10-K 1 esv-20121231x10k.htm 10-K ESV-2012.12.31-10K


 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
  Washington, D.C. 20549  
 
FORM 10-K

(Mark One)
ý
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
o
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from                  to                      
 
Commission File Number 1-8097
 
 Ensco plc
(Exact name of registrant as specified in its charter)
England and Wales
(State or other jurisdiction of
incorporation or organization)
 
6 Chesterfield Gardens
London, England
(Address of principal executive offices)
 
98-0635229
(I.R.S. Employer
Identification No.)
 
 
W1J5BQ
(Zip Code)
 
Registrant's telephone number, including area code: +44 (0) 20 7659 4660
 
Securities registered pursuant to Section 12(b) of the Act:
Title of each class
 
Class A Ordinary Shares, U.S. $0.10 par value

 
 
Name of each exchange on which registered       
 
New York Stock Exchange
 
 
 

 
Securities registered pursuant to Section 12(g) of the Act: None
 
Indicate by check mark if the registrant is a well-known seasoned issuer as defined in Rule 405 of the Securities Act.        Yes ý       No  o
 
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.   Yes  o       No ý
 
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 ý       No  o

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 (S232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).   Yes  ý       No o





Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (S229.405) is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  o 
 
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, 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 (Check one):

Large accelerated filer
 
x
  
Accelerated filer
 
o
 
 
 
 
 
 
 
Non-Accelerated filer
 
o  (Do not check if a smaller reporting company)
  
Smaller reporting company
 
o
 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).
Yes o        No ý
 
The aggregate market value of the Class A ordinary shares, (based upon the closing price on the New York Stock Exchange on June 30, 2012 of $46.97) of Ensco plc held by non-affiliates of Ensco plc at that date was approximately $9,156,830,000.
 
As of February 14, 2013, there were 232,709,320 Class A ordinary shares of Ensco plc issued and outstanding.
 
DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Company's Proxy Statement for the 2013 General Meeting of Shareholders are incorporated by reference into Part III of this report.









FORWARD-LOOKING STATEMENTS
 
 
Statements contained in this report that are not historical facts are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended.  Forward-looking statements include words or phrases such as "anticipate," "believe," "estimate," "expect," "intend," "plan," "project," "could," "may," "might," "should," "will" and similar words and specifically include statements regarding expected financial performance; expected utilization, day rates, revenues, operating expenses, contract term, contract backlog, capital expenditures, insurance, financing and funding; the timing of availability, delivery, mobilization, contract commencement or relocation or other movement of rigs; future rig construction (including construction in progress and completion thereof), enhancement, upgrade or repair and timing thereof; the suitability of rigs for future contracts; general market, business and industry conditions, trends and outlook; future operations; the impact of increasing regulatory complexity; expected contributions from our rig fleet expansion program and our program to high-grade the rig fleet by investing in new equipment and divesting selected assets and underutilized rigs; expense management; and the likely outcome of litigation, legal proceedings, investigations or insurance or other claims and the timing thereof.

Such statements are subject to numerous risks, uncertainties and assumptions that may cause actual results to vary materially from those indicated, including:
 
downtime and other risks associated with offshore rig operations or rig relocations, including rig or equipment failure, damage and other unplanned repairs, the limited availability of transport vessels, hazards, self-imposed drilling limitations and other delays due to severe storms and hurricanes and the limited availability or high cost of insurance coverage for certain offshore perils, such as hurricanes in the Gulf of Mexico or associated removal of wreckage or debris;

changes in worldwide rig supply and demand, competition or technology, including changes as a result of delivery of newbuild drilling rigs;

changes in future levels of drilling activity and expenditures, whether as a result of global capital markets and liquidity, prices of oil and natural gas or otherwise, which may cause us to idle or stack additional rigs;

governmental action, terrorism, piracy, military action and political and economic uncertainties, including uncertainty or instability resulting from civil unrest, political demonstrations, mass strikes, or an escalation or additional outbreak of armed hostilities or other crises in oil or natural gas producing areas of the Middle East, North Africa, West Africa or other geographic areas, which may result in expropriation, nationalization, confiscation or deprivation of our assets or result in claims of a force majeure situation;

risks inherent to shipyard rig construction, repair or enhancement, including risks associated with concentration of our construction contracts with two shipyards, unexpected delays in equipment delivery and engineering or design issues following delivery, or changes in the commencement, completion or service dates;

possible cancellation or suspension of drilling contracts as a result of mechanical difficulties, performance or other reasons;

the outcome of litigation, legal proceedings, investigations or other claims or contract disputes, including any inability to collect receivables or resolve significant contractual or day rate disputes, any purported renegotiation, nullification, cancellation or breach of contracts with customers or other parties and any failure to negotiate or complete definitive contracts following announcements of receipt of letters of intent;


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governmental regulatory, legislative and permitting requirements affecting drilling operations, including limitations on drilling locations (such as the Gulf of Mexico during hurricane season);

new and future regulatory, legislative or permitting requirements, future lease sales, changes in laws, rules and regulations that have or may impose increased financial responsibility, additional oil spill abatement contingency plan capability requirements and other governmental actions that may result in claims of force majeure or otherwise adversely affect our existing drilling contracts;

our ability to attract and retain skilled personnel on commercially reasonable terms, whether due to labor regulations, unionization or otherwise;

environmental or other liabilities, risks or losses, whether related to storm or hurricane damage, losses or liabilities (including wreckage or debris removal), collisions, groundings, blowouts, fires, explosions and other accidents or terrorism or otherwise, for which insurance coverage and contractual indemnities may be insufficient, unenforceable or otherwise unavailable;

our debt levels and debt agreement restrictions may limit our liquidity and flexibility in obtaining additional financing and in pursuing other business opportunities;

our ability to realize expected benefits from the December 2009 redomestication as a U.K. public limited company and the related reorganization of Ensco’s corporate structure, including the effect of any changes in laws, rules and regulations, or the interpretation thereof, or in the applicable facts, that could adversely affect our status as a non-U.S. corporation for U.S. tax purposes or otherwise adversely affect our anticipated consolidated effective income tax rate;

delays in actual contract commencement dates;

adverse changes in foreign currency exchange rates, including their effect on the fair value measurement of our derivative instruments; and

potential long-lived asset or goodwill impairments.

In addition to the numerous risks, uncertainties and assumptions described above, you should also carefully read and consider "Item 1A. Risk Factors" in Part I and "Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations" in Part II of this Form 10-K.  Each forward-looking statement speaks only as of the date of the particular statement, and we undertake no obligation to publicly update or revise any forward looking statements, except as required by law.

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PART I

Item 1.  Business

General
Ensco plc is a global offshore contract drilling company. Unless the context requires otherwise, the terms "Ensco," "Company," "we," "us" and "our" refer to Ensco plc together with all its subsidiaries and predecessors.

We are one of the leading providers of offshore contract drilling services to the international oil and gas industry. We own an offshore drilling rig fleet of 74 rigs, including rigs under construction, spanning most of the strategic, high-growth markets around the globe. Our rig fleet includes nine drillships, 13 dynamically positioned semisubmersible rigs, six moored semisubmersible rigs and 46 jackup rigs.  Our fleet is the world's second largest amongst competitive rigs, our ultra-deepwater fleet is the newest in the industry and our premium jackup fleet is the largest of any offshore drilling company.  We currently have three technologically-advanced drillships and three ultra-premium harsh environment jackup rigs under construction as part of our ongoing strategy to continually expand and high-grade our fleet.

Our customers include most of the leading national and international oil companies, in addition to many independent operators. We are among the most geographically diverse offshore drilling companies, with current operations and drilling contracts spanning approximately 20 countries on six continents in nearly every major deepwater and shallow-water basin around the world. The regions in which we operate include major markets in Southeast Asia, Australia, the North Sea, the Mediterranean, the U.S. Gulf of Mexico, Mexico and the Middle East, as well as the fastest-growing floater markets in Brazil and West Africa, where some of the world's most prolific geology resides.

We provide drilling services on a "day rate" contract basis. Under day rate contracts, we provide a drilling rig and rig crews and receive a fixed amount per day for drilling a well. Our customers bear substantially all of the ancillary costs of constructing the well and supporting drilling operations, as well as the economic risk relative to the success of the well. In addition, our customers may pay all or a portion of the cost of moving our equipment and personnel to and from the well site. We do not provide "turnkey" or other risk-based drilling services.
Acquisitions
We have assembled one of the largest and most capable offshore drilling rig fleets in the world. We have grown our rig fleet through corporate acquisitions, rig acquisitions and new rig construction. A total of seven drillships, including rigs under construction, 11 semisubmersible rigs and 31 jackup rigs in our current fleet were obtained through the acquisitions of Penrod Holding Corporation during 1993, Dual Drilling Company during 1996, Chiles Offshore Inc. during 2002 and Pride International, Inc. during 2011.  During 2010, we acquired ENSCO 109, an ultra-high specification jackup rig constructed in 2008. 

On May 31, 2011 (the "Merger Date"), Ensco plc completed a merger transaction (the "Merger") with Pride International, Inc., a Delaware corporation ("Pride"), ENSCO International Incorporated, a Delaware corporation and an indirect, wholly-owned subsidiary and predecessor of Ensco plc ("Ensco Delaware"), and ENSCO Ventures LLC, a Delaware limited liability company and an indirect, wholly-owned subsidiary of Ensco plc ("Merger Sub"). Pursuant to the merger agreement and subject to the conditions set forth therein, Merger Sub merged with and into Pride, with Pride as the surviving entity and an indirect, wholly-owned subsidiary of Ensco plc.  The total consideration delivered in the Merger was $7.4 billion, consisting of $2.8 billion of cash, 85.8 million Ensco ADSs with an aggregate value of $4.6 billion based on the closing price of Ensco ADSs of $53.32 on the Merger Date and the estimated fair value of $35.4 million of vested Pride employee stock options assumed by Ensco.
Drilling Rig Construction and Delivery
We continue to maintain our long-established strategy of high-grading our jackup rig fleet by investing in newer equipment while expanding the size and quality of our floater rig fleet.  During the five-year period ended December 31, 2012, we invested $3.6 billion in the construction of new drilling rigs.

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We previously contracted Keppel FELS Limited ("KFELS") to construct seven 8500 Series® ultra-deepwater semisubmersible rigs (the "ENSCO 8500 Series®" rigs) based on our proprietary design. The ENSCO 8500 Series® rigs are enhanced versions of ENSCO 7500 and are capable of drilling in up to 8,500 feet of water. ENSCO 8500 and ENSCO 8501 were delivered in 2008 and 2009, respectively, and commenced drilling operations in the U.S. Gulf of Mexico under long-term contracts during 2009. ENSCO 8502 was delivered and commenced drilling operations under a long-term contract in the U.S. Gulf of Mexico during 2010. ENSCO 8503 was delivered in 2010, commenced drilling operations in French Guiana under a short-term sublet agreement during the first quarter of 2011 and subsequently commenced drilling operations under a long-term contract in the U.S. Gulf of Mexico during the first quarter of 2012. ENSCO 8504 was delivered and commenced drilling operations under a long-term contract in Brunei during the third quarter of 2011, and ENSCO 8505 was delivered and commenced drilling operations under a long-term contract in the U.S. Gulf of Mexico during the second quarter of 2012. ENSCO 8506, the final rig in the ENSCO 8500 Series®, was delivered during the third quarter of 2012 and commenced drilling operations in the U.S. Gulf of Mexico under a long-term contract during the first quarter of 2013.

In connection with the Merger, we acquired seven drillships, two of which were under construction at the time of the Merger. These newbuild drillships are based on a Samsung Heavy Industries ("SHI") proprietary hull design capable of drilling in water depths of up to 10,000 feet of water. ENSCO DS-6 was delivered in January 2012, underwent customer specified upgrades and commenced drilling operations in Angola under a long-term contract during the first quarter of 2013. ENSCO DS-7 is under construction and scheduled for delivery in the third quarter of 2013. The rig is expected to commence drilling operations under a long-term contract with TOTAL during the fourth quarter of 2013. During the second quarter of 2012, we entered into agreements with SHI to construct two additional ultra-deepwater drillships (ENSCO DS-8 and ENSCO DS-9). These rigs are scheduled for delivery during the second half of 2014 and remain uncontracted.

We previously entered into agreements with KFELS to construct three ultra-high specification harsh environment jackup rigs (ENSCO 120, ENSCO 121 and ENSCO 122).  These rigs are scheduled for delivery during the second quarter and fourth quarter of 2013 and the second half of 2014, respectively.  ENSCO 120 is committed under a long-term drilling contract in the North Sea, while the other two jackup rigs under construction are uncontracted.
Divestitures
Our business strategy has been to focus on ultra-deepwater floater and premium jackup operations, and de-emphasize other assets and operations considered to be non-core or that do not meet our standards for financial performance. Accordingly, we sold our marine transportation service vessel fleet, two platform rigs and two barge rigs during 2003.  We sold one jackup rig and two platform rigs to KFELS during 2004 in connection with the execution of the ENSCO 107 construction agreement.  We disposed of six barge rigs and two platform rigs during 2005 and our last remaining platform rig during 2006. We sold four jackup rigs during 2010 and one jackup rig during 2011. Consistent with this strategy, we sold three jackup rigs, one moored semisubmersible rig and our last remaining barge rig during 2012.
Redomestication
Our predecessor, Ensco Delaware, was formed as a Texas corporation during 1975 and reincorporated in Delaware during 1987.  In December 2009, we completed the reorganization of the corporate structure of the group of companies controlled by Ensco Delaware, pursuant to which an indirect, wholly-owned subsidiary merged with Ensco Delaware, and Ensco plc became our publicly-held parent company incorporated under English law (the "redomestication").

The redomestication was accounted for as an internal reorganization of entities under common control and, therefore, Ensco Delaware's assets and liabilities were accounted for at their historical cost basis and not revalued in the transaction. We remain subject to the U.S. Securities and Exchange Commission ("SEC") reporting requirements, the mandates of the Sarbanes-Oxley Act of 2002, as amended, and the applicable corporate governance rules of the New York Stock Exchange ("NYSE"), and we continue to report our consolidated financial results in U.S. dollars and in accordance with U.S. generally accepted accounting principles ("GAAP"). We also must comply with additional reporting requirements of English law.

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Our principal executive office is located at 6 Chesterfield Gardens, London W1J5BQ, England, United Kingdom, and our telephone number is +44 (0) 20 7659 4660.  Our website is www.enscoplc.com.  Information contained on our website is not included as part of, or incorporated by reference into, this report.
Contract Drilling Operations        
Our business consists of three operating segments: (1) Floaters, which includes our drillships and semisubmersible rigs, (2) Jackups and (3) Other, which currently consists of management services on rigs owned by third-parties. Our two reportable segments, Floaters and Jackups, provide one service, contract drilling.

We currently own an offshore drilling rig fleet of 74 rigs, including rigs under construction. Our expanded rig fleet includes nine drillships, 13 dynamically positioned semisubmersible rigs, six moored semisubmersible rigs and 46 jackup rigs.  Of our 74 rigs, 22 are currently located in the North and South America region (excluding Brazil), ten are located in Brazil, nine are located in the Europe and Mediterranean region, 14 are located in the Middle East and Africa region and 19 are located in the Asia Pacific rim region.
 
Our drilling rigs drill and complete oil and natural gas wells. Demand for our drilling services is based upon many factors beyond our control, including:

market price of oil and natural gas and the stability thereof, 
production levels and related activities of the Organization of Petroleum Exporting Countries ("OPEC") and other oil and natural gas producers, 
global oil supply and demand, 
regional natural gas supply and demand, 
worldwide expenditures for offshore oil and natural gas drilling, 
long-term effect of worldwide energy conservation measures, 
applicable regulatory and legislative restrictions, 
the development and use of alternatives to hydrocarbon-based energy sources, and 
worldwide economic activity.
Our drilling contracts are the result of negotiations with our customers, and most contracts are awarded upon competitive bidding. Our drilling contracts generally contain the following commercial terms:

contract duration extending over a specific period of time or a period necessary to drill one or more wells, 
term extension options in favor of our customer, generally exercisable upon advance notice to us, at mutually agreed, indexed or fixed rates, 
provisions permitting early termination of the contract (i) if the rig is lost or destroyed or (ii) by the customer if operations are suspended for a specified period of time due to breakdown of major rig equipment, unsatisfactory performance, "force majeure" events beyond the control of either party or other specified conditions,
payment of compensation to us (generally in U.S. dollars although some contracts require a portion of the compensation to be paid in local currency) on a "day work" basis such that we receive a fixed amount for each day ("day rate") that the drilling unit is operating under contract (lower rates or no payments ("zero rate") generally apply during periods of equipment breakdown and repair or in the event operations are suspended or interrupted by other specified conditions, some of which may be beyond our control), 

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payment by us of the operating expenses of the drilling unit, including crew labor and incidental rig supply costs, and 
provisions in term contracts allowing us to recover certain labor and other operating cost increases from our customers through day rate adjustment or otherwise.
In addition, some of our drilling contracts permit early termination of the contract by the customer for convenience (without cause), generally exercisable upon advance notice and in some cases without making an early termination payment to us.
 
Financial information regarding our operating segments and geographic regions is presented in Note 13 to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data." Additional financial information regarding our operating segments is presented in "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations."
Backlog Information
Our contract drilling backlog reflects firm commitments, typically represented by signed drilling contracts, and was calculated by multiplying the contracted operating day rate by the firm contract period. The contracted operating day rate excludes certain types of non-recurring revenues for rig mobilization, demobilization, contract preparation, other customer reimbursables, bonus opportunities and amortization of drilling contract intangibles included in “Item 8. Financial Statements and Supplementary Data.” Contract backlog includes drilling contracts signed after each respective balance sheet date but prior to filing each of our annual reports on Form 10-K on February 21, 2013 and February 24, 2012, respectively.

    The following table summarizes our contract backlog of business as of December 31, 2012 and 2011 (in millions):


2012
 
2011
 
 
 
 
Floaters
$
8,278.3

 
$
7,635.5

Jackups
2,424.5

 
1,909.9

Other
145.1

 
120.8

Total
$
10,847.9

 
$
9,666.2


Our Floaters, Jackups and Other segment backlog increased by $642.8 million, $514.6 million and $24.3 million, respectively, primarily due to new contract additions, partially offset by revenues realized during 2012. The following table summarizes our contract backlog of business as of December 31, 2012 and the periods in which such revenues are expected to be realized (in millions):
 
      2013 
 

 
2014

 
2015

 
2016
and Beyond

 
 Total  

Floaters
$
2,817.4

 
$
2,345.9

 
$
1,684.9

 
$
1,430.1

 
$
8,278.3

Jackups
1,193.1

 
764.1

 
311.8

 
155.5

 
2,424.5

Other
77.1

 
55.2

 
12.8

 

 
145.1

Total
$
4,087.6

 
$
3,165.2

 
$
2,009.5

 
$
1,585.6

 
$
10,847.9

 
Our drilling contracts generally contain provisions permitting early termination of the contract (i) if the rig is lost or destroyed or (ii) by the customer if operations are suspended for a specified period of time due to breakdown of major rig equipment, unsatisfactory performance, "force majeure" events beyond the control of either party or other specified conditions.  In addition, some of our drilling contracts permit early termination of the contract by the customer for convenience (without cause), generally exercisable upon advance notice to us and in some cases without making an early termination payment to us.  There can be no assurances that our customers will be able to or willing to fulfill

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their contractual commitments to us.  Therefore, revenues recorded in future periods could differ materially from the backlog amounts presented in the table above.

Major Customers

We provide our contract drilling services to major international, government-owned and independent oil and gas companies. During 2012, our five largest customers accounted for 48% of consolidated revenues. Petrobras, our largest customer, accounted for 24% of 2012 consolidated revenues.
Competition
The offshore contract drilling industry is highly competitive with numerous industry participants. Drilling contracts are, for the most part, awarded on a competitive bid basis. Price competition is often the primary factor in determining which contractor is awarded a contract, although quality of service, operational and safety performance, equipment suitability and availability, location of equipment, reputation and technical expertise also are factors.  We have numerous competitors in the offshore contract drilling industry that have significant resources.
Governmental Regulation
Our operations are affected by political developments and by laws and regulations that relate directly to the oil and gas industry, including laws and regulations that have or may impose increased financial responsibility and oil spill abatement contingency plan capability requirements.  Accordingly, we will be directly affected by the approval and adoption of laws and regulations curtailing exploration and development drilling for oil and natural gas for economic, environmental, safety or other policy reasons. It is also possible that these laws and regulations could adversely affect our operations in the future by significantly increasing our operating costs.  See "Item 1A. Risk Factors - Increasing regulatory complexity could adversely impact the costs associated with our offshore drilling operations."
Environmental Matters
Our operations are subject to laws and regulations controlling the discharge of materials into the environment, pollution, contamination and hazardous waste disposal or otherwise relating to the protection of the environment. Environmental laws and regulations specifically applicable to our business activities could impose significant liability on us for damages, clean-up costs, fines and penalties in the event of oil spills or similar discharges of pollutants or contaminants into the environment or improper disposal of hazardous waste generated in the course of our operations, which may not be covered by contractual indemnification or insurance and could have a material adverse effect on our financial position, operating results and cash flows.  To date, such laws and regulations have not had a material adverse effect on our operating results, and we have not experienced an accident that has exposed us to material liability arising out of or relating to discharges of pollutants into the environment.   However, the legislative, judicial and regulatory response to the Macondo well incident could substantially increase our customers' liabilities in respect of oil spills and also could increase our liabilities. In addition to potential increased liabilities, such legislative, judicial or regulatory action could impose increased financial, insurance or other requirements that may adversely impact the entire offshore drilling industry.

The International Convention on Oil Pollution Preparedness, Response and Cooperation, the U.K. Merchant Shipping Act 1995, the U.K. Merchant Shipping (Oil Pollution Preparedness, Response and Cooperation Convention) Regulations 1998 and other related legislation and regulations and the Oil Pollution Act of 1990 ("OPA 90"), as amended, and other U.S. federal statutes applicable to us and our operations, as well as similar statutes in Texas, Louisiana, other coastal states and other non-U.S. jurisdictions, address oil spill prevention and control and significantly expand liability, fine and penalty exposure across many segments of the oil and gas industry. Such statutes and related regulations impose a variety of obligations on us related to the prevention of oil spills, disposal of waste and liability for resulting damages. For instance, OPA 90 imposes strict and, with limited exceptions, joint and several liability upon each responsible party for oil removal costs as well as a variety of fines, penalties and damages. Similar environmental laws apply in our other areas of operation. Failure to comply with these statutes and regulations, including OPA 90, may subject us to civil or criminal enforcement action, which may not be covered by contractual indemnification or insurance and could have a material adverse effect on our financial position, operating results and cash flows.


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Events in recent years, including the Macondo well incident, have heightened governmental and environmental concerns about the oil and gas industry. From time to time, legislative proposals have been introduced that would materially limit or prohibit offshore drilling in certain areas.  We are adversely affected by restrictions on drilling in certain areas of the U.S. Gulf of Mexico and elsewhere, including the conditions for lifting the recent moratorium/suspension in the U.S. Gulf of Mexico, the adoption of associated new safety requirements and policies regarding the approval of drilling permits, restrictions on development and production activities in the U.S. Gulf of Mexico and associated Notices to Lessees ("NTLs") that have and may further impact our operations.  If new laws are enacted or other government action is taken that restrict or prohibit offshore drilling in our principal areas of operation or impose environmental protection requirements that materially increase the liabilities, financial requirements or operating or equipment costs associated with offshore drilling, exploration, development or production of oil and natural gas, our financial position, operating results and cash flows could be materially adversely affected.  See "Item 1A. Risk Factors - Compliance with or breach of environmental laws can be costly and could limit our operations." 
Non-U.S. Operations
Revenues from non-U.S. operations were 70%, 73% and 75% of our total consolidated revenues during 2012, 2011 and 2010, respectively. Our non-U.S. operations and shipyard rig construction and enhancement projects are subject to political, economic and other uncertainties, including:

terrorist acts, war and civil disturbances, 
expropriation, nationalization, deprivation or confiscation of our equipment, 
expropriation or nationalization of a customer's property or drilling rights,
repudiation or nationalization of contracts, 
assaults on property or personnel, 
piracy, kidnapping and extortion demands, 
significant governmental influence over many aspects of local economies, 
unexpected changes in law and regulatory requirements, including changes in interpretation or enforcement of existing laws, 
work stoppages, 
complications associated with repairing and replacing equipment in remote locations, 
limitations on insurance coverage, such as war risk coverage, in certain areas, 
imposition of trade barriers, 
wage and price controls, 
import-export quotas, 
exchange restrictions, 
currency fluctuations, 
changes in monetary policies, 
uncertainty or instability resulting from hostilities or other crises in the Middle East, West Africa, Latin America or other geographic areas in which we operate, 
changes in the manner or rate of taxation, 
limitations on our ability to recover amounts due, 

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increased risk of government and vendor/supplier corruption, 
changes in political conditions, and 
other forms of government regulation and economic conditions that are beyond our control.
See "Item 1A. Risk Factors - Our non-U.S. operations involve additional risks not associated with U.S. operations."
Executive Officers
    The table below sets forth certain information regarding our principal officers including our executive officers:
          Name
 
Age
 
Position         
Daniel W. Rabun
 
58

 
Chairman, President and Chief Executive Officer
J. Mark Burns
 
56

 
Executive Vice President - Chief Operating Officer
James W. Swent III
 
62

 
Executive Vice President and Chief Financial Officer
(principal financial officer)
Steven J. Brady
 
53

 
Senior Vice President - Western Hemisphere
John S. Knowlton
 
53

 
Senior Vice President - Technical
P. Carey Lowe
 
54

 
Senior Vice President - Eastern Hemisphere
Kevin C. Robert
 
54

 
Senior Vice President - Marketing
Brady K. Long
 
40

 
Vice President - General Counsel and Secretary
Robert W. Edwards, III
 
35

 
Controller (principal accounting officer)
 
Set forth below is certain additional information on our executive officers, including the business experience of each executive officer for at least the last five years:

Daniel W. Rabun joined Ensco in March 2006 as President and as a member of the Board of Directors. Mr. Rabun was appointed to serve as our Chief Executive Officer effective January 1, 2007 and elected Chairman of the Board of Directors in 2007.  Prior to joining Ensco, Mr. Rabun was a partner at the international law firm of Baker & McKenzie LLP where he had practiced law since 1986, except for one year when he served as Vice President, General Counsel and Secretary of a company in Dallas, Texas. Mr. Rabun provided legal advice and counsel to us for over fifteen years before joining Ensco and served as one of our directors during 2001. He has been a Certified Public Accountant since 1976 and a member of the Texas Bar since 1983.  Mr. Rabun holds a Bachelor of Business Administration Degree in Accounting from the University of Houston and a Juris Doctorate Degree from Southern Methodist University. He also served as Chairman of the International Association of Drilling Contractors in 2012.

J. Mark Burns joined Ensco in 2008 and was appointed to his current position of Executive Vice President and Chief Operating Officer in September 2012. Prior to his current position, Mr. Burns served Ensco as Senior Vice President—Western Hemisphere, Senior Vice President and as President of ENSCO Offshore International Company, a subsidiary of Ensco. Prior to joining Ensco, Mr. Burns served in various international capacities with Noble Corporation (a leading offshore drilling contractor), including his most recent position as Vice President & Division Manager responsible for offshore units located in the Gulf of Mexico. In 2007, Mr. Burns was named IADC Drilling Contractor of the Year. Mr. Burns holds a Bachelor of Arts Degree in Business and Political Science from Sam Houston State University.

James W. Swent III joined Ensco in 2003 and was appointed to his current position of Executive Vice President – Chief Financial Officer in July 2012. Prior to his current position, Mr. Swent served as Senior Vice President – Chief Financial Officer. Prior to joining Ensco, Mr. Swent served as Co-Founder and Managing Director of Amrita Holdings, LLC since 2001.   Mr. Swent previously held various financial executive positions in the information technology, telecommunications and manufacturing industries, including positions with Memorex Corporation and Nortel Networks.  He served as Chief Financial Officer and Chief Executive Officer of Cyrix Corporation from 1996 to 1997 and Chief Financial Officer and Chief Executive Officer of American Pad and Paper Company from 1998 to 2000. 

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Mr. Swent holds a Bachelor of Science Degree in Finance and a Master Degree in Business Administration from the University of California at Berkeley.

Steven J. Brady joined Ensco in 2002 and was appointed to his current position of Senior Vice President – Western Hemisphere in August 2012. Prior to his current position, Mr. Brady served as Vice President – Europe and Mediterranean, General Manager – Middle East and Asia Pacific, and in other leadership positions in the Eastern Hemisphere. Prior to joining Ensco, Mr. Brady spent 18 years in various technical and managerial roles for ConocoPhillips in locations around the world. Mr. Brady holds a Bachelor of Science Degree in Petroleum Engineering from Mississippi State University.

John S. Knowlton joined Ensco in 1998 and was appointed to his current position of Senior Vice President – Technical in May 2011. Prior to his current position, Mr. Knowlton served Ensco as Vice President – Engineering & Capital Projects, General Manager – North & South America, Operations Manager – Asia Pacific Rim, and Operations Manager overseeing the construction and operation of our first ultra-deepwater semisubmersible, rig ENSCO 7500. Before joining Ensco, Mr. Knowlton served in various domestic and international capacities with Ocean Drilling & Exploration Company and Diamond Offshore Drilling, Inc. Mr. Knowlton holds a Bachelor of Science Degree in Civil Engineering from Tulane University.
 
P. Carey Lowe joined Ensco in 2008 and was appointed to his current position of Senior Vice President – Eastern Hemisphere in May 2011. Prior to his current position, Mr. Lowe served Ensco as Senior Vice President with responsibilities including the Deepwater Business Unit, safety, health and environmental matters, capital projects, engineering and strategic planning. Prior to joining Ensco, Mr. Lowe served as Vice President – Latin America for Occidental Oil & Gas. He also served as President & General Manager, Occidental Petroleum of Qatar Ltd. from 2001 to 2007. Mr. Lowe held various drilling-related management positions with Sedco Forex and Schlumberger Oilfield Services from 1980 to 2000, including Business Manager – Drilling, North and South America and General Manager – Oilfield Services, Saudi Arabia, Bahrain and Kuwait. Following Schlumberger, he was associated with a business-to-business e-procurement company until he joined Occidental during 2001. Mr. Lowe holds a Bachelor of Science Degree in Civil Engineering from Tulane University.
 
Kevin C. Robert joined Ensco in May 2011 as Senior Vice President – Marketing in connection with the acquisition of Pride.  Before joining Ensco, Mr. Robert served as Senior Vice President, Marketing and Business Development and Vice President, Marketing with Pride from 2005 to 2011.  He served as Vice President, EPIC Contracts with Samsung Heavy Industries from 2002 to 2005. Mr. Robert also served as Vice President, Marketing with Marine Drilling Companies, Inc. and Director of Business Development with Pride from 2001 to 2002. He was Managing Member of Maverick Offshore L.L.C. from 1997 to 2000 and was employed by Conoco Inc. from 1981 to 1997.  Mr. Robert holds a Bachelor of Science Degree in Chemical Engineering from Louisiana State University.
 
Brady K. Long joined Ensco in May 2011 as Vice President - General Counsel and Secretary in connection with the acquisition of Pride. Prior to joining Ensco, Mr. Long served as Vice President – General Counsel and Secretary with Pride from 2009 to 2011. From 2005 to 2009, he served Pride in various positions, including Vice President, Chief Compliance Officer and Deputy General Counsel. Mr. Long previously practiced corporate and securities law for BJ Services Company and with the law firm of Bracewell & Patterson LLP, the predecessor to Bracewell & Giuliani LLP. He holds a Bachelor of Arts Degree from Brigham Young University and a Juris Doctorate Degree from The University of Texas School of Law.
 
Robert W. Edwards, III joined Ensco in September 2007 and was appointed to his current position of Controller in November 2012. Prior to his current position, he served as Director – Corporate Accounting, Director of Finance and Administration – Deepwater Business Unit and Manager- Accounting Public Reporting. From 2001 to 2007, Mr. Edwards served in various capacities as an employee in the audit practice at Deloitte & Touche LLP. Mr. Edwards holds a Bachelor of Science Degree in Business Administration and a Master Degree in Accounting from Trinity University.
 
Officers generally serve for a one-year term or until successors are elected and qualified to serve.

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Employees
We employed approximately 9,000 personnel worldwide as of February 1, 2013.  The majority of our personnel work on rig crews and are compensated on an hourly basis.

Available Information

Our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and amendments to these reports that we file or furnish to the SEC in accordance with the Securities Exchange Act of 1934, as amended, are available on our website at www.enscoplc.com. These reports also are available in print without charge by contacting our Investor Relations Department at 713-430-4607 as soon as reasonably practicable after we electronically file the information with, or furnish it to, the SEC.  The information contained on our website is not included as part of, or incorporated by reference into, this report.
 
Item 1A.  Risk Factors
 
Risks Related to Our Business
 
There are numerous factors that affect our business and operating results, many of which are beyond our control. The following is a description of significant factors that might cause our future operating results to differ materially from those currently expected. The risks described below are not the only risks facing our Company. Additional risks and uncertainties not specified herein, not currently known to us or currently deemed to be immaterial also may materially adversely affect our business, financial position, operating results and/or cash flows.

We are subject to a number of operating hazards, including those specific to offshore operations. We may not have insurance to cover all these hazards, and our contractual indemnification provisions may be insufficient to cover these hazards.

Our operations are subject to hazards inherent in the offshore drilling industry, such as blowouts, reservoir damage, loss of production, loss of well control, uncontrolled formation pressures, lost or stuck drill strings, equipment failures and mechanical breakdowns, punch throughs, craterings, industrial accidents, fires, explosions, oil spills and pollution. These hazards can cause personal injury or loss of life, severe damage to or destruction of property and equipment, pollution or environmental damage, which could lead to claims by third parties or customers, suspension of operations and contract terminations. Our fleet is also subject to hazards inherent in marine operations, either while on-site or during mobilization, such as capsizing, sinking, grounding, collision, damage from severe weather and marine life infestations.  Additionally, a security breach of our information systems or other technological failure could lead to a material disruption of our operations, information systems, and/or loss of business information, which could result in an adverse impact to our business.  Our drilling contracts provide for varying levels of indemnification from our customers, including with respect to well control and subsurface risks. We also maintain insurance for personal injuries, damage to or loss of equipment and other insurance coverage for various business risks. Our insurance policies typically consist of twelve-month policy periods, and the next renewal date for a substantial portion of our insurance program is scheduled for May 31, 2013.

Our insurance program provides coverage, to the extent not otherwise paid by the customer under the indemnification provisions of the drilling contract, for liability due to control-of-well events, liability arising from named windstorms and liability arising from third-party claims, including wrongful death and other personal injury claims by our personnel as well as claims brought on behalf of individuals who are not our employees. Generally, our program provides liability coverage up to $740.0 million, with a deductible of $10.0 million or less.

Well control events generally include an unintended flow from the well that cannot be contained by using equipment on site (e.g., a blowout preventer), by increasing the weight of drilling fluid or by diverting the fluids safely into production. Our program provides coverage for third-party liability claims relating to pollution from a well control event up to $890.0 million per occurrence, with the first $150.0 million of such coverage also covering re-drilling of the well and control-of-well costs. Our program also provides coverage for liability resulting from pollution originating

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from our rigs up to $740.0 million per occurrence. We retain the risk for liability not indemnified by the customer in excess of our insurance coverage. In addition, our insurance program covers only sudden and accidental pollution.

Our insurance program also provides coverage for physical damage to, including total loss or constructive total loss of, our rigs, generally excluding damage arising from a named windstorm in the U.S. Gulf of Mexico. This coverage is based on an agreed amount for each rig, and has a per occurrence deductible for losses ranging from $15.0 million to $25.0 million. With respect to hull and machinery losses arising from U.S. Gulf of Mexico windstorm damage, we obtained $800.0 million of aggregate coverage for ultra-deepwater drillship and semisubmersible hull and machinery losses with a $50.0 million per occurrence self-insured retention (deductible). However, due to the significant premium, high self-insured retention and limited coverage, we decided not to purchase windstorm insurance for our jackup rigs in the U.S. Gulf of Mexico. Accordingly, we have retained the risk for loss or damage of our 10 jackup rigs in the U.S. Gulf of Mexico arising out of windstorm damage.

Our drilling contracts provide for varying levels of indemnification and allocation of liabilities between our customers and us with respect to loss or damage to property and injury or death to persons arising out of the drilling operations we perform. Under our drilling contracts, liability with respect to personnel and property customarily is allocated so that we and our customers each assume liability for our respective personnel and property. However, in certain drilling contracts we assume liability for damage to our customers' property and the property of other contractors of our customers resulting from our negligence, subject to negotiated caps on a per occurrence or per event basis.  In other contracts, we are not indemnified by our customers for damage to their property and the property of their other contractors, or the enforceability of our indemnity may be limited or prohibited by applicable law in cases of gross negligence or willful misconduct. Accordingly, we could be liable for any such damage under applicable law. In addition, our customers typically indemnify us, generally based on replacement cost minus some level of depreciation, for damage to our down-hole equipment, and in some cases for all or a limited amount of the replacement cost of our subsea equipment, unless the damage is caused by our negligence, normal wear and tear, or defects in the equipment.

Our customers typically assume most of the responsibility for and indemnify us from any loss, damage or other liability resulting from pollution or contamination arising from operations under the contract when the source of the pollution originates from the well or reservoir, including clean-up and removal, third-party damages, and fines and penalties, including as a result of blow-outs or cratering of the well. In some drilling contracts, however, we may have liability for third-party damages (including punitive damages) resulting from such pollution or contamination caused by our gross negligence, or, in some cases, ordinary negligence, subject to negotiated caps on a per occurrence or per event basis and/or for the term of the contract or our indemnity may be limited or unenforceable under applicable law in cases of gross negligence or willful misconduct.  In certain contracts, we may not be indemnified by our customers for losses or damages caused by pollution or contamination, and we could be liable for such losses or damages under applicable law and for fines and penalties imposed by regulatory authorities, each of which could be substantial.  In addition, in substantially all of our contracts, the customer assumes responsibility and indemnifies us for loss or damage to the reservoir, for loss of hydrocarbons escaping from the reservoir and for the costs of bringing the well under control.  Further, most of our contracts provide that the customer assumes responsibility and indemnifies us for loss or damage to the well, except when the loss or damage to the well is due to our negligence, in which case most of our contracts provide that the customer's sole remedy is to require us to redrill the lost or damaged portion of the well at a substantially reduced rate.

In certain cases, vendors who provide equipment or services to us limit their pollution liability to a specific monetary cap, and we assume the liability above that cap. Typically, in the case of original equipment manufacturers, the cap is a negotiated amount based on mutual agreement of the parties considering the risk profiles and thresholds of each party. However, for smaller vendors, the liability will usually be limited to the value, or double the value, of the contract.

We generally indemnify the customer for legal and financial consequences of spills of waste oil, fuels, lubricants, motor oils, pipe dope, paint, solvents, ballast, bilge, garbage, debris, sewage, hazardous waste and other liquids the discharge of which originates from our rigs or equipment above the surface of the water and in some cases

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from our subsea equipment. Some of our contracts provide that, in the event of any such spill from our rigs, we are responsible for fines and penalties.
 
The above description of our insurance program and the indemnification provisions of our drilling contracts is only a summary as of the date hereof and is general in nature. In addition, our drilling contracts are individually negotiated, and the degree of indemnification we receive from operators against the liabilities discussed above can vary from contract to contract, based on market conditions and customer requirements existing when the contract was negotiated and the interpretation and enforcement of applicable law when the claim is adjudicated. 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. Our insurance program and the terms of our drilling contracts may change in the future. In addition, the indemnification provisions of our drilling contracts may be subject to differing interpretations, and such provisions may be unenforceable, void or limited by public policy considerations, primarily in situations where the cause of the underlying loss or damage is due to our gross negligence, where punitive damages are attributable to us, or where any fines and/or penalties are imposed directly against us, especially if the fines and/or penalties are punitive in nature. In addition, under the laws of certain jurisdictions, the courts may enforce an indemnity obligation between the contracting parties with respect to claims by a third party where the underlying claim is the result of gross negligence, but will not enforce an indemnity and allow a party to be indemnified for its gross negligence for claims of the other contracting party that is in the nature of a release. The question may ultimately need to be decided by a court or other proceeding taking into consideration the specific contract language, the facts and applicable laws. The law with respect to the enforceability of indemnities varies from jurisdiction to jurisdiction and is unsettled under certain laws that are applicable to our contracts.

If any of the aforementioned operating hazards results in substantial liability and our insurance and contractual indemnification provisions are unavailable or insufficient to cover such liability, our financial condition, operating results or cash flows may be materially adversely affected.

The potential for U.S. Gulf of Mexico hurricane related windstorm damage or liabilities could result in uninsured losses and may cause us to alter our operating procedures during hurricane season, which could adversely affect our business.

Certain areas in and near the U.S. Gulf of Mexico experience hurricanes and other extreme weather conditions on a relatively frequent basis. Some of our drilling rigs in the U.S. Gulf of Mexico are located in areas that could cause them to be susceptible to damage and/or total loss by these storms, and we have a larger concentration of jackup rigs in the U.S. Gulf of Mexico than most of our competitors. We currently have 10 jackup rigs and eight floaters in the U.S. Gulf of Mexico. Damage caused by high winds and turbulent seas could result in rig loss or damage, termination of drilling contracts for lost or severely damaged rigs or curtailment of operations on damaged drilling rigs with reduced or suspended day rates for significant periods of time until the damage can be repaired. Moreover, even if our drilling rigs are not directly damaged by such storms, we may experience disruptions in our operations due to damage to our customers' platforms and other related facilities in the area. Our drilling operations in the U.S. Gulf of Mexico have been impacted by hurricanes, including the total loss of one jackup rig during 2004, one platform rig during 2005 and two jackup rigs during 2008, with associated losses of contract revenues and potential liabilities.

Insurance companies incurred substantial losses in the offshore drilling, exploration and production industries as a consequence of hurricanes that occurred in the U.S. Gulf of Mexico during 2004, 2005 and 2008. Accordingly, insurance companies have substantially reduced the nature and amount of insurance coverage available for losses arising from named tropical storm or hurricane damage in the U.S. Gulf of Mexico ("windstorm damage") and have dramatically increased the cost of available windstorm coverage. The tight insurance market not only applies to coverage related to U.S. Gulf of Mexico windstorm damage or loss of our drilling rigs, but also impacts coverage for any potential liabilities to third parties associated with property damage, personal injury or death and environmental liabilities, as well as coverage for removal of wreckage and debris associated with hurricane losses. We have no assurance that the tight insurance market for windstorm damage, liabilities and removal of wreckage and debris will not continue into the foreseeable future.


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Upon renewal of our annual insurance policies effective May 31, 2012, we obtained $800.0 million of aggregate coverage for floater hull and machinery losses arising from U.S. Gulf of Mexico windstorm damage with a $50.0 million per occurrence self-insured retention (deductible). However, due to the significant premium, high self-insured retention and limited coverage, we decided not to purchase windstorm insurance for our jackup rigs in the U.S. Gulf of Mexico. Accordingly, we have retained the risk for loss or damage of our 10 jackup rigs in the U.S. Gulf of Mexico arising out of windstorm damage.

Our current liability insurance policies provide coverage for U.S. Gulf of Mexico windstorm exposures for removal of wreckage and debris in excess of $50.0 million per occurrence as respects our jackup and floater rig operations and have an annual aggregate coverage limit of $450.0 million. Our limited windstorm insurance coverage exposes us to a significant level of risk due to jackup rig damage or loss related to severe weather conditions caused by U.S. Gulf of Mexico tropical storms or hurricanes.

We have established operational procedures designed to mitigate risk to our jackup rigs in the U.S. Gulf of Mexico during hurricane season. In addition to procedures designed to better secure the drilling package on jackup rigs, improve jackup leg stability and increase the air gap to position the hull above waves, our procedures involve analysis of prospective drilling locations, which may include enhanced bottom surveys. These procedures may result in a decision to decline to operate on a customer-designated location during hurricane season notwithstanding that the location, water depth and other standard operating conditions are within a rig's normal operating range. Our procedures and the associated regulatory requirements addressing Mobile Offshore Drilling Unit operations in the U.S. Gulf of Mexico during hurricane season, coupled with our decision to retain (self-insure) certain windstorm-related risks, may result in a significant reduction in the utilization of our jackup rigs in the U.S. Gulf of Mexico.
Our retained exposures for property loss or damage and wreckage and debris removal or other liabilities associated with U.S. Gulf of Mexico tropical storms or hurricanes could have a material adverse effect on our financial position, operating results and cash flows if we sustain significant uninsured or underinsured losses or liabilities as a result of U.S. Gulf of Mexico tropical storms or hurricanes.

The success of our business largely depends on the level of activity in the oil and gas industry, which can be significantly affected by volatile oil and natural gas prices.

The success of our business largely depends on the level of activity in offshore oil and natural gas exploration, development and production. Oil and natural gas prices, and market expectations of potential changes in these prices, may significantly affect the level of drilling activity. An actual decline, or the perceived risk of a decline, in oil and/or natural gas prices could cause oil and gas companies to reduce their overall level of activity or spending, in which case demand for our services may decline and revenues may be adversely affected through lower rig utilization and/or lower day rates.  Numerous factors may affect oil and natural gas prices and the level of demand for our services, including:

demand for oil and natural gas, 
the ability of OPEC to set and maintain production levels and pricing, 
the level of production by non-OPEC countries, 
U.S. and non-U.S. tax policy, 
laws and government regulations that limit, restrict or prohibit exploration and development of oil and natural gas in various jurisdictions, 
advances in exploration and development technology, 
disruption to exploration and development activities due to hurricanes and other severe weather conditions and the risk thereof, 
the cost of exploring for, developing, producing and delivering oil and natural gas, 

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expectations regarding future energy prices, 
local and international political, economic and weather conditions, 
the development and exploitation of alternative fuels, 
the worldwide military or political environment, including uncertainty or instability resulting from an escalation or additional outbreak of armed hostilities or other crises in oil or natural gas producing areas of the Middle East or geographic areas in which we operate, or acts of terrorism, and 
global economic conditions. 
Any prolonged reduction in oil and natural gas prices will depress the levels of exploration, development and production activity. In addition, continued hostilities in foreign countries and the occurrence or threat of terrorist attacks against the United States or other countries could create downward pressure on the economies of the United States and other countries. Moreover, even during periods of high commodity prices, customers may cancel or curtail their drilling programs, or reduce their levels of capital expenditures for exploration and production for a variety of reasons, including their lack of success in exploration efforts. These factors could cause our revenues and margins to decline, as a result of declines in utilization and day rates, and limit our future growth prospects. Any significant decrease in day rates or utilization of our rigs, particularly our high-specification floaters, could materially reduce our revenues and profitability. In addition, these risks could increase instability in the financial and insurance markets and make it more difficult for us to access capital and to obtain insurance coverages that we consider adequate or are otherwise required by our contracts.

Deterioration of the global economy and/or a decline in oil and natural gas prices could cause our customers to reduce spending on exploration and development drilling. These conditions also could cause our customers and/or vendors to fail to fulfill their commitments and/or fund their future operations and obligations, which could have a material adverse effect on our business.

The success of our business largely depends on the level of activity in offshore oil and natural gas exploration and development drilling worldwide. Oil and natural gas prices, and market expectations of potential changes in these prices, significantly impact the level of worldwide drilling activity.

A decline in oil and natural gas prices, whether caused by economic conditions, international or national climate change and/or environmental regulations or other factors, could cause oil and gas companies to reduce their overall level of drilling activity and spending. Disruption in the capital markets could also cause oil and gas companies to reduce their overall level of drilling activity and spending. These conditions could cause our customers and vendors to fail to fulfill their commitments to us.

Historically, when drilling activity and spending decline, utilization and day rates also decline and drilling may be reduced or discontinued, resulting in an oversupply of drilling rigs. The oversupply of drilling rigs could be exacerbated by the entry of newbuild rigs into the market. When idled or stacked, drilling rigs do not earn revenues, but continue to require cash expenditures for crews, fuel, insurance, berthing and associated items.

A decline in oil and natural gas prices, together with a deterioration of the global economy, could substantially reduce demand for drilling rigs and result in a material adverse effect on our financial position, operating results or cash flows.


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We may incur asset impairments as a result of future declining demand for offshore drilling rigs.
   
As of December 31, 2012, the carrying value of our property and equipment totaled $13.1 billion, which represented 71% of our total assets. See Note 4 to our consolidated financial statements for additional information on our property and equipment.  We evaluate the carrying value of our property and equipment, primarily our drilling rigs, when events or changes in circumstances indicate that the carrying value of such rigs may not be recoverable. The offshore drilling industry historically has been highly cyclical, and it is not unusual for rigs to be unutilized or underutilized for significant periods of time and subsequently resume full or near full utilization when business cycles change. Likewise, during periods of supply and demand imbalance, rigs are frequently contracted at or near cash break-even rates for extended periods of time until day rates increase when the supply/demand balance is restored. However, if the global economy were to deteriorate and/or the offshore drilling industry were to incur a significant prolonged downturn, impairment charges may occur with respect to specific individual rigs, groups of rigs, such as a specific type of drilling rig, or rigs in a certain geographic location.
    
As of December 31, 2012, the carrying value of our goodwill totaled $3.3 billion, which represented 18% of total assets. See Note 1 to our consolidated financial statements for additional information on our goodwill. We test goodwill for impairment on an annual basis or when events or changes in circumstances indicate that a potential impairment exists. The goodwill impairment test requires us to identify reporting units, perform a qualitative assessment of the likelihood that a reporting unit’s carrying value exceeds its estimated fair value, and in certain circumstances estimate each reporting unit's fair value as of the testing date. In most instances, our calculation of the fair value of our reporting units is based on estimates of future discounted cash flows to be generated by our drilling rigs, which reflect management's judgments and assumptions regarding the appropriate risk-adjusted discount rate, as well as future industry conditions and operations, including expected utilization, day rates, expense levels, capital requirements and terminal values for each of our rigs. If the aggregate fair value of our reporting units exceeds our market capitalization, we evaluate the reasonableness of the implied control premium. If we determine the implied control premium is not reasonable, we adjust the discount rate in our discounted cash flow model and reduce the estimated fair values of our reporting units.

If the global economy were to deteriorate and the offshore drilling industry were to incur a significant prolonged downturn, our expectations of future cash flows may decline and could ultimately result in a goodwill impairment. Additionally, a significant decline in the market value of our shares could result in a goodwill impairment.

The offshore contract drilling industry historically has been highly competitive and cyclical, with periods of low demand and excess rig availability that could result in adverse effects on our business.

Our industry is highly competitive, and our contracts are traditionally awarded on a competitive bid basis. Pricing, safety records and competency are key factors in determining which qualified contractor is awarded a job. Rig availability, location and technical ability also can be significant factors in the determination. In addition, consolidations within the oil and gas industry have reduced the number of available customers, resulting in increased competition for projects. Our potential inability to compete successfully may reduce our revenues and profitability.

Financial operating results in the offshore contract drilling industry historically have been very cyclical and primarily are related to the demand for drilling rigs and the available supply of drilling rigs.  Demand for rigs is directly related to the regional and worldwide levels of offshore exploration and development spending by oil and gas companies, which is beyond our control. Offshore exploration and development spending may fluctuate substantially from year-to-year and from region-to-region.
    
The supply of offshore drilling rigs has increased in recent years; however, new rigs require substantial capital investment and a long period of time to construct.  There are 184 newbuild drillships, semisubmersibles and jackup rigs reported to be on order or under construction with delivery expected by the end of 2020.  Approximately 75 of these rigs are scheduled for delivery during 2013 representing an approximate 10% increase in the total worldwide fleet of offshore drilling rigs. There are no assurances that the market in general or a geographic region in particular will be able to fully absorb the supply of new rigs in future periods.


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The increase in supply of offshore drilling rigs during 2013 and future periods could result in an oversupply of offshore drilling rigs and could cause a decline in utilization and/or day rates, a situation which could be exacerbated by a decline in demand for drilling rigs. Lower utilization and/or day rates in one or more of the regions in which we operate could adversely affect our revenues, utilization and profitability.

Certain events, such as limited availability or non-availability of insurance for certain perils in some geographic areas, rig loss or damage due to hurricanes, blowouts, craterings, punchthroughs and other operational events, may impact the supply of rigs in a particular market and cause rapid fluctuations in utilization and day rates.

Future periods of reduced demand and/or excess rig supply may require us to idle additional rigs or enter into lower day rate contracts or contracts with less favorable terms. There can be no assurance that the current demand for drilling rigs will not decline in future periods. A decline in demand for drilling rigs or an oversupply of drilling rigs could adversely affect our financial position, operating results and cash flows.

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

Revenues from non-U.S. operations were 70%, 73% and 75% of our total revenues during 2012, 2011 and 2010, respectively. Our non-U.S. operations and shipyard rig construction and enhancement projects are subject to political, economic and other uncertainties, including:

terrorist acts, war and civil disturbances, 
expropriation, nationalization, deprivation or confiscation of our equipment, 
expropriation or nationalization of a customer's property or drilling rights, 
repudiation or nationalization of contracts, 
assaults on property or personnel, 
piracy, kidnapping and extortion demands, 
significant governmental influence over many aspects of local economies, 
unexpected changes in law and regulatory requirements, including changes in interpretation or enforcement of existing laws, 
work stoppages, often due to strikes over which we have little or no control,
complications associated with repairing and replacing equipment in remote locations, 
limitations on insurance coverage, such as war risk coverage, in certain areas, 
imposition of trade barriers, 
wage and price controls, 
import-export quotas, 
exchange restrictions, 
currency fluctuations, 
changes in monetary policies, 
uncertainty or instability resulting from hostilities or other crises in the Middle East, West Africa, Latin America or other geographic areas in which we operate, 
changes in the manner or rate of taxation, 

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limitations on our ability to recover amounts due, 
increased risk of government and vendor/supplier corruption, 
increased local content requirements,
changes in political conditions, and 
other forms of government regulation and economic conditions that are beyond our control.
We historically have maintained insurance coverage and obtained contractual indemnities that protect us from some, but not all, of the risks associated with our non-U.S. operations such as nationalization, deprivation, confiscation, political and war risks. However, there can be no assurance that any particular type of contractual or insurance protection will be available in the future or that we will be able to purchase our desired level of insurance coverage at commercially feasible rates.  Moreover, we may initiate a self-insurance program through one or more captive insurance subsidiaries.  In circumstances where we have insurance protection for some or all of the risks associated with non-U.S. operations, such insurance may be subject to cancellation on short notice, and it is unlikely that we will be able to remove our rig or rigs from the affected area within the notice period. Accordingly, a significant event for which we are uninsured, underinsured or self-insured, or for which we have not received an enforceable contractual indemnity from a customer, could cause a material adverse effect on our financial position, operating results and cash flows.

We are subject to various tax laws and regulations in substantially all countries in which we operate or have a legal presence. We evaluate applicable tax laws and employ various business structures and operating strategies to obtain the optimal level of taxation on our revenues, income, assets and personnel. Actions by tax authorities that impact our business structures and operating strategies, such as changes to tax treaties, laws and regulations, or the interpretation or repeal of any of the foregoing, adverse rulings in connection with audits or otherwise, or other challenges may substantially increase our tax expense.

As required by law, we file periodic tax returns that are subject to review and examination by various revenue agencies within the jurisdictions in which we operate. We cannot predict or provide assurance as to the ultimate outcome of existing or future tax assessments.

Our non-U.S. operations also face the risk of fluctuating currency values, which may impact our revenues, operating costs and capital expenditures. We currently conduct contract drilling operations in certain countries that have experienced substantial fluctuations in the value of their currency compared to the U.S. dollar. In addition, some of the countries in which we operate have occasionally enacted exchange controls. Historically, these risks have been limited by invoicing and receiving payment in U.S. dollars (our functional currency) or freely convertible currency and, to the extent possible, by limiting our acceptance of foreign currency to amounts which approximate our expenditure requirements in such currencies. However, there is no assurance that our contracts will contain such terms in the future.

A portion of the costs and expenditures incurred by our non-U.S. operations, including a portion of the construction payments for new rigs, are settled in local currencies, exposing us to risks associated with fluctuation in the value of these currencies relative to the U.S. dollar. We use foreign currency forward contracts to reduce this exposure. However, a relative weakening in the value of the U.S. dollar in relation to the local currencies in these countries may increase our costs and expenditures.

Our non-U.S. operations are also subject to various laws and regulations in countries in which we operate, including laws and regulations relating to the operation of drilling rigs and the requirements for equipment. We may be required to make significant capital expenditures to operate in such countries, which may not be reimbursed by our customers. Governments in some non-U.S. countries have become increasingly active in regulating and controlling the ownership of oil, natural gas and mineral concessions and companies holding concessions, the exploration of oil and natural gas and other aspects of the oil and gas industry in their countries. In addition, government action, including initiatives by OPEC, may continue to cause oil and/or natural gas price volatility. In some areas of the world, government activity has adversely affected the amount of exploration and development work performed by major international oil

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companies and may continue to do so. Moreover, certain countries accord preferential treatment to local contractors or joint ventures or impose specific quotas for local goods and services, which can increase our operational costs and place us at a competitive disadvantage. There can be no assurance that such laws and regulations or activities will not have a material adverse effect on our future operations.
    
The shipment of goods, services and technology across international borders subjects us to extensive trade laws and regulations. Our import activities are governed by unique customs laws and regulations in each of the countries where we operate. Moreover, many countries, including the United States, control the export and re-export of certain goods, services and technology and impose related export recordkeeping and reporting obligations. Governments also may impose express or de facto economic sanctions against certain countries, persons and other entities that may restrict or prohibit transactions involving such countries, persons and entities.

The laws and regulations concerning import activity, export recordkeeping and reporting, 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. Shipments can be delayed and denied export or entry for a variety of reasons, some of which are outside our control and some of which may result from failure to comply with existing legal and regulatory regimes. Shipping delays or denials could cause unscheduled operational downtime. Any failure to comply with applicable legal and regulatory trading obligations also could result in criminal and civil penalties and sanctions, such as fines, imprisonment, exclusion from government contracts, seizure of shipments and loss of import and export privileges.

Although we implement and enforce policies and procedures designed to promote compliance with the laws of the jurisdictions in which we operate, our employees, contractors and agents may take actions in violation of our policies and such laws. Any such violation, even if prohibited by our policies, could have a material adverse effect on our financial position, operating results or cash flows.

Rig construction, upgrade and enhancement projects are subject to risks, including delays and cost overruns, which could have a material adverse effect on our operating results. The risks are concentrated because our three ultra-deepwater drillships currently under construction are at a single shipyard in South Korea and our three ultra-high specification harsh environment jackup rigs currently under construction are at a single shipyard in Singapore.

There are 184 new offshore drilling rigs reported to be on order or under construction with expected delivery dates through 2020.  As a result, shipyards and third-party equipment vendors are under significant resource constraints to meet delivery obligations. Such constraints may lead to substantial delivery and commissioning delays and/or equipment failures and/or quality deficiencies. Furthermore, new drilling rigs may face start-up or other operational complications following completion of construction work or other unexpected difficulties including equipment failures, design or engineering problems that could result in significant downtime at reduced or zero day rates or the cancellation or termination of drilling contracts.

We currently have three ultra-deepwater drillships and three ultra-high specification harsh environment jackup rigs under construction. In addition, we may construct additional rigs and continue to upgrade the capability and extend the service lives of our existing rigs. Some of these expenditures are unplanned.

Rig construction, upgrade, life extension and repair projects are subject to the risks of delay or cost overruns inherent in any large construction project, including the following:

failure of third-party equipment to meet quality and/or performance standards, 
delays in equipment deliveries or shipyard construction, 
shortages of materials or skilled labor, 
damage to shipyard facilities or construction work in progress, including damage resulting from fire, explosion, flooding, severe weather, terrorism, war or other armed hostilities, 

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unforeseen design or engineering problems, including those relating to the commissioning of newly designed equipment, 
unanticipated actual or purported change orders, 
strikes, labor disputes or work stoppages, 
financial or operating difficulties of equipment vendors or the shipyard while constructing, enhancing, upgrading, improving or repairing a rig or rigs, 
unanticipated cost increases, 
foreign currency exchange rate fluctuations impacting overall cost, 
inability to obtain the requisite permits or approvals, 
client acceptance delays, 
disputes with shipyards and suppliers, 
latent damages or deterioration to hull, equipment and machinery in excess of engineering estimates and assumptions, 
claims of force majeure events, and 
additional risks inherent to shipyard projects in a non-U.S. location.
Our risks are concentrated because our six rigs currently under construction are at two shipyards.

Two of our six rigs currently under construction have secured a drilling contract upon completion of construction. These rigs are scheduled to be delivered beginning in the first half of 2013 through 2014.  There is no assurance that we will secure drilling contracts for these rigs or that the drilling contracts we may be able to secure will be based upon rates and terms that will provide a reasonable rate of return on these investments. Our failure to secure contractual commitments for these rigs at rates and terms that result in a reasonable return upon completion of construction may result in a material adverse effect on our financial position, operating results and cash flows. If we are able to secure drilling contracts prior to completion, we will be exposed to the risk of delays that could impact the projected financial results or the viability of the contracts and could have a material adverse effect on our financial position, operating results and cash flows.

Our drilling contracts with national oil companies expose us to greater risks than we normally assume in drilling contracts with non-governmental customers.

We currently have 25 rigs contracted with national oil companies. The terms of these contracts are often non-negotiable and may expose us to greater commercial, political and operational risks than we assume in other contracts, such as exposure to materially greater environmental liability and other claims for damages (including consequential damages) and personal injury related to our operations, or the risk that the contract may be terminated by our customer without cause on short-term notice, contractually or by governmental action, under certain conditions that may not provide us an early termination payment, collection risks and political risks. While we believe that the financial, commercial and risk allocation terms of these contracts and our operating safeguards mitigate these risks, we can provide no assurance that the increased risk exposure will not have an adverse impact on our future operations or that we will not increase the number of rigs contracted to national oil companies with commensurate additional contractual risks. 


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Legal proceedings could affect us adversely.

We are involved in litigation, including various claims, disputes and regulatory proceedings that arise in the ordinary course of business, many of which are uninsured and relate to intellectual property, commercial, operational, employment, regulatory, or other activities.
 
Additionally, in 2010, Pride and its subsidiaries resolved with the U.S. Department of Justice (“DOJ”) and the SEC their previously disclosed investigations into potential violations of the Foreign Corrupt Practices Act ("FCPA").  The settlement with the DOJ included a deferred prosecution agreement ("DPA") between Pride and the DOJ and a guilty plea by Pride Forasol, S.A.S., one of Pride’s subsidiaries, to FCPA-related charges. In November 2012, the DOJ moved (i) to dismiss the charges against Pride and end the DPA one year prior to its scheduled expiration; and (ii) to terminate the unsupervised probation of Pride Forasol, S.A.S.   The Court granted the motions.
    
Pride has received preliminary inquiries from governmental authorities of certain of the countries referenced in its settlements with the DOJ and SEC. We could face additional fines, sanctions and other penalties from authorities in these and other relevant jurisdictions, including prohibition of our participating in or curtailment of business operations in those jurisdictions and the seizure of our rigs or other assets. At this early stage of such inquiries, we are unable to determine what, if any, legal liability may result. 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 directors, officers, employees, affiliates, advisors, attorneys, agents, stockholders, debt holders, or other interest holders or constituents of our Company. In addition, disclosure of the subject matter of the investigations and settlements could adversely affect our reputation and our ability to obtain new business or retain existing business from our current clients and potential clients, to attract and retain employees and to access the capital markets.

Although we cannot accurately predict the outcome of our litigation, claims, disputes, regulatory proceedings and investigations or the amount or impact of any associated liability or other sanctions, these matters could adversely affect our financial position, operating results or cash flows.

Increasing regulatory complexity could adversely impact the costs associated with our offshore drilling operations.

Increases in regulatory requirements, particularly in the U.S. Gulf of Mexico, could significantly increase our costs.  In recent years, we have seen several significant regulatory changes that have affected the way we operate in the U.S. Gulf of Mexico.

Hurricanes Katrina and Rita in 2005 and Hurricanes Gustav and Ike in 2008 caused damage to a number of rigs in the Gulf of Mexico. Rigs that were moved off location by the storms damaged platforms, pipelines, wellheads and other drilling rigs. The U.S. Bureau of Ocean Energy Management, Regulation and Enforcement ("BOEMRE") has issued guidelines for jackup rig fitness requirements during hurricane seasons, which are scheduled to be effective through the 2013 hurricane season. As a result of these BOEMRE guidelines, jackup rigs in the U.S. Gulf of Mexico are required to operate with a higher air gap (the space between the water level and the bottom of the rig's hull) during hurricane season, effectively reducing the water depth in which they can operate. The guidelines also provide for enhanced information and data requirements from oil and gas companies operating in the U.S. Gulf of Mexico. The Bureau of Safety and Environmental Enforcement (“BSEE”), one of the successor agencies to BOEMRE, may take other steps that could increase the cost of operations or reduce the area of operations. Implementation of BSEE guidelines and regulations may subject us to increased costs and limit the operational capabilities of our rigs.
Similarly, as a result of the Macondo well incident in the U.S. Gulf of Mexico, the U.S. Department of the Interior issued Notices to Lessees (“NTLs"), implementing new regulations applicable to drilling operations in the U.S. Gulf of Mexico. In 2011, BSEE issued an interim drilling safety rule formalizing many of the requirements in the NTLs and a workplace safety rule with additional environmental and safety requirements. These regulations provide for certification and verification requirements applicable to drilling activities in the U.S. Gulf of Mexico, and requirements with respect to exploration, development and production activities in the U.S. Gulf of Mexico, including regulations relating to the design of wells and testing of the integrity of wellbores, the use of drilling fluids, the

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functionality and compatibility of blowout preventers with drilling rigs and rig designs and testing of well control equipment (including third-party inspections), minimum requirements for personnel operating blowout preventers and training in deepwater well control and other safety regulations.
In 2012, BSEE issued the final drilling safety rule, which finalized and made certain revisions to the interim safety rule, including enhancing the description and classification of well-control barriers, defining testing requirements for cement, clarifying requirements for cement, clarifying requirements for installation of dual mechanical barriers and extending requirements for blowout preventers and well-control fluids to well completions, workovers and de-commissioning operations. Current or future NTLs or other rules, directives and regulations may further impact our customers' ability to obtain permits and commence or continue deep or shallow water operations in the U.S. Gulf of Mexico. Future legislative or regulatory enactments may impose new requirements for well control and blowout prevention equipment that could increase our costs and cause delays in our operations due to unavailability of associated equipment.
In 2012, BSEE also issued an interim policy document for use by BSEE inspectors in issuing incidents of noncompliance (“INCs”) to contractors conducting operations under BSEE jurisdiction on the Outer Continental Shelf of the U.S. Gulf of Mexico. The stated purpose of the rule is to provide for consistency in application of BSEE enforcement authority by establishing guidelines for issuance of INCs to contractors in addition to operators. The policy indicates that BSEE's enforcement actions will continue to focus primarily on lessees and operators, but makes it clear that BSEE will “in appropriate circumstances” also issue INCs to contractors for serious violations of BSEE regulations. Further, the industry has adopted new standards, including API Standard 53 relating to the maintenance, inspection and testing of well control equipment. The imposition of INCs on contractors exposes us to fines and penalties for violation of BSEE regulations and the new standards expose us to increased costs and loss of revenue.
New regulatory, legislative, permitting or certification requirements in the U.S., including laws and regulations that have or may impose increased financial responsibility, oil spill abatement contingency plan capability requirements, or additional operational requirements and certifications, could materially adversely affect our financial condition, operating results or cash flows.
We anticipate that government regulation in other countries where we operate may follow the U.S. in regard to enhanced safety and environmental regulation, which could also result in governments imposing sanctions on contractors for operators not complying with regulations that impact drilling operations. Even if not a requirement in these countries, most international operating companies, and many others, are voluntarily complying with some or all of the U.S. inspections and safety and environmental guidelines when operating outside the U.S. Such additional governmental regulation and voluntary compliance by operators could increase the cost of our operations and expose us to greater liability.


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Laws and governmental regulations may add to costs, limit our drilling activity or reduce demand for our drilling services.

Our operations are affected by political developments and by laws and regulations that relate directly to the oil and gas industry, including initiatives to limit greenhouse gas emissions. The offshore contract drilling industry is dependent on demand for services from the oil and gas industry. Accordingly, we will be directly affected by the approval and adoption of laws and regulations limiting or curtailing exploration and development drilling for oil and natural gas for economic, environmental, safety and other policy reasons. We may be exposed to risks related to new laws or regulations pertaining to climate change, carbon emissions or energy use that could reduce the use of oil or natural gas, thus reducing demand for hydrocarbon-based fuel and our drilling services. Governments also may pass laws or regulations encouraging or mandating the use of alternative energy sources, such as wind power and solar energy, which may reduce demand for oil and natural gas and our drilling services. Furthermore, we may be required to make significant capital expenditures or incur substantial additional costs to comply with new governmental laws and regulations. It is also possible that legislative and regulatory activity could adversely affect our operations by limiting drilling opportunities or significantly increasing our operating costs.

Geopolitical events, terrorist attacks, piracy and military action could affect the markets for our services and have a material adverse effect on our business and cost and availability of insurance.

Geopolitical events have resulted in military actions, terrorist, pirate and other armed attacks, civil unrest, political demonstrations, mass strikes and government responses. Military action by the United States or other nations could escalate, and acts of terrorism, piracy, kidnapping, extortion, acts of war, violence, civil war, or general disorder may initiate or continue. Such acts could be directed against companies such as ours. Such developments have caused instability in the world’s financial and insurance markets in the past. In addition, these developments could lead to increased volatility in prices for oil and natural gas and could affect the markets for our products and services. Insurance premiums could increase and coverage for these kinds of events may be unavailable in the future. Any or all of these effects could have a material adverse effect on our financial position, operating results or cash flows.
 
We may suffer losses if our customers terminate or seek to renegotiate our contracts, if operations are suspended or interrupted or if a rig becomes a total loss.

Our drilling contracts often are subject to termination without cause upon notice by the customer. Although contracts may require the customer to pay an early termination payment in the event of a termination for convenience (without cause), such payment may not fully compensate for the loss of the contract and some of our contracts permit termination by the customer without an early termination payment. In periods of rapid market downturn, our customers may not honor the terms of existing contracts (including contracts for new rigs under construction), may terminate contracts or may seek to renegotiate contract day rates and terms to conform to depressed market conditions.

Drilling contracts customarily specify automatic termination or termination at the option of the customer in the event of a total loss of the drilling rig and often include provisions addressing termination rights or reduction or cessation of day rates if operations are suspended or interrupted for extended periods due to breakdown of major rig equipment, unsatisfactory performance, "force majeure" events beyond the control of either party or other specified conditions. Our financial position, operating results and cash flows may be adversely affected by early termination of contracts, contract renegotiations or cessation of day rates while operations are suspended.

Our business may be materially adversely affected if certain customers cease to do business with us.

We provide our services to major international, government-owned and independent oil and gas companies.  During 2012, our five largest customers accounted for 48% of our consolidated revenues in the aggregate, with our largest customer representing 24% of our consolidated revenues.  Our financial position, operating results and cash flows may be materially adversely affected if a major customer terminates its contracts with us, fails to renew its existing contracts with us, requires renegotiation of our contracts or declines to award new contracts to us.


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Failure to recruit and retain skilled personnel could adversely affect our operations and financial results.

We require skilled personnel to operate our drilling rigs and to provide technical services and support for our business. Competition for skilled and other labor has intensified as additional, more technically advanced, rigs are added to the worldwide fleet. There are 184 new offshore drilling rigs reported to be on order or under construction with delivery expected by the end of 2020. These rigs will require more workers with specialized training and skills to operate. In periods of high utilization, it is more difficult and costly to recruit and retain qualified employees, especially in foreign countries that require a certain percentage of national employees. Competition for such personnel could increase our future operating expenses, with a resulting reduction in net income, or impact our ability to fully staff and operate our rigs. We may also incur additional costs to provide training for prospective employees for skilled positions on our newer rigs.

We may be required to maintain or increase existing levels of compensation to retain our skilled workforce, especially if our competitors raise their wage rates. Much of the skilled workforce is nearing retirement age, which may impact the availability of skilled personnel. In addition, a large percentage of our international employees are protected by collective bargaining agreements that require periodic salary negotiations, which usually result in higher personnel expenses and other benefits. We also are subject to potential further unionization of our labor force or legislative or regulatory action that may impact working conditions, paid time off or other conditions of employment. If such labor trends continue, they could further increase our costs or limit our ability to fully staff and operate our rigs and create the potential for more work stoppages, which may be beyond our control.

Unionization efforts and labor regulations in certain countries in which we operate could materially increase our costs or limit our flexibility.

Certain of our employees in non-U.S. markets are represented by labor unions and work under collective bargaining or similar agreements, which are subject to periodic renegotiation. Efforts have been made from time to time to unionize other portions of our workforce. In addition, we have been subjected to strikes or work stoppages and other labor disruptions in certain countries. Additional unionization efforts, new collective bargaining agreements or work stoppages could materially increase our costs, reduce our revenues or limit our flexibility.
 
Certain legal obligations require us to contribute certain amounts to retirement funds or other benefit plans and restrict our ability to dismiss employees. Future regulations or court interpretations established in the countries in which we conduct our operations could increase our costs and materially adversely affect our business, financial condition, operating results or cash flows.

Compliance with or breach of environmental laws can be costly and could limit our operations.

Our operations are subject to laws and regulations controlling the discharge of materials into the environment, pollution, contamination and hazardous waste disposal or otherwise relating to the protection of the environment. Environmental laws and regulations specifically applicable to our business activities could impose significant liability on us for damages, clean-up costs, fines and penalties in the event of oil spills or similar discharges of pollutants or contaminants into the environment or improper disposal of hazardous waste generated in the course of our operations. To date, such laws and regulations have not had a material adverse effect on our operating results, and we have not experienced an accident that has exposed us to material liability arising out of or relating to discharges of pollutants into the environment.  However, the legislative, judicial and regulatory response to the Macondo well incident could substantially increase our and our customers' liabilities.  In addition to potential increased liabilities, such legislative, judicial or regulatory action could impose increased financial, insurance or other requirements that may adversely impact the entire offshore drilling industry.
    
The International Convention on Oil Pollution Preparedness, Response and Cooperation, the U.K. Merchant Shipping Act 1995, the U.K. Merchant Shipping (Oil Pollution Preparedness, Response and Cooperation Convention) Regulations 1998, the Clean Water Act and other related legislation and regulations and Oil Pollution Act of 1990 ("OPA 90") and other U.S. federal statutes applicable to us and our operations, as well as similar statutes in Texas, Louisiana, other coastal states and other non-U.S. jurisdictions, address oil spill prevention and control and significantly

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expand liability, fine and penalty exposure across many segments of the oil and gas industry. Such statutes and related regulations impose a variety of obligations on us related to the prevention of oil spills, disposal of waste and liability for resulting damages. For instance, OPA 90 imposes strict and, with limited exceptions, joint and several liability upon each responsible party for oil removal costs as well as a variety of fines, penalties and damages. Although the OPA 90 provides for certain limits of liability, such limits are not applicable where there is any safety violation or where gross negligence is involved. Failure to comply with these statutes and regulations, including OPA 90, may subject us to civil or criminal enforcement action, which may not be covered by contractual indemnification or insurance and could have a material adverse effect on our financial position, operating results and cash flows. Further, remedies under the Clean Water Act and related legislation and the OPA 90 do not preclude claims under state regulations or civil claims for damages to third parties under state laws.

Events in recent years, including the Macondo well incident, have heightened governmental and environmental concerns about the oil and gas industry. From time to time, legislative proposals have been introduced that would materially limit or prohibit offshore drilling in certain areas. We are adversely affected by restrictions on drilling in certain areas of the U.S. Gulf of Mexico and elsewhere, including the conditions for lifting the recent moratorium/ suspension in the U.S. Gulf of Mexico, the adoption of associated new safety requirements and policies regarding the approval of drilling permits, restrictions on development and production activities in the U.S. Gulf of Mexico and associated NTLs, rules, directives and regulations that have and may further impact our operations. If new laws are enacted or other government action is taken that restrict or prohibit offshore drilling in our principal areas of operation or impose environmental protection requirements that materially increase the liabilities, financial requirements or operating or equipment costs associated with offshore drilling, exploration, development or production of oil and natural gas, our financial position, operating results and cash flows could be materially adversely affected.

Our debt levels and debt agreement restrictions may limit our liquidity and flexibility in obtaining additional financing and in pursuing other business opportunities.
 
As of December 31, 2012, we had $4.8 billion in total debt outstanding, representing approximately 29% of our total capitalization . Our current indebtedness may have several important effects on our future operations, including:
 
a portion of our cash flow from operations will be dedicated to the payment of principal and interest; 
covenants contained in our debt arrangements require us to meet certain financial tests, which may affect our flexibility in planning for, and reacting to, changes in our business and may limit our ability to dispose of assets or place restrictions on the use of proceeds from such dispositions, withstand current or future economic or industry downturns and compete with others in our industry for strategic opportunities; and 
our ability to obtain additional financing to fund working capital requirements, capital expenditures, acquisitions, dividend payments and general corporate or other cash requirements may be limited.
Our ability to maintain a sufficient level of liquidity to meet our financial obligations will be dependent upon our future performance, which will be subject to general economic conditions, industry cycles and financial, business and other factors affecting our operations, many of which are beyond our control. Our future cash flows may be insufficient to meet all of our working capital requirements, debt obligations and contractual commitments, and any insufficiency could negatively impact our business. To the extent we are unable to repay our indebtedness as it becomes due or at maturity with cash on hand or from other sources, we will need to refinance our debt, sell assets or repay the debt with the proceeds from equity offerings.


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Risks Related to Our Redomestication to the U.K.

There are risks associated with the issuance and trading of our Class A ordinary shares that were not associated with our ADSs.

In connection with the termination in May 2012 of our American depositary share ("ADS") facility and the conversion of our outstanding ADSs into Class A ordinary shares, we entered into arrangements with The Depository Trust Company ("DTC") whereby DTC has accepted such shares for deposit, book entry and clearing services. The facilities of DTC are widely-used for rapid electronic transfers of securities between participants within the DTC system, which include numerous major international financial institutions and brokerage firms.

We entered into this structure in part so that transfers of our shares held in book entry form through DTC will not be subject to a charge for stamp duty or stamp duty reserve tax (“SDRT”) in the U.K. Generally, stamp duty and/or SDRT are imposed in the U.K. on certain transfers of chargeable securities (which include shares in companies incorporated in the U.K.) at a rate of 0.5% of the consideration paid for the transfer. Certain transfers of shares to depositaries or into clearance systems, such as DTC, are charged at a higher rate of 1.5%. Eligibility for acceptance of foreign securities for deposit, book entry, clearing or other services is at the discretion of DTC and may be revoked by DTC under the terms of our agreement and in accordance with the rules, procedures and bylaws of DTC. A condition for continued eligibility of our shares is that DTC and its affiliates will not be liable for stamp duty or SDRT. We have indemnified DTC for any liability arising from stamp duty or SDRT.

We have obtained a favorable ruling from Her Majesty's Revenue & Customs ("HMRC") in respect of stamp duty and SDRT in relation to both the conversion and also our arrangement with DTC. Furthermore, following decisions of the European Court of Justice and the U.K. first-tier tax tribunal, HMRC has announced that they will not seek to apply a charge to stamp duty or SDRT on the issuance of shares (or, where it is integral to the raising of new capital, the transfer of new shares) into depository receipt or clearance systems, such as DTC. However, it is possible that the U.K. government may change or enact laws applicable to stamp duty or SDRT in response to this decision, which could have a material effect on the cost of trading in our shares. If DTC determines at any time that our shares are not eligible for continued deposit and clearance within its facilities, our shares may become ineligible for continued listing on a U.S. securities exchange or inclusion in the S&P 500, and trading in such shares would be disrupted. In this event, DTC has agreed it will provide us advance notice and assist us, to the extent possible, with efforts to mitigate adverse consequences. While we would pursue alternative arrangements to preserve our listing and maintain trading, any such disruption could have a material adverse effect on the trading price of our Class A ordinary shares and a resulting adverse effect on our financial position, operating results and/or cash flows.

Tax authorities may challenge our tax positions, and we may not be able to realize expected tax benefits.
    
Our tax positions are subject to audit by U.K., U.S. and other foreign tax authorities. Such tax authorities may disagree with our interpretations or assessments of the effects of tax laws, treaties, or regulations or their applicability to our corporate structure or certain transactions we have undertaken. Even if we are successful in maintaining our positions, we may incur significant expenses in defending our position and contesting claims or positions asserted by tax authorities. If we are unsuccessful in defending them, such audits could significantly impact our consolidated effective income tax rate in past or future periods.

We cannot provide any assurances as to what our consolidated effective income tax rate will be because of, among other matters, uncertainty regarding the nature and extent of our business activities in any particular jurisdiction in the future and the tax laws of such jurisdictions, as well as potential changes in U.K., U.S. and other foreign tax laws, regulations or treaties or the interpretation or enforcement thereof or any reclassification or other matter (such as changes in applicable accounting rules) that increases the amounts we have provided for income taxes or deferred tax assets and liabilities in our consolidated financial statements. If we are unable to mitigate the negative consequences of any change in law, audit or other matter, this could cause our consolidated effective income tax rate to increase and cause a material adverse effect on our financial position, operating results and/or cash flows.    


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We have not requested a ruling from HMRC on the U.K. tax aspects of the redomestication, and HMRC may disagree with our conclusion.

We believe that our redomestication to the U.K. in December 2009 did not result in any material U.K. corporation tax liability to Ensco plc, based on relevant U.K. corporation tax law and the current U.K.-U.S. income tax treaty. Further, we believe that we have satisfied all SDRT payment and filing obligations in connection with the issuance and deposit of our Class A ordinary shares into the ADS facility pursuant to the deposit agreement governing the ADS facility.

However, if HMRC disagrees with this view, it may take the position that material U.K. corporation tax or SDRT liabilities or amounts on account thereof are payable by Ensco plc as a result of the redomestication, in which case we expect that we would contest such assessment. If we were unsuccessful in disputing the assessment, the implications could be materially adverse to our financial position, operating results and/or cash flows. We have not requested an HMRC ruling on the U.K. tax aspects of the redomestication, and there can be no assurance that HMRC will agree with our interpretations of U.K. corporation tax law or any related matters associated therewith.

Expected financial, logistical and operational benefits of our redomestication to the U.K. may not be realized.

We cannot be assured that all of the goals of the redomestication will be achieved, particularly as achievement of our goals is in many important respects subject to factors that we do not control. These factors include the reactions of U.K. and U.S. tax authorities, the reactions of third parties with whom we enter into contracts and conduct business and the reactions of investors and analysts.

Whether we realize other expected financial benefits of the redomestication will depend on a variety of factors, many of which are beyond our control. These factors include changes in the relative rate of economic growth in the U.K. compared to the U.S., our financial performance in jurisdictions with lower tax rates, foreign currency exchange rate fluctuations, and significant changes in trade, monetary or fiscal policies of the U.K. or the U.S., including changes in taxation or interest rates. It is difficult to predict or quantify the effect of these factors, individually and in the aggregate, in part because the occurrence of any of these events or circumstances may be interrelated. If any of these events or circumstances occur, we may not be able to realize the expected financial benefits of the redomestication, and our expenses may increase to a greater extent than if we had not completed the redomestication.

    Realization of the logistical and operational benefits of the redomestication is also dependent on a variety of factors including the geographic regions in which our drilling rigs are deployed, the location of the business unit offices that oversee our global offshore contract drilling operations, the locations of our customers' corporate offices and principal areas of operation and the location of our investors. If events or changes in circumstances occur affecting the aforementioned factors, we may not be able to realize the expected logistical and operational benefits of the redomestication.

Investor enforcement of civil judgments against us may be more difficult.

Because our parent company is now a public limited company incorporated under English law, investors could experience more difficulty enforcing judgments obtained against us in U.S. courts than would have been the case for U.S. judgments obtained against us prior to the redomestication. In addition, it may be more difficult (or impossible) to bring some types of claims against us in courts in England than it would be to bring similar claims against a U.S. company in a U.S. court.
 

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We have less flexibility as a U.K. public limited company with respect to certain aspects of capital management than U.S. corporations due to increased shareholder approval requirements.

Directors of a Delaware and other U.S. corporations may issue, without further shareholder approval, shares of common stock authorized in its certificate of incorporation that were not already issued or reserved.  The business corporation laws of Delaware and other U.S. states also provide substantial flexibility in establishing the terms of preferred stock. However, English law provides that a board of directors may only allot shares with the prior authorization of an ordinary resolution of the shareholders, which authorization must state the maximum amount of shares that may be allotted under it and specify the date on which it will expire, which must not be more than five years from the date on which the shareholder resolution is passed. An ordinary resolution was passed prior to the effective time of the redomestication in December 2009 to authorize the allotment of additional shares for a five-year term. Such authorization will have to be renewed on or before its expiration (i.e. in December 2014). It is possible for an allotment authorization to be sought for a period shorter than five years.

English law also generally provides shareholders pre-emption rights over new shares that are issued for cash. However, it is possible, where the board of directors is generally authorized to allot shares, to exclude pre-emption rights by a special resolution of the shareholders or by a provision in the articles of association. Such exclusion of pre-emption rights will cease to have effect when the general allotment authority to which it relates is revoked or expires. If the general allotment authority is renewed, the authority excluding pre-emption rights may also be renewed by a special resolution of the shareholders. A special resolution was passed, in conjunction with an allotment authority, to exclude pre-emption rights prior to the effective time of the redomestication in December 2009 for a five-year term.

English law prohibits us from conducting "on-market purchases" as our shares will not be traded on a recognized investment exchange in the U.K. English law also generally prohibits a company from repurchasing its own shares by way of "off-market purchases" without the approval by a special resolution of the shareholders of the terms of the contract by which the purchase(s) is effected. Such approval may only last for a maximum period of five years after the date on which the resolution is passed. A special resolution was passed in December 2009 to permit "off-market purchases" prior to the effective time of the redomestication. In connection with the termination of the ADS facility and the conversion to Class A ordinary shares during the second quarter of 2012, our previously executed share repurchase agreements with two investment banks became of no effect by their own terms. Accordingly, a new resolution would need to be passed in order to approve the terms of any new contract(s) under which "off-market purchases" of the Company's shares can be effected.

We have no assurances that situations will not arise where such shareholder approval requirements for any of these actions would deprive our shareholders of substantial benefits.

Our articles of association contain anti-takeover provisions.

Certain provisions of our articles of association have anti-takeover effects, such as the ability to issue shares under the Rights Plan (as defined therein). These provisions are intended to ensure that any takeover or change of control of the Company is conducted in an orderly manner, all members of the Company are treated equally and fairly and receive an optimum price for their shares and the long-term success of the Company is safeguarded. Under English law, it may not be possible to implement these provisions in all circumstances.


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Implementation of the changes proposed in a consultation on companies subject to the U.K.'s Code on Takeovers and Mergers (the “Code”) would result in the Company becoming subject to the Code.

Currently the Code only applies to an offer for a public company that is registered in the U.K. (or the Channel Islands or the Isle of Man) and securities of which are not admitted to trading on a regulated market in the U.K. (or the Channel Islands or the Isle of Man) if the company is considered by the Takeover Panel to have its place of central management and control in the U.K. (or the Channel Islands or the Isle of Man). This is known as the "residency test." The test for central management and control under the Takeover Code is different from that used by the U.K. tax authorities. Under the Takeover Code, the Panel will look to where the majority of the directors of the company are themselves resident for the purposes of determining where the company has its place of central management and control.
 
If the amendments proposed as part of a process of consultation (which began in July 2012 and has now ended), the purpose of which was to gauge feedback to suggested changes to the Code, are implemented, the Company would become subject to the provisions of the Code. A number of these provisions could affect a potential bidder's ability to implement a takeover of the Company. The Company itself would also be subject to a number of rules and restrictions, including but not limited to the following: (1) the ability of the Company to enter into deal protection arrangements with a bidder would be extremely limited; (2) the Company might not, without the approval of its shareholders, be able to perform certain actions that could have the effect of frustrating an offer, such as issuing shares or carrying out acquisitions or disposals; and (3) the Company would be obliged to provide equality of information to all bona fide competing bidders.

Item 1B.  Unresolved Staff Comments

None.

30



Item 2.  Properties

Contract Drilling Fleet

The following table provides certain information about the rigs in our drilling fleet by operating segment as of February 19, 2013:
 
 
 
Rig Name
 
 
  Rig Type
 
 
Year Built/
Rebuilt
 
 
 
Design      
 
   Maximum
 Water Depth/
Drilling Depth
 
 
  Location   
 
 
Customer    
Floaters
 
 

 
 
 
 
 


ENSCO DS-1
Drillship
 
1999
 
Dynamically Positioned
 
6,000'/30,000'
 
Angola
TOTAL
ENSCO DS-2
Drillship
 
1999
 
Dynamically Positioned
 
6,000'/30,000'
 
Angola
TOTAL
ENSCO DS-3
Drillship
 
2010
 
Dynamically Positioned
 
10,000'/40,000'
 
Gulf of Mexico
BP
ENSCO DS-4
Drillship
 
2010
 
Dynamically Positioned
 
10,000'/40,000'
 
Brazil
BP
ENSCO DS-5
Drillship
 
2011
 
Dynamically Positioned
 
10,000'/40,000'
 
Gulf of Mexico
Petrobras
ENSCO DS-6
Drillship(1)
 
2012
 
Dynamically Positioned
 
10,000'/40,000'
 
Angola
BP
ENSCO DS-7
Drillship
 
2013
 
Dynamically Positioned
 
10,000'/40,000'
 
South Korea
Under construction/contracted(3)
ENSCO DS-8
Drillship(2)
 
2014
 
Dynamically Positioned
 
10,000'/40,000'
 
South Korea
Under construction(3)
ENSCO DS-9
Drillship(2)
 
2014
 
Dynamically Positioned
 
10,000'/40,000'
 
South Korea
Under construction(3)
ENSCO 5000(4)
Semisubmersible
 
1973/1995/2008
 
Neptune Pentagon
 
2,300'/25,000'
 
Brazil
Petrobras
ENSCO 5001
Semisubmersible
 
1977/1999/2009
 
Sonat
 
5,000'/25,000'
 
South Africa
PetroSA
ENSCO 5002
Semisubmersible
 
1975/2001
 
Aker H-3
 
1,000'/25,000'
 
Brazil
OGX
ENSCO 5004
Semisubmersible
 
1982/2001
 
F&G Enhanced Pacesetter
 
1,500'/25,000'
 
Brazil
OGX
ENSCO 5005
Semisubmersible
 
1982
 
F&G Enhanced Pacesetter
 
1,500'/25,000'
 
Singapore
Shipyard
ENSCO 5006
Semisubmersible
 
1999
 
Bingo 8000
 
6,200'/25,000'
 
Israel
Noble Energy
ENSCO 6000
Semisubmersible
 
1987/1996
 
Dynamically Positioned
 
3,400'/12,000'
 
Brazil
Petrobras
ENSCO 6001(5)
Semisubmersible
 
2000/2010
 
Megathyst
 
5,700'/25,000'
 
Brazil
Petrobras
ENSCO 6002(6)
Semisubmersible
 
2001/2009
 
Megathyst
 
5,700'/25,000'
 
Brazil
Petrobras
ENSCO 6003(7)
Semisubmersible
 
2004
 
Megathyst
 
5,700'/25,000'
 
Brazil
Petrobras
ENSCO 6004(8)
Semisubmersible
 
2004
 
Megathyst
 
5,700'/25,000'
 
Brazil
Petrobras
ENSCO 7500
Semisubmersible
 
2000
 
Dynamically Positioned
 
8,000'/30,000'
 
Brazil
Petrobras
ENSCO 8500
Semisubmersible
 
2008
 
Dynamically Positioned
 
8,500'/35,000'
 
Gulf of Mexico
Anadarko/Eni
ENSCO 8501
Semisubmersible
 
2009
 
Dynamically Positioned
 
8,500'/35,000'
 
Gulf of Mexico
Nexen/Noble Energy
ENSCO 8502
Semisubmersible
 
2010
 
Dynamically Positioned
 
8,500'/35,000'
 
Gulf of Mexico
Nexen/LLOG
ENSCO 8503
Semisubmersible
 
2010
 
Dynamically Positioned
 
8,500'/35,000'
 
Gulf of Mexico
Cobalt
ENSCO 8504
Semisubmersible
 
2011
 
Dynamically Positioned
 
8,500'/35,000'
 
Philippines
Shell
ENSCO 8505
Semisubmersible(1)
 
2012
 
Dynamically Positioned
 
8,500'/35,000'
 
Gulf of Mexico
Anadarko/Apache/Noble Energy
ENSCO 8506
Semisubmersible(1)
 
2012
 
Dynamically Positioned
 
8,500'/35,000'
 
Gulf of Mexico
Anadarko
 
 
 
 
 
 
 
 
 
 
 
Jackups
 
 
 
 
 
 
 
 
 
 
ENSCO 52
Jackup
 
1983/1997
 
F&G L-780 MOD II-C
 
300'/25,000'
 
Malaysia
Murphy
ENSCO 53
Jackup
 
1982/2009
 
F&G L-780 MOD II-C
 
300'/25,000'
 
Malaysia
BC Petroleum
ENSCO 54
Jackup
 
1982/1997
 
F&G L-780 MOD II-C
 
300'/25,000'
 
UAE
Bunduq
ENSCO 56
Jackup
 
1982/1997
 
F&G L-780 MOD II-C
 
300'/25,000'
 
Indonesia
Pertamina
ENSCO 58
Jackup
 
1981/2002
 
F&G L-780 MOD II
 
250'/30,000'
 
Saudi Arabia
Saudi Aramco
ENSCO 67
Jackup
 
1976/2005
 
MLT 84-CE
 
400'/30,000'
 
Indonesia
Pertamina
ENSCO 68
Jackup
 
1976/2004
 
MLT 84-CE
 
400'/30,000'
 
Gulf of Mexico
Chevron
ENSCO 69
Jackup
 
1976/1995
 
MLT 84-Slot
 
300'/25,000'
 
Gulf of Mexico
Cold Stacked
ENSCO 70
Jackup
 
1981/1996
 
Hitachi K1032N
 
250'/30,000
 
United Kingdom
RWE Dea
ENSCO 71
Jackup
 
1982/1995
 
Hitachi K1032N
 
225'/25,000'
 
Denmark
Maersk
ENSCO 72
Jackup
 
1981/1996
 
Hitachi K1025N
 
225'/25,000'
 
Denmark
Maersk

31



 
 
Rig Name
 
 
  Rig Type
 
 
Year Built/  
Rebuilt 
 
 
 
Design      
 
   Maximum
 Water Depth/
Drilling Depth
 
 
  Current
  Location   
 
Current Customer   
Jackups

 
 
 

 
 
 
 
 
ENSCO 75
Jackup
 
1999
 
MLT Super 116-C
 
400'/30,000'
 
Gulf of Mexico
Apache
ENSCO 76
Jackup
 
2000
 
MLT Super 116-C
 
400'/30,000'
 
Saudi Arabia
Saudi Aramco
ENSCO 80
Jackup
 
1978/1995
 
MLT 116-CE
 
225'/30,000'
 
United Kingdom
Perenco
ENSCO 81
Jackup
 
1979/2003
 
MLT 116-C
 
350'/30,000'
 
Gulf of Mexico
Dynamic
ENSCO 82
Jackup
 
1979/2003
 
MLT 116-C
 
300'/30,000'
 
Gulf of Mexico
Energy XXI
ENSCO 83
Jackup
 
1979/2007
 
MLT 82-SD-C
 
250'/25,000'
 
Mexico
Pemex
ENSCO 84
Jackup
 
1981/2005
 
MLT 82-SD-C
 
250'/25,000'
 
Saudi Arabia
Saudi Aramco
ENSCO 85
Jackup
 
1981/1995
 
MLT 116-C
 
300'/25,000'
 
Indonesia
Pertamina
ENSCO 86
Jackup
 
1981/2006
 
MLT 82-SD-C
 
250'/30,000'
 
Gulf of Mexico
Apache
ENSCO 87
Jackup
 
1982/2006
 
MLT 116-C
 
350'/25,000'
 
Gulf of Mexico
Apache
ENSCO 88
Jackup
 
1982/2004
 
MLT 82-SD-C
 
250'/25,000'
 
Qatar
Ras Gas
ENSCO 89
Jackup
 
1982/2005
 
MLT 82-SD-C
 
250'/25,000'
 
Mexico
Pemex
ENSCO 90
Jackup
 
1982/2002
 
MLT 82-SD-C
 
250'/25,000'
 
Gulf of Mexico
Energy XXI
ENSCO 91
Jackup
 
1980/2001
 
Hitachi Zosen
 
270'/20,000'
 
Saudi Arabia
Saudi Aramco
ENSCO 92
Jackup
 
1982/1996
 
MLT 116-C
 
225'/25,000'
 
United Kingdom
RWE Dea
ENSCO 93
Jackup
 
1982/2008
 
MLT 82-SD-C
 
250'/25,000'
 
Mexico
Pemex
ENSCO 94
Jackup
 
1981/2001
 
Hitachi 250-C
 
250'/25,000'
 
Qatar
Shipyard
ENSCO 96
Jackup
 
1982/1997
 
Hitachi 250-C
 
250'/25,000'
 
Saudi Arabia
Saudi Aramco
ENSCO 97
Jackup
 
1980/1997
 
MLT 82 SD-C
 
250'/25,000'
 
Saudi Arabia
Saudi Aramco
ENSCO 98
Jackup
 
1977/2003
 
MLT 82 SD-C
 
250'/25,000'
 
Mexico
Pemex
ENSCO 99
Jackup
 
1985/2005
 
MLT 82 SD-C
 
250'/30,000'
 
Gulf of Mexico
Energy XXI
ENSCO 100
Jackup
 
1987/2009
 
MLT 150-88-C
 
350'/30,000
 
United Kingdom
E.ON
ENSCO 101
Jackup
 
2000
 
KELFS MOD V-A
 
400'/30,000'
 
United Kingdom
Maersk
ENSCO 102
Jackup
 
2002
 
KELFS MOD V-A
 
400'/30,000'
 
United Kingdom
ConocoPhillips
ENSCO 104
Jackup
 
2002
 
KELFS MOD V-B
 
400'/30,000'
 
Australia
Apache
ENSCO 105
Jackup
 
2002
 
KELFS MOD V-B
 
400'/30,000'
 
Malaysia
Petronas Carigali
ENSCO 106
Jackup
 
2005
 
KELFS MOD V-B
 
400'/30,000'
 
Malaysia
Newfield
ENSCO 107
Jackup
 
2006
 
KELFS MOD V-B
 
400'/30,000'
 
Vietnam
Thang Long JOC
ENSCO 108
Jackup
 
2007
 
KELFS MOD V-B
 
400'/30,000'
 
Thailand
PTTEP
ENSCO 109
Jackup
 
2008
 
KELFS MOD V-Super B
 
350'/35,000'
 
Australia
Eni/Murphy/Vermillion/Santos
ENSCO 120
Jackup
 
2013
 
KFELS Super A
 
400'/40,000'
 
Singapore
Under construction/contracted(3)
ENSCO 121
Jackup(2)
 
2013
 
KFELS Super A
 
400'/40,000'
 
Singapore
Under construction(3)
ENSCO 122
Jackup(2)
 
2014
 
KFELS Super A
 
400'/40,000'
 
Singapore
Under construction(3)
Pride Pennsylvania
Jackup
 
1973/1998
 
MLT
 
300'/20,000'
 
Bahrain
Cold Stacked
Pride Wisconsin
Jackup
 
1976/2002
 
MLT-Slot
 
300'/20,000'
 
Gulf of Mexico
Cold Stacked
Other
 
 
 
 
 
 
 
 
 
 
Kizomba
Managed Rig
 
2004
 
Managed Rig
 
5,000'/25,000'
 
Angola
ExxonMobil
Thunderhorse
Managed Rig
 
2004
 
Managed Rig
 
6,000'/25,000'
 
Gulf of Mexico
BP
Mad Dog 
Managed Rig 
 
2004
 
Managed Rig 
 
4,500'/25,000' 
 
Gulf of Mexico 
BP 

(1) 
ENSCO 8505 was delivered in January 2012 and commenced drilling operations under a long-term contract in the U.S. Gulf of Mexico in June 2012. ENSCO DS-6 was delivered in January 2012, underwent customer specified upgrades in a shipyard in Singapore, and commenced drilling operations under a five-year contract in Angola during the first quarter of 2013. ENSCO 8506 was delivered during the third quarter of 2012 and commenced drilling operations in the U.S. Gulf of Mexico under a long-term contract during the first quarter of 2013.

(2) 
We currently are marketing ENSCO DS-8, ENSCO DS-9, ENSCO 121 and ENSCO 122 and anticipate they will be contracted in advance of delivery. For additional information on our rigs under construction, see "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations."

(3) 
Rig currently is under construction. The "year built" provided is based on the current construction schedule.


32



(4) 
We are in the process of changing the name of this rig. For the purpose of this annual report, we used the new name even though the name change has not been legally completed. The current name of this rig is Pride Mexico.

(5) 
We are in the process of changing the name of this rig. For the purpose of this annual report, we used the new name even though the name change has not been legally completed. The current name of this rig is Pride Carlos Walter.

(6) 
We are in the process of changing the name of this rig. For the purpose of this annual report, we used the new name even though the name change has not been legally completed. The current name of this rig is Pride Brazil.

(7) 
We are in the process of changing the name of this rig. For the purpose of this annual report, we used the new name even though the name change has not been legally completed. The current name of this rig is Pride Rio de Janeiro.

(8) 
We are in the process of changing the name of this rig. For the purpose of this annual report, we used the new name even though the name change has not been legally completed. The current name of this rig is Pride Portland.

The equipment on our drilling rigs includes engines, drawworks, derricks, pumps to circulate the drilling fluid, well control systems, drill string and related equipment. The engines power a top-drive mechanism that turns the drill string and drill bit so that the hole is drilled by grinding subsurface materials, which are then returned to the rig by the drilling fluid. The intended water depth, well depth and drilling conditions are the principal factors that determine the size and type of rig most suitable for a particular drilling project.
 
Floater rigs consist of drillship rigs and semisubmersible rigs. Drillship rigs are maritime vessels that have been outfitted with drilling apparatus.  Drillships are self-propelled and can be positioned over a drill site through the use of a computer-controlled propeller or "thruster" (dynamic positioning) system.  Our drillships are capable of drilling in water depths of 10,000 feet or less and are suitable for deepwater drilling in remote locations because of their mobility and large load-carrying capacity.  Although drillships are most often used for deepwater drilling and exploratory well drilling, drillships can also be used as a platform to carry out well maintenance or completion work such as casing and tubing installation or subsea tree installations.
    
Semisubmersible rigs are floating offshore drilling units with pontoons and columns that partially submerge to a predetermined depth when sea water is permitted to enter the hull. Semisubmersible rigs can be held in a fixed location over the ocean floor either by being anchored to the sea bottom with mooring chains (moored semisubmersible rig) or dynamically positioned by computer-controlled propellers or "thrusters" (dynamically positioned semisubmersible rig) similar to that used by our drillships.  Moored semisubmersible rigs are most commonly used for drilling in water depths of 4,499 feet or less.  However, ENSCO 5001 and ENSCO 5006, which are moored semisubmersible rigs, are capable of deepwater drilling in water depths greater than 5,000 feet.  ENSCO 7500, which is capable of drilling in water depths up to 8,000 feet, is a dynamically positioned rig that also can be adapted for moored operations. The rig uses a riser system to manage the drilling fluid and well control equipment located on the ocean floor.  Dynamically positioned semisubmersible rigs generally are outfitted for drilling in deeper water depths and are well-suited for deepwater development and exploratory well drilling.
 
Jackup rigs stand on the ocean floor with their hull and drilling equipment elevated above the water on connected leg supports. Jackup rigs are generally preferred over other rig types in shallow water depths of 400 feet or less, primarily because jackup rigs provide a more stable drilling platform with above water well control equipment. Our jackup rigs are of the independent leg design where each leg can be fixed into the ocean floor at varying depths and equipped with a cantilever that allows the drilling equipment to extend outward from the hull over fixed platforms enabling safer drilling of both exploratory and development wells. The jackup rig hull supports the drilling equipment, jacking system, crew quarters, storage and loading facilities, helicopter landing pad and related equipment and supplies.
 
Over the life of a typical rig, many of the major systems are replaced due to normal wear and tear or technological advancements in drilling equipment. We believe all of our rigs are in good condition. As of February 15, 2013, we owned all of the rigs in our fleet. We also manage the drilling operations for three rigs owned by a third-party. 
 
We lease our executive offices in London, England and own offices and other facilities in Louisiana, Brazil, France and Scotland.  In addition to our executive offices, we currently lease office space in Texas, Abu Dhabi, Angola, Australia, Brunei, Denmark, Dubai, Indonesia, Israel, Korea, Malaysia, Mexico, Qatar, Saudi Arabia, Singapore, Switzerland, Tunisia, Vietnam and several additional international locations.

33




Item 3.  Legal Proceedings
 
Pride FCPA Investigation

During 2010, Pride and its subsidiaries resolved with the DOJ and the SEC their previously disclosed investigations into potential violations of the FCPA.  The settlement with the DOJ included a DPA between Pride and the DOJ and a guilty plea by Pride Forasol, S.A.S., one of Pride’s subsidiaries, to FCPA-related charges. In November 2012, the DOJ moved (i) to dismiss the charges against Pride and end the DPA one year prior to its scheduled expiration; and (ii) to terminate the unsupervised probation of Pride Forasol, S.A.S.   The Court granted the motions.

     Pride has received preliminary inquiries from governmental authorities of certain of the countries referenced in its settlements with the DOJ and SEC. We could face additional fines, sanctions and other penalties from authorities in these and other relevant jurisdictions, including prohibition of our participating in or curtailment of business operations in those jurisdictions and the seizure of rigs or other assets. At this early stage of such inquiries, we are unable to determine what, if any, legal liability may result. 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 directors, officers, employees, affiliates, advisors, attorneys, agents, stockholders, debt holders, or other interest holders or constituents of our Company. In addition, disclosure of the subject matter of the investigations and settlements could adversely affect our reputation and our ability to obtain new business or retain existing business from our current clients and potential clients, to attract and retain employees and to access the capital markets.

We cannot currently predict what, if any, actions may be taken by any other applicable government or other authorities or our customers or other third parties or the effect any such actions may have on our financial condition, operating results or cash flows.

Asbestos Litigation
 
We and certain subsidiaries have been named as defendants, along with numerous third-party companies as co-defendants, in multi-party lawsuits filed in Mississippi and Louisiana by approximately 100 plaintiffs. The lawsuits seek an unspecified amount of monetary damages on behalf of individuals alleging personal injury or death, primarily under the Jones Act, purportedly resulting from exposure to asbestos on drilling rigs and associated facilities during the 1960s through the 1980s.

We intend to vigorously defend against these claims and have filed responsive pleadings preserving all defenses and challenges to jurisdiction and venue. However, discovery is still ongoing and, therefore, available information regarding the nature of all pending claims is limited. At present, we cannot reasonably determine how many of the claimants may have valid claims under the Jones Act or estimate a range of potential liability exposure, if any.
 
In addition to the pending cases in Mississippi and Louisiana, we have other asbestos or lung injury claims pending against us in litigation in other jurisdictions. Although we do not expect the final disposition of these asbestos or lung injury lawsuits to have a material adverse effect upon our financial position, operating results or cash flows, there can be no assurances as to the ultimate outcome of the lawsuits.


34



Environmental Matters
 
We are currently subject to, or expecting, notices of assessment issued from 2008 to 2012 pursuant to which governmental authorities in Brazil are seeking fines in an aggregate amount of approximately $2.0 million for the release of drilling fluids, oil, brine, chemicals, grease or fuel from drilling rigs operating offshore Brazil.  We have contested these notices and appealed certain adverse decisions, and are awaiting decisions in these cases. Although we do not expect the outcome of these assessments to have a material adverse effect on our financial position, operating results or cash flows, there can be no assurance as to the ultimate outcome of these assessments. A $2.0 million liability related to these matters is included in accrued liabilities and other on our consolidated balance sheet as of December 31, 2012.
 
We currently are subject to a pending administrative proceeding initiated in July 2009 by a governmental authority of Spain pursuant to which such governmental authority is seeking payment in an aggregate amount of approximately $4.0 million for an alleged environmental spill originating from the ENSCO 5006 while it was operating offshore Spain. Our customer has posted guarantees with the Spanish government to cover potential penalties. Additionally, we expect to be indemnified for any payments resulting from this incident by our customer under the terms of the drilling contract. A criminal investigation of the incident was initiated in July 2010 by a prosecutor in Tarragona, Spain, and the administrative proceedings have been suspended pending the outcome of this investigation.  We do not know at this time what, if any, involvement we may have in this investigation.
 
We intend to vigorously defend ourselves in the administrative proceeding and any criminal investigation. At this time, we are unable to predict the outcome of these matters or estimate the extent to which we may be exposed to any resulting liability. Although we do not expect the outcome of the proceedings to have a material adverse effect on our financial position, operating results or cash flows, there can be no assurance as to the ultimate outcome of the proceedings.

Other Matters

In addition to the foregoing, we are named defendants or parties in certain other lawsuits, claims or proceedings incidental to our business and are involved from time to time as parties to governmental investigations or proceedings, including matters related to taxation, arising in the ordinary course of business. Although the outcome of such lawsuits or other proceedings cannot be predicted with certainty and the amount of any liability that could arise with respect to such lawsuits or other proceedings cannot be predicted accurately, we do not expect these matters to have a material adverse effect on our financial position, operating results or cash flows.

Item 4.  Mine Safety Disclosures
 
    Not applicable.

35



PART II


Item 5.
Market for Registrant's Common Equity, Related Shareholder Matters and Issuer Purchases of Equity Securities

Market Information
The following table provides the high and low sales price of our American depositary shares ("ADSs"), each representing one Class A ordinary share, par value U.S. $0.10 per share, until May 22, 2012 and of our Class A ordinary shares ("shares") thereafter for each period indicated during the last two fiscal years:
 
 
First
Quarter
 
 Second
Quarter
 
  Third
Quarter
 
 Fourth
Quarter
 
 
 Year
2012 High
 
$
59.90

 
$
55.66

 
$
61.48

 
$
60.73

 
$
61.48

2012 Low
 
$
46.28

 
$
41.63

 
$
45.95

 
$
53.53

 
$
41.63

2011 High
 
$
59.61

 
$
60.31

 
$
54.12

 
$
55.29

 
$
60.31

2011 Low
 
$
49.70

 
$
50.00

 
$
39.51

 
$
37.39

 
$
37.39


On May 22, 2012, we terminated our ADS facility and converted our outstanding ADSs into Class A ordinary shares on a one-for-one basis. Our Class A ordinary shares are traded on the NYSE with the ticker symbol "ESV."  In connection with the conversion, many of our shareholders now hold shares electronically, all of which are owned by a nominee of The Depository Trust Company. We had 63 holders of record of our shares on February 1, 2013.
 
Dividends
 
We began paying a $.025 per share quarterly cash dividend during the third quarter of 1997 and continued to pay this quarterly dividend through March 31, 2010.  During the second quarter of 2010, our Board of Directors declared a regular quarterly cash dividend of $.35 per share. We continued to pay this quarterly cash dividend through December 31, 2011. During the first quarter of 2012, our Board of Directors declared a regular quarterly cash dividend of $.375 per share, and we have continued to pay this quarterly cash dividend through December 31, 2012.  Cash dividends totaling $1.50 and $1.40 per share were paid during 2012 and 2011, respectively.  We currently intend to continue paying quarterly dividends for the foreseeable future. However, our Board of Directors may change the timing and amount of payment of dividends on our shares depending on several factors including our profitability, liquidity, financial condition, reinvestment opportunities and capital requirements.

Exchange Controls

There are no U.K. government laws, decrees or regulations that restrict or affect the export or import of capital, including but not limited to, foreign exchange controls on remittance of dividends on our ordinary shares or on the conduct of our operations.

U.K. Taxation
 
The following paragraphs are intended to be a general guide to current U.K. tax law and what is understood to be HMRC practice applying as of the date of this report (both of which are subject to change at any time, possibly with retrospective effect) in respect of the taxation of capital gains, the taxation of dividends paid by us and stamp duty and SDRT on the transfer of our shares. In addition, the following paragraphs relate only to persons who for U.K. tax purposes are beneficial owners of the shares (“shareholders”).

These paragraphs may not relate to certain classes of holders or beneficial owners of shares, such as our employees or directors, persons who are connected with us, insurance companies, charities, collective investment

36



schemes, pension schemes, trustees or persons who hold shares other than as an investment, or U.K. resident individuals who are not domiciled in the U.K.

These paragraphs do not describe all of the circumstances in which shareholders may benefit from an exemption or relief from taxation. It is recommended that all shareholders obtain their own taxation advice. In particular, any shareholders who are non-U.K. resident or domiciled are advised to consider the potential impact of any relevant double tax treaties, including the Convention between the United States of America and the United Kingdom for the Avoidance of Double Taxation with respect to Taxes on Income, to the extent applicable.

Pursuant to provisions providing for a statutory definition of U.K. tax residence that will be included in the Finance Bill 2013, the concept of “ordinary residence” will be abolished with effect on and after April 6, 2013.

U.K. Taxation of Dividends
 
U.K. Withholding Tax - Dividends paid by us will not be subject to any withholding or deduction for, or on account of, U.K. tax, irrespective of the residence or the individual circumstances of the shareholders.

U.K. Income Tax - An individual shareholder who is resident or ordinarily resident in the U.K. may, depending on his or her individual circumstances, be subject to U.K. income tax on dividends received from us. An individual shareholder who is not resident or ordinarily resident in the U.K. will not be subject to U.K. income tax on dividends received from us, unless that shareholder carries on (whether alone or in partnership) any trade, profession or vocation through a branch or agency in the U.K. and shares are used by, or held by or for, that branch or agency. In these circumstances, the non-U.K. resident shareholder may, depending on his or her individual circumstances, be subject to U.K. income tax on dividends received from us.

The rate of U.K. income tax payable with respect to dividends received by higher rate taxpayers in the tax year 2012/2013 is 32.5%. Individuals whose total income subject to income tax exceeds £150,000 will be subject to income tax in respect of dividends in excess of that amount at the rate of 42.5% in the tax year 2012/2013. An individual's dividend income is treated as the top slice of his or her total income subject to income tax.  Individual shareholders who are resident in the U.K. will be entitled to a tax credit equal to one-ninth of the amount of the dividend received from us, which will be taken into account in computing the gross amount of the dividend subject to income tax. The tax credit will be credited against the relevant shareholder's liability (if any) to income tax on the gross amount of the dividend. An individual shareholder who is not subject to U.K. income tax on dividends received from us will not be entitled to claim payment of the tax credit in respect of such dividends. The right to a tax credit for an individual shareholder who is not resident in the U.K. will depend on his or her individual circumstances.
    
U.K. Corporation Tax - Unless an exemption is available (as discussed below), a corporate shareholder that is resident in the U.K. will be subject to U.K. corporation tax on dividends received from us. A corporate shareholder that is not resident in the U.K. will not be subject to U.K. corporation tax on dividends received from us, unless that shareholder carries on a trade in the U.K. through a permanent establishment in the U.K. and the shares are used by, for or held by or for, the permanent establishment. In these circumstances, the non-U.K. resident corporate shareholder may, depending on its individual circumstances (and if no exemption is available), be subject to U.K. corporation tax on dividends received from us.

The main rate of corporation tax payable with respect to dividends received from us in the financial year 2012 is 24%, although small companies may be entitled to claim the small companies rate of tax. If dividends paid by us fall within any of the exemptions from U.K. corporation tax set out in Part 9A of the U.K. Corporation Tax Act 2009, the receipt of the dividend by a corporate shareholder generally will be exempt from U.K. corporation tax. Generally, the conditions for one or more of those exemptions from U.K. corporation tax on dividends paid by us should be satisfied, although the conditions that must be satisfied in any particular case will depend on the individual circumstances of the relevant corporate shareholder.

Shareholders that are regarded as small companies should generally be exempt from U.K. corporation tax on dividends received from us, unless the dividends are received as part of a tax advantage scheme. Shareholders that are

37



not regarded as small companies should generally be exempt from U.K. corporation tax on dividends received from us on the basis that the shares should be regarded as non-redeemable ordinary shares. Alternatively, shareholders that are not small companies should also generally be exempt from U.K. corporation tax on dividends received from us if they hold shares representing less than 10% of our issued share capital, would be entitled to less than 10% of the profits available for distribution to our equity-holders and would be entitled on a winding up to less than 10% of our assets available for distribution to such equity-holders. In certain limited circumstances, the exemption from U.K. corporation tax will not apply to such shareholders if a dividend is made as part of a scheme that has a main purpose of falling within the exemption from U.K. corporation tax.

U.K. Taxation of Capital Gains
 
U.K. Withholding Tax - Capital gains accruing to non-U.K. resident shareholders on the disposal of shares will not be subject to any withholding or deduction for or on account of U.K. tax, irrespective of the residence or the individual circumstances of the relevant shareholder.

U.K. Capital Gains Tax - A disposal of shares by an individual shareholder who is resident or ordinarily resident in the U.K. may, depending on his or her individual circumstances, give rise to a taxable capital gain or an allowable loss for the purposes of U.K. capital gains tax (“CGT”). An individual shareholder who temporarily ceases to be resident or ordinarily resident in the U.K. for a period of less than five years and who disposes of his or her shares during that period of temporary non-residence may be liable to CGT on a taxable capital gain accruing on the disposal on his or her return to the U.K. under certain anti-avoidance rules.

An individual shareholder who is neither resident nor ordinarily resident in the U.K. will not be subject to CGT on capital gains arising on the disposal of their shares, unless that shareholder carries on a trade, profession or vocation in the U.K. through a branch or agency in the U.K. and the shares were acquired, used in or for the purposes of the branch or agency or used in or for the purposes of the trade, profession or vocation carried on by the shareholder through the branch or agency. In these circumstances, the relevant non-U.K. resident shareholder may, depending on his or her individual circumstances, be subject to CGT on chargeable gains arising from a disposal of his or her shares. The rate of CGT in the tax year 2012/2013 is 18% for basic rate taxpayers and 28% for higher and additional rate taxpayers.

U.K. Corporation Tax - A disposal of shares by a corporate shareholder resident in the U.K. may give rise to a chargeable gain or an allowable capital loss for the purposes of U.K. corporation tax. A corporate shareholder not resident in the U.K. will not be liable for U.K. corporation tax on chargeable gains accruing on the disposal of its shares, unless that shareholder carries on a trade in the U.K. through a permanent establishment in the U.K. and the shares were acquired, used in or for the purposes of the permanent establishment or used in or for the purposes of the trade carried on by the shareholder through the permanent establishment. In these circumstances, the relevant non-U.K. resident shareholder may, depending on its individual circumstances, be subject to U.K. corporation tax on chargeable gains arising from a disposal of its shares.

The financial year for U.K. corporation tax purposes runs from April 1 to March 31. The main rate of U.K. corporation tax on chargeable gains is 26% in the financial year 2011 and 24% in the financial year 2012, although small companies may be entitled to claim the small companies rate of tax. Corporate shareholders will be entitled to an indexation allowance in computing the amount of a chargeable gain accruing on a disposal of the shares, which will provide relief for the effects of inflation by reference to movements in the U.K. retail price index.

If the conditions of the applicable shareholding exemption are satisfied in relation to a chargeable gain accruing to a corporate shareholder on a disposal of its shares, the chargeable gain will be exempt from U.K. corporation tax. The conditions of the substantial shareholding exemption that must be satisfied will depend on the individual circumstances of the relevant corporate shareholder. One of the conditions of the substantial shareholding exemption that must be satisfied is that the corporate shareholder must have held a substantial shareholding in the Company throughout a twelve-month period beginning not more than two years before the day on which the disposal takes place. Ordinarily, a corporate shareholder will not be regarded as holding a substantial shareholding in us, unless it (whether alone, or together with other group companies) directly holds not less than 10% of our ordinary share capital.

38




U.K. Stamp Duty and SDRT
 
The discussion below relates to shareholders wherever resident but not to holders such as market makers, brokers, dealers and intermediaries, to whom special rules apply. Special rules also apply in relation to certain stock lending and repurchase transactions.

Transfer of Shares held in book entry form via DTC - A transfer of shares held in book entry (i.e., electronic) form within the facilities of the DTC will not be subject to U.K. stamp duty or SDRT.

Transfers of Shares out of, or outside of, DTC - Subject to an exemption for certain low value transactions, a transfer of shares from within the DTC system out of that system or any transfer of shares that occurs entirely outside the DTC system generally will be subject to a charge to ad valorem U.K. stamp duty (normally payable by the transferee) at 0.5% of the purchase price of the shares (rounded up to the nearest multiple of £5). SDRT generally will be payable on an unconditional agreement to transfer such shares at 0.5% of the amount or value of the consideration for the transfer. However, such liability for SDRT generally will be cancelled and any SDRT paid will be refunded if the agreement is completed by a duly-stamped transfer within six years of either the date of the agreement or, if the agreement was conditional, the date when the agreement became unconditional.

We have put in place arrangements to require that shares held outside the facilities of DTC cannot be transferred into such facilities (including where shares are re-deposited into DTC by an existing shareholder) until the transferor of the shares has first delivered the shares to a depository we specified, so that SDRT may be collected in connection with the initial delivery to the depository. Before such transfer can be registered in our books, the transferor will be required to put in the depository funds to settle the resultant liability for SDRT, which will be 1.5% of the value of the shares, and to pay the transfer agent such processing fees as may be established from time to time.

Following a decision of the European Court of Justice in 2009 and a decision of the U.K. first-tier tax tribunal in 2012, HMRC has announced that it will not seek to apply the 1.5% charge to stamp duty or SDRT on the issuance of shares (or, where it is integral to the raising of new capital, the transfer of new shares) into depository receipt or clearance systems, such as DTC. Thus, the 1.5% U.K. stamp duty or SDRT charge will apply only to the transfer of existing shares to clearance services or depositary receipt systems in circumstances where the transfer is not integral to the raising of new capital (for example, where shares are re-deposited into DTC by an existing shareholder). Investors should, however, be aware that this area may be subject to further developments in the future.
    
The above statements are intended only as a general guide to the current U.K. stamp duty and SDRT position. Transfers to certain categories of persons are not liable to U.K. stamp duty or SDRT and transfers to others may be liable at a higher rate than discussed above.
 
Equity Compensation Plans
 
For information on shares issued or to be issued in connection with our equity compensation plans, see "Part III, Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters."


39



Issuer Purchases of Equity Securities
 
The following table provides a summary of our repurchases of our equity securities during the quarter ended December 31, 2012.

Issuer Purchases of Equity Securities
 
 
 
 
 
 
 
Period
Total Number of Securities Purchased
 
Average Price Paid per Security
 
Total Number of Securities Purchased as Part of Publicly Announced Plans or Programs*    
 
Approximate Dollar Value of Securities that May Yet Be Purchased Under Plans or Programs
 
 
 
 
 
 
 
 
October 1 - October 31 
2,216

 
$
54.84

 

 
$

November 1 - November 30
1,471

 
$
56.90

 

 
$

December 1 - December 31
1,233

 
$
58.86

 

 
$

Total 
4,920

 
$
56.46

 

 
 


* In connection with the termination of the ADS facility and the conversion to Class A ordinary shares during the second quarter of 2012, our previously executed share repurchase agreements with two investment banks became of no effect by their own terms. Accordingly, our share repurchase program, which provided for the repurchase from time to time, of Ensco’s ADSs in an aggregate amount of up to $562.4 million, ended. The establishment of a new share repurchase program would require approval from our shareholders by special resolution.

During the quarter ended December 31, 2012, repurchases of our equity securities primarily were made by an affiliated employee benefit trust from employees and non-employee directors in connection with the settlement of income tax withholding obligations arising from the vesting of share awards.  Such securities remain available for reissuance in connection with employee share awards.
 

40



The chart below presents a comparison of the five-year cumulative total return, assuming $100 invested on December 31, 2007 and the reinvestment of dividends, for our shares, the Standard & Poor's 500 Stock Price Index and the Dow Jones U.S. Oil Equipment & Services Index.* 

 
 
12/07
 
12/08
 
12/09
 
12/10
 
12/11
 
12/12
 
 
 
 
 
 
 
 
 
 
 
 
Ensco plc
100.00

 
47.72

 
67.34

 
92.33

 
83.32

 
108.24

S&P 500
100.00

 
63.00

 
79.67

 
91.67

 
93.61

 
108.59

Dow Jones US Oil Equipment & Services
100.00

 
40.70

 
67.22

 
85.60

 
74.96

 
75.20

____________________________________
 
* $100 invested on December 31, 2007 in shares or index, including reinvestment of dividends for each fiscal year ending December 31. 

41



Item 6.  Selected Financial Data

The financial data below should be read in conjunction with "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" and our consolidated financial statements and notes thereto included in "Item 8. Financial Statements and Supplementary Data."

 
Year Ended December 31,

2012
 
       2011(1) 
 
2010
 
2009
 
2008
  
(in millions, except per share amounts)
Consolidated Statement of Income Data


 
 

 
 

 
 

 
 

Revenues
$
4,300.7

 
$
2,797.7

 
$
1,674.2

 
$
1,859.0

 
$
2,201.3

Operating expenses
 

 
 

 
 

 
 

 
 

Contract drilling (exclusive of depreciation)
2,028.0

 
1,449.1

 
741.8

 
693.5

 
716.1

Depreciation
558.6

 
408.9

 
210.4

 
182.8

 
165.1

General and administrative
148.9

 
158.6

 
86.1

 
64.0

 
53.8

Operating income
1,565.2

 
781.1

 
635.9

 
918.7

 
1,266.3

Other (expense) income, net
(98.6
)
 
(57.9
)
 
18.2

 
8.8

 
(4.2
)
Provision for income taxes
244.4

 
115.4

 
97.2

 
178.6

 
218.6

Income from continuing operations
1,222.2

 
607.8

 
556.9

 
748.9

 
1,043.5

(Loss) income from discontinued operations, net(2)
(45.5
)
 
(2.2
)
 
29.0

 
35.6

 
113.2

Net income
1,176.7

 
605.6

 
585.9

 
784.5

 
1,156.7

Net income attributable to noncontrolling interests
(7.0
)
 
(5.2
)
 
(6.4
)
 
(5.1
)
 
(5.9
)
Net income attributable to Ensco
$
1,169.7

 
$
600.4

 
$
579.5

 
$
779.4

 
$
1,150.8

Earnings (loss) per share – basic
 

 
 

 
 

 
 

 
 

Continuing operations
$
5.24

 
$
3.10

 
$
3.86

 
$
5.24

 
$
7.26

Discontinued operations
(0.19
)
 
(0.01
)
 
0.20

 
0.24

 
0.78

 
$
5.05

 
$
3.09

 
$
4.06

 
$
5.48

 
$
8.04

Earnings (loss) per share - diluted
 

 
 

 
 

 
 

 
 

Continuing operations
$
5.23

 
$
3.09

 
$
3.86

 
$
5.24

 
$
7.24

Discontinued operations
(0.19
)
 
(0.01
)
 
0.20

 
0.24

 
0.78

 
$
5.04

 
$
3.08

 
$
4.06

 
$
5.48

 
$
8.02

Net income attributable to Ensco shares - Basic and Diluted
$
1,157.4

 
$
593.5

 
$
572.1

 
$
769.7

 
$
1,138.2

Weighted-average shares outstanding
 

 
 

 
 

 
 

 
 

Basic
229.4

 
192.2

 
141.0

 
140.4

 
141.6

Diluted
229.7

 
192.6

 
141.0

 
140.5

 
141.9

Cash dividends per share
$
1.50

 
$
1.40

 
$
1.08

 
$
0.10

 
$
0.10


42



 
Year Ended December 31,
 
2012
 
2011
 
2010
 
2009
 
2008
  
(in millions)
Consolidated Balance Sheet and
   Cash Flow Statement Data
 
 
 
 
 
 
 
 
 
Working capital
$
734.2

 
$
348.7

 
$
1,087.7

 
$
1,167.9

 
$
973.0

Total assets
18,565.3

 
17,898.8

 
7,051.5

 
6,747.2

 
5,830.1

Long-term debt, net of current portion
4,798.4

 
4,877.6

 
240.1

 
257.2

 
274.3

Ensco shareholders' equity
11,846.4

 
10,879.3

 
5,959.5

 
5,499.2

 
4,676.9

Cash flow from continuing operations
2,200.2

 
731.8

 
807.0

 
1,176.4

 
994.3


(1) 
Includes the results of Pride International, Inc. from the Merger Date. 

(2) 
See Note 11 to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" for information on discontinued operations.

43



Item 7.  Management's Discussion and Analysis of Financial Condition and Results of Operations

INTRODUCTION

Our Business
 
We are one of the leading providers of offshore contract drilling services to the international oil and gas industry. We own an offshore drilling rig fleet of 74 rigs, including rigs under construction, spanning most of the strategic, high-growth markets around the globe. Our rig fleet includes nine drillships, 13 dynamically positioned semisubmersible rigs, six moored semisubmersible rigs and 46 jackup rigs.  Our fleet is the world's second largest amongst competitive rigs, our ultra-deepwater fleet is the newest in the industry and our premium jackup fleet is the largest of any offshore drilling company.  We currently have three technologically-advanced drillships and three ultra-premium harsh environment jackup rigs under construction as part of our ongoing strategy to continually expand and high-grade our fleet.

        Our customers include most of the leading national and international oil companies, in addition to many independent operators. We are among the most geographically diverse offshore drilling companies, with current operations and drilling contracts spanning approximately 20 countries on six continents in nearly every major deepwater and shallow-water basin around the world. The regions in which we operate include major markets in Southeast Asia, Australia, the North Sea, the Mediterranean, the U.S. Gulf of Mexico, Mexico and the Middle East, as well as the fastest-growing deepwater markets in Brazil and West Africa, where some of the world's most prolific geology resides.

We provide drilling services on a "day rate" contract basis. Under day rate contracts, we provide a drilling rig and rig crews and receive a fixed amount per day for drilling a well. Our customers bear substantially all of the ancillary costs of constructing the well and supporting drilling operations, as well as the economic risk relative to the success of the well. In addition, our customers may pay all or a portion of the cost of moving our equipment and personnel to and from the well site. We do not provide "turnkey" or other risk-based drilling services.

Our Industry

Operating results in the offshore contract drilling industry are cyclical and directly related to the demand for drilling rigs and the available supply of drilling rigs. While the cost of moving a rig and the availability of rig-moving vessels may cause the balance of supply and demand to vary somewhat between regions, significant variations between regions are generally of a short-term nature due to rig mobility.

Drilling Rig Demand

Demand for drilling rigs is directly related to the regional and worldwide levels of offshore exploration and development spending by oil and gas companies, which is beyond our control. The markets for our contract drilling services are cyclical.  Offshore exploration and development spending may fluctuate substantially from year-to-year and from region-to-region. Such spending fluctuations result from many factors, including:

demand for oil and natural gas, 
regional and global economic conditions and changes therein, 
political, social and legislative environments in major oil-producing countries, 
production and inventory levels and related activities of the Organization of Petroleum Exporting Countries ("OPEC") and other oil and natural gas producers, 
technological advancements that impact the methods or cost of oil and natural gas exploration and development, 

44



disruption to exploration and development activities due to hurricanes and other severe weather conditions and the risk thereof, and 
the impact that these and other events, whether caused by economic conditions, international or national climate change regulations or other factors, may have on the current and expected future prices of oil and natural gas.
Demand remained weak in most regions for shallow-water drilling during 2010 while demand for floaters came under additional pressure as a result of delays in operators' ability to secure permits in the U.S. Gulf of Mexico due to the Macondo well incident and related regulatory developments and other actions imposed by the U.S. Department of the Interior. Jackup rig utilization and day rates stabilized during 2011 as demand for shallow-water drilling improved while permit issuances in the U.S. Gulf of Mexico related to deepwater programs also improved, in addition to an upward movement in global demand for deepwater drilling. During 2012, the permitting process in the U.S. Gulf of Mexico improved significantly and an increase in demand for jackup and floater rigs resulted in increased utilization and day rates.
  
Since factors that affect offshore exploration and development spending are beyond our control and, because rig demand can change quickly, it is difficult for us to predict future industry conditions, demand trends or future operating results. Periods of low rig demand often result in excess rig supply, which generally results in reductions in utilization levels and day rates; periods of high rig demand often result in a shortage of rigs, which generally results in increased utilization levels and day rates.

Drilling Rig Supply

During recent periods, various industry participants ordered the construction of 298 new drillships, semisubmersible rigs and jackup rigs, 114 of which were delivered during the last three years.

Worldwide rig supply in the Floaters segment continues to increase as a result of newbuild construction programs.  It has been reported that 96 newbuild drillships and semisubmersible rigs currently are under construction, over 20 of which are scheduled for delivery during 2013.  Over half of all newbuild floater rigs scheduled for delivery are contracted.  We expect newbuild floater rigs will be absorbed into the market without a significant effect on utilization and day rates.

Worldwide rig supply in the Jackups segment continues to increase as a result of newbuild construction programs.  It has been reported that 88 newbuild jackup rigs are under construction, over 55 of which are scheduled for delivery during 2013.  The majority of all newbuild jackup rigs scheduled for delivery are not contracted.  Although the supply of available jackup rigs is expected to further increase from newbuild deliveries, given the aforementioned improvements in demand and utilization, day rates generally are expected to trend upward in the near-term in most regions.

The limited availability of insurance for certain perils in some geographic regions and rig loss or damage due to hurricanes, blowouts, craterings, punchthroughs and other operational events may impact the supply of offshore drilling rigs in a particular market and cause fluctuations in utilization and day rates.

Conversion to Class A Ordinary Shares

In connection with our redomestication to the U.K. in December 2009, each issued and outstanding share of common stock of Ensco was converted into the right to receive one American depositary share ("ADS"), each representing one Class A ordinary share of Ensco, par value U.S. $0.10 per share. Our ADSs were governed by a deposit agreement with Citibank, N.A. (“Citibank”) as depositary and traded on the New York Stock Exchange (the "NYSE") under the symbol "ESV." Eligibility rules for the S&P 500 Index exclude companies listed in ADS form; therefore, we were removed from the index subsequent to the redomestication.


45



On May 22, 2012, we terminated our ADS facility and converted our outstanding ADSs into Class A ordinary shares on a one-for-one basis. Our Class A ordinary shares trade on the NYSE under the same symbol “ESV.” 
The conversion was executed in response to favorable regulatory developments involving shares of certain companies domiciled in the U.K. and allows shareholders to directly own and trade our Class A ordinary shares on the NYSE, which is a requirement to be eligible for the S&P 500 Index. After the close of trading on July 30, 2012, we were readmitted to the S&P 500 index. The conversion did not significantly impact our shareholder rights or our share capital.
In connection with the termination of the ADS facility and the conversion to Class A ordinary shares, our previously executed share repurchase agreements with two investment banks became of no effect by their own terms. Accordingly, our share repurchase program, which provided for the repurchase from time to time, of Ensco’s ADSs in an aggregate amount of up to $562.4 million, ended. The establishment of a new share repurchase program would require approval from our shareholders by special resolution.

Drilling Rig Construction and Delivery

We continue to maintain our long-established strategy of high-grading our jackup rig fleet by investing in newer equipment while expanding the size and quality of our floater drilling rig fleet.  During the three-year period ended December 31, 2012, we invested $2.3 billion in the construction of new drilling rigs.

We previously contracted Keppel FELS Limited ("KFELS") to construct seven 8500 Series® ultra-deepwater semisubmersible rigs (the "ENSCO 8500 Series®" rigs) based on our proprietary design. The ENSCO 8500 Series® rigs are enhanced versions of ENSCO 7500 and are capable of drilling in up to 8,500 feet of water. ENSCO 8500 and ENSCO 8501 were delivered in 2008 and 2009, respectively, and commenced drilling operations in the U.S. Gulf of Mexico under long-term contracts during 2009. ENSCO 8502 was delivered and commenced drilling operations under a long-term contract in the U.S. Gulf of Mexico during 2010. ENSCO 8503 was delivered in 2010, commenced drilling operations in French Guiana under a short-term sublet agreement during the first quarter of 2011 and subsequently commenced drilling operations under a long-term contract in the U.S. Gulf of Mexico during the first quarter of 2012. ENSCO 8504 was delivered and commenced drilling operations under a long-term contract in Brunei during the third quarter of 2011, and ENSCO 8505 was delivered and commenced drilling operations under a long-term contract in the U.S. Gulf of Mexico during the second quarter of 2012. ENSCO 8506, the final rig in the ENSCO 8500 Series®, was delivered during the third quarter of 2012 and commenced drilling operations in the U.S. Gulf of Mexico under a long-term contract during the first quarter of 2013.

In connection with the Merger, we acquired seven drillships, two of which were under construction at the time of the Merger. These newbuild drillships are based on a Samsung Heavy Industries ("SHI") proprietary hull design capable of drilling in water depths of up to 10,000 feet of water. ENSCO DS-6 was delivered in January 2012, underwent customer specified upgrades, and commenced drilling operations in Angola under a long-term contract during the first quarter of 2013. ENSCO DS-7 is under construction and scheduled for delivery in the third quarter of 2013. The rig is expected to commence drilling operations under a long-term contract with TOTAL during the fourth quarter of 2013. During the second quarter of 2012, we entered into agreements with SHI to construct two additional ultra-deepwater drillships (ENSCO DS-8 and ENSCO DS-9). These rigs are scheduled for delivery during the second half of 2014 and remain uncontracted.

We previously entered into agreements with KFELS to construct three ultra-high specification harsh environment jackup rigs (ENSCO 120, ENSCO 121 and ENSCO 122).  These rigs are scheduled for delivery during the second quarter and fourth quarter of 2013 and the second half of 2014, respectively.  ENSCO 120 is committed under a long-term drilling contract in the North Sea, while the other two jackup rigs under construction are uncontracted.

We historically have relied on our cash flow from continuing operations to meet liquidity needs and fund the majority of our cash requirements. We have maintained a strong financial position through the disciplined and conservative use of debt, which has provided us the ability to achieve future growth potential through acquisitions and

46



newbuild construction. A substantial portion of our cash flow has been and will continue to be invested in the expansion and enhancement of our fleet of drilling rigs in general and newbuild construction in particular. We believe our strong balance sheet, $10.8 billion of contract backlog, $1.9 billion of availability under our revolving credit facilities and our $1.0 billion commercial paper program will enable us to meet the capital expenditure obligations associated with our newbuild rig construction contracts and sustain an adequate level of liquidity during 2013 and beyond.

Divestitures

Our business strategy has been to focus on ultra-deepwater floater and premium jackup operations, and de-emphasize other assets and operations considered to be non-core or that do not meet our standards for financial performance.  Consistent with this strategy, we sold three jackup rigs, one moored semisubmersible rig and our last remaining barge rig during 2012.

Segment Highlights
 
Floaters
 
Operating results for our Floaters segment significantly improved during 2012, primarily due to a full year of operations by five drillships and eleven semisubmersible rigs acquired in connection with the Merger and the addition of ENSCO 8505 to our floater fleet.  During 2012, ENSCO 8505 commenced drilling operations for Anadarko, Apache and Noble Energy in the U.S. Gulf of Mexico at a day rate of approximately $480,000. 
 
ENSCO 8506 was contracted to Anadarko in January 2012 and commenced drilling operations in the U.S. Gulf of Mexico during the first quarter of 2013 under a long-term contract at a day rate of approximately $530,000. ENSCO DS-6 was contracted to BP in April 2012 at a day rate of approximately $522,000, underwent customer specified upgrades in a shipyard in Singapore and commenced drilling operations during the first quarter of 2013.

     ENSCO 8504 was contracted to Shell in the Philippines beginning in February 2013 under a six-month contract at a day rate of approximately $460,000 followed by a long-term contract with Shell in Malaysia beginning in July 2013 at a day rate of approximately $535,000. ENSCO 5006 was contracted to INPEX Corporation in December 2012 and is expected to commence drilling operations in Australia, after the completion of customer requested upgrades, during the third quarter of 2014 under a long-term contract. The initial day rate is approximately $461,000 and will average approximately $490,000 over the term of the contract.

ENSCO DS-7 is scheduled for delivery in the third quarter of 2013. The rig is committed under a long-term contract with TOTAL at an initial day rate of $615,000 and expected to commence drilling operations during the fourth quarter of 2013.
 

47



 Jackups
     
During 2012, an increase in utilization and average day rates resulted in improved operating results for our Jackups segment. In particular, high specification jackup rigs earned significantly higher day rates in 2012 as compared to the prior year as customer demand for more capable rigs increased. Additionally, certain previously cold stacked and uncontracted rigs commenced drilling operations under long-term contracts. The jackup market remains tight and as of December 31, 2012 all of our marketed jackup rigs were contracted.

The demand for jackup rigs is expected to continue to increase in 2013. ENSCO 81 was contracted to Stone in the U.S. Gulf of Mexico beginning in April 2013 at a day rate of approximately $138,000 per day, which is an increase of more than $45,000 from its existing contract. ENSCO 107 was contracted to OMV in New Zealand beginning in October 2013, after completion of its existing contracts. The day rate of approximately $230,000 is one of the highest for the rig class since 2007.

ENSCO 120, ENSCO 121 and ENSCO 122, three ultra-high specification harsh environment jackup rigs, are currently under construction and are scheduled for delivery during the second quarter and fourth quarter of 2013 and the second half of 2014, respectively.  ENSCO 120 is committed under a long-term drilling contract with Nexen in the North Sea at a day rate of approximately $230,000 and is expected to commence drilling operations during the fourth quarter of 2013.

BUSINESS ENVIRONMENT

Floaters

During 2010, demand for drilling rigs in the Floaters segment remained stable but came under pressure as a result of delays in operators' ability to secure permits in the U.S. Gulf of Mexico due to regulatory developments and other actions imposed by the U.S. Department of Interior. Several drilling permits were issued during 2011 in the U.S. Gulf of Mexico related to programs that had been interrupted by the response to the Macondo well incident as offshore drilling contractors continued to work with operators and government regulators to address new regulatory requirements and secure drilling permits. During 2012, the permitting process in the U.S. Gulf of Mexico improved significantly, which, combined with increased demand, has added new floaters to the market. We expect this positive trend to continue in 2013.

Demand for work in 2013 and beyond also remains strong in various other regions. With discoveries being announced regularly in West Africa, the market has tightened, and there is upward pressure on day rates. Demand remains especially strong in Angola and Nigeria where there are several long-term requirements outstanding for development projects. In Brazil, the demand for drilling is expected to continue as Petrobras taps its pre-salt reserves. We believe demand for floaters will increase in 2013 in Southeast Asia and Australia. In Mexico, Petróleos Mexicanos, the national oil company of Mexico, has publicly announced the need for deepwater drilling to offset declines in production from shallow-water and onshore fields. Exploration and production success, new deepwater basins, and strong commodity prices are expected to have a continued positive impact on future rig demand in the Floaters segment.
 
Jackups

During 2010, demand for drilling rigs in the Jackups segment was limited, resulting in softness in day rates for standard duty jackup rigs. Tender activity increased during 2011 as demand for shallow-water drilling improved, which helped to stabilize jackup rig utilization and day rates. During 2012, demand and average day rates increased from 2011, and the market remains tight with demand for jackup rigs forecasted to increase during 2013.

Demand remains strong in the Asia Pacific Rim, and the market is expected to tighten in 2013 with a number of incremental long-term projects from several operators. Tender activity remains strong in Australia, Indonesia, Malaysia and the Philippines.


48



The North Sea market remains tight with all rigs in the marketed fleet currently contracted and only a limited supply of standard duty jackup rigs becoming available in the second half of 2013. Several newbuild rigs are expected to enter the region in 2013 and will likely be absorbed based on the number of new inquiries for work starting during 2013 and 2014.

In the Middle East, rig demand improved during 2012, and existing contract backlog for 2013 is approximately 80% of the available supply of jackup rigs. The backlog of firm commitments for 2014 is over 50% of available supply. This increased demand has resulted in upward pressure on day rates, and we expect incremental demand in Saudi Arabia, Oman and Qatar.

Demand for jackup rigs in the U.S. Gulf Mexico improved during 2012, and we expect the market will remain strong during 2013. In Mexico, Petróleos Mexicanos continues to attract rigs in an effort to increase their jackup fleet.
    

49



RESULTS OF OPERATIONS

The following table summarizes our consolidated results of operations for each of the years in the three-year period ended December 31, 2012 (in millions):
 
 
2012
 
2011
 
2010
Revenues
 
$
4,300.7

 
$
2,797.7

 
$
1,674.2

Operating expenses
 
 

 
 

 
 

Contract drilling (exclusive of depreciation)
 
2,028.0

 
1,449.1

 
741.8

Depreciation
 
558.6

 
408.9

 
210.4

General and administrative 
 
148.9

 
158.6

 
86.1

Operating income 
 
1,565.2

 
781.1

 
635.9

Other (expense) income, net 
 
(98.6
)
 
(57.9
)
 
18.2

Provision for income taxes 
 
244.4

 
115.4

 
97.2

Income from continuing operations 
 
1,222.2

 
607.8

 
556.9

(Loss) income from discontinued operations, net 
 
(45.5
)
 
(2.2
)
 
29.0

Net income 
 
1,176.7

 
605.6

 
585.9

Net income attributable to noncontrolling interests
 
(7.0
)
 
(5.2
)
 
(6.4
)
Net income attributable to Ensco
 
$
1,169.7

 
$
600.4

 
$
579.5

 
During 2012, excluding an increase of $826.6 million in revenues and $354.3 million in operating income attributable to the impact of the Merger, revenues and operating income increased by $676.4 million, or 38%, and $429.8 million, or 81%, respectively, as compared to the prior year. The increase in revenues and operating income primarily was due to newbuild additions to the Floaters segment and an increase in utilization and average day rates for existing rigs in our Floaters and Jackups segments. See below for additional information on our operating results by segment.

During 2011, excluding $1.0 billion of revenues and $216.3 million of operating income attributable to the impact of the Merger, revenues increased by $92.1 million, or 6%, and operating income declined by $71.1 million, or 11%, as compared to the prior year.  The increase in revenues primarily was due to newbuild additions to our floater fleet, partially offset by lower revenue contribution from ENSCO 7500, which was undergoing a shipyard enhancement project.  The decline in operating income primarily was due to a decrease in average day rates for our Jackups segment, ENSCO 7500 as previously noted and general and administrative expense incurred by Ensco to effect the Merger. See below for additional information on our operating results by segment.

A significant number of our drilling contracts are of a long-term nature. Accordingly, an increase or decline in demand for contract drilling services generally affects our operating results and cash flows gradually over future periods as long-term contracts expire and new contracts and/or options are priced at current market rates.



50



Rig Locations, Utilization and Average Day Rates
   
The following table summarizes our offshore drilling rigs by reportable segment and rigs under construction as of December 31, 2012, 2011 and 2010:
 
 
2012
 
2011 (1)
 
2010
Floaters(2)
25
 
22
 
5
Jackups
42
 
42
 
39
Under construction(2)(3)
6
 
7
 
3
Total(4)
73
 
71
 
47
 
(1) 
In connection with the Merger, we acquired 19 floater rigs, two of which were under construction, and seven jackup rigs. Subsequent to the Merger, one floater rig and four jackup rigs were reclassified as discontinued operations, including Pride Pennsylvania which was classified as held-for-sale as of December 31, 2012. Rigs reclassified as discontinued operations were excluded from the total number of rigs for each period.

(2) 
ENSCO 8505 was delivered during the first quarter of 2012 and commenced drilling operations in the U.S. Gulf of Mexico under a long-term contract during the second quarter of 2012. ENSCO DS-6 was delivered during the first quarter of 2012, underwent customer specified upgrades in a shipyard in Singapore and commenced drilling operations during the first quarter of 2013. ENSCO 8506 was delivered during the third quarter of 2012 and commenced drilling operations in the U.S. Gulf of Mexico under a long-term contract during the first quarter of 2013. 
ENSCO 8504 was delivered and commenced drilling operations in Brunei during the third quarter of 2011. 
(3) 
During the second quarter of 2012, we entered into agreements with SHI to construct our sixth and seventh ultra-deepwater drillships (ENSCO DS-8 and ENSCO DS-9). The rigs are uncontracted and scheduled for delivery during the second half of 2014.
In 2011, we entered into agreements with KFELS to construct three ultra-high specification harsh environment jackup rigs (ENSCO 120, ENSCO 121 and ENSCO 122).  These rigs are scheduled for delivery during the second quarter and fourth quarter of 2013 and the second half of 2014, respectively.  ENSCO 120 is committed under a long-term contract in the North Sea, while the other two jackup rigs under construction are uncontracted.  
(4) 
The total number of rigs for each period excludes rigs reclassified as discontinued operations. 

The following table summarizes our rig utilization and average day rates from continuing operations by reportable segment for each of the years in the three-year period ended December 31, 2012:
 
 
2012
 
2011
 
2010
Rig Utilization(1)
 
 

 
 

 
 

Floaters
 
87%
 
80%
 
81%
Jackups(3)
 
89%
 
80%
 
77%
Total
 
88%
 
80%
 
78%
Average Day Rates(2)
 
 
 
 

 
 
Floaters
 
$
358,336

 
$
339,017

 
$
375,098

Jackups(3)
 
106,212

 
98,249

 
106,316

Total
 
$
193,407

 
$
160,717

 
$
129,543


(1) 
Rig utilization is derived by dividing the number of days under contract by the number of days in the period. Days under contract equals the total number of days that rigs have earned a day rate, including days associated with

51



compensated downtime and mobilizations. For newly constructed or acquired rigs, the number of days in the period begins upon commencement of drilling operations for rigs with a contract or when the rig becomes available for drilling operations for rigs without a contract. 
(2) 
Average day rates are derived by dividing contract drilling revenues, adjusted to exclude certain types of non-recurring reimbursable revenues, lump sum revenues and revenues attributable to amortization of drilling contract intangibles, by the aggregate number of contract days, adjusted to exclude contract days associated with certain mobilizations, demobilizations, shipyard contracts and standby contracts. 
(3) 
ENSCO 69 has been excluded from rig utilization and average day rates for our Jackups operating segment during the period the rig was controlled and operated by Petrosucre, a subsidiary of Petróleos de Venezuela S.A., the national oil company of Venezuela (January 2009 - August 2010).
Detailed explanations of our operating results, including discussions of revenues, contract drilling expense and depreciation expense by segment, are provided below.
 
Operating Income

Management of our business is a dynamic and constantly evolving process. This was especially true during 2011 and 2012 as we completed the Merger and executed integration activities. During the fourth quarter, the Chief Operating Decision Maker ("CODM") evaluated the manner in which our business was being managed and concluded that distinctions in water depth capabilities for our floating rigs were no longer a significant factor in the performance assessment and resource allocation decision making process. The CODM requested that financial information previously disaggregated between floating rigs capable of drilling in 4,500 feet and greater (Deepwater) and floating rigs capable of drilling in 4,499 feet or less (Midwater) be combined into a single floaters category for internal financial reporting purposes effective for the fourth quarter of 2012. We now consider our drillship and semisubmersible rig fleet to be one operating segment.

Our business now consists of three operating segments: (1) Floaters, which includes our drillships and semisubmersible rigs, (2) Jackups and (3) Other, which currently consists of management services on rigs owned by third-parties. Our two reportable segments, Floaters and Jackups, provide one service, contract drilling.
Segment information for each of the years in the three-year period ended December 31, 2012 is presented below (in millions).  General and administrative expense and depreciation expense incurred by our corporate office are not allocated to our operating segments for purposes of measuring segment operating income and were included in "Reconciling Items."  Prior year information has been reclassified to conform to the current year presentation.
 
Year Ended December 31, 2012

 
Floaters
 
Jackups
 
Other
 
Operating Segments Total
 
Reconciling Items
 
Consolidated Total
 
 
 
 
 
 
 
 
 
 
 
 
Revenues
$
2,707.8

 
$
1,510.1

 
$
82.8

 
$
4,300.7

 
$

 
$
4,300.7

Operating expenses
 
 
 
 
 
 
 
 
 
 
 
  Contract drilling (exclusive
     of depreciation)
1,225.1

 
741.8

 
61.1

 
2,028.0

 

 
2,028.0

Depreciation
382.3

 
167.4

 

 
549.7

 
8.9

 
558.6

General and administrative

 

 

 

 
148.9

 
148.9

Operating income (loss)
$
1,100.4

 
$
600.9

 
$
21.7

 
$
1,723.0

 
$
(157.8
)
 
$
1,565.2

 
 

52



Year Ended December 31, 2011
 
Floaters
 
Jackups
 
Other
 
Operating Segments Total
 
Reconciling Items
 
Consolidated Total
 
 
 
 
 
 
 
 
 
 
 
 
Revenues
$
1,532.8

 
$
1,212.5

 
$
52.4

 
$
2,797.7

 
$

 
$
2,797.7

Operating expenses
 
 
 
 
 
 
 
 
 
 
 
  Contract drilling (exclusive
     of depreciation)
785.1

 
621.1

 
42.9

 
1,449.1

 

 
1,449.1

Depreciation
235.9

 
168.6

 

 
404.5

 
4.4

 
408.9

General and administrative

 

 

 

 
158.6

 
158.6

Operating income (loss)
$
511.8

 
$
422.8

 
$
9.5

 
$
944.1

 
$
(163.0
)
 
$
781.1


Year Ended December 31, 2010
 
Floaters
 
Jackups
 
Other
 
Operating Segments Total
 
Reconciling Items
 
Consolidated Total
 
 
 
 
 
 
 
 
 
 
 
 
Revenues
$
475.2

 
$
1,199.0

 
$

 
$
1,674.2

 
$

 
$
1,674.2

Operating expenses
 
 
 
 
 
 
 
 
 
 
 
  Contract drilling (exclusive
     of depreciation)
176.1

 
565.7

 

 
741.8

 

 
741.8

Depreciation
44.8

 
164.3

 

 
209.1

 
1.3

 
210.4

General and administrative

 

 

 

 
86.1

 
86.1

Operating income (loss)
$
254.3

 
$
469.0

 
$

 
$
723.3

 
$
(87.4
)
 
$
635.9


Floaters

During 2012, excluding an increase of $785.9 million attributable to the impact of the Merger, Floaters revenues increased by $389.1 million, or 67%, as compared to the prior year. The increase in revenues primarily was due to commencement of ENSCO 8503, ENSCO 8504 and ENSCO 8505 drilling operations during the first and third quarters of 2011 and the second quarter of 2012, respectively. Increased utilization, primarily attributable to ENSCO 7500, which was undergoing a shipyard enhancement project during the prior year, and increased average day rates, primarily attributable to ENSCO 8502 and ENSCO 8503, which were sublet during the prior year before commencing original two-year contracts in the U.S. Gulf of Mexico in June 2011 and January 2012, respectively, also led to the increase in revenues.

Excluding an increase of $319.9 million attributable to the impact of the Merger, contract drilling expense increased by $120.1 million, or 53%