form10_k2012.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, 2012
 
OR
 
¨  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)
 

Transocean Logo
 
 
Zug, Switzerland
98-0599916
(State or other jurisdiction of incorporation or organization)
(I.R.S. Employer Identification No.)
   
10 Chemin de Blandonnet
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 reporting company.  See the 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, 2012, 359,284,907 shares were outstanding and the aggregate market value of shares held by non-affiliates was approximately $16.1 billion (based on the reported closing market price of the shares of Transocean Ltd. on June 29, 2012 of $44.73 and assuming that all directors and executive officers of the Company are “affiliates,” although the Company does not acknowledge that any such person is actually an “affiliate” within the meaning of the federal securities laws).  As of February 20, 2013, 359,542,668 shares were outstanding.
 
DOCUMENTS INCORPORATED BY REFERENCE
 
Portions of the registrant’s definitive Proxy Statement to be filed with the U.S. Securities and Exchange Commission within 120 days of December 31, 2012, for its 2013 annual general meeting of shareholders, are incorporated by reference into Part III of this Form 10-K.
 
 


 
 

 
 
TRANSOCEAN LTD. AND SUBSIDIARIES
 
INDEX TO ANNUAL REPORT ON FORM 10-K
 
FOR THE YEAR ENDED DECEMBER 31, 2012
 

Item
 
Page
     
PART I
     
PART II
     
PART III
     
PART IV
     
     

 
 

 
 
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, claims, settlement and related matters,
 
§  
the impact of the Brazil Frade field 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 a 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,
 
§  
pending or possible transactions, including the timing, benefits and terms thereof,
 
§  
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 United States,
 
§  
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,
 
§  
shipyard, construction and other delays,
 
§  
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.
 

 
- 1 -

 

PART I
 
 
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 20, 2013, we owned or had partial ownership interests in and operated 82 mobile offshore drilling units associated with our continuing operations.  As of this date, the fleet associated with our continuing operations consisted of 48 High-Specification Floaters (Ultra-Deepwater, Deepwater and Harsh Environment semisubmersibles and drillships), 25 Midwater Floaters and nine High-Specification Jackups.  At February 20, 2013, we also had six Ultra-Deepwater drillships and three High-Specification Jackups under construction or under contract to be constructed.
 
 
We specialize in technically demanding regions 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, consisting of floaters and high-specification jackups used in support of offshore drilling activities and offshore support services on a worldwide basis.  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 (“SIX”) 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 “Part II. Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Part II. Item 8. Financial Statements and Supplementary Data—Notes to Consolidated Financial Statements—Note 25—Operating Segments, Geographical Analysis and Major Customers.”
 
 
Recent Developments
 
 
In November 2012, in connection with our efforts to improve the overall technical capabilities of our fleet and dispose of non-strategic assets, we completed the sale of 37 Standard Jackups and one swamp barge to Shelf Drilling Holdings, Ltd. (“Shelf Drilling”).  For a transition period following the completion of the sale transactions, we agreed to continue to operate a substantial portion of the Standard Jackups on behalf of Shelf Drilling and to provide certain other transition services to Shelf Drilling.  Under operating agreements, we agreed to continue to operate these Standard Jackups on behalf of Shelf Drilling for periods ranging from nine months to 27 months, until expiration or novation of the underlying drilling contracts by Shelf Drilling.  As of February 20, 2013, we operated 25 Standard Jackups under operating agreements with Shelf Drilling.  In addition, under a transition services agreement, we agreed to provide certain transition services for a period of up to 18 months following the completion of the sale transactions.  See “Part II. Item 8. Financial Statements and Supplementary Data—Notes to Consolidated Financial Statements—Note 9—Discontinued Operations.”
 
 
In March 2012, we announced our intent to discontinue drilling management services operations in the shallow waters of the United States (“U.S.”) Gulf of Mexico, upon completion of our then-existing contracts.  In December 2012, we completed the final drilling management project and discontinued offering our drilling management services in this region.
 

 
- 2 -

 

 
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.
 
 
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, five Enhanced Enterprise-class and two other Ultra-Deepwater 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 and two other 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 further 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” and (3) “High-Specification Jackups”.
 
 
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 4,500 and 7,500 feet.  Harsh Environment Floaters are capable of drilling in harsh environments in water depths between 1,500 and 10,000 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 have higher capacity derricks, drawworks, mud systems and storage.  Typically, High-Specification Jackups also have deeper water depth capacity than Standard Jackups.
 
 
As of February 14, 2013, we owned and operated a fleet of 82 rigs, excluding rigs under construction, was as follows:
 
§  
48 High-Specification Floaters, which are comprised of:
 
§  
27 Ultra-Deepwater Floaters;
 
§  
14 Deepwater Floaters; and
 
§  
Seven Harsh Environment Floaters;
 
§  
25 Midwater Floaters; and
 
§  
Nine High-Specification Jackups.
 
 
As of February 14, 2013, we also operated a fleet of 25 previously owned Standard Jackups, associated with our discontinued operations, under operating agreements with Shelf Drilling, the buyer of these rigs.  We agreed to continue to operate these rigs, for periods ranging from nine months to 27 months, until expiration or novation of the underlying drilling contracts by Shelf Drilling.  See “Part II.  Item 8. Financial Statements and Supplementary Data—Notes to Consolidated Financial Statements—Note 9—Discontinued Operations.”
 

 
- 3 -

 

 
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, 2013, 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, 2013, 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.
 
 

 
 
Rigs Under Construction (9)
 
     
Water
Drilling
 
     
depth
depth
 
   
Expected
capacity
capacity
Contracted
Name
Type
completion
(in feet)
(in feet)
location
Ultra-Deepwater Floaters
         
Deepwater Asgard
HSD
2Q 2014
12,000
40,000
To be determined
Deepwater Invictus
HSD
2Q 2014
12,000
40,000
U.S. Gulf
DSME 12000 Drillship TBN1
HSD
4Q 2015
12,000
40,000
To be determined
DSME 12000 Drillship TBN2
HSD
2Q 2016
12,000
40,000
To be determined
DSME 12000 Drillship TBN3
HSD
4Q 2016
12,000
40,000
To be determined
DSME 12000 Drillship TBN4
HSD
1Q 2017
12,000
40,000
To be determined
 
High-Specification Jackups
         
Transocean Siam Driller
Jackup
1Q 2013
350
35,000
Thailand
Transocean Andaman
Jackup
2Q 2013
350
35,000
Thailand
Transocean Ao Thai
Jackup
4Q 2013
350
35,000
Thailand
 ______________________________
 
“HSD” means high-specification drillship.

 
- 4 -

 

 
High-Specification Floaters (48)
 
   
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) (e)
HSD
2009
12,000
40,000
U.S. Gulf
Discoverer Inspiration (b) (c) (d) (e)
HSD
2010
12,000
40,000
U.S. Gulf
Deepwater Champion (b) (c) (e)
HSD
2011
12,000
40,000
U.S. Gulf
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
U.S. Gulf
GSF C.R.  Luigs (b)
HSD
2000
10,000
35,000
U.S. Gulf
GSF Jack Ryan (b)
HSD
2000
10,000
35,000
Nigeria
Deepwater Discovery (b)
HSD
2000
10,000
30,000
Brazil
Deepwater Frontier (b)
HSD
1999
10,000
30,000
Australia
Deepwater Millennium (b)
HSD
1999
10,000
30,000
Kenya
Deepwater Pathfinder (b)
HSD
1998
10,000
30,000
U.S. Gulf
Deepwater Expedition (b)
HSD
1999
8,500
30,000
Saudi Arabia
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
Idle
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
Nigeria
 
Deepwater Floaters (14)
         
Deepwater Navigator (b)
HSD
1971/2000
7,200
25,000
Brazil
Discoverer Seven Seas (b)
HSD
1976/1997
7,000
25,000
Sri Lanka
Transocean Marianas (g)
HSS
1979/1998
7,000
30,000
Namibia
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
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)
Pledged as collateral for certain debt instruments or credit facilities.
(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.

 
- 5 -

 

 
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
Idle
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
U.K. N. Sea
Sedco 714
OS
1983/1997
1,600
25,000
U.K. N. Sea
Actinia
OS
1982
1,500
25,000
India
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
Nigeria
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
Transocean Honor (b)
 
2012
400
30,000
Angola
GSF Constellation I
 
2003
400
30,000
Indonesia
GSF Constellation II
 
2004
400
30,000
Gabon
GSF Galaxy I
 
1991/2001
400
30,000
U.K. N. Sea
GSF Galaxy II
 
1998
400
30,000
U.K. N. Sea
GSF Galaxy III
 
1999
400
30,000
U.K. N. Sea
GSF 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.
(b)  
Owned through our 70 percent interest in Transocean Drilling Services Offshore Inc.

 
- 6 -

 

 
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, 2013, the fleet associated with our continuing operations was located in the U.S. Gulf of Mexico (15 units), United Kingdom (“U.K.”) North Sea (12 units), Brazil (10 units), Far East (nine units), Norway (seven units), Nigeria (seven units), India (five units), West African countries other than Nigeria and Angola (five units), Angola (four units), Australia (three units), Canada (two units), Middle East (two units), and Denmark (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 and (3) jackup.  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, which is characterized by marshes, rivers, lakes and shallow bay and coastal water areas, 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.
 
 
Financial Information about Geographic Areas
 
 
The following table presents the geographic areas in which our operating revenues were earned (in millions):
 
   
Years ended December 31,
 
   
2012
   
2011
   
2010
 
Operating revenues
                       
U.S.
 
$
2,472
   
$
1,971
   
$
1,937
 
Norway
   
1,174
     
897
     
765
 
Brazil
   
1,114
     
1,019
     
1,288
 
U.K.
   
1,028
     
1,099
     
1,097
 
Other countries (a)
   
3,408
     
3,041
     
2,862
 
Total operating revenues
 
$
9,196
   
$
8,027
   
$
7,949
 
 
______________________________
(a)
Other countries represents countries in which we operate that individually had operating revenues representing less than 10 percent of total operating revenues earned for any of the periods presented.
 

 
 
The following table presents the geographic areas in which our long-lived assets were located (in millions):
 
   
December 31,
 
   
2012
   
2011
 
Long-lived assets
             
U.S.
 
$
7,395
   
$
6,553
 
Brazil
   
2,285
     
2,185
 
Norway
   
2,072
     
2,067
 
Other countries (a)
   
9,128
     
9,983
 
Total long-lived assets
 
$
20,880
   
$
20,788
 
______________________________
(a)
Other countries represents countries in which we operate that individually had long-lived assets representing less than 10 percent of total long-lived assets for any of the periods presented.

 
- 7 -

 



 
Contract Backlog
 
 
At December 31, 2012, the contract backlog associated with our continuing operations was approximately $29.4 billion, representing a 40.7 percent and 24.6 percent increase compared to the contract backlog associated with our continuing operations at December 31, 2011 and 2010, which was $20.9 billion and $23.6 billion, respectively.  See “Part II. Item 7.  Management’s Discussion and Analysis of Financial Condition and Results of Operations—Outlook—Drilling market” and “Part II. 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.  See “Item 1A. Risk Factors—Risks related to our business—Our business involves numerous operating hazards.”
 
 
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 (“CWA”) 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.  Courts also restrict indemnification for criminal fines and penalties.  See “Part II. Item 8. Financial Statements and Supplementary Data—Notes to Consolidated Financial Statements—Note 17—Commitments and Contingencies—Macondo well incident—Contractual indemnity.”
 

 
- 8 -

 

 
Drilling Management Services
 
 
We provide drilling management services primarily on a turnkey basis through Applied Drilling Technology Inc., a Texas corporation and our wholly owned subsidiary, which primarily operates in non-U.S. market sectors outside of the North Sea, 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 drilling management 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 management 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.
 
 
In March 2012, we announced our intent to discontinue drilling management services operations in the shallow waters of the U.S. Gulf of Mexico, a component of our drilling management services segment, upon completion of our then existing contracts.  In December 2012, we completed the final project for our drilling management services operations in the U.S. Gulf of Mexico and discontinued offering our drilling management services in the U.S.
 
 
Revenues from the continuing operations of our drilling management services represented less than three percent of our consolidated revenues from continuing operations for the year ended December 31, 2012.  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.
 
 
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, 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 65 percent interest in Angola Deepwater Drilling Company Limited (“ADDCL”), a consolidated Cayman Islands joint venture company formed to own Discoverer Luanda.  Our local partner, Angco Cayman Limited, a Cayman Islands company, holds the remaining 35 percent interest in ADDCL.  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.
 
 
We hold a 70 percent interest in Transocean Drilling Services Offshore Inc. (“TDSOI”), a consolidated British Virgin Islands joint venture company formed to own Transocean Honor.  Our local partner, Angco II, a Cayman Islands company, holds the remaining 30 percent interest in TDSOI.  Under certain circumstances, Angco II 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 jackup, subject to certain adjustments.
 
 
We hold a 65 percent interest in TSSA – Servicos de Apoio, Lda. (“TSSA”), a consolidated Angola limited liability company formed to operate Discoverer Luanda and Transocean Honor.  Our local partner, Angco Cayman Limited, a Cayman Islands company, holds the remaining 35 percent interest in TSSA.  Under a management services agreement with TSSA, we provide operating management services for Discoverer Luanda and Transocean Honor.
 
 
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 oil companies and independent oil companies.  For the year ended December 31, 2012, our most significant customers were Chevron Corporation, BP America Production Co. (together with its affiliates, “BP”) and Petrobras, accounting for approximately 11 percent, 11 percent and 10 percent, respectively, of our consolidated operating revenues from continuing operations.  No other customers accounted for 10 percent or more of our consolidated operating revenues from continuing operations in the year ended December 31, 2012.  See “Item 1A. Risk Factors—Risks related to our business—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.”
 

 
- 9 -

 

 
Employees
 
 
We require highly skilled personnel to operate our drilling units.  Consequently, we conduct extensive personnel recruiting, training and safety programs.  At December 31, 2012, we had approximately 18,400 employees associated with our continuing operations, including approximately 1,700 persons engaged through contract labor providers.  Of our 18,400 employees, approximately 3,000 persons are working under operating agreements with Shelf Drilling and are expected to transition upon expiration of such operating agreements.  Some of our employees working in Angola, the U.K., Nigeria, Norway, Australia and Brazil 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.  Additionally, failure to reach agreement on certain key issues may result in strikes, lockouts or other work stoppages that may materially impact our operations.
 
 
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 year-round Sub-Arctic operations, and the latest generations of ultra-deepwater drillships and semisubmersibles.  Fifteen rigs in our existing fleet, and six of our rigs that are currently under construction, 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 allows offline tubular and riser activities during normal drilling operations and is patented in certain market sectors in which we operate.  In 2011, we acquired two custom designed, semisubmersible drilling rigs, equipped for year-round operations in harsh environments, including those of the Norwegian continental shelf and sub-Arctic waters.  We have three jackup drilling rigs currently under construction that are expected to be capable of constructing wells up to 35,000 feet deep and feature advanced offshore drilling technology, including offline tubular handling features and simultaneous operations support.  In 2012, we entered into shipyard contracts for the construction of four newbuild dynamically positioned Ultra-Deepwater drillships that will be equipped with dual activity, industry-leading hoisting capacity, a second blowout preventer system and will be outfitted to accommodate a future upgrade to a 20,000 psi blowout preventer.  We continue to seek to develop industry-leading technology, including managed pressure drilling solutions, emission monitoring, hybrid power systems, and advanced generator protection.  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
 
 
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.  To date, we have not incurred material 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.
 
 
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.”
 
 
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 U.S. Securities and Exchange Commission (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, which 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.
 

 
- 10 -

 

 
 
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.  In January 2013, we agreed with the U.S. Department of Justice (“DOJ”) to pay $1.4 billion in fines, recoveries and penalties, excluding interest, over a five-year period through 2017, and we may be subject to additional governmental fines or penalties.  These payments will not be deductible for tax purposes, and the criminal fines will not be covered in full by insurance.  Although we have excess liability insurance coverage relating to certain other liabilities associated with the Macondo well incident, our personal injury and other third-party liability insurance coverage is subject to deductibles and overall aggregate policy limits and does not cover criminal fines and penalties.  There can be no assurance that our insurance will ultimately be adequate to cover all of our remaining 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 Macondo well 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.  In the three years ended December 31, 2012, 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.  We also lost approximately $1.1 billion of contract backlog associated with the termination of the Deepwater Horizon contract in April 2010 resulting from the loss of the rig and the termination of another drilling contract in December 2011 resulting from the previously mentioned increased downtime.  Through December 31, 2012, we have recognized estimated losses of $1.9 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 three years ended December 31, 2012, we incurred cumulative incremental costs, primarily associated with legal expenses for lawsuits and investigations, in the amount of $372 million.  Collectively, the lost contract backlog from the incident and from the termination in December 2011, the lost revenues and incremental costs and expenses and other losses have had an effect of greater than $4.0 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.  We have recognized a liability for such loss contingencies in the amount of $1.9 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, 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 11 percent of our consolidated operating revenues from continuing operations for the year ended December 31, 2012.  Ultimately, these factors could have a material adverse effect on our statement of financial position, results of operations or cash flows.
 

 
- 11 -

 


 
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 $42.2 billion in relation to the spill as of February 5, 2013.  As described under “Part II. Item 8. Financial Statements and Supplementary Data—Notes to Consolidated Financial Statements—Note 17—Commitments and 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 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 CWA.  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.
 
 
In addition, in connection with our settlement with the DOJ, we agreed that we will not use payments pursuant to a civil consent decree by and among the DOJ and certain of our affiliates (the “Consent Decree”) as a basis for indemnity or reimbursement from non-insurer defendants named in the complaint by the U.S. or their affiliates.
 
 
Despite our settlement with the DOJ, we could have additional liabilities to the U.S. government and others.  The ultimate outcome of investigations of the Macondo well incident, DOJ lawsuits and our settlement with the DOJ is uncertain.
 
 
On December 15, 2010, the DOJ filed a civil lawsuit against us and other unaffiliated defendants.  The complaint alleged claims under the Oil Pollution Act of 1990 (“OPA”) and the CWA, including claims for per barrel civil penalties.  The complaint asserted 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 CWA, 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 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 CWA, and that we therefore are not liable for such discharges as an owner of the vessel under the CWA.  This ruling is currently being appealed to the Fifth Circuit Court of Appeals.  In addition, the court ruled that the issue of whether we could be held liable for such discharge under the CWA 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.
 
 
The DOJ also conducted a criminal investigation into the Macondo well incident.  On March 7, 2011, the DOJ announced the formation of a task force to investigate possible violations by us and certain unaffiliated parties of the CWA, 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.  On January 3, 2013, we reached an agreement with the DOJ to resolve certain outstanding civil and potential criminal charges against us arising from the Macondo well incident through a cooperation guilty plea agreement by and among the DOJ and certain of our affiliates (the “Plea Agreement”) and the Consent Decree.  As part of this resolution, we agreed to pay $1.4 billion in fines, recoveries and civil penalties, excluding interest, in scheduled payments over a five-year period through 2017, which will decrease our available liquidity capacity.  Our settlement with the DOJ does not release us from liabilities to the U.S. government as to all Macondo-related matters nor does it release all Transocean-related persons and entities.  In particular, this agreement is without prejudice to the rights of the U.S. with respect to all other matters, including certain liabilities under the OPA for removal costs or for damages, damages for injury to, loss of or loss of use of natural resources, including the reasonable cost of assessing the damage, certain claims for a declaratory judgment of liability under OPA already claimed by the U.S., and certain liabilities for response costs and damages, including injury to park system resources, damages for injury to or loss of natural resources and for the cost of any natural resource damage assessments.  Both our criminal Plea Agreement and our civil Consent Decree have received final court approval.  We will incur costs, expenses and be required to devote management and other corporate resources to comply with our agreements with the U.S.  Under these agreements, we will be subject to restrictions and obligations not imposed on other drilling contractors, which may adversely impact us.
 

 
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See “Part II. Item 8. Financial Statements and Supplementary Data—Notes to Consolidated Financial Statements—Note 17—Commitments and Contingencies—Macondo well incident—Litigation.”
 
 
Pursuant to our Plea Agreement, we will be subject to five years’ probation.  Pursuant to the terms of our civil Consent Decree, we will be subject to the restrictions of that decree for an extended period of time that will be at least five years.  Any failure to comply with the Consent Decree or probation could result in additional penalties, sanctions and costs and could adversely affect us.  See “Part II. Item 8. Financial Statements and Supplementary Data—Notes to Consolidated Financial Statements—Note 17—Commitments and Contingencies—Macondo well incident—Litigation.”
 
 
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.  Many of these investigations have resulted in reports that are critical of us and our actions leading up to and in connection with the incident.
 
 
See “Part II. Item 8. Financial Statements and Supplementary Data—Notes to Consolidated Financial Statements—Note 17—Commitments and Contingencies—Macondo well incident—Litigation.”
 
 
We cannot predict the ultimate outcome of the remaining DOJ or other governmental claims 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 or the potential impact of implementing measures resulting from the settlement with the DOJ, our guilty plea or arising 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 standard 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.
 
 
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 requirements applicable to us under the Consent Decree with the DOJ cover safety, environmental, reporting, operational and other matters and are in addition to the regulations applicable to all industry participants and may add additional costs and liabilities.
 
 
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 effect 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.
 

 
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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.  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, a prosecutor in the town of Campos in Rio de Janeiro State sought an injunction 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.  In July 2012, the appellate court granted the requested for preliminary injunction.  On September 22, 2012, the federal court in Rio de Janeiro served us with the preliminary injunction.  The terms of this injunction required us to cease conducting extraction or transportation activities in Brazil within 30 days from the date of service.  On September 28, 2012, the Brazilian Superior Court of Justice partially suspended this preliminary injunction.  As a result of this suspension, the preliminary injunction only applied to our operations in the Campo de Frade field, and we could continue to operate in all other offshore oil and gas fields in Brazil.  On November 27, 2012, the Court of Appeals in Rio de Janeiro ruled unanimously to suspend the entire preliminary injunction order, including the injunction in the Campo de Frade field that had been entered in July 2012.  This ruling was published on December 5, 2012.  The lawsuit will continue in the trial court, and there remains a risk that the preliminary injunction could be reinstated, or that at the conclusion of the case Brazilian authorities could permanently enjoin us from further operations in Brazil.  For the year ended December 31, 2012, our operations in Brazil accounted for 12 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.
 
 
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.
 
 
Oil and gas prices are extremely volatile and are affected by numerous factors, including the following:
 
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worldwide demand for oil and gas, including economic activity in the U.S. and other large energy-consuming markets;
 
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the ability of the Organization of the Petroleum Exporting Countries (“OPEC”) to set and maintain production levels, productive spare capacity and pricing;
 
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the level of production in non-OPEC countries;
 
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the policies of various governments regarding exploration and development of their oil and gas reserves;
 
§  
advances in exploration and development technology;
 
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the discovery rate of new oil and gas reserves;
 
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the rate of decline of existing oil and gas reserves;
 
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laws and regulations related to environmental matters, including those addressing alternative energy sources and the risks of global climate change;
 
§  
the development and exploitation of alternative fuels;
 
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the development of new technology to exploit oil and gas reserves, such as shale oil;
 
§  
adverse weather conditions; and
 
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the worldwide military and political environment, including uncertainty or instability resulting from an escalation or outbreak of armed hostilities, civil unrest or other crises in the Middle East or other geographic areas or acts of terrorism.
 
 
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 near-term commodity prices do not necessarily translate into increased drilling activity since customers’ expectations of longer-term 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, China, 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.
 

 
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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 are also considered.
 
 
Our industry has historically been cyclical and is impacted by oil and gas price levels and volatility.  There have been periods of high demand, short rig supply and high dayrates, followed by periods of low demand, excess rig supply and low dayrates.  Changes in commodity prices can have a dramatic effect on rig demand, and periods of excess rig supply intensify the competition in the industry and often result in rigs being idle for long periods of time.  We 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 rig utilization rates, industry participants have increased the supply of rigs by ordering the construction of new units.  This has historically resulted in an oversupply of rigs and has caused a subsequent decline in dayrates and rig utilization rates, 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.  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 or lead to accelerated stacking of the existing fleet.  A significant number of the newbuild units have not been contracted for work, which may intensify price competition.  Any further increase in construction of new units would likely exacerbate the negative impact on dayrates and utilization rates.  Lower dayrates and rig utilization rates could adversely affect our revenues and profitability.
 
 
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 $12.5 billion and $13.5 billion at December 31, 2012 and 2011, respectively.  This substantial level of debt and other obligations could have significant adverse consequences on our business and future prospects, including the following:
 
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we may not be able to obtain financing in the future for working capital, capital expenditures, acquisitions, debt service requirements, distributions, share repurchases, or other purposes;
 
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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;
 
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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;
 
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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; and
 
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we may be less able to take advantage of significant business opportunities and to react to changes in market or industry conditions than our less levered 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 have material adverse consequences on our business and future prospects, including the following:
 
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limit our ability to access debt markets, including for the purpose of refinancing our existing debt;
 
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cause us to refinance or issue debt with less favorable terms and conditions, which debt may require collateral and restrict, among other things, our ability to pay distributions or repurchase shares;
 
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increase certain fees under our credit facilities and interest rates under agreements governing certain of our senior notes;
 
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cause additional indebtedness of approximately $30 million to become due;
 
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negatively impact current and prospective customers’ willingness to transact business with us;
 
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impose additional insurance, guarantee and collateral requirements;
 
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limit our access to bank and third-party guarantees, surety bonds and letters of credit; and
 
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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.  Any further downgrade by any of the rating agencies could have the effects 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.”
 

 
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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 oil companies and independent oil companies.  For the year ended December 31, 2012, our most significant customers were Chevron, BP and Petrobras, accounting for approximately 11 percent, 11 percent and 10 percent, respectively, of our consolidated operating revenues from continuing operations.  As of February 14, 2013, the aggregate amount of contract backlog associated with our contracts with Chevron, BP and Petrobras was $6.8 billion.  Additionally, in the year ended December 31, 2012, we entered into 10-year drilling contracts with Royal Dutch Shell plc (“Royal Dutch Shell”) for four newbuild Ultra-Deepwater drillships.  As of February 14, 2013, the aggregate amount of contract backlog associated with Royal Dutch Shell was $8.8 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 any of these customers or another significant customer could, at least in the short term, have a material adverse effect on our results of operations and cash flows.
 
 
Significant part or equipment shortages, supplier capacity constraints, supplier production disruptions, supplier quality and sourcing issues or price increases could increase our operating costs, decrease our revenues and adversely impact our operations.
 
 
Our reliance on third-party suppliers, manufacturers and service providers to secure equipment, parts, components and sub-systems used in our operations exposes us to volatility in the quality, prices and availability of such items.  Certain high specification parts and equipment we use in our operations may be available only from a small number of suppliers, manufacturers or service providers, or in some cases must be sourced through a single supplier, manufacturer or service provider.  A disruption in the deliveries from such third-party suppliers, manufacturers or service providers, capacity constraints, production disruptions, price increases, quality control issues, recalls or other decreased availability of parts and equipment could adversely affect our ability to meet our commitments to customers, adversely impact our operations and revenues or increase our operating costs.
 
 
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.
 
 
Our shipyard projects and operations are subject to delays and cost overruns.
 
 
As of February 20, 2013, we had six Ultra-Deepwater Floater and three 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:
 
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availability of suppliers to recertify equipment for enhanced regulations;
 
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shipyard availability, failures and difficulties;
 
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shortages of equipment, materials or skilled labor;
 
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unscheduled delays in the delivery of ordered materials and equipment;
 
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design and engineering problems, including those relating to the commissioning of newly designed equipment;
 
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latent damages or deterioration to hull, equipment and machinery in excess of engineering estimates and assumptions;
 
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unanticipated actual or purported change orders;
 
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disputes with shipyards and suppliers;
 
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failure or delay of third-party vendors or service providers;
 
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strikes, labor disputes and work stoppages;
 
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customer acceptance delays;
 
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adverse weather conditions, including damage caused by such conditions;
 
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terrorist acts, war, piracy and civil unrest;
 
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unanticipated cost increases; and
 
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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.
 

 
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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 some offshore areas, we may be liable for damages and costs incurred in connection with oil spills or waste disposals related to those operations.  Laws and regulations protecting the environment 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.  In addition, our Consent Decree and probation arising out of our guilty plea agreement with the DOJ add to these regulations, requirements and liabilities.  Numerous lawsuits, including one brought by the DOJ, allege that we may have liability under the environmental laws relating to the Macondo well incident.  Our guilty plea to negligently discharging oil into the U.S. Gulf of Mexico in connection with the Macondo well incident caused us to incur such liabilities.  We may be subject to additional liabilities and penalties.  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 or other third parties 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 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 significant downtime or impaired performance caused by equipment or operational issues, or sustained periods of downtime due to force majeure events.  Many of these events are beyond our control.  During periods of depressed market conditions, we 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, including their ability to fulfill their indemnity obligations to us, may also be negatively impacted by an economic downturn.  Our customers, which include national oil companies, often have significant bargaining leverage over us.  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.
 
 
At February 14, 2013, the contract backlog associated with our continuing operations was approximately $28.8 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.
 
 
Several factors could cause rig downtime or a suspension of operations, including:
 
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breakdowns of equipment and other unforeseen engineering problems;
 
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work stoppages, including labor strikes;
 
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shortages of material and skilled labor;
 
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surveys by government and maritime authorities;
 
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periodic classification surveys;
 
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severe weather, strong ocean currents or harsh operating conditions; and
 
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force majeure events.
 
 
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 in the past and these liquidity issues could be experienced again if commodity prices decline to lower levels for an extended period of time.  Liquidity issues could lead our customers to go into bankruptcy or could encourage our customers to seek to repudiate, cancel or renegotiate these agreements for various reasons, as described under “Our drilling contracts may be terminated due to a number of events” above.  Our inability to realize the full amount of our contract backlog may have a material adverse effect on our consolidated statement of financial position, results of operations or cash flows.
 

 
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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:
 
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terrorist acts, war, piracy and civil unrest;
 
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seizure, expropriation or nationalization of our equipment;
 
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expropriation or nationalization of our customers’ property;
 
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repudiation or nationalization of contracts;
 
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imposition of trade barriers;
 
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import-export quotas;
 
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wage and price controls;
 
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changes in law and regulatory requirements, including changes in interpretation and enforcement;
 
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involvement in judicial proceedings in unfavorable jurisdictions;
 
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damage to our equipment or violence directed at our employees, including kidnappings;
 
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complications associated with supplying, repairing and replacing equipment in remote locations;
 
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the inability to move income or capital; and
 
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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.  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 or require use of a local agent.  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.
 
 
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, our functional currency, or to other currencies in which we operate.  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.  Ongoing economic challenges may increase some foreign governments’ 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.
 

 
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     Our business involves numerous operating hazards.
 
 
Our operations are subject to the usual hazards inherent in the drilling of oil and gas wells, such as blowouts, reservoir damage, loss of production, loss of well control, punch-throughs, craterings, fires and natural disasters such as hurricanes and tropical storms.  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.  We also generally self-insure coverage for ADTI exposures related to well control and redrill liability for well blowouts.  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.  With respect to the remaining $775 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 the $50 million self-insured retention noted above.
 
 
If a significant accident or other event occurs and is not fully covered by insurance or an enforceable or recoverable indemnity from a customer or, with respect to the Standard Jackups we operate under operating agreements with Shelf Drilling for a transitional period, Shelf Drilling, 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.  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.
 
 
Failure to recruit and retain key personnel could hurt our operations.
 
 
We depend on the continuing efforts of key members of our management, as well as other highly skilled personnel, to operate and provide technical services and support for our business worldwide.  Historically, competition for the personnel 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 qualified personnel were to intensify in the future we may experience increases in costs or limits on operations.
 

 
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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., Nigeria, Norway, Australia and Brazil, 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.
 
 
Worldwide financial and economic conditions could cause our ability to access the capital markets to 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.  Worldwide economic conditions have in the past impacted, and could in the future impact, the lenders participating in our credit facilities and our customers, causing them to fail to meet their obligations to us.  A slowdown in economic activity could reduce worldwide demand for energy and result in an extended period of lower oil and natural gas prices.  A decline in oil and natural gas prices, could reduce demand for our drilling services and have a material adverse effect on our revenue, profitability and financial position.
 
 
Failure to comply with the U.S. Foreign Corrupt Practices Act and the U.K. Bribery Act 2010 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 U.K. Bribery Act 2010, which became effective 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.
 
 
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, shareholders, 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.”
 

 
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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 Doha in 2012.  Also, the U.S. Environmental Protection Agency (“EPA”) has undertaken 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, the 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 commencing when the motor vehicle standards took effect on January 2, 2011.  Facilities containing petroleum and natural gas systems that emit 25,000 metric tons or more of CO2 equivalent per year are now required to report annual GHG emissions to the EPA.
 
 
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 or limit drilling opportunities.  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.
 
 
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.  Insurance may not be applicable or sufficient in all cases, insurers may not remain solvent, and policies may not be located, and liabilities associated with 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, including a trial on criminal and civil charges that commenced in Norway in late 2012.  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, piracy 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, piracy and social unrest could lead to increased volatility in prices for crude oil and natural gas and could affect the markets for drilling services.  Insurance premiums could increase and coverages may be unavailable in the future.  U.S. government regulations may effectively preclude us from actively engaging in business activities in certain countries.  These regulations could be amended to cover countries where we currently operate or where we may wish to operate in the future.
 
 
Our contracts do not generally provide indemnification against loss of capital assets or loss revenues resulting from acts of terrorism, piracy or social unrest.  We have limited insurance coverage for physical damage losses resulting from risks, such as terrorist acts, piracy, civil unrest, expropriation and acts of war, for our assets, but we do not carry insurance for loss of revenues resulting from such risks.
 

 
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Other risks
 
 
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, in November 2011 and again in February 2013, the U.S. Congress 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.  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 U.S. 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.  This trial is currently ongoing.  We cannot be certain that the Norwegian authorities will not be successful in proving their allegations in a Norwegian court of law.  An unfavorable outcome on the Norwegian civil or criminal tax matters could result in a material adverse effect on our consolidated statement of financial position, results of operations or cash flows.
 

 
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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.  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 have significant carrying amounts of goodwill and long-lived assets that are subject to impairment testing.
 
 
At December 31, 2012, the carrying amount of our property and equipment was $20.9 billion, representing 61 percent of our total assets, and the carrying amount of our goodwill was $3.0 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.
 
 
In the year ended December 31, 2012, in connection with the sale of 38 drilling units to Shelf Drilling, we recognized losses of $744 million and $112 million on the impairment of long-lived assets and goodwill, respectively, attributable to the transactions.  As a result of our goodwill impairment test, performed as of October 1, 2011, we recognized aggregate losses of $5.3 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.  Future expectations of low dayrates or rig utilization rates 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 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 or goodwill may be impaired.
 

 
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We have significant exposure to losses resulting from our contractual relationships with Shelf Drilling and its affiliates.
 
 
In connection with our sale transactions with Shelf Drilling, we have agreed to indemnify Shelf from certain liabilities, and Shelf Drilling has agreed to indemnify us from certain liabilities and make certain payments to us.  However, the indemnity from Shelf Drilling may not be sufficient to protect us against the full amount of liabilities to third parties, and Shelf Drilling may not be willing or able to satisfy its indemnification or payment obligations in the future.
 
 
Pursuant to the agreements we entered into with Shelf Drilling, including purchase agreements, operating agreements with respect to rigs that we continue to operate on behalf of Shelf Drilling and a transition services agreement, we have agreed to indemnify Shelf Drilling from certain liabilities, and Shelf Drilling has agreed to indemnify us from certain liabilities (including, without limitation, liabilities related to operational risks with respect to Shelf Drilling's rigs, liabilities related to credit support we are providing to Shelf Drilling and certain liabilities related to employees) and make certain payments to us.  However, third parties could seek to hold us responsible for the liabilities with respect to which Shelf Drilling has agreed to indemnify us.  In addition, the indemnity may not be sufficient to protect us against the full amount of such liabilities, and Shelf Drilling may not be willing or able to satisfy its indemnification or payment obligations to us. Moreover, even if we ultimately succeed in recovering from Shelf Drilling any amounts for which we are held liable, we may be temporarily required to bear these losses ourselves.  Each of these risks could adversely affect our business, results of operations and financial condition.
 
 
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 carryforwards before they expire.  We have established a valuation allowance against the future tax benefit for a number of our non-U.S. net operating loss 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 net operating loss carryforwards are subject to review and potential disallowance upon audit by the tax authorities of the jurisdictions where the net operating losses 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 and May 2012 issuance of new shares, our available authorized share capital decreased to 7.61 percent of our existing stated 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 $16.13 based on a foreign exchange rate of CHF 0.93 to USD 1.00 on February 20, 2013, 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 7.61 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.
 
 
Unresolved Staff Comments
 
 
None.
 
 
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; and
 
    §  
corporate offices in Zug, Switzerland; Houston, Texas; Cayman Islands; Barbados and Luxembourg.
 
 
Our remaining offices and bases are located in various countries in North America, South America, the Caribbean, Europe, Africa, the Middle East, India, the Far East and Australia.  We lease most of these facilities.
 

 
- 25 -

 


 
Legal Proceedings
 
 
We have certain actions, claims and other matters pending as discussed and reported in “Part II. Item 8. Financial Statements and Supplementary Data—Notes to Consolidated Financial Statements—Note 17—Commitments and Contingencies” and “Part II. Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Contingencies—Macondo well incident” in this annual report on Form 10-K for the year ended December 31, 2012.  We are also involved in various tax matters as described in “Part II. Financial Statements and Supplementary Data—Notes to Condensed Consolidated Financial Statements—Note 8—Income Taxes” and in “Part II. Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Contingencies—Tax matters” in this annual report on Form 10-K for the year ended December 31, 2012.  All such actions, claims, tax and other matters are incorporated herein by reference.
 
 
As of December 31, 2012, we were also involved in a number of other lawsuits and other matters which have arisen in the ordinary course of our business and for which we do not expect the liability, if any, resulting from these lawsuits to have a material adverse effect on our current consolidated financial position, results of operations or cash flows.  We cannot predict with certainty the outcome or effect of any of the matters referred to above or of any such other pending or threatened litigation or legal proceedings.  There can be no assurance that our beliefs or expectations as to the outcome or effect of any lawsuit or other matters will prove correct and the eventual outcome of these matters could materially differ from management’s current estimates.
 
 
Mine Safety Disclosures
 
 
Not applicable.
 
 
Executive Officers of the Registrant
 
 
We have included the following information, presented as of February 20, 2013, 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 20, 2013
Steven L. Newman
 
President and Chief Executive Officer
 
48
Esa Ikäheimonen
 
Executive Vice President, Chief Financial Officer
 
49
Allen M. Katz
 
Interim Senior Vice President and General Counsel
 
64
John B. Stobart
 
Executive Vice President, Chief Operating Officer
 
58
Ihab Toma
 
Executive Vice President, Chief of Staff
 
49
David Tonnel
 
Senior Vice President, Finance and Controller
 
43
 
 
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 from the Colorado School of Mines in 1989 and received his Master of Business Administration from the Harvard University Graduate School of Business in 1992.  Mr. Newman is also a member of the Society of Petroleum Engineers.
 
 
Esa Ikäheimonen is Executive Vice President, Chief Financial Officer of the Company.  Before being named Executive Vice President, Chief Financial Officer in November 2012, Mr. Ikäheimonen served as a consultant to the Company from September 2012 to November 2012.  He has served as a non-executive director and the chairman of the audit committee of Ahlstrom Corporation since April 2011.  Mr. Ikäheimonen served as Senior Vice President and Chief Financial Officer of Seadrill Ltd. from August 2010 to September 2012, and he served as Executive Vice President and Chief Financial Officer of Poyry plc from March 2009 to July 2010.  At Royal Dutch Shell, Mr. Ikäheimonen served as Vice President Finance, Shell Africa E&P from June 2007 to March 2009, as Vice President Finance, Shell Upstream Middle East from January 2007 to June 2007, and as Finance and Commercial Director, Shell Qatar from May 2004 to January 2007.  Prior to May 2004, Mr. Ikäheimonen served in various financial roles for Royal Dutch Shell, including Strategy and Portfolio Manager, Shell Europe Oil Products, Finance Director, Shell Scandinavia, and Finance Director, Shell Finland.  Mr. Ikäheimonen received his Master of Laws degree from the University of Turku in Finland in 1989.
 

 
- 26 -

 


 
Allen M. Katz is Interim Senior Vice President and General Counsel of the Company.  Before joining the Company in November 2012, he served as an advisor to the Company from June 2010 to November 2012, in his capacity as an attorney at Munger, Tolles & Olson, LLP.  Mr. Katz was in retirement from May 1996 to June 2010.  He practiced as a partner with Munger, Tolles & Olson, LLP from 1974 to 1996, and served as Managing Partner of the firm from 1991 to 1995.  Mr. Katz received his Bachelor of Arts in History from Brandeis University in Massachusetts in 1969 and received his Juris Doctorate from Stanford Law School in 1972.  Mr. Katz is a member of the California, 5th and 9th Circuit bars and is admitted to practice before the U.S. Supreme Court.
 
 
John B. Stobart is Executive Vice President, Chief Operating Officer of the Company.  Before joining the Company in October 2012, Mr. Stobart served as Vice President, Global Drilling for BHP Billiton Petroleum from July 2011 to October 2012.  At BHP Billiton, he also served as Worldwide Drilling Manager for BHP Billiton in Australia, the U.K. and the U.S. from January 1995 to June 2011 and as Senior Drilling Engineer, Senior Drilling Supervisor, Drilling Superintendent and Drilling Manager in the United Arab Emirates, Oman, India, Burma, Malaysia, Vietnam and Australia from June 1988 to December 1994.  Mr. Stobart served as Engineering Manager at Husky/Bow Valley from November 1984 to May 1988, and he worked in engineering roles at Dome Petroleum/Canadian Marine Drilling from May 1980 to October 1984.  He began his career working on land rigs in Canada and the High Arctic in June 1971.  Mr. Stobart received his Bachelor of Science in Mechanical Engineering from the University of Calgary in 1980 and completed the London Business School Accelerated Development Program in 2000.
 
 
Ihab Toma is Executive Vice President, Chief of Staff of the Company.  Before being named to his current position in October 2012, Mr. Toma served as Executive Vice President, Operations from August 2011 to October 2012.  Mr. Toma also served as Executive Vice President, Global Business from August 2010 to August 2011 and as Senior Vice President, Marketing and Planning 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 Limited from April 2006 to August 2009.  Prior to April 2006, Mr. Toma led Schlumberger Information Solutions in various capacities, including Vice President, Sales and Marketing, President of Schlumberger Information Solutions, Vice President of Information Management and Vice President of Europe, Africa and CIS Operations.  He started his career with Schlumberger Limited in 1986.  Mr. Toma received his Bachelor of Science in Electrical Engineering from Cairo University in 1985.
 
 
David Tonnel is Senior Vice President, Finance and Controller of the Company.  Before being named to his current position in March 2012, Mr. Tonnel served as Senior Vice President of the Europe and Africa Unit from June 2009 to March 2012.  Mr. Tonnel served as Vice President of Global Supply Chain from November 2008 to June 2009, as Vice President of Integration and Process Improvement from November 2007 to November 2008, and as Vice President and Controller from February 2005 to November 2007.  Prior to February 2005, he served in various financial roles, including Assistant Controller; Finance Manager, Asia Australia Region; and Controller, Nigeria.  Mr. Tonnel joined the Company in 1996 after working for Ernst & Young in France as Senior Auditor.  Mr. Tonnel received his Master of Science in Management from Ecole des Hautes Etudes Commerciales in Paris, France in 1991.
 

 
- 27 -

 

PART II
 
 
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
 
   
2012
   
2011
   
2012
   
2011
 
   
High
   
Low
   
High
   
Low
   
High
   
Low
   
High
   
Low
 
First quarter
 
$
59.03
   
$
38.80
   
$
85.98
   
$
68.89
   
CHF
54.30
   
CHF
36.70
   
CHF
79.95
   
CHF
64.60
 
Second quarter
   
56.36
     
39.32
     
83.05
     
59.30
     
50.80
     
37.92
     
75.80
     
49.58
 
Third quarter
   
50.38
     
43.04
     
65.39
     
47.70
     
49.06
     
41.55
     
55.25
     
36.52
 
Fourth quarter
   
49.50
     
43.65
     
60.09
     
38.21
     
46.62
     
40.18
     
51.70
     
36.02
 

 
On February 20, 2013, the last reported sales price of our shares on the NYSE and the SIX was $54.32 per share and CHF 51.15 per share, respectively.  On such date, there were 7,465 holders of record of our shares and 359,542,668 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 United States (“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. On March 21, 2012, we paid the final installment in the aggregate amount of $278 million to shareholders of record as of February 24, 2012.
 
 
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.
 
 
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.
 

 
- 28 -

 

 
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, 2012, the aggregate amount of par value of our outstanding shares was CHF 5.6 billion, equivalent to $6.1 billion, and the aggregate amount of qualifying additional paid-in capital of our outstanding shares was at least CHF 11.2 billion, equivalent to at least $12.2 billion, at an exchange rate of $1.00 to CHF 0.92 on December 31, 2012.  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.
 

 
- 29 -

 


 
Switzerland has entered into bilateral treaties for the avoidance of double taxation with respect to income taxes with numerous countries, including the U.S., whereby under certain circumstances all or part of the withholding tax may be refunded.
 
 
U.S. residents—The Swiss-U.S. tax treaty provides that U.S. residents eligible for benefits under the treaty can seek a refund of the Swiss withholding tax on dividends for the portion exceeding 15 percent, leading to a refund of 20 percent, or a 100 percent refund in the case of qualified pension funds.
 
 
As a general rule, the refund will be granted under the treaty if the U.S. resident can show evidence of:
 
§  
beneficial ownership,
 
§  
U.S. residency, and
 
§  
meeting the U.S.-Swiss tax treaty’s limitation on benefits requirements.
 
 
The claim for refund must be filed with the Swiss federal tax authorities (Eigerstrasse 65, 3003 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 2012
   
11,160
   
$
47.51
   
   
$
3,560
November 2012
   
12,626
     
44.85
   
     
3,560
December 2012
   
3,403
     
46.26
   
     
3,560
Total
   
27,189
   
$
46.12
   
   
$
3,560
______________________________
(1)
Total number of shares purchased in the fourth quarter of 2012 includes 27,189 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 $3.8 billion at an exchange rate as of the close of trading on December 31, 2012 of USD 1.00 to CHF 0.92).  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, 2012, we have repurchased a total of 2.9 million of our shares under this share repurchase program at a total cost of $240 million ($83.74 per share).  See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Sources and Uses of Liquidity—Overview.”
 

 
- 30 -

 

 
Item 6.                 Selected Financial Data
 
 
The selected financial data as of December 31, 2012 and 2011 and for each of the three years in the period ended December 31, 2012 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, 2010, 2009 and 2008, and for each of the two years in the period ended December 31, 2009 have been derived from our accounting records.  We have reclassified the financial data of our discontinued operations for all periods presented.  See “Item 8. Financial Statements and Supplementary Data—Notes and Consolidated Financial Statements—Note 9—Discontinued Operations.”  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,
 
   
2012
 
2011 (a)
 
2010
 
2009
 
2008
 
   
(In millions, except per share data)
 
               
Statement of operations data
                               
Operating revenues
 
$
9,196
 
$
8,027
 
$
7,949
 
$
8,910
 
$
8,917
 
Operating income (loss)
   
1,581
   
(4,762
)
 
2,730
   
3,525
   
3,901
 
Income (loss) from continuing operations
   
816
   
(5,762
)
 
1,863
   
2,426
   
2,736
 
Net income (loss)
   
(211
)
 
(5,677
)
 
969
   
3,170
   
4,029
 
Net income (loss) attributable to controlling interest
   
(219
)
 
(5,754
)
 
926
   
3,181
   
4,031
 
                                 
Per share earnings (loss) from continuing operations
                               
Basic
 
$
2.27
 
$
(18.14
)
$
5.66
 
$
7.56
 
$
8.58
 
Diluted
 
$
2.27
 
$
(18.14
)
$
5.66
 
$
7.54
 
$
8.52
 
                                 
Balance sheet data (at end of period)
                               
Total assets
 
$
34,255
 
$
35,032
 
$
36,814
 
$
36,436
 
$
35,182
 
Debt due within one year
   
1,367
   
2,187
   
2,160
   
1,868
   
664
 
Long-term debt
   
11,092
   
11,349
   
9,061
   
9,849
   
12,893
 
Total equity
   
15,730
   
15,627
   
21,340
   
20,559
   
17,167
 
                                 
Other financial data
                               
Cash provided by operating activities
 
$
2,708
 
$
1,825
 
$
3,906
 
$
5,598
 
$
4,959
 
Cash used in investing activities
   
(389
)
 
(1,896
)
 
(721
)
 
(2,694
)
 
(2,196
)
Cash provided by (used in) financing activities
   
(1,202
)
 
734
   
(961
)
 
(2,737
)
 
(3,041
)
Capital expenditures
   
1,303
   
974
   
1,349
   
2,948
   
2,037
 
Distributions of qualifying additional paid-in capital
   
278
   
763
   
   
   
 
                                 
Per share distributions of qualifying additional paid-in capital
 
$
0.79
 
$
2.37
 
$
 
$
 
$
 
 
______________________________
(a)  
In October 2011, we completed our acquisition of Aker Drilling ASA (“Aker Drilling”) 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.
 

 
- 31 -

 

 
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 “Part I. Item 1. Business,” “Part I. 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 20, 2013, we owned or had partial ownership interests in and operated 82 mobile offshore drilling units associated with our continuing operations.  As of February 20, 2013, our fleet consisted of 48 High-Specification Floaters (Ultra-Deepwater, Deepwater and Harsh Environment semisubmersibles and drillships), 25 Midwater Floaters, and nine High-Specification Jackups.  At February 20, 2013, we also had six Ultra-Deepwater drillships and three High-Specification Jackups under construction or under contract to be constructed.
 
 
We have two operating segments: (1) contract drilling services and (2) drilling management services.  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 and jackups 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.
 
 
In November 2012, in connection with our efforts to improve the overall technical capabilities of our fleet and dispose of non-strategic assets, we completed the sale of 37 Standard Jackups and one swamp barge to Shelf Drilling Holdings, Ltd. (“Shelf Drilling”).  For a transition period following the completion of the sale transactions, we agreed to continue to operate a substantial portion of the Standard Jackups on behalf of Shelf Drilling and to provide certain other transition services to Shelf Drilling.  Under operating agreements, we agreed to continue to operate these Standard Jackups on behalf of Shelf Drilling for periods ranging from nine months to 27 months, until expiration or novation of the underlying drilling contracts by Shelf Drilling.  As of February 20, 2013, we operated 25 Standard Jackups under operating agreements with Shelf Drilling.  Under a transition services agreement, we agreed to provide certain transition services for a period of up to 18 months following the completion of the sale transactions.  See “Part II. Item 8. Financial Statements and Supplementary Data—Notes to Consolidated Financial Statements—Note 9—Discontinued Operations.”
 
 
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 outside of the U.S. through Applied Drilling Technology Inc., our wholly owned subsidiary, and through ADT International, a division of one of our United Kingdom (“U.K.”) subsidiaries (together, “ADTI”).
 
 
Significant Events
 
 
Macondo well incident—On January 3, 2013, we reached an agreement with the U.S. Department of Justice (the “DOJ”) to resolve certain outstanding civil and potential criminal charges against us arising from the Macondo well incident.  As part of this resolution, we agreed to pay $1.4 billion in fines, recoveries and penalties, plus interest, in scheduled payments over a five-year period through 2017.  See “—Contingencies—Macondo well incident.”
 
 
Fleet expansion—In May 2012, we completed construction of the High-Specification Jackup Transocean Honor, and the drilling unit commenced operations under its contract.  See “—Liquidity and Capital Resources—Drilling Fleet.”
 
 
In September 2012, we were awarded 10-year drilling contracts for four newbuild dynamically positioned Ultra-Deepwater drillships.  We also entered into shipyard contracts for the construction of such drillships.  See “—Performance and Other Key Indicators—Contract Backlog” and “—Liquidity and Capital Resources—Drilling Fleet.”
 

 
- 32 -

 


 
Discontinued operations—In November 2012, in connection with our efforts to dispose of non-strategic assets, we completed the sale of 37 Standard Jackups and one swamp barge to Shelf Drilling.  As of February 20, 2013, we operated 25 Standard Jackups under operating agreements with Shelf Drilling.  See “—Operating Results—Discontinued Operations.”
 
 
In December 2012, having completed the final drilling management project in the shallow waters of the U.S. Gulf of Mexico, we discontinued the U.S. operations of our drilling management services segment.  See—“Results of Operations—Discontinued Operations.”
 
 
During the year ended December 31, 2012, we completed the sale of the assets of Challenger Minerals Inc. and Challenger Minerals (Ghana) Limited.  See “—Results of Operations—Discontinued Operations.”
 
 
Dispositions—During the year ended December 31, 2012, we completed the sales of the Deepwater Floaters Discoverer 534 and Jim Cunningham and related equipment.  In connection with the sales, we received aggregate net cash proceeds of $178 million.  See “—Liquidity and Capital Resources—Drilling Fleet.”
 
 
Debt issuance—In September 2012, we issued $750 million aggregate principal amount of 2.5% Senior Notes due October 2017 and $750 million aggregate principal amount of 3.8% Senior Notes due October 2022.  See “—Liquidity and Capital Resources—Sources and Uses of Liquidity.”
 
 
Three-Year Secured Revolving Credit Facility—On October 25, 2012, we entered into a bank credit agreement, which establishes a $900 million senior secured revolving credit facility expiring on October 25, 2015.  See “—Liquidity and Capital Resources—Sources and Uses of Liquidity.”
 
 
Debt repurchase—Holders of the 1.50% Series C Convertible Senior Notes due 2037 (“Series C Convertible Senior Notes”) had the option to require Transocean Inc., our wholly owned subsidiary and the issuer of the Series C Convertible Senior Notes, to repurchase all or any part of such holder’s notes on December 17, 2012.  As a result, we were required to repurchase an aggregate principal amount of $1.7 billion of the Series C Convertible Senior Notes for an aggregate cash payment of $1.7 billion.  On February 7, 2013, we redeemed the remaining $62 million aggregate principal amount of the Series C Convertible Senior Notes for an aggregate cash payment of $62 million.  See “—Liquidity and Capital Resources—Sources and Uses of Liquidity.”
 
 
Transocean Pacific Drilling Inc.—On February 29, 2012, Quantum Pacific Management Limited (“Quantum”) exercised its right, pursuant to a put option agreement, to exchange its interest in Transocean Pacific Drilling Inc. (“TPDI”) for our shares or cash, and, on March 29, 2012, Quantum elected to exchange its interest in TPDI for our shares, net of Quantum’s share of TPDI’s indebtedness.  On May 31, 2012, we issued 8.7 million shares to Quantum in a non-cash exchange for its interest in TPDI.  In August 2012, we paid $72 million as the final cash settlement, representing 50 percent of TPDI’s working capital at May 29, 2012.  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 March 21, 2012, we paid the final installment in the aggregate amount of $278 million to shareholders of record as of February 24, 2012.
 

 
- 33 -

 

Outlook
 
 
Drilling market—We expect the commodity pricing underlying the exploration and production programs of our customers to continue to support contracting opportunities for all asset classes within our drilling fleet in the year ending December 31, 2013.  As of February 14, 2013, the contract backlog for our continuing operations was $28.8 billion compared to $29.7 billion as of October 17, 2012.
 
 
Following the Macondo well incident, the U.S. government implemented enhanced regulations related to offshore drilling in the U.S. Gulf of Mexico, which require operators to submit applications for new drilling permits that demonstrate compliance with such enhanced regulations.  The enhanced regulations 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.  The voluntary application by some of our customers of such third-party inspections and certifications of well control equipment operating outside the U.S. Gulf of Mexico has caused and may continue to cause us to experience additional out of service time and incur additional maintenance costs.  Although the enhanced regulations have affected our revenues, costs and out of service time, we are unable to predict, with certainty, the magnitude with which the enhanced regulations will continue to impact our operations.
 

 
Fleet status—As of February 14, 2013, uncommitted fleet rates for the remainder of 2013, 2014, 2015 and 2016 were as follows:
 
   
2013
 
2014
 
2015
 
2016
Uncommitted fleet rate (a)
               
High-Specification Floaters
 
14
%
 
45
%
 
67
%
 
79
%
Midwater Floaters
 
44
%
 
50
%
 
75
%
 
98
%
High-Specification Jackups
 
9
%
 
31
%
 
49
%
 
75
%
______________________________
(a)  
The uncommitted fleet rate is defined as the number of uncommitted days divided by the total number of available rig calendar days in the measurement period, expressed as a percentage.  An uncommitted day is defined as a calendar day during which a rig is idle or stacked, is not contracted to a customer and is not committed to a shipyard.
 
 
As of February 14, 2013, we had six existing contracts associated with our continuing operations that had 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 are uncertain whether these options will be exercised by our customers in 2013.  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 six units with availability in 2013, and in the second quarter of 2014, the Ultra-Deepwater drillship Deepwater Asgard, is expected to be available to commence operations.  During the fourth quarter of 2012, 12 contracts for Ultra-Deepwater Floaters were entered into worldwide, including two long-term contracts for our High-Specification Floater fleet.  We expect continued customer demand to support high rig utilization rates for the Ultra-Deepwater Fleet and provide opportunities to absorb the near-term supply through 2013.  The Deepwater Floater fleet rig utilization rate for the industry dropped slightly during the fourth quarter of 2012 with some available units in the global fleet coming off contract without immediate follow on work.  However, the tendering activity and contract term remain stable over the previous quarter, and we are in active discussions with our customers on a few of the units available in 2013.  As of February 14, 2013, we had 34 of our 48 High-Specification Floaters contracted through the end of 2013.  Although 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, we may see a flattening of dayrates and more competition for term opportunities in the short term.
 
 
Midwater Floaters—Customer demand for our Midwater Floater fleet, which includes 25 semisubmersible rigs, has continued to increase in the U.K. and Norway with multiple customers interested in available rigs.  We entered into two contracts for our Midwater Floater fleet in the fourth quarter of 2012, one of which was at a leading edge dayrate for this asset class offshore UK.  Based on the customer demand, we continue to believe that we could have new opportunities to extend the contracts on our active fleet available in 2013 and 2014 and reactivate one Midwater Floater in the U.K.  The tendering pace and expected demand outside of the U.K. and Norway has slowed, notably in Brazil, which could have an impact on global utilization and dayrates for this asset class in 2013.
 
 
High-Specification Jackups—Our High-Specification Jackup fleet continues to benefit from the interest of our customers, evidenced by four drilling contracts signed in the fourth quarter 2012.  We believe that the currently high rig utilization rates will continue to prevail during this period and increased tendering and contracting activity to continue through 2013 and into 2014.  As of February 14, 2013, three of our existing nine High-Specification Jackups have availability in 2013.
 
 
Operating results—We expect our total revenues for the year ending December 31, 2013 to be higher than our total revenues for the year ended December 31, 2012, primarily due to increased dayrates, fewer expected out of service and idle days, increased activity for our drilling management services segment and increased drilling activity associated with the commencement of operations of our newbuild unit delivered in 2012 and those newbuild units to be delivered in 2013.  We are unable to predict, with certainty, the full impact that the enhanced regulations, described under “—Drilling market”, will have on our operations for the year ending December 31, 2013 and beyond.
 
 
After adjusting for loss contingencies recognized in the year ended December 31, 2012, we expect our total operating and maintenance expenses for the year ending December 31, 2013 to be higher than our total operating and maintenance expenses for the year ended December 31, 2012, primarily due to higher costs and expenses associated with normal inflationary trends for personnel, maintenance and other operating costs, increased activity for our drilling management services segment, and increased drilling activity associated with the commencement of operations of our newbuild units to be delivered in 2013 and increased shipyard costs.  Our projected operating and maintenance expenses for the year ending December 31, 2013 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 above expectations, as well as other factors.
 
 
Although we are unable to estimate the full direct and indirect effect 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 three years ended December 31, 2012, 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.  We also lost approximately $1.1 billion of contract backlog associated with the termination of the Deepwater Horizon contract in April 2010 resulting from the loss of the rig and the termination of another drilling contract in December 2011 resulting from the previously mentioned increased downtime.  We have recognized estimated losses of $1.9 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.  See Part II. Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Contingencies—Macondo well incident.  Additionally, in the three years ended December 31, 2012, we incurred cumulative incremental costs, primarily associated with legal expenses for lawsuits and investigations, in the amount of $372 million.  Collectively, the lost contract backlog from the incident and from the termination in December 2011, the lost revenues and incremental costs and expenses and other losses have had an effect of greater than $4.0 billion.  See “—Contingencies—Insurance matters.”
 
 
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.  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 declines in actual or anticipated dayrates or other impairment indicators, especially with respect to our High-Specification Jackup fleet, we may be required to recognize losses in future periods as a result of an impairment of the carrying amount of one or more of our asset groups.  At December 31, 2012, the carrying amount of our property and equipment was $20.9 billion, representing 61 percent of our total assets.  See “—Critical Accounting Policies and Estimates.”
 

 
- 34 -

 

Performance and Other Key Indicators
 
 
Contract backlog—The contract backlog for our contract drilling services segment was as follows:
 
   
February 14,
2013
   
October 17,
2012
   
February 14,
2012
 
Contract backlog (a)
 
(In millions)
 
High-Specification Floaters
                       
Ultra-Deepwater Floaters
 
$
19,144
   
$
20,238
   
$
12,232
 
Deepwater Floaters
   
2,127
     
2,339
     
2,228
 
Harsh Environment Floaters
   
1,942
     
2,189
     
2,188
 
Total High-Specification Floaters
   
23,213
     
24,766
     
16,648
 
Midwater Floaters
   
4,145
     
3,403
     
2,249
 
High-Specification Jackups
   
1,486
     
1,493
     
1,051
 
Total
 
$
28,844
   
$
29,662
   
$
19,948
 
 
______________________________
(a)  
Contract backlog is defined as the maximum contractual operating dayrate multiplied by the number of days remaining in the firm contract period, excluding revenues for mobilization, demobilization and contract preparation or other incentive provisions, which are not expected to be significant to our contract drilling revenues.
 
 
The contract backlog represents the maximum contract drilling revenues that can be earned considering the contractual operating dayrate in effect during the firm contract period and represents the basis for the maximum revenues in our revenue efficiency measurement.  To determine maximum revenues for purposes of calculating revenue efficiency, however, we include the revenues earned for mobilization, demobilization and contract preparation, which are excluded from the amounts presented for 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.
 
 
For the year ended December 31, 2012, we added $16.1 billion to our contract backlog for continuing operations, including 10-year drilling contracts for four newbuild dynamically positioned Ultra-Deepwater drillships, which collectively added approximately $7.6 billion to our contract backlog.  In addition, we contracted the newbuild Ultra-Deepwater drillship Deepwater Invictus, currently under construction in Korea, for three years, adding another $700 million to our contract backlog.
 

 
- 35 -

 

 
At February 14, 2013, the contract backlog and average contractual dayrates for our contract drilling services segment were as follows:
 
         
For the years ending December 31,
       
   
Total
   
2013
   
2014
   
2015
   
2016
   
Thereafter
 
Contract backlog (a)
 
(In millions, except average dayrates)
 
High-Specification Floaters
                                               
Ultra-Deepwater Floaters
 
$
19,144
   
$
4,060
   
$
3,182
   
$
1,703
   
$
1,457
   
$
8,742
 
Deepwater Floaters
   
2,127
     
969
     
640
     
403
     
115
     
 
Harsh Environment Floaters
   
1,942
     
1,035
     
763
     
144
     
     
 
Total High-Specification Floaters
   
23,213
     
6,064
     
4,585
     
2,250
     
1,572
     
8,742
 
Midwater Floaters
   
4,145
     
1,411
     
1,645
     
932
     
157
     
 
High-Specification Jackups
   
1,486
     
440
     
478
     
300
     
119
     
149
 
Total contract backlog
 
$
28,844
   
$
7,915
   
$
6,708
   
$
3,482
   
$
1,848
   
$
8,891
 
                                                 
Average-contractual dayrates (b)
                                               
High-Specification Floaters
                                               
Ultra-Deepwater Floaters
 
$
527,000
   
$
528,000
   
$
545,000
   
$
532,000
   
$
504,000
   
$
502,000
 
Deepwater Floaters
 
$
354,000
   
$
367,000
   
$
337,000
   
$
367,000
   
$
302,000
   
$
 
Harsh Environment Floaters
 
$
465,000
   
$
457,000
   
$
472,000
   
$
483,000
   
$
   
$
 
Total High-Specification Floaters
 
$
487,000
   
$
481,000
   
$
492,000
   
$
489,000
   
$
480,000
   
$
502,000
 
Midwater Floaters
 
$
338,000
   
$
323,000
   
$
352,000
   
$
349,000
   
$
258,000
   
$
 
High-Specification Jackups
 
$
150,000
   
$
150,000
   
$
159,000
   
$
146,000
   
$
137,000
   
$
135,000
 
Total fleet average
 
$
396,000
   
$
398,000
   
$
396,000
   
$
377,000
   
$
400,000
   
$
421,000
 
 
______________________________
(a)  
Contract backlog is defined as the maximum contractual operating dayrate multiplied 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.
  (b)
Average contractual dayrate relative to our contract backlog is defined as the maximum contractual operating dayrate to be earned per operating day in the measurement period.  An operating day is defined as a day for which a rig is contracted to earn a dayrate during the firm contract period after commencement of operations.
 
 
Our contract backlog includes amounts associated with our newbuild units that are currently under construction.  The actual amounts of revenues earned and the actual periods during which revenues are earned will differ from the amounts and periods shown in the tables above due to various factors, including shipyard and maintenance projects, unplanned downtime and other factors that result in lower applicable dayrates than the full contractual operating dayrate.  Additional factors that could affect the amount and timing of actual revenue to be recognized include customer liquidity issues and contract terminations, which are available to our customers under certain circumstances.
 

 
- 36 -

 


 
Fleet average daily revenue—The average daily revenue for our contract drilling services segment was as follows:
 
   
Three months ended
 
   
December 31,
2012
   
September 30,
2012
   
December 31,
2011
 
Average daily revenue (a)
                 
High-Specification Floaters
                       
Ultra-Deepwater Floaters
 
$
514,300
   
$
515,000
   
$
490,200
 
Deepwater Floaters
 
$
337,100
   
$
356,300
   
$
315,200
 
Harsh Environment Floaters
 
$
476,400
   
$
421,000
   
$
463,000
 
Total High-Specification Floaters
 
$
469,300
   
$
464,600
   
$
446,100
 
Midwater Floaters
 
$
280,300
   
$
264,500
   
$
264,800
 
High-Specification Jackups
 
$
162,400
   
$
154,600
   
$
107,300
 
Total fleet average daily revenue
 
$
382,000
   
$
376,200
   
$
369,900
 
 
__________________________
(a)  
Average daily revenue is defined as contract drilling revenues earned per operating day.  An operating day is defined as a calendar day during which a rig is contracted to earn a dayrate during the firm contract period after commencement of operations.
 
 
Our average daily revenue fluctuates relative to market conditions.  Our total fleet average daily revenue is also affected by the mix of rig classes being operated, as Midwater Floaters and High-Specification Jackups are typically contracted at lower dayrates compared to  High-Specification Floaters.  We include newbuilds in the calculation when the rigs commence operations upon acceptance by the customer.  We remove rigs from the calculation upon disposal or classification as held for sale.
 
 
Revenue efficiency—The revenue efficiency rates for our contract drilling services segment were as follows:
 
   
Three months ended
 
   
December 31,
2012
   
September 30,
2012
   
December 31,
2011
 
Revenue efficiency (a)
                 
High-Specification Floaters
                       
Ultra-Deepwater Floaters
   
96
%
   
96
%
   
90
%
Deepwater Floaters
   
91
%
   
96
%
   
90
%
Harsh Environment Floaters
   
97
%
   
95
%
   
98
%
Total High-Specification Floaters
   
95
%
   
96
%
   
91
%
Midwater Floaters
   
94
%
   
90
%
   
95
%
High-Specification Jackups
   
95
%
   
97
%
   
93
%
Total fleet average revenue efficiency
   
95
%
   
95
%
   
92
%
 
______________________________
  (a)
Revenue efficiency is defined as actual contract drilling revenues for the measurement period divided by the maximum revenue calculated for the measurement period, expressed as a percentage.  Maximum revenue is defined as the greatest amount of contract drilling revenues the drilling unit could earn for the measurement period, excluding amounts related to incentive provisions.
 
 
Our revenue efficiency rate varies due to revenues earned under alternative contractual dayrates, such as a waiting-on-weather rate, repair rate, standby rate, force majeure rate or zero rate, that may apply under certain circumstances.  We include newbuilds in the calculation when the rigs commence operations upon acceptance by the customer.  We exclude rigs that are not operating under contract, such as those that are stacked.
 

 
- 37 -

 


 
Rig utilization—The rig utilization rates for our contract drilling services segment were as follows:
 
   
Three months ended
 
   
December 31,
2012
   
September 30,
2012
   
December 31,
2011
 
Rig utilization (a)
                 
High-Specification Floaters
                       
Ultra-Deepwater Floaters
   
94
%
   
95
%
   
88
%
Deepwater Floaters
   
64
%
   
63
%
   
55
%
Harsh Environment Floaters
   
72
%
   
91
%
   
96
%
Total High-Specification Floaters
   
82
%
   
85
%
   
78
%
Midwater Floaters
   
72
%
   
70
%
   
57
%
High-Specification Jackups
   
81
%
   
86
%
   
74
%
Total fleet average utilization
   
79
%
   
80
%
   
72
%
 
______________________________
(a)  
Rig utilization is defined as the total number of operating days divided by the total number of available rig calendar days in the measurement period, expressed as a percentage.
 
 
Our rig utilization declines as a result of idle and stacked rigs and during shipyard and mobilization periods to the extent these rigs are not earning revenues.  We include newbuilds in the calculation when the rigs commence operations upon acceptance by the customer.  We remove rigs from the calculation upon disposal or classification as held for sale.
 

 
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Results of Operations
 
 
Historical 2012 compared to 2011
 
 
Following is an analysis of our operating results.  See “—Performance and Other Key Indicators—Fleet average daily revenue” for a definition of revenue earning days and average daily revenue.  See “—Performance and Other Key Indicators—Utilization” for a definition of utilization.
 
 
Years ended December 31,
               
 
2012
   
2011
   
Change
   
% Change
 
 
(In millions, except day amounts and percentages)
 
                       
Revenue earning days
 
23,577
     
20,017
     
3,560
   
18
%
 
Utilization
 
78
%
   
69
%
               
Average daily revenue
$
370,300
   
$
367,600
   
$
2,700
   
1
%
 
                               
Contract drilling revenues
$
8,773
   
$
7,407
   
$
1,366
   
18
%
 
Other revenues
 
423
     
620
     
(197
)
 
(32)
%
 
   
9,196
     
8,027
     
1,169
   
15
%
 
Operating and maintenance expense
 
(6,106
)
   
(6,179
)
   
73
   
(1)
%
 
Depreciation and amortization
 
(1,123
)
   
(1,109
)
   
(14
)
 
1
%
 
General and administrative expense
 
(282
)
   
(288
)
   
6
   
(2)
%
 
Loss on impairment
 
(140
)
   
(5,201
)
   
5,061
   
(97)
%
 
Gain (loss) on disposal of assets, net
 
36
     
(12
)
   
48
   
n/m
   
Operating income (loss)
 
1,581
     
(4,762
)
   
6,343
&#