequent contracts, and some of the delays could be significant.

High-Specification Floaters—Our Ultra-Deepwater Floater fleet has four remaining Ultra-Deepwater Floaters with availability in 2012. During the fourth quarter 2011, 13 Ultra-Deepwater Floaters were contracted worldwide, and we expect continued customer demand to support high utilization of our Ultra-Deepwater Floater fleet in 2012 and 2013. Additionally, we expect increased demand for Deepwater Floaters to continue to improve in 2012, recently indicated by two new contracts and a contract extension for our Deepwater Floaters. Through our acquisition of Aker Drilling in October 2011, we have enhanced our High-Specification Floater fleet with the addition of two Harsh Environment, Ultra-Deepwater semisubmersible drilling rigs operating under long-term contracts in Norway and two Ultra-Deepwater drillships under construction with expected deliveries in 2014. As of February 14, 2012, we had 36 of our 50 High-Specification Floaters contracted through the end of 2012. We believe continued exploration successes in the major deepwater offshore provinces and the emerging markets will generate additional demand and support our long-term positive outlook for our High-Specification Floater fleet.

Midwater Floaters—For our Midwater Floater fleet, which includes 25 semisubmersible rigs, customer interest has increased with multiple customers interested in available rigs, and we expect to see increased activity in Southeast Asia, the U.K., West Africa and India. We have entered into eight contracts for our Midwater Floater fleet in the fourth quarter of 2011. Although many of the contracts are for short-term work, we also entered into a long-term contract for one unit in India. We believe that future demand will offer new opportunities to extend our active fleet. With the improvement in market conditions, we expect that moored Deepwater Floaters previously competing in the midwater market sector will now be contracted for deepwater opportunities.

High-Specification Jackups—The High-Specification Jackup fleet continues to attract the interest of our customers, evidenced by increased tendering activity that we expect to continue to improve during 2012. As a result, we expect utilization to remain high during this period. We recently entered into one three-year contract for our BMC400 design, High-Specification Jackup Transocean Honor in Angola, currently under construction with operations expected to commence in the first quarter of 2012. As of February 14, 2012, we had one of our existing nine High-Specification Jackups available.

Standard Jackups—With increased tendering activity and high utilization in the high-specification jackup market sector, customers are now showing increased interest in the Standard Jackups, resulting in expected improvements in utilization and opportunities to reactivate some of the idle capacity. We expect this trend to continue through 2012, resulting in new opportunities for our Standard Jackups. We recently reactivated one jackup for a three-year contract in Saudi Arabia. As of February 14, 2012, we had 19 of our 49 Standard Jackups stacked, excluding one that was held for sale. In 2012, we expect increasing demand to provide opportunities to extend our available fleet and to reactivate a few of our Standard Jackups that require minimal reactivation costs.

Operating results—We expect our total revenues for the year ending December 31, 2012 to be higher than our total revenues for the year ended December 31, 2011, primarily due to fewer expected out of service and idle days, increased activity produced by the addition of two Harsh Environment, Ultra-Deepwater semisubmersibles acquired in the Aker Drilling acquisition, and the commencement of operations of our newbuild units delivered in 2011 and to be delivered in 2012. We are unable to predict, with certainty, the full impact that the enhanced regulations, described under “—Drilling market”, will have on our operations in 2012 and beyond.

We expect our total operating and maintenance expenses for the year ending December 31, 2012 to be higher than our total operating and maintenance expenses for the year ended December 31, 2011, primarily due to increased operating costs resulting from the additional rigs acquired in the Aker Drilling acquisition and higher personnel costs resulting from increased salaries and increased drilling activity associated with our newbuild units delivered in 2011 and 2012. Our projected operating and maintenance expenses for the year ending December 31, 2012 are subject to change and could be affected by actual activity levels, rig reactivations, the enhanced regulations described under “—Drilling market”, the Macondo well incident and related contingencies, exchange rates and cost inflation, as well as other factors.

Although we are unable to estimate the full direct and indirect impact that the Macondo well incident will have on our business, the incident has had and could continue to have a material adverse effect on our consolidated statement of financial position, results of operations and cash flows. In the two years ended December 31, 2011, we estimate that the Macondo well incident had a direct and indirect effect of greater than $1.0 billion in lost revenues and incremental costs and expenses associated with extended shipyard projects and increased downtime, both as a result of complying with the enhanced regulations and our customers’ requirements. In one case, the increased downtime has resulted in the recent termination of one of our contracts, which represented backlog of approximately $470 million. In the three months ended December 31, 2011, we recognized an estimated loss of $1.0 billion, recorded in operating and maintenance expense, in connection with loss contingencies associated with the Macondo well incident that we believe are probable and for which a reasonable estimate can be made. Additionally, in the years ended December 31, 2011 and 2010, we incurred incremental costs, primarily associated with legal expenses for lawsuits and investigations, net of expected insurance recoveries, in the amount of $71 million and $139 million, respectively.

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Collectively, the lost contract backlog from the incident and from the recent termination, lost revenues and incremental expenses from extended shipyard projects and increased downtime, loss contingencies associated with the incident and other incremental costs have had an effect of greater than $3.0 billion. See “—Contingencies—Insurance matters” and “Part I., Item 1A. Risk Factors.”

In accordance with our critical accounting policies, 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, and we conduct impairment testing for our goodwill annually and when events and circumstances indicate that the fair value of a reporting unit may have fallen below its carrying amount. As of October 1, 2011, we determined that the goodwill associated with our contract drilling services reporting unit was impaired due to a decline in projected cash flows and market valuations for this reporting unit, and we recognized an estimated loss on impairment of goodwill in the amount of $5.2 billion. In the three months ended December 31, 2010, we determined that the Standard Jackup asset group in our contract drilling services reporting unit was impaired due to projected declines in dayrates and utilization for this asset group, and we recognized a loss on impairment of $1.0 billion (see “—Results of Operations” and “—Critical Accounting Policies and Estimates”). If we are unable to secure new or extended contracts for our active units or the reactivation of any of our stacked units, or if we experience further declines in actual or anticipated dayrates, especially with respect to our High-Specification Jackup fleet, we may be required to recognize additional losses in future periods as a result of an impairment of the carrying amount of one or more of our asset groups. We may be required to recognize additional losses on impairment of goodwill if we determine that the fair value of our contract drilling services reporting unit has declined below its carrying amount. At December 31, 2011, the carrying amount of our property and equipment was $22.5 billion, representing 64 percent of our total assets. The carrying amount of our goodwill was $3.2 billion, representing nine percent of our total assets after the effect of the impairment noted above. See “—Critical Accounting Policies and Estimates” and “Part I., Item 1A. Risk Factors.”

Performance and Other Key Indicators

Contract backlog—The contract backlog for our contract drilling services segment was as follows:

	February 14, 2012		October 17, 2011		February 10, 2011
Contract backlog (a)	(in millions)
High-Specification Floaters
Ultra-Deepwater Floaters	$	12,232	$	14,070	$	15,673
Deepwater Floaters		2,228		2,574		3,383
Harsh Environment Floaters		2,188		2,545		1,900
Total High-Specification Floaters		16,648		19,189		20,956
Midwater Floaters		2,249		2,140		1,912
High-Specification Jackups		1,051		914		129
Standard Jackups		1,434		1,213		936
Swamp Barge		24		30		47
Total	$	21,406	$	23,486	$	23,980

______________________________

(a)

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.

We acquired contract backlog of $901 million in connection with our acquisition of Aker Drilling, measured as of the acquisition date, October 3, 2011.

On December 31, 2011, two of our customers issued a joint notice to our Malaysian operating subsidiary terminating the Deepwater Expedition drilling contract on grounds of extensive downtime. At the time of the termination notice, the drilling contract represented approximately $470 million of our contract backlog.

Our contract backlog includes only firm commitments for our contract drilling services segment, which are represented by signed drilling contracts or, in some cases, by other definitive agreements awaiting contract execution. Our contract backlog includes amounts associated with our newbuild units that are currently under construction. The contractual operating dayrate may be higher than the actual dayrate we ultimately receive or an alternative contractual dayrate, such as a waiting-on-weather rate, repair rate, standby rate or force majeure rate, may apply under certain circumstances. The contractual operating dayrate may also be higher than the actual dayrate we ultimately receive because of a number of factors, including rig downtime or suspension of operations. In certain contracts, the dayrate may be reduced to zero if, for example, repairs extend beyond a stated period of time.

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At February 14, 2012, the contract backlog and average contractual dayrates for our contract drilling services segment were as follows:

			For the years ending December 31,
	Total		2012		2013		2014		2015		Thereafter
Contract backlog (a)	(In millions, except average dayrates)
High-Specification Floaters
Ultra-Deepwater Floaters	$	12,232	$	3,902	$	3,526	$	1,958	$	872	$	1,974
Deepwater Floaters		2,228		876		516		487		240		109
Harsh Environment Floaters		2,188		901		935		327		25		—
Total High-Specification Floaters		16,648		5,679		4,977		2,772		1,137		2,083
Midwater Floaters		2,249		1,218		588		255		133		55
High-Specification Jackups		1,051		255		175		206		164		251
Standard Jackups		1,434		702		455		226		51		—
Swamp Barge		24		24		—		—		—		—
Total contract backlog	$	21,406	$	7,878	$	6,195	$	3,459	$	1,485	$	2,389

Average contractual dayrates (b)
High-Specification Floaters
Ultra-Deepwater Floaters	$	502,000	$	506,000	$	511,000	$	520,000	$	497,000	$	470,000
Deepwater Floaters	$	341,000	$	347,000	$	346,000	$	341,000	$	329,000	$	302,000
Harsh Environment Floaters	$	440,000	$	432,000	$	446,000	$	402,000	$	451,000	$	—
Total High-Specification Floaters	$	464,000	$	461,000	$	474,000	$	470,000	$	449,000	$	456,000
Midwater Floaters	$	284,000	$	290,000	$	298,000	$	258,000	$	239,000	$	264,000
High-Specification Jackups	$	139,000	$	138,000	$	147,000	$	141,000	$	139,000	$