10-K 1 form10k2009.htm FORM 10-K 2009 10-K
Table of Contents



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, 2009

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 International 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 (1224) 780 400


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

Title of each class

Class A Ordinary Shares, U.S. $0.10 par value
American Depositary Shares, each representing one Class A Ordinary Share,
U.S. $0.10 par value per Class A Ordinary Share
 
  Name of each exchange on which registered

New York Stock Exchange*
New York Stock Exchange

 
* Not for trading, but only in connection with the registration of American depositary shares, pursuant to the requirements of the Securities and Exchange Commission.


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 (Š232.405 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 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:

Large accelerated filer 
ý                                                                              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 our American depositary shares, each representing one Class A ordinary share, (based upon the closing price on the New York Stock Exchange on June 30, 2009 of $34.87) of Ensco International plc held by nonaffiliates of the registrant at that date was approximately $4,339,487,000.

As of February 24, 2010, there were 142,522,784 American depositary shares of the registrant issued and outstanding, each representing one Class A ordinary share.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Company's Proxy Statement for the 2010 General Meeting of Shareholders are incorporated by reference into Part III of this report.



 

TABLE OF CONTENTS


PART I      
  ITEM 1. BUSINESS 3
  ITEM 1A. RISK FACTORS 11
  ITEM 1B. UNRESOLVED STAFF COMMENTS 27
  ITEM 2. PROPERTIES 28
  ITEM 3. LEGAL PROCEEDINGS 30
  ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS 33


PART II      
  ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED SHAREHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES 34
  ITEM 6. SELECTED FINANCIAL DATA 39
  ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS 41
  ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK 62
  ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA 63
  ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE 108
  ITEM 9A. CONTROLS AND PROCEDURES 108
  ITEM 9B. OTHER INFORMATION 108


PART III      
  ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE 109
  ITEM 11. EXECUTIVE COMPENSATION 109
  ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED SHAREHOLDER MATTERS 110
  ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE 110
  ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES 110


PART IV      
  ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES 111
  SIGNATURES   118


Table of Contents

 

FORWARD-LOOKING STATEMENTS


       This report contains forward-looking statements that are subject to a number of risks and uncertainties and are based on information as of the date of this report. We assume no obligation to update these statements based on information after the date of this report.

       Forward-looking statements include words or phrases such as "anticipate," "believe," "estimate," "expect," "intend," "plan," "project," "could," "may," "might," "should," "will" and words and phrases of similar import. The forward-looking statements include, but are not limited to, statements about the impact of the December 2009 reorganization of the Company's corporate structure (referred to elsewhere herein as the "redomestication") and our plans, objectives, expectations and intentions with respect thereto and with respect to future operations, including the tax savings or other benefits that we expect to achieve as a result of the redomestication. Forward-looking statements also include statements regarding future operations, market conditions, cash generation, the impact of recently contracted premium jackups, contributions from our ultra-deepwater semisubmersible rig fleet expansion program and expense management, industry trends or conditions and the business environment; statements regarding future levels of, or trends in, utililzation, day rates, revenues, operating expenses, contract term, contract backlog, capital expenditures, insurance, financing and funding; statements regarding future construction (including construction in progress and completion thereof), enhancement, upgrade or repair of rigs and timing thereof; statements regarding future delivery, mobilization, contract commencement, relocation or other movement of rigs and timing thereof; statements regarding future availability or suitability of rigs and the timing thereof, and statements regarding the likely outcome of litigation, legal proceedings, investigations or insurance or other claims and the timing thereof.

       Forward-looking statements are made pursuant to safe harbor provisions of the Private Securities Litigation Reform Act of 1995. Numerous factors could cause actual results to differ materially from those in the forward-looking statements, including:
 

  changes in U.S. or non-U.S. laws, including tax laws, that could effectively reduce or eliminate the benefits we expect to achieve from the redomestication,
  an inability to realize expected benefits from the redomestication,
  costs related to the redomestication and ancillary matters, which could be greater than expected,
  industry conditions and competition, including changes in rig supply and demand or new technology,
  risks associated with the global economy and its impact on capital markets and liquidity,
  prices of oil and natural gas, and their impact upon future levels of drilling activity and expenditures,
  further declines in rig activity, which may cause us to idle or stack additional rigs,
  excess rig availability or supply resulting from delivery of newbuild drilling rigs,
  concentration of our fleet in premium jackup rigs,
  cyclical nature of the industry,
  worldwide expenditures for oil and natural gas drilling,
  the ultimate resolution of the ENSCO 69 situation in general and the potential return of the rig or package policy political risk insurance recovery in particular,
  changes in the timing of revenue recognition resulting from the deferral of certain revenues for mobilization of our drilling rigs, time waiting on weather or time in shipyards, which are recognized over the contract term upon commencement of drilling operations,
  operational risks, including excessive unplanned downtime due to rig or equipment breakdown, damage or repair in general and hazards created by severe storms and hurricanes in particular,
  risks associated with offshore rig operations or rig relocations,
  renegotiation, nullification, cancellation or breach of contracts or letters of intent with customers or other parties, including failure to negotiate definitive contracts following announcements or receipt of letters of intent,
  inability to collect receivables,
  changes in the dates new contracts actually commence,
  changes in the dates our rigs will enter a shipyard, be delivered, return to service or enter service,
  risks inherent to shipyard rig construction, repair or enhancement, including risks associated with concentration of our ENSCO 8500 Series® rig construction contracts in a single shipyard in Singapore, unexpected delays in equipment delivery and engineering or design issues following shipyard delivery,
  availability of transport vessels to relocate rigs,
  environmental or other liabilities, risks or losses, whether related to hurricane damage, losses or liabilities (including wreckage or debris removal) in the Gulf of Mexico or otherwise, that may arise in the future which are not covered by insurance or indemnity in whole or in part,
  limited availability or high cost of insurance coverage for certain perils such as hurricanes in the Gulf of Mexico or associated removal of wreckage or debris,
  self-imposed or regulatory limitations on drilling locations in the Gulf of Mexico during hurricane season,
  impact of current and future government laws and regulation affecting the oil and gas industry in general and our operations in particular, including taxation, as well as repeal or modification of same,
  our ability to attract and retain skilled personnel,
  governmental action and political and economic uncertainties, including expropriation, nationalization, confiscation or deprivation of our assets,
  terrorism or military action impacting our operations, assets or financial performance,
  outcome of litigation, legal proceedings, investigations or insurance or other claims,
  adverse changes in foreign currency exchange rates, including their impact on the fair value measurement of our derivative instruments,
  potential long-lived asset or goodwill impairments, and
  potential reduction in fair value of our auction rate securities.
 

       Moreover, the United States Congress, the Internal Revenue Service (the "IRS"), the United Kingdom Parliament or Her Majesty's Revenue and Customs ("HMRC") may enact new statutory or regulatory provisions that could adversely affect our status as a non-U.S. corporation or otherwise adversely affect our anticipated consolidated effective income tax rate. Retroactive statutory or regulatory actions have occurred in the past, and there can be no assurance that any such provisions, if enacted or promulgated, would not have retroactive application.

       In addition to the numerous factors described above, you should 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.


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PART I

Item 1.  Business

General

       Ensco International plc is a global offshore contract drilling company. As of February 15, 2010, our offshore rig fleet included 42 jackup rigs, four ultra-deepwater semisubmersible rigs and one barge rig. Additionally, we have four ultra-deepwater semisubmersible rigs under construction.

       We are one of the leading providers of offshore contract drilling services to the international oil and gas industry. Our operations are concentrated in the geographic regions of Asia Pacific (which includes Asia, the Middle East and Australia), Europe and Africa, and North and South America. Unless the context requires otherwise, the terms "Ensco", "Company", "we", "us" and "our" refer to Ensco International plc together with all subsidiaries and predecessors.

       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.

       We have assembled one of the largest and most capable offshore drilling rig fleets in the world. We have grown our fleet through corporate acquisitions, rig acquisitions and new rig construction. A total of 30 jackup rigs in our current fleet were obtained through the acquisitions of Penrod Holding Corporation during 1993, Dual Drilling Company during 1996 and Chiles Offshore Inc. during 2002. During 2000, we completed construction of ENSCO 101, a harsh environment jackup rig, and ENSCO 7500, a dynamically positioned ultra-deepwater semisubmersible rig capable of drilling in water depths of up to 8,000 feet.

       During 2004 and 2005, we acquired full ownership of ENSCO 102, a harsh environment jackup rig, and ENSCO 106, an ultra-high specification jackup rig. Both rigs were initially constructed through joint ventures with Keppel FELS Limited ("KFELS"), a major international shipyard. During 2006 and 2007, we completed construction of ENSCO 107 and ENSCO 108, respectively, both of which are ultra-high specification jackup rigs.

       We have contracted KFELS to construct seven 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 capable of drilling in up to 8,500 feet of water. ENSCO 8500 was delivered in September 2008 and commenced operations in the Gulf of Mexico under a four-year contract in June 2009. ENSCO 8501 was delivered in June 2009 and commenced operations in the Gulf of Mexico under a three-and-a-half year contract in October 2009. ENSCO 8502 was delivered in January 2010 and is expected to commence operations in the Gulf of Mexico under a two-year contract during the third quarter of 2010. ENSCO 8503, ENSCO 8504, ENSCO 8505 and ENSCO 8506 are expected to be delivered during the fourth quarter of 2010, the second half of 2011 and the first and second half of 2012, respectively. ENSCO 8503 has secured a two-year contract in the Gulf of Mexico. ENSCO 8504, ENSCO 8505 and ENSCO 8506 are currently without contracts.

       Our business strategy has been to focus on ultra-deepwater semisubmersible rig and premium jackup rig operations and de-emphasize other operations and assets 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 also disposed of five barge rigs and one platform rig during 2005 and our last remaining platform rig during 2006.

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       Our predecessor, ENSCO International Incorporated ("Ensco Delaware"), was formed as a Texas corporation during 1975 and reincorporated in Delaware during 1987. On December 23, 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 International plc became our publicly-held parent company incorporated under English law (the "redomestication"). In connection with the redomestication, each issued and outstanding share of common stock of Ensco Delaware was converted into the right to receive one American depositary share ("ADS" or "share"), each representing one Class A ordinary share, par value U.S. $0.10 per share, of Ensco International plc. Our ADSs are governed by a deposit agreement with Citibank, N.A. as depositary and trade on the New York Stock Exchange (the "NYSE") under the symbol "ESV," the symbol for Ensco Delaware common stock before 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 (the "SEC") reporting requirements, the mandates of the Sarbanes-Oxley Act and the applicable corporate governance rules of the NYSE, and we will 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.

       Our principal executive office is located at 6 Chesterfield Gardens, London W1J5BQ, England, United Kingdom, and our telephone number is +44 (1224) 780 400. Our website is www.enscointernational.com.

Contract Drilling Operations

       We are in the process of developing a fleet of ultra-deepwater semisubmersible rigs and established a separate business unit to manage our deepwater operations during 2008. Our jackup rigs and barge rig are managed by major geographic region. Accordingly, our business consists of four operating segments: (1) Deepwater, (2) Asia Pacific, (3) Europe and Africa and (4) North and South America. Each of our four operating segments provides one service, contract drilling. We engage in the drilling of offshore oil and natural gas wells by providing our drilling rigs and crews under contracts with major international, government-owned and independent oil and gas companies.

       We currently own and operate 42 jackup rigs, four ultra-deepwater semisubmersible rigs and one barge rig. Of the 42 jackup rigs, 19 are located in the Asia Pacific geographic region, ten are located in the Europe and Africa geographic region and 13 are located in the North and South America geographic region. Our ENSCO 7500 ultra-deepwater semisubmersible rig is operating in Australia, and ENSCO 8500 and ENSCO 8501 are operating under long-term contracts in the Gulf of Mexico. ENSCO 8502 was delivered in January 2010 and is currently preparing to mobilize from Singapore to the Gulf of Mexico where it is expected to commence drilling operations under a two-year contract during the third quarter of 2010. In addition, we have four ultra-deepwater semisubmersible rigs under construction by KFELS at a shipyard in Singapore. The rigs are scheduled for delivery during the fourth quarter of 2010, the second half of 2011 and the first and second half of 2012. Our barge rig is currently stacked in Singapore.

       Our drilling rigs are used to drill and complete oil and natural gas wells. Demand for our drilling services is based upon many factors which are 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,
  the development and use of alternatives to hydrocarbon-based energy sources, and
  worldwide economic activity.
 


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       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,
  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,
  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),
  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.
 

       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 and other customer reimbursables.

       The following table summarizes our contract backlog of business as of February 1, 2010 and 2009 (in millions):
 

                 2010(*)                2009(*)
           
       Deepwater  $1,689 .9 $1,895 .7
       Asia Pacific  466 .5 724 .4
       Europe and Africa  363 .4 858 .1
       North and South America  435 .3 556 .8

           Total  $2,955 .1 $4,035 .0

 
          (*)  Backlog includes revenues realized during January of the respective year.


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       We did not enter into a new ultra-deepwater semisubmersible rig contract during 2009, which resulted in a $205.8 million decline in Deepwater backlog. Our Asia Pacific and Europe and Africa backlog declined by an aggregate $752.6 million primarily due to the lack of tender activity during 2009 in these markets. Our North and South America backlog declined by $121.5 million due to the lack of tender activity in the Gulf of Mexico, partially offset by two additional long-term contracts secured in Mexico. The table summarizes our annual backlog by operating segment as of February 1, 2010 (in millions):
 

        2010 (*)      2011        2012        2013          Total  
                       
       Deepwater  $   471 .9 $601 .2 $514 .2 $102 .6 $1,689 .9
       Asia Pacific  391 .4 60 .7 14 .4   -- 466 .5
       Europe and Africa  239 .5 102 .7 21 .2   -- 363 .4
       North and South America  232 .6 144 .4 58 .3   -- 435 .3

           Total  $1,335 .4 $909 .0 $608 .1 $102 .6 $2,955 .1


       (*)
  Backlog for the year ended December 31, 2010 includes revenues realized during January 2010.


       Our Deepwater backlog includes $382.6 million associated with ENSCO 8503, which is scheduled for delivery during the fourth quarter of 2010. Additional information on rig construction risks is presented in "Item 1A. Risk Factors."

       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. 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 2009, ConocoPhillips represented 13% of our revenues, and our five largest customers accounted for 44% of consolidated revenues in the aggregate.

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 are also factors. We have numerous competitors in the offshore contract drilling industry, several of which are larger and have greater resources than us.

Governmental Regulation

       Our operations are affected by political developments and by laws and regulations that relate directly to the oil and gas industry. 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.


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Environmental Matters

       Our operations are subject to laws and regulations controlling the discharge of materials into the environment, as well as pollution, contamination and hazardous waste disposal, or that otherwise relate to the protection of the environment. 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 us, and we have not experienced an accident that has exposed us to material liability for discharges of pollutants into the environment. However, events in recent years have heightened environmental concerns regarding the oil and gas 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 applicable to us and our operations in the North Sea and in other offshore waters and the United States Oil Pollution Act of 1990 ("OPA 90"), as amended, and other U.S. federal statutes applicable to us and our operations in the Gulf of Mexico, 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 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 and a variety of fines, penalties and damages. Similar environmental laws apply in our other areas of operation. A 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.

       From time to time, legislative proposals have been introduced that would materially limit or prohibit offshore drilling in certain areas. To date, no proposals have been enacted into law which would materially limit or prohibit offshore drilling in our principal areas of operation. However, we are adversely affected by a U.S. federal moratoria on drilling in certain areas of the Gulf of Mexico and elsewhere. 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 cost of offshore drilling, exploration, development or production of oil and natural gas, we could be materially adversely affected.

Non-U.S. Operations

       Revenues from non-U.S. operations were 86%, 80% and 77% of our total revenues during 2009, 2008 and 2007, 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,
  exchange restrictions,
  currency fluctuations,
  changes in the manner or rate of taxation,
  limitations on our ability to recover amounts due,
  increased risk of government and/or vendor/supplier corruption,
  changes in political conditions, and
  changes in monetary policies.

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       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. 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 or underinsured, 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 of the 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 same, adverse rulings in connection with audits or otherwise or other challenges, may substantially increase our tax expense.

       Our non-U.S. operations also face the risk of fluctuating currency values, which can impact our revenues, operating costs and capital expenditures. 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 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.

       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. Our drilling contracts generally stipulate payment wholly or substantially in U.S. dollars, which reduces the impact currency fluctuations have on our earnings and cash flows. However, there is no assurance that our contracts will contain such payment 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 our ENSCO 8500 Series® 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, the 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 requirement for equipment thereon. Governments in some 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 and gas companies and may continue to do so. Moreover, certain countries accord preferential treatment to local contractors or joint ventures, which can 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.


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Executive Officers

The table below sets forth certain information regarding our principal officers including our executive officers:

 
          Name   Age   Position         
         
Daniel W. Rabun    55   Chairman, President and Chief Executive Officer
         
William S. Chadwick, Jr.    62   Executive Vice President - Chief Operating Officer
         
John Mark Burns    53   Senior Vice President
         
Patrick Carey Lowe    51   Senior Vice President
         
James W. Swent III    59   Senior Vice President - Chief Financial Officer
         
David A. Armour    52   Vice President - Finance
         
H. E. Malone, Jr.    66   Vice President and Assistant Secretary
         
Cary A. Moomjian, Jr.    62   Vice President, General Counsel and Secretary
         
Sean P. O'Neill    46   Vice President - Investor Relations
         
Michael B. Howe    43   Treasurer
         
Douglas J. Manko    35   Controller and Assistant Secretary
         


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       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 the Company's Chief Executive Officer effective January 1, 2007 and elected Chairman of the Board of Directors in May 2007. Prior to joining the Company, 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 the Company 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. He holds a Bachelor of Business Administration Degree in Accounting from the University of Houston and a Juris Doctorate Degree from Southern Methodist University.

       William S. Chadwick, Jr. joined Ensco in June 1987 and was elected to his current position of Executive Vice President - Chief Operating Officer effective January 1, 2006. Prior to his current position, Mr. Chadwick served the Company as Senior Vice President - Operations, Senior Vice President, Member - Office of the President and Chief Operating Officer and Vice President - Administration and Secretary. Mr. Chadwick holds a Bachelor of Science Degree in Economics from the Wharton School of the University of Pennsylvania.

       John Mark Burns joined Ensco in June 2008 and was elected to his current position of Senior Vice President in December 2009. Prior to his current position, Mr. Burns served as President of ENSCO Offshore International Company, a subsidiary of the Company. Prior to joining Ensco, Mr. Burns served in various international capacities with Noble Corporation (a leading offshore drilling contractor) and most recently served as Vice President & Division Manager responsible for offshore units located in the Gulf of Mexico. Mr. Burns holds a Bachelor of Arts Degree in Business and Political Science from Sam Houston State University.

       Patrick Carey Lowe joined Ensco in August 2008 as Senior Vice President. His responsibilities include the Deepwater Business Unit, capital projects, engineering and strategic planning. Prior to joining Ensco, Mr. Lowe was Vice President - Latin America for Occidental Oil & Gas (one of the world's largest independent oil and natural gas producers). 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.

       James W. Swent III joined Ensco in July 2003 and thereupon was elected to his current position of Senior Vice President - Chief Financial Officer. 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. Prior to joining the Company, Mr. Swent served as Co-Founder and Managing Director of Amrita Holdings, LLC. Mr. Swent holds a Bachelor of Science Degree in Finance and a Masters Degree in Business Administration from the University of California at Berkeley.

       David A. Armour joined Ensco in October 1990 and was elected to his current position of Vice President - Finance in September 2008. Prior to his current position, Mr. Armour served the Company as Assistant Controller and Controller. From 1981 to 1990, Mr. Armour served in various capacities as an employee of the public accounting firm Deloitte & Touche LLP and its predecessor firm Touche Ross & Co. Mr. Armour holds a Bachelor of Business Administration Degree from The University of Texas at Austin.


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       H. E. Malone, Jr. joined Ensco in August 1987 and was elected to his current position of Vice President and Assistant Secretary in December 2009. Prior to his current position, Mr. Malone served as Vice President - Finance (International), Vice President - Finance, Vice President - Accounting, Tax and Information Systems and Vice President - Controller. Mr. Malone holds Bachelor of Business Administration Degrees from The University of Texas at Austin and Southern Methodist University and a Masters of Business Administration Degree from the University of North Texas.

       Cary A. Moomjian, Jr. joined Ensco in January 2002 and thereupon was elected to his current position of Vice President, General Counsel and Secretary. Mr. Moomjian has over thirty years of experience in the oil and gas industry. From 1976 to 2001, Mr. Moomjian served in various management and executive capacities as an employee of Santa Fe International Corporation, including Vice President, General Counsel and Secretary from 1993 to 2001. Mr. Moomjian was admitted to the California Bar during 1972 and to the Texas Bar during 1994. He holds a Bachelor of Arts Degree from Occidental College and a Juris Doctorate Degree from Duke University School of Law.

       Sean P. O'Neill joined the Company in May 2009 as Vice President-Investor Relations. Prior to joining Ensco, Mr. O'Neill had served as Senior Vice President, Investor Relations and Corporate Communications of First Industrial Realty Trust, Inc. since 2004. Mr. O'Neill previously held similar positions at two Fortune 500 companies and was Managing Director of Strategic Investor Relations Consulting at Thomson Financial (Thomson Reuters). Mr. O'Neill holds a Bachelor of Science Degree in Finance from Fairfield University and a Masters of Business Administration Degree from DePaul University, Kellstadt Graduate School of Business. Mr. O'Neill is also a member of DePaul University's Finance Advisory Board.

       Michael B. Howe joined Ensco in February 2009 as Treasurer. Prior to joining the Company, Mr. Howe was an employee of Devon Energy Corp. (the largest U.S. based independent oil and natural gas producer) where he had served as Assistant Treasurer since 2002. Mr. Howe previously held positions in various capacities at Enron Corp., BG Group PLC and Arthur Andersen. Mr. Howe holds a Bachelor of Science Degree in Accounting from Oklahoma State University and a Masters of Business Administration Degree from The University of Texas at Austin.

       Douglas J. Manko joined Ensco in May 2004 and was elected to his current position of Controller and Assistant Secretary in December 2009. Prior to his current position, Mr. Manko served as Controller, Director - Management Systems and Manager - Accounting Public Reporting. From 1996 to 2004, Mr. Manko served in various capacities as an employee of the public accounting firm Ernst & Young LLP. Mr. Manko holds a Bachelor of Arts Degree in Business Administration from Baldwin Wallace College.

       Officers generally serve for a one-year term or until successors are elected and qualified to serve.

Employees

       We employed 3,585 personnel worldwide as of February 1, 2010, of which 2,347 were full-time employees. 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.enscointernational.com. These reports are also available in print without charge by contacting our Investor Relations Department at 214-397-3045 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

       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.

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WE HAVE NOT REQUESTED AN HMRC RULING ON THE U.K. TAX ASPECTS OF THE REDOMESTICATION, AND HMRC MAY DISAGREE WITH OUR CONCLUSIONS.

       Based on current U.K. corporation tax law and the current U.K.-U.S. income tax treaty, as amended, we expect that the redomestication will not result in any material U.K. corporation tax liability to Ensco International plc. Further, we believe that we have satisfied all stamp duty reserve tax ("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 International 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 us. 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.

THE IRS MAY DISAGREE WITH OUR CONCLUSIONS ON TAX TREATMENT OF THE REDOMESTICATION.

       We expect that the redomestication will not result in any material U.S. federal income tax liability to Ensco International plc. However, the IRS may disagree with our assessments of the effects or interpretation of the tax laws, treaties or regulations or their enforcement with respect to the redomestication. Nevertheless, even if our conclusions on the U.S. tax treatment of the redomestication to Ensco International plc do not ultimately prevail, we do not believe that a contrary treatment of the redomestication by the IRS would result in a material increase in U.S. taxes compared to our pre-redomestication U.S. tax position. In this event we may not realize the expected tax benefits of the redomestication, and our operating results may be adversely affected in comparison to what they would have been if the IRS agreed with our conclusions.

IF ENSCO INTERNATIONAL PLC AND ITS NON-U.S. SUBSIDIARIES BECOME SUBJECT TO U.S. FEDERAL INCOME TAX, OUR FINANCIAL POSITION, OPERATING RESULTS AND CASH FLOWS WOULD BE ADVERSELY AFFECTED.

       Ensco International plc and its non-U.S. subsidiaries will conduct their operations in a manner intended to minimize the risk that Ensco International plc or its non-U.S. subsidiaries engage in the conduct of a U.S. trade or business. Our U.S. and U.S.-owned subsidiaries will continue to be subject to U.S. federal income tax on their worldwide income, and our non-U.S. subsidiaries will continue to be subject to U.S. federal income tax on their U.S. operations. However, if Ensco International plc or any of its non-U.S. subsidiaries is or are determined to be engaged in a trade or business in the U.S., Ensco International plc or such non-U.S. subsidiaries would be required to pay U.S. federal income tax on income that is subject to the taxing jurisdiction of the U.S. If this occurs, our financial position, operating results and cash flows may be adversely affected.

WE MAY BE TREATED AS A U.S. CORPORATION FOR U.S. FEDERAL INCOME TAX PURPOSES FOLLOWING THE REDOMESTICATION.

       Generally for U.S. federal income tax purposes, a corporation is considered tax resident in the place of its incorporation. Ensco International plc is incorporated under U.K. law and should be deemed a U.K. corporation under these general rules. However, Section 7874 of the U.S. Internal Revenue Code of 1986, as amended (the "Code"), generally provides that a corporation organized outside the U.S. that acquires substantially all of the assets of a corporation organized in the U.S. will be treated as a U.S. corporation (and, therefore, a U.S. tax resident) for U.S. federal income tax purposes if shareholders of the acquired U.S. corporation own at least 80% (of either the voting power or the value) of the shares of the acquiring foreign corporation after the acquisition and the acquiring foreign corporation does not have substantial business activities in the country in which it is organized. As a result, Ensco must have substantial business activities in the U.K. to avoid being treated as a U.S. corporation for U.S. federal income tax purposes under Section 7874.

       There is currently no "safe harbor" or other guidance that confirms when a foreign corporation's business activities in its country of incorporation are deemed to be substantial. Therefore, it is possible that the IRS would interpret the Section 7874 "anti-inversion" rules so as to treat Ensco International plc as a U.S. corporation. Moreover, the U.S. or U.K. may enact new statutory or regulatory provisions that could adversely affect our status as a non-U.S. corporation or otherwise adversely affect our anticipated consolidated effective income tax rate. Retroactive statutory or regulatory actions have occurred in the past, and there can be no assurance that any such provisions, if enacted or promulgated, would not have retroactive application.

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       Ensco International plc is a company formed under English law and has historic, continuous and substantial business activities in the U.K. as a result of its longstanding North Sea drilling activities and management and control over the Europe and Africa Business Unit, headquartered in Aberdeen, Scotland. Therefore, we believe Ensco International plc should not be treated as a U.S. corporation for U.S. federal income tax purposes under Section 7874. However, there is no certainty that the IRS will not assert a contrary position, in which case we could become involved in tax controversy with the IRS regarding possible additional U.S. tax liability. If we are unsuccessful in resolving any such tax controversy in our favor, we would likely not realize the tax savings we anticipate achieving through the redomestication, and we could be liable for additional U.S. federal income tax as a result of certain transactions undertaken as part of the redomestication.

THE REDOMESTICATION MAY NOT ALLOW US TO MAINTAIN A COMPETITIVE CONSOLIDATED EFFECTIVE INCOME TAX RATE.

       We believe the redomestication should improve our ability to maintain a competitive consolidated effective income tax rate because the U.K. corporate tax rate is lower than the U.S. corporate tax rate and because the U.K. has implemented a dividend exemption system that generally does not subject non-U.K. earnings to U.K. tax when such earnings are repatriated to the U.K. in the form of dividends from non-U.K. subsidiaries.

       The U.K. Government is consulting on reform of the U.K. controlled foreign companies rules (the "CFC rules") and published a discussion document in January 2010 that contains updated CFC rules related proposals. It has been announced that consultation regarding reform of the CFC rules will continue during 2010 with draft legislation expected later in 2010 and amendments to the CFC rules not likely to be enacted until 2011. The effect of any such amendments to the CFC rules on Ensco International plc will not be clear until the new legislation is published and enacted in its entirety. We will closely monitor the proposed amendments in order to address and mitigate their effects (if any) and will consider submitting representations to the U.K. Government on such proposed amendments as may affect us.

       We cannot provide any assurances as to what our effective income tax rates will be because of, among other things, 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. and U.S. tax laws. Our actual effective income tax rates may vary from our expectation and that variance may be material. Additionally, the tax laws of other jurisdictions could change in the future, and such changes could cause a material change in our consolidated effective income tax rate.

       We also could be subject to future audits conducted by U.K., U.S. and other tax authorities, and the resolution of such audits could significantly impact our effective income tax rates in future periods, as would any reclassification or other matter (such as changes in applicable accounting rules) that increases the amounts we have provided for income taxes in our consolidated financial statements. There can be no assurance that we would be successful in attempting to mitigate the adverse impacts resulting from any changes in law, audits and other matters. Our inability to mitigate the negative consequences of any changes in the law, audits and other matters could cause our effective income tax rates to increase and our financial position, operating results or cash flows to be adversely affected.

CHANGES IN LAWS, INCLUDING TAX LAW CHANGES, COULD ADVERSELY AFFECT ENSCO, ITS SUBSIDIARIES AND ITS SHAREHOLDERS.

       Changes in tax laws, regulations or treaties or the interpretation or enforcement thereof, in the U.S., the U.K. or elsewhere, could adversely affect the tax consequences of the redomestication to Ensco and its shareholders and/or our effective income tax rates (whether associated with the redomestication or otherwise). For example, one reason for the redomestication was to begin to align our structure so as to have an opportunity to take advantage of U.K. corporate tax rates, which are lower than the U.S. income tax rates, and to take advantage of the recent dividend exemption system implemented in the U.K., which generally does not subject earnings of non-U.K. subsidiaries to U.K. tax when such earnings are repatriated to the U.K. as dividends. Future changes in tax laws, regulations or treaties or the interpretation or enforcement thereof in general or any such changes resulting in a material change in the U.S. or U.K. tax rates in particular could reduce or eliminate the benefits that we expect to achieve from the redomestication.

CHANGES IN EFFECTIVE INCOME TAX RATES OR ADVERSE OUTCOMES RESULTING FROM EXAMINATION OF OUR TAX RETURNS COULD ADVERSELY AFFECT OUR FINANCIAL RESULTS.

       Changes in the valuation of our deferred tax assets and liabilities or changes in tax treaties, regulations, accounting principles or interpretations thereof in one or more countries in which we operate could result in a higher effective income tax rate on our worldwide earnings and such change could be significant to our financial results. Our future effective income tax rates could also be adversely affected by lower than anticipated earnings in countries where we have lower statutory rates and higher than anticipated earnings in countries where we have higher statutory rates. In addition, we are subject to examinations of our income tax returns by HMRC, the IRS and other tax authorities. We regularly assess the likelihood of adverse outcomes resulting from these examinations to determine the adequacy of our provision for income taxes. There can be no assurance that such examinations will not have an adverse effect on our financial position, operating results or cash flows.

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THE EXPECTED FINANCIAL, LOGISTICAL AND OPERATIONAL BENEFITS OF THE REDOMESTICATION 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.

       While we expect that the redomestication will enable us to take advantage of lower U.K. tax rates and the benefits of the U.K. dividend exemption system for certain non-U.K. source dividends repatriated to the U.K. in the years after implementation of the redomestication to a greater extent than would likely have been available if the redomestication had not occurred, these benefits may not be achieved. In particular, U.K. or U.S. tax authorities may challenge our application and/or interpretation of relevant tax laws, regulations or treaties, valuations and methodologies or other supporting documentation. If they are successful in doing so, we may not experience the level of benefits we anticipate, or we may be subject to adverse tax consequences. 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.

       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 (especially as between the British pound and the U.S. dollar), and significant changes in trade, monetary or fiscal policies of the U.K. or the U.S., including changes in 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 rigs are deployed, the location of the business unit offices that oversee our global offshore contract drilling operations, the locations of our customer's 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.

AS A RESULT OF INCREASED SHAREHOLDER APPROVAL REQUIREMENTS, WE MAY HAVE LESS FLEXIBILITY AS A U.K. PUBLIC LIMITED COMPANY THAN WE HAD AS A U.S. CORPORATION WITH RESPECT TO CERTAIN ASPECTS OF CAPITAL MANAGEMENT.

       Under Delaware law, our directors could issue, without further shareholder approval, any shares of common stock authorized in our certificate of incorporation that were not already issued or reserved. Delaware law also provided 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 shareholders, such authorization being up to the aggregate nominal amount of shares and for a maximum period of five years, each as specified in the articles of association or relevant shareholder resolution. Such authorization would need to be renewed by our shareholders upon its expiration (i.e., at least every five years). An ordinary resolution was adopted prior to the effective time of the redomestication to authorize the allotment of additional shares and renewal of such authorization for additional five-year terms may be sought more frequently.


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       English law also generally provides shareholders preemptive rights when new shares are issued for cash. However, it is possible for the articles of association or shareholders in a general meeting to exclude preemptive rights. Such an exclusion of preemptive rights may be for a maximum period of up to five years from the date of adoption of the articles of association, if the exclusion is contained in the articles of association, or from the date of the shareholder resolution, if the exclusion is by shareholder resolution. In either case, this exclusion would need to be renewed upon its expiration (i.e., at least every five years). A special resolution was adopted to exclude preemptive rights prior to the effective time of the redomestication and renewal of such exclusion for additional five-year terms may be sought more frequently.

       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 prior approval of 75% of its shareholders by special resolution. Such approval lasts for a maximum period of up to five years. A special resolution was adopted to permit "off-market purchases" prior to the effective time of the redomestication. This special resolution will need to be renewed upon expiration (i.e., at least every five years) to permit "off-market purchases" and renewal for additional five-year terms may be sought more frequently.

       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 ABILITY TO DECLARE DIVIDENDS AND REPURCHASE SHARES WILL BE MORE LIMITED DUE TO THE REDOMESTICATION.

       Under English law, with limited exceptions, we will only be able to declare dividends, make distributions or repurchase shares out of distributable profits. Distributable profits are a company's accumulated realized profits, so far as not previously utilized by distribution or capitalization, less its accumulated realized losses, so far as not previously written off in a reduction or reorganization of capital duly made. It is expected that, subject to the risk factors discussed in this section and to the factors discussed in our Forward-Looking Statements, Ensco will have income from continuing operations sufficient to accumulate distributable profits in an amount sufficient to continue paying quarterly dividends at a rate of $0.025 per share on the anticipated schedule for the foreseeable future and to continue our repurchases of shares from employees in connection with the settlement of income tax withholding obligations arising from the vesting of share awards. However, our subsidiaries would need to declare a dividend payable to our U.K. parent and pay the associated withholding taxes to provide Ensco International plc the initial distributable profits sufficient to fully implement our previously disclosed Board authorization to repurchase up to $562.4 million of our shares.

THE REDOMESTICATION WILL RESULT IN ADDITIONAL ONGOING COSTS.

       The redomestication will result in an increase in some of our ongoing expenses and require us to incur some new expenses. Some costs, including those related to relocation and employment of expatriate officers and other employees in our U.K. offices and holding Board of Directors meetings in the U.K., are expected to be higher than would be the case if our principal executive offices were not relocated to England. We also expect to incur new expenses, including professional fees, to comply with U.K. corporate and tax laws.

THE MARKET FOR ADSs REPRESENTING CLASS A ORDINARY SHARES MAY DIFFER FROM THE FORMER MARKET FOR ENSCO COMMON STOCK.

       Although the ADSs are listed on the NYSE under the symbol "ESV," which is the same symbol under which common stock of Ensco Delaware was formerly listed, the market prices, trading volume and volatility of the ADSs could be different from those of the shares of Ensco Delaware common stock and certain funds and institutional holders may have rules or policies that restrict investment in ADSs.


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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.

       Worldwide military, political, environmental and economic events also contribute to oil and natural gas price volatility. Numerous other 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 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.
 
THE OFFSHORE CONTRACT DRILLING INDUSTRY HISTORICALLY HAS BEEN CYCLICAL, WITH PERIODS OF LOW DEMAND AND EXCESS RIG AVAILABILITY THAT COULD RESULT IN ADVERSE EFFECTS ON OUR BUSINESS.

       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 is limited and new rigs require substantial capital investment and a long period of time to construct. There are 95 new jackup and semisubmersible rigs reported to be on order for delivery by the end of 2012. More that half of these rigs are scheduled for delivery during 2010, representing an approximate 10% increase in the total worldwide fleet of jackups and semisubmersible 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.

       The increase in supply of offshore drilling rigs during 2010 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.

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       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 increase in drilling rig supply could adversely affect our financial position, operating results and cash flows.

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 COULD ALSO CAUSE OUR CUSTOMERS AND/OR VENDORS TO FAIL TO FULFILL THEIR COMMITMENTS AND/OR FUND 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.

       Oil and natural gas prices have declined significantly from their record highs reached in July 2008. A sustained decline in oil and natural gas prices, whether caused by economic conditions, international or national climate change regulations or other factors, could cause oil and gas companies to further reduce their overall level of drilling activity and spending. Disruption in the capital markets could also cause oil and gas companies to further reduce their overall level of drilling activity and spending.

       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 sustained decline in oil and natural gas prices, together with deterioration of the global economy, could substantially reduce demand for drilling rigs and adversely affect our financial position, operating results and 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 specific 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 with 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.

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WE MAY INCUR ASSET IMPAIRMENTS AS A RESULT OF DECLINING DEMAND FOR OFFSHORE DRILLING RIGS.

       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 demand comes back into balance with supply. 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.

       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 and estimate each 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.

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. Our five largest customers accounted for 44% of consolidated revenues in the aggregate, with our largest customer representing 13%. 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 rigs are added to the worldwide fleet. There are 95 new jackup and semisubmersible rigs reported to be on order for delivery by the end of 2012, more than half of which are scheduled for delivery during 2010. These rigs will require new skilled and other personnel to operate. In periods of high utilization, it is more difficult and costly to recruit and retain qualified 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.

       Notwithstanding current global economic conditions, we may be required to maintain or increase existing levels of compensation to retain our skilled workforce. Much of the skilled workforce is nearing retirement age, which may impact the availability of skilled personnel. 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.

OUR DRILLING CONTRACTS WITH NATIONAL OIL COMPANIES EXPOSE US TO GREATER RISKS THAN WE NORMALLY ASSUME.

       We currently have twelve jackup rigs contracted with national oil companies. The terms of these non-U.S. 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 greater environmental liability, 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.

OUR DRILLING RIG FLEET IS CONCENTRATED IN PREMIUM JACKUP RIGS, WHICH LEAVES US VULNERABLE TO RISKS RELATED TO LACK OF DIVERSIFICATION.

       The offshore contract drilling industry is generally divided into two broad markets: deepwater and shallow water drilling. These broad markets are generally divided into smaller sub-markets based upon various factors, including type of drilling rig. The primary types of drilling rigs include jackup rigs, semisubmersible rigs, drillships, platform rigs, barge rigs and submersible rigs. While all drilling rigs are affected by general economic and industry conditions, each type of drilling rig can be affected differently by changes in demand. We currently have 42 jackup rigs, four ultra-deepwater semisubmersible rigs and one barge rig. Additionally, we have four ultra-deepwater semisubmersible rigs under construction.

       Our drilling rig fleet is concentrated in premium jackup rigs. If the market for premium jackup rigs should decline relative to the markets for other drilling rig types, our operating results could be more adversely affected relative to our competitors with drilling fleets that are less concentrated in premium jackup rigs.


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OUR NON-U.S. OPERATIONS INVOLVE ADDITIONAL RISKS NOT ASSOCIATED WITH U.S. OPERATIONS.

       Revenues from non-U.S. operations were 86%, 80% and 77% of our total revenues during 2009, 2008 and 2007, 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,
  exchange restrictions,
  currency fluctuations,
  changes in the manner or rate of taxation,
  limitations on our ability to recover amounts due,
  increased risk of government and vendor/supplier corruption,
  changes in political conditions, and
  changes in monetary policies.


       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. 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 or underinsured, 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 same, adverse rulings in connection with audits or otherwise, or other challenges may substantially increase our tax expense.


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       Our non-U.S. operations also face the risk of fluctuating currency values, which can impact our revenues, operating costs and capital expenditures. 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 international currency and, to the extent possible, by limiting 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.

       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. Our drilling contracts generally stipulate payment wholly or substantially in U.S. dollars, which reduces the impact currency fluctuations have on our earnings and cash flows. However, there is no assurance that our contracts will contain such payment 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 the ENSCO 8500 Series® 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, the 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 requirement for equipment thereon. 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 companies and may continue to do so. Moreover, certain countries accord preferential treatment to local contractors or joint ventures, which can 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.

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 FOUR ULTRA-DEEPWATER SEMISUBMERSIBLE RIGS CURRENTLY UNDER CONSTRUCTION ARE AT A SINGLE SHIPYARD IN SINGAPORE. THREE OF THESE RIGS DO NOT HAVE DRILLING CONTRACTS.

       There are 95 new jackup and semisubmersible rigs reported to be on order or under construction with expected delivery dates through 2012. 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.


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       We currently have four ultra-deepwater semisubmersible 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. 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 or terrorism,
  unforeseen design or engineering problems,
  unanticipated actual or purported change orders,
  strikes, labor disputes or work stoppages,
  financial or operating difficulties of equipment vendors or the shipyard while constructing, upgrading, refurbishing 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,
  force majeure, and
  additional risks inherent to shipyard projects in a non-U.S. location.


       Our risks are concentrated because our four ultra-deepwater semisubmersible rigs currently under construction are at a single shipyard in Singapore. Although based on the design of ENSCO 7500 which has operated without significant downtime since its delivery in 2000, these four rigs and the recently delivered ENSCO 8500, ENSCO 8501 and ENSCO 8502 have a common risk of unforeseen design or engineering problems. Furthermore, ENSCO 8503 is subject to a firm, fixed day rate drilling contract upon completion of construction and significant shipyard project cost overruns or delays could impact the projected financial results or the viability of the contract and have a materially adverse effect on our financial position, operating results and cash flows.

       ENSCO 8504, ENSCO 8505 and ENSCO 8506 have not secured drilling contracts upon completion of their construction. These rigs are scheduled to be delivered during the second half of 2011 and first and second half of 2012, respectively. 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.

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WE HAVE INVESTED A PORTION OF OUR CASH IN AUCTION RATE SECURITIES AND WE MAY BE REQUIRED TO HOLD THEM INDEFINITELY DUE TO AN ILLIQUID MARKET.

       As of December 31, 2009, we held $66.8 million (par value) of auction rate securities. Auctions for most of our auction rate securities began to fail in February 2008, as there were more sellers than buyers at scheduled interest rate auctions and parties desiring to sell their auction rate securities were unable to do so. When an auction fails, the interest rate is adjusted according to the provisions of the associated security agreement.

       The majority of our auction rate securities are currently rated Aaa by Moody's, AAA by Standard & Poor's and/or AAA by Fitch. An aggregate $64.3 million (par value), or 96% of our auction rate securities, were issued by state agencies and are supported by student loans for which repayment is substantially guaranteed by the U.S. government under the Federal Family Education Loan Program.

       Auction failures and the resulting lack of liquidity have affected the entire auction rate securities market, and we are currently unable to determine whether these conditions will be of an extended duration. While it is estimated that more than half of the $330.0 billion auction rate securities market has been refinanced, student loan supported auction rate securities remain mostly constrained and illiquid. Although $5.5 million and $6.0 million of our auction rate securities were redeemed at par value during the years ended December 31, 2009 and 2008, respectively, we are currently unable to determine whether issuers of our auction rate securities will attempt and/or be able to refinance.

       We are also unable to determine if alternative markets that provide orderly purchases and sales of auction rate securities will develop. Pursuant to regulatory settlements, several major brokerage firms have offered to repurchase auction rate securities from retail investors, charities and small businesses, and use best efforts to provide liquidity to institutional investors within the next several years. However, we are currently unable to determine whether these brokerage firms will be able to comply with the terms of their regulatory settlements. Moreover, current global economic conditions may impede auction rate security repurchases.

       Although we acquired our auction rate securities with the intention of selling them in the near-term, we do not currently expect to experience liquidity problems or alter any business plans if we maintain our investment in these securities indefinitely. Our auction rate securities have final maturity dates ranging from 2025 to 2047.

THE POTENTIAL FOR 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 Gulf of Mexico experience hurricanes and other extreme weather conditions on a relatively frequent basis. Some of our drilling rigs in the 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 Gulf of Mexico than most of our competitors. We currently have seven jackup rigs and two ultra-deepwater semisubmersible rigs in the Gulf of Mexico. Damage caused by high winds and turbulent seas could result in rig loss or damage, termination of drilling contracts on 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 Gulf of Mexico have been impacted by hurricanes, including the total loss of one jackup rig during 2004, one platform rig during 2005 and one jackup rig during 2008, with associated loss of contract revenues and potential liabilities.


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       Insurance companies incurred substantial losses in the offshore drilling, exploration and production industries as a consequence of hurricanes that occurred in the 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 Gulf of Mexico ("windstorm damage") and have dramatically increased the cost of available windstorm coverage. In discussions with insurance brokers and underwriters concerning our 2009 mid-year, annual insurance renewal, we were advised that coverage for risks associated with Gulf of Mexico windstorm damage had limited capacity and would be very costly. The tight insurance market not only applies to coverage related to Gulf of Mexico windstorm damage or loss of our drilling rigs, but also impacts coverage for 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.

       Upon renewal of our annual insurance policies effective July 1, 2009, we obtained $450.0 million of annual coverage for ultra-deepwater semisubmersible rig hull and machinery losses arising from 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 jackups remaining in the Gulf of Mexico. Accordingly, we have retained the risk for loss or damage of our seven jackup rigs remaining in the Gulf of Mexico arising out of windstorm damage.

       Our current liability insurance policies only provide coverage for Gulf of Mexico windstorm exposures for removal of wreckage and debris in excess of $50.0 million per occurrence as respects both our jackup and ultra-deepwater semisubmersible rig operations. 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 Gulf of Mexico hurricanes.

       We have established operational procedures designed to mitigate risk to our jackup rigs in the 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 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 Gulf of Mexico.

       As noted above, we have a $50.0 million per occurrence deductible for windstorm loss or damage to our ultra-deepwater semisubmersible rigs in the Gulf of Mexico and have elected not to purchase loss or damage insurance coverage for our seven jackup rigs in the area. Moreover, we have retained the risk for the first $50.0 million of liability exposure for removal of wreckage and debris resulting from windstorm related exposures associated with our rigs in the Gulf of Mexico. These and other retained exposures for property loss or damage and wreckage and debris removal or other liabilities associated with Gulf of Mexico 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 Gulf of Mexico hurricanes.

THE LOSS OF ENSCO 74 MAY EXPOSE US TO COSTS ASSOCIATED WITH REMOVAL OF WRECKAGE AND DEBRIS, LIABILITIES FOR PROPERTY LOSS OR DAMAGE, PERSONAL INJURY OR DEATH OR ENVIRONMENTAL LIABILITIES THAT MAY NOT BE FULLY RECOVERABLE UNDER OUR INSURANCE OR CONTRACTUAL INDEMNITIES.

       In September 2008, ENSCO 74 was lost as a result of Hurricane Ike in the Gulf of Mexico. Portions of its legs remained underwater adjacent to the customer's platform, and we conducted extensive aerial and sonar reconnaissance but did not locate the rig hull. In March 2009, the sunken rig hull of ENSCO 74 was located approximately 95 miles from the original drilling location when it was struck by an oil tanker. Following discovery of the sunken rig hull, we removed the accessible hydrocarbons onboard the rig and began planning for removal of the wreckage. As an interim measure, the wreckage has been appropriately marked, and the U.S. Coast Guard has issued a Notice to Mariners. We are currently communicating with various government agencies to address removal of the wreckage and related debris.

       We are involved in civil litigation in the U.S. District Court for the Southern District of Texas in which the owners of the tanker SKS Satilla are seeking monetary damages of $10.0 million for losses incurred when the tanker struck the sunken hull of ENSCO 74. In addition, we received notice from legal counsel representing owners of another tanker alleging that the sunken hull of the ENSCO 74 caused damage to their tanker in January 2009 resulting in unspecified damages and losses.

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       We are involved in civil litigation in the U.S. District Court for the Southern District of Texas in which the owner of a pipeline, High Island Offshore System, LLC, alleges that ENSCO 74 damaged the pipeline in the aftermath of Hurricane Ike and is seeking damages for the cost of repairs and business interruption in excess of $26.0 million. We also are involved in civil litigation in the Fifteenth Judicial Court for the Parish of Lafayette and in the Nineteenth Judicial Court for the Parish of Baton Rouge, State of Louisiana in which the owner of a pipeline, Sea Robin Pipeline Company, LLC, is seeking unspecified damages in relation to the cost of repairing damage to the pipeline, loss of revenues, survey and other damages allegedly caused by ENSCO 74 in the aftermath of Hurricane Ike.

       On November 2, 2009, the owners of two other subsea pipelines presented claims in the exoneration or limitation of liability proceedings we filed in U.S. District Court for the Southern District of Texas as described below. The claims were filed on behalf of Stingray Pipeline Company, LLC, and Tennessee Gas Pipeline seeking monetary damages incurred by reason of damage to pipelines allegedly caused by ENSCO 74 in the aftermath of Hurricane Ike. The Stingray claim is in the amount of $14.0 million, and the Tennessee Gas Pipeline claim is for unspecified damages.

       We are exposed to costs associated with removal of the ENSCO 74 legs that remain underwater adjacent to the customer's platform and the sunken rig hull and related debris. Although we expect the cost of removal of the leg sections and the hull and related debris to be covered by available insurance and contractual indemnification, we may not be fully protected from such costs, liability or exposure (without any additional deductible or self-insured retention). Moreover, although appropriately marked following issuance of a U.S. Coast Guard Notice to Mariners, the sunken hull of ENSCO 74 may expose us to liabilities as a hazard to navigation and may also expose us to various potential liabilities for property loss or damage, personal injury or death and environmental liabilities, including penalties, fines and clean-up costs.

       Our liability insurance may not fully protect us from cost, liability or exposure associated with the loss of ENSCO 74. As respects liabilities to third-parties, including the aforementioned tanker and pipeline claims, our applicable insurance is subject to a $10.0 million per occurrence self-insured retention and an annual aggregate policy limit of $500.0 million. We believe all liabilities associated with the ENSCO 74 loss during Hurricane Ike resulted from a single occurrence under the terms of the applicable insurance policies. However, legal counsel for certain liability underwriters have asserted that the liability claims arise from separate occurrences. In the event of multiple occurrences, the self-insured retention is $15.0 million for two occurrences and $1.0 million for each occurrence thereafter.

       We plan to undertake all appropriate defensive measures and filed a petition for exoneration or limitation of liability under U.S. admiralty and maritime law in the U.S. District Court for the Southern District of Texas on September 2, 2009. The petition seeks exoneration from or limitation of liability for any and all injury, loss or damage caused, occasioned or occurred in relation to the ENSCO 74 loss in September 2008. The exoneration/limitation proceeding currently includes the SKS Satilla claim and the four pipeline claims described above. The matter has been scheduled for trial in September 2011. See Note 11 and Note 12 to our consolidated financial statements for additional information on the loss of ENSCO 74 and associated contingencies.

OUR BUSINESS INVOLVES NUMEROUS OPERATING HAZARDS, AND WE ARE NOT FULLY INSURED AGAINST ALL OPERATING HAZARDS.

       Contract drilling and offshore oil and gas operations in general are subject to numerous risks, including the following:
 

  rig or other property damage, liability or loss, including removal of wreckage or debris, resulting from hurricanes and other severe weather conditions, collisions, groundings, blowouts, fires, explosions and other accidents or terrorism,
  blowouts, fires, explosions and other loss of well control events causing damage to wells, reservoirs, production facilities and other properties and which may require wild well control, including drilling of relief wells,
  craterings, punchthroughs or other events causing rigs to capsize, sink or otherwise incur significant damage or total loss,
  extensive uncontrolled rig or well fires, blowouts, oil spills or other discharges of pollutants causing damage to the environment,
  machinery breakdowns, equipment failures, personnel shortages, failure of subcontractors and vendors to perform or supply goods and services and other events causing the suspension or cancellation of drilling operations, and
  unionization or similar collective actions by our employees or employees of subcontractors causing suspension of drilling operations or significant increases in operating costs.


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       In addition to these risks to property and the environment, many of the hazards and risks associated with our operations and accidents or other events resulting from such hazards and risks, as well as our routine operations, expose our personnel, as well as personnel of our customers, subcontractors, vendors and other third-parties, to the risk of personal injury or death.

       Although we currently maintain broad insurance coverage, subject to certain significant deductibles and levels of self-insurance or risk retention, it does not cover all types of losses and, in some situations such as rig loss or damage resulting from Gulf of Mexico hurricane related windstorm exposures, may not provide coverage for damages, in whole or in part, losses or liabilities resulting from our operations. Except for windstorm coverage on our Gulf of Mexico rigs subsequent to July 1, 2006, which was placed on a limited basis, we historically have maintained insurance coverage for damage to or loss of our drilling rigs in amounts not less than the estimated fair market value thereof. Even when insured, we have encountered circumstances in which insurance companies have issued reservations of rights or denied coverage which has, in certain circumstances, resulted in litigation. However, in the event of total loss, such coverage is unlikely to be sufficient to recover the cost of a newly-constructed replacement rig. Since we do not maintain business interruption or loss of hire insurance, we are fully exposed to loss of contract drilling revenues resulting from rig loss or damage.

       We generally obtain contractual indemnification obligating our customers to protect and indemnify us for all or part of the liabilities resulting from pollution and damage to the environment, damage to wells, reservoirs and other customer property, control of wild wells, drilling of relief wells and certain non-rig crew personnel injuries. Such indemnification protection may be qualified or limited and may exclude certain perils or events or the application of local law. In some circumstances, we are unable to obtain indemnification protection for some or all of the risks generally assumed by our customers, including risks and liabilities relating to environmental damage, well loss or damage or wild well control. The inability to obtain such indemnification or the failure of a customer to meet indemnification obligations or losses or liabilities resulting from uninsured or underinsured events could have a material adverse effect on our financial position, operating results and cash flows.

       Our contracts generally protect us in whole or part from certain losses sustained as a result of our negligence, most frequently as respects pollution and damage to the environment, damage to wells or reservoirs, control of wild wells, drilling of relief wells and consequential damages. However, losses resulting from contracts that do not contain such protection could have a material adverse affect on our financial position, operating results and cash flows. Losses resulting from our gross negligence or willful misconduct may not be protected contractually by specific provision or by application of law, and our insurance may not provide adequate protection for such losses.

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. 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 for discharges of pollutants into the environment. However, there can be no assurance that such laws and regulations or accidents will not expose us to material liability in the future.

       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 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 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. 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 have generally heightened 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. To date, no proposals have been enacted into law which would materially limit or prohibit offshore drilling in our principal areas of operation. However, we are adversely affected by moratoria on drilling in certain areas of the Gulf of Mexico and elsewhere. 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 cost of offshore drilling, exploration, development or production of oil and natural gas, we could be materially adversely affected.

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.

TERRORIST ATTACKS, PIRACY AND MILITARY ACTION COULD HAVE A MATERIAL ADVERSE EFFECT ON OUR BUSINESS.

       Terrorist acts, piracy, kidnapping, extortion or acts of war may cause damage to or disruption of our operations, employees, property and equipment or customers, suppliers and subcontractors, which may not be covered by insurance or an enforceable contractual indemnity and could significantly impact our financial position, operating results and cash flows. These acts create many economic and political uncertainties and the potential for future similar acts, the national and international responses and other acts of war or hostility could create many economic and political uncertainties, including an impact upon oil and natural gas drilling, exploration and development. This could adversely affect our business in ways that cannot readily be determined.

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 commercial, employment or regulatory activities. We also are concluding an internal investigation relating to compliance with the anti-bribery, recordkeeping and accounting provisions of the U.S. Foreign Corrupt Practices Act ("FCPA") that focuses on activities related to our former operations in Nigeria and the associated accounting entries and internal accounting controls and have self-reported to the appropriate U.S. government authorities.

       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.


Item 1B.  Unresolved Staff Comments

       None.


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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 16, 2010:
 

Rig Name Rig Type  
Year Built/
   Rebuilt   
        Design     Maximum
Water Depth/
Drilling Depth
    Current
    Location    
      Current
     Customer  
                           
Deepwater                          
ENSCO 7500  Semisubmersible      2000   Dynamically Positioned  8,000'/30,000'  Australia  Chevron 
ENSCO 8500  Semisubmersible      2008    Dynamically Positioned  8,500'/35,000'  Gulf of Mexico  Eni/Anadarko 
ENSCO 8501  Semisubmersible      2009   Dynamically Positioned  8,500'/35,000'  Gulf of Mexico  Nexen/Noble Energy 
ENSCO 8502  Semisubmersible      2010(1)  Dynamically Positioned  8,500'/35,000'  Singapore  Shipyard  
ENSCO 8503  Semisubmersible     2010(2)  Dynamically Positioned  8,500'/35,000'  Singapore  Under construction(3) 
ENSCO 8504  Semisubmersible     2011(2)   Dynamically Positioned  8,500'/35,000'  Singapore  Under construction(3) 
ENSCO 8505  Semisubmersible     2012(2)  Dynamically Positioned  8,500'/35,000'  Singapore  Under construction(3) 
ENSCO 8506  Semisubmersible     2012(2)  Dynamically Positioned  8,500'/35,000'  Singapore  Under construction(3) 


Asia Pacific
 
ENSCO 50  Jackup  1983/1998  F&G L-780 MOD II-C  300'/25,000'  Qatar  Sime Darby 
ENSCO 51  Jackup  1981/2002  F&G L-780 MOD II-C  300'/25,000'  Malaysia  Available 
ENSCO 52  Jackup  1983/1997  F&G L-780 MOD II-C  300'/25,000'  Malaysia  Petronas Carigali 
ENSCO 53  Jackup  1982/2009  F&G L-780 MOD II-C  300'/25,000'  India  BG 
ENSCO 54  Jackup  1982/1997  F&G L-780 MOD II-C  300'/25,000'  Qatar  ADOC/Bunduq 
ENSCO 56  Jackup  1982/1997  F&G L-780 MOD II-C  300'/25,000'  Malaysia  Available 
ENSCO 57  Jackup  1982/2003  F&G L-780 MOD II-C  300'/25,000'  Malaysia  Petronas Carigali 
ENSCO 67  Jackup  1976/2005  MLT 84-CE  400'/30,000'  Indonesia  Pertamina 
ENSCO 76  Jackup      2000  MLT Super 116-C  300'/30,000'  Saudi Arabia  Saudi Aramco 
ENSCO 84  Jackup  1981/2005  MLT 82 SD-C  250'/25,000'  Bahrain  Cold stacked 
ENSCO 88  Jackup  1982/2004  MLT 82 SD-C  250'/25,000'  Qatar  Ras Gas 
ENSCO 94  Jackup  1981/2001  Hitachi 250-C  250'/25,000'  Qatar  Ras Gas 
ENSCO 95  Jackup  1981/2005  Hitachi 250-C  250'/25,000'  Saudi Arabia  Saudi Aramco 
ENSCO 96  Jackup  1982/1997  Hitachi 250-C  250'/25,000'  Qatar  Larsen & Toubro 
ENSCO 97  Jackup  1980/1997  MLT 82 SD-C  250'/25,000'  Bahrain  Available 
ENSCO 104  Jackup      2002  KFELS MOD V-B  400'/30,000'  Australia  ConocoPhillips 
ENSCO 106  Jackup      2005  KFELS MOD V-B  400'/30,000'  Malaysia  Newfield 
ENSCO 107  Jackup      2006  KFELS MOD V-B  400'/30,000'  Singapore  Available/Committed 
ENSCO 108  Jackup      2007  KFELS MOD V-B  400'/30,000'  Brunei  Total 
ENSCO I  Barge      1999  Barge  --/18,000'  Singapore  Cold stacked 

Europe and Africa
 
ENSCO 70  Jackup  1981/1996  Hitachi K1032N  250'/30,000'  United Kingdom  Available/Committed 
ENSCO 71  Jackup  1982/1995  Hitachi K1032N  225'/25,000'  Denmark  Maersk 
ENSCO 72  Jackup  1981/1996  Hitachi K1025N  225'/25,000'  United Kingdom  Eni 
ENSCO 80  Jackup  1978/1995  MLT 116-CE  225'/30,000'  United Kingdom  Available/Committed 
ENSCO 85  Jackup  1981/1995  MLT 116-C  300'/25,000'  Greece  Aegean Energy 
ENSCO 92  Jackup  1982/1996  MLT 116-C  225'/25,000'  United Kingdom  EIS Consortium 
ENSCO 100  Jackup  1987/2009  MLT 150-88-C  350'/30,000'  United Kingdom  GDF Suez 
ENSCO 101  Jackup      2000  KFELS MOD V-A  400'/30,000'  United Kingdom  Available/Committed 
ENSCO 102  Jackup      2002  KFELS MOD V-A  400'/30,000'  United Kingdom  ConocoPhillips 
ENSCO 105  Jackup      2002  KFELS MOD V-B  400'/30,000'  Tunisia  BG 


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

North & South America
         
ENSCO 60  Jackup  1981/2003  Levingston 111-C  300'/25,000'  Gulf of Mexico  Cold stacked 
ENSCO 68  Jackup  1976/2004  MLT 84-CE  400'/30,000'  Venezuela  Chevron 
ENSCO 75  Jackup      1999  MLT Super 116-C  400'/30,000'  Gulf of Mexico  W&T 
ENSCO 81  Jackup  1979/2003  MLT 116-C  350'/30,000'  Mexico  Pemex 
ENSCO 82  Jackup  1979/2003  MLT 116-C  300'/30,000'  Gulf of Mexico  Chevron 
ENSCO 83  Jackup  1979/2007  MLT 82 SD-C  250'/25,000'  Mexico  Pemex 
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 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  Stone 
ENSCO 93  Jackup  1982/2008  MLT 82 SD-C  250'/25,000'  Mexico  Pemex 
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  Exxon 


     (1)

 

ENSCO 8502 was delivered by KFELS in January 2010 and is expected to mobilize to the Gulf of Mexico where it will undergo deepwater sea trials and final outfitting. The rig is projected to commence operations under a two-year drilling contract with Nexen/Noble Energy during the third quarter of 2010.

     (2)

 

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

     (3)

 

ENSCO 8503 has secured a two-year drilling contract in the Gulf of Mexico. We are currently marketing ENSCO 8504, ENSCO 8505 and ENSCO 8506 and anticipate they will be contracted in advance of delivery. For additional information on our rigs under construction, see "Cash Flow and Capital Expenditures" included in "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations."


       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.

       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 safe 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.

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       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 or dynamically positioned by computer-controlled propellers or "thrusters." 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. The ENSCO 8500 Series® rigs are enhanced versions of the ENSCO 7500, capable of drilling in up to 8,500 feet of water, and can be upgraded to 10,000 foot water-depth capability if required. Enhancements over ENSCO 7500 include a two million pound quad derrick, upgraded riser tensioning systems, offline pipe handling capability, increased drilling capacity, greater variable deck load, increased capacity in rig crew living quarters, improved automatic station keeping and the ability to modify the rig with an additional drilling platform. With these features, we believe the ENSCO 8500 Series® rigs are especially well-suited for deepwater development and exploratory well drilling.

       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. All of our rigs are in good condition. As of February 15, 2010, we owned all of the rigs in our fleet.

       We lease our executive offices in London, England and own offices and other facilities in Louisiana and Scotland. In addition to our executive offices, we currently lease office space in Dallas and Houston, Texas, Abu Dhabi, Australia, Brunei, Denmark, Dubai, India, Indonesia, Malaysia, Mexico, New Zealand, Qatar, Saudi Arabia, Singapore, Tunisia and Venezuela.

Item 3.  Legal Proceedings

   FCPA Internal Investigation

       Following disclosures by other offshore service companies announcing internal investigations involving the legality of amounts paid to and by customs brokers in connection with temporary importation of rigs and vessels into Nigeria, the Audit Committee of our Board of Directors and management commenced an internal investigation in July 2007. The investigation initially focused on our payments to customs brokers relating to the temporary importation of ENSCO 100, our only rig that operated offshore Nigeria during the pertinent period.

       As is customary for companies operating offshore Nigeria, we had engaged independent customs brokers to process customs clearance of routine shipments of equipment, materials and supplies and to process the ENSCO 100 temporary importation permits, extensions and renewals. One or more of the customs brokers that our subsidiary in Nigeria used to obtain the ENSCO 100 temporary import permits, extensions and renewals also provided this service to other offshore service companies that have undertaken FCPA compliance internal investigations.

       The principal purpose of our investigation was to determine whether any of the payments made to or by our customs brokers were inappropriate under the anti-bribery provisions of the FCPA or whether any violations of the recordkeeping or internal accounting control provisions of the FCPA occurred. Our Audit Committee engaged a Washington, D.C. law firm with significant experience in investigating and advising upon FCPA matters to assist in the internal investigation.

       Following notification to the Audit Committee and to KPMG LLP, our independent registered public accounting firm, in consultation with the Audit Committee's external legal counsel, we voluntarily notified the United States Department of Justice and SEC that we had commenced an internal investigation. We expressed our intention to cooperate with both agencies, comply with their directives and fully disclose the results of the investigation. The internal investigation process has involved extensive reviews of documents and records, as well as production to the authorities, and interviews of relevant personnel. In addition to the temporary importation of ENSCO 100, the investigation has examined our customs clearance of routine shipments and immigration activities in Nigeria.


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       Our internal investigation has essentially been concluded. Meetings to review the results of the investigation and discuss associated matters were held with the authorities on February 24, 2009, September 14, 2009 and February 9, 2010. We expect to discuss a possible negotiated disposition with the authorities in the near-term.

       Although we believe the U.S. authorities will take into account our voluntary disclosure, our cooperation with the agencies and the remediation and compliance enhancement activities that are underway, we are unable to predict the ultimate disposition of this matter, whether we will be charged with violation of the anti-bribery, recordkeeping or internal accounting control provisions of the FCPA or whether the scope of the investigation will be extended to other issues in Nigeria or to other countries. We also are unable to predict what potential corrective measures, fines, sanctions or other remedies, if any, the agencies may seek against us or any of our employees.

       In November 2008, our Board of Directors approved enhanced FCPA compliance recommendations issued by the Audit Committee's external legal counsel, and the Company embarked upon an enhanced compliance initiative that included appointment of a Chief Compliance Officer and a Director - Corporate Compliance. We engaged consultants to assist us in implementing the compliance recommendations approved by our Board of Directors, which include an enhanced compliance policy, increased training and testing, prescribed contractual provisions for our service providers that interface with foreign government officials, due diligence for the selection of such service providers and an increased Company-wide awareness initiative that includes periodic issuance of FCPA Alerts.

       Since ENSCO 100 completed its contract commitment and departed Nigeria in August 2007, this matter is not expected to have a material effect on or disrupt our current operations. As noted above, we are unable to predict the outcome of this matter or estimate the extent to which we may be exposed to any resulting potential liability, sanctions or significant additional expense.

   ENSCO 74 Loss

       In September 2008, ENSCO 74 was lost as a result of Hurricane Ike in the Gulf of Mexico. Portions of its legs remained underwater adjacent to the customer's platform, and we conducted extensive aerial and sonar reconnaissance but did not locate the rig hull. The rig was a total loss, as defined under the terms of our insurance policies.

       In March 2009, the sunken rig hull of ENSCO 74 was located approximately 95 miles from the original drilling location when it was struck by the oil tanker SKS Satilla. Following discovery of the sunken rig hull, we removed the accessible hydrocarbons onboard the rig and began planning for removal of the wreckage. As an interim measure, the wreckage has been appropriately marked, and the U.S. Coast Guard has issued a Notice to Mariners. We are currently communicating with various government agencies to address removal of the wreckage and related debris.

       On March 17, 2009, we received notice from legal counsel representing certain underwriters in a subrogation claim alleging that ENSCO 74 caused a pipeline to rupture during Hurricane Ike. On September 4, 2009, High Island Offshore System, LLC, commenced civil litigation against us in the U.S. District Court for the Southern District of Texas seeking damages for the cost of repairs and business interruption in excess of $26.0 million. Based on information currently available, primarily the adequacy of available defenses, we have not concluded that it is probable that a liability exists with respect to this matter.

       On March 18, 2009, SKS OBO & Tankers AS and Kristen Gehard Jebsen Skipsrederi AS, the owner and manager of the SKS Satilla, commenced civil litigation against us in the U.S. District Court for the Southern District of Texas seeking monetary damages of $10.0 million for losses incurred when the tanker struck the sunken hull of ENSCO 74. Based on information currently available, primarily the adequacy of available defenses, we have not concluded that it is probable a liability exists with respect to this matter.

       On June 9, 2009, we received notice from legal counsel representing another pipeline owner which allegedly sustained damages to a subsea pipeline caused by ENSCO 74 in the aftermath of Hurricane Ike. On September 18, 2009, Sea Robin Pipeline Company, LLC, commenced civil litigation against us in the Fifteenth Judicial Court for the Parish of Lafayette and in the Nineteenth Judicial Court for the Parish of Baton Rouge, State of Louisiana seeking unspecified damages in relation to the cost of repairing damage to the pipeline, loss of revenues, survey and other damages. Based on information currently available, we have concluded that it is remote that a liability exists with respect to this matter.

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       We filed a petition for exoneration or limitation of liability under U.S. admiralty and maritime law in the U.S. District Court for the Southern District of Texas on September 2, 2009. The petition seeks exoneration from or limitation of liability for any and all injury, loss or damage caused, occasioned or occurred in relation to the ENSCO 74 loss in September 2008. On November 2, 2009, the owners of two other subsea pipelines presented claims in the exoneration/limitation of liability proceedings. The claims were filed on behalf of Stingray Pipeline Company, LLC, and Tennessee Gas Pipeline seeking monetary damages incurred by reason of damage to pipelines allegedly caused by ENSCO 74 in the aftermath of Hurricane Ike. The Stingray claim is in the amount of $14.0 million, and the Tennessee Gas Pipeline claim is for unspecified damages. Based on information currently available, we have concluded that it is remote that liabilities exist with respect to these matters.

       We have liability insurance policies that provide coverage for third-party claims such as the tanker and pipeline claims, subject to a $10.0 million per occurrence self-insured retention and an annual aggregate limit of $500.0 million. We believe all liabilities associated with the ENSCO 74 loss during Hurricane Ike resulted from a single occurrence under the terms of the applicable insurance policies. However, legal counsel for certain liability underwriters have asserted that the liability claims arise from separate occurrences. In the event of multiple occurrences, the self-insured retention is $15.0 million for two occurrences and $1.0 million for each occurrence thereafter.

       The exoneration/limitation proceedings currently include the SKS Satilla claim and the four pipeline claims described above. The matter has been scheduled for trial in September 2011. Although we do not expect final disposition of the claims associated with the ENSCO 74 loss 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.

   ENSCO 29 Wreck Removal

       A portion of the ENSCO 29 platform drilling rig was lost over the side of a customer's platform as a result of Hurricane Katrina during 2005. Although beneficial ownership of ENSCO 29 was transferred to our insurance underwriters when the rig was determined to be a total loss, management believes we may be legally required to remove ENSCO 29 wreckage and debris from the seabed and currently estimates the removal cost to range from $5.0 million to $15.0 million. Our property insurance policies include coverage for ENSCO 29 wreckage and debris removal costs up to $3.8 million. We also have liability insurance policies that provide specified coverage for wreckage and debris removal costs in excess of the $3.8 million coverage provided under our property insurance policies.

       Our liability insurance underwriters have issued letters reserving rights and effectively denying coverage by questioning the applicability of coverage for the potential ENSCO 29 wreckage and debris removal costs. During 2007, we commenced litigation in the Texas District Court of Dallas County against certain underwriters at Lloyd's of London and other insurance companies, Bryan Johnson and BC Johnson Associates, LLC (collectively "the Underwriters") alleging breach of contract, wrongful denial, bad faith and other claims which seek a declaration that removal of wreckage and debris is covered under our liability insurance, monetary damages, attorneys' fees and other remedies. The Underwriters removed the case to the United States District Court for the Northern District of Texas, Dallas Division. The case was then remanded back to the Texas District Court by the United States District Court. The Underwriters subsequently appealed the remand to the United States Court of Appeals. The United States Court of Appeals upheld the United States District Court's order to remand the case back to the Texas District Court. The litigation is in an early stage.

       While we anticipate that any ENSCO 29 wreckage and debris removal costs incurred will be largely or fully covered by insurance, a $1.2 million provision, representing the portion of the $5.0 million low end of the range of estimated removal cost we believe is subject to liability insurance coverage, was recognized during 2006.

   Asbestos Litigation

       During 2004, we and certain current and former subsidiaries were named as defendants, along with numerous other third-party companies as co-defendants, in three multi-party lawsuits filed in the Circuit Courts of Jones County (Second Judicial District) and Jasper County (First Judicial District), Mississippi. The lawsuits sought 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 period 1965 through 1986.

       In compliance with the Mississippi Rules of Civil Procedure, the individual claimants in the original multi-party lawsuits whose claims were not dismissed were ordered to file either new or amended single plaintiff complaints naming the specific defendant(s) against whom they intended to pursue claims. As a result, out of more than 600 initial multi-party claims, we have been named as a defendant by 65 individual plaintiffs. Of these claims, 62 claims or lawsuits are pending in Mississippi state courts and three are pending in the U.S. District Court as a result of their removal from state court.

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       To date, written discovery and plaintiff depositions have taken place in eight cases involving us. While several cases have been selected for trial during 2010 and 2011, none of the cases pending against us in Mississippi state court are included within those selected cases.

       The three cases removed from state court have been assigned to the Multi-District Litigation 875, which is currently before the U.S. District Court for the Eastern District of Pennsylvania. Although the Houston law firm representing these three plaintiffs filed a Motion to Remand, seeking to bring the cases back to Mississippi state court, the U.S. District Court denied the plaintiffs' motion by order dated December 10, 2009.

       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, we have eight other asbestos or lung injury claims pending against us in litigation in various other jurisdictions. Although we do not expect the final disposition of the Mississippi and other 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.

   Other Matters

       In July and August 2009, we filed arbitration claims with the Financial Industry Regulatory Authority ("FINRA") alleging fraud, conflict of interest and breach of contract against Citigroup Global Markets, Inc. and Merrill Lynch, Pierce, Fenner & Smith, Inc. and breach of contract against Jefferies & Company, Inc. and Oppenheimer & Co., Inc. in connection with the sale of certain auction rate securities to us in the aggregate principal amount of $57.9 million. These proceedings are in an early stage and there can be no assurances as to the ultimate outcome.

       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.  Submission of Matters to a Vote of Security Holders

       On December 22, 2009, we held a Special Meeting (the "Special Meeting") of the stockholders of Ensco Delaware. As of November 16, 2009, the record date for the Special Meeting, there were 142,515,432 shares of common stock of Ensco Delaware issued, outstanding and entitled to vote at the Special Meeting. A total of 110,905,713 shares of common stock (or 78%) were represented in person or by proxy at the Special Meeting. The following proposal, a detailed description of which was included in our proxy statement related to the Special Meeting, was submitted for a stockholder vote at the Special Meeting:
 

  Adoption of the Agreement and Plan of Merger and Reorganization by and between Ensco Delaware and ENSCO Newcastle LLC, a newly-formed Delaware limited liability company ("Ensco Mergeco") and a wholly-owned subsidiary of ENSCO Global Limited, a newly-formed Cayman Islands exempted company ("Ensco Cayman") and a wholly-owned subsidiary of Ensco Delaware, pursuant to which Ensco Mergeco merged with and into Ensco Delaware, with Ensco Delaware surviving the merger as a wholly-owned subsidiary of Ensco Cayman, which became a wholly-owned subsidiary of Ensco International plc, an English public limited company.


The results of the stockholder vote were as follows:

Votes For Votes Against Votes Abstaining Broker
Non-Votes
 
109,027,297        1,638,164           240,252           --                   


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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 shares of common stock, U.S. $.10 par value, until December 22, 2009 and of our ADSs thereafter for each period indicated during the last two fiscal years:

 
     First
Quarter
 Second
Quarter
  Third
Quarter
 Fourth
Quarter
 
Year
 
2009 High    $32.37    $42.47    $43.14    $51.30  $51.30 
2009 Low    $22.04    $25.05    $32.26    $39.73  $22.04 
 
2008 High     $65.23     $83.24     $81.12     $57.85   $83.24  
2008 Low    $45.94    $59.81    $52.50    $22.38  $22.38 
 

Dividends

       Our ADSs (Symbol: ESV) are traded on the NYSE. We had 1,061 holders of record of our ADSs on February 1, 2010.

       We began paying a $.025 per share quarterly cash dividend during the third quarter of 1997 and have continued to pay this quarterly dividend through December 31, 2009. Cash dividends totaling $.10 per share were paid during 2009 and 2008. We currently intend to continue paying quarterly dividends for the foreseeable future. However, our Board of Directors may change the timing, amount and 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 the Company's operations.

U.K. Taxation

       The following paragraphs are intended to be a general guide to current U.K. tax law and 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 Ensco International plc and stamp duty and SDRT on the transfer of Class A ordinary shares, uncertificated ADSs and ADSs evidenced by American depositary receipts ("ADRs"). In addition, the following paragraphs relate only to persons who are beneficial owners of the ADSs ("ADS holders").

       These paragraphs may not relate to certain classes of holders of the ADSs, such as employees or directors of Ensco International plc or its affiliates, persons who are connected with Ensco International plc, insurance companies, charities, collective investment schemes, pension schemes or persons who hold ADSs 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 ADS holders may benefit from an exemption or relief from taxation. It is recommended that all ADS holders obtain their own taxation advice. In particular, non-U.K. resident or domiciled ADS holders 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.

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    U.K. Taxation of Dividends

       U.K. Withholding Tax - Dividends paid by Ensco International plc 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 ADS holders.

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

       The rate of U.K. income tax which is payable with respect to dividends received by higher rate taxpayers in the tax year 2009/2010 is 32.5%. Individual ADS holders 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 Ensco International plc, which will be taken into account in computing the gross amount of the dividend which is subject to income tax. The tax credit will be credited against the ADS holder's liability (if any) to income tax on the gross amount of the dividend. An individual ADS holder who is not subject to U.K. income tax on dividends received from Ensco International plc will not be entitled to claim payment of the tax credit in respect of such dividends. The right of an individual ADS holder who is not resident in the U.K. to a tax credit will depend on his or her individual circumstances. 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 new rate of 42.5% in the tax year 2010/2011. An individual's dividend income is treated as the top slice of their total income which is subject to income tax.

       U.K. Corporation Tax - Unless an exemption is available as discussed below, a corporate ADS holder that is resident in the U.K. will be subject to U.K. corporation tax on dividends received from Ensco International plc. A corporate ADS holder that is not resident in the U.K. will not be subject to U.K. corporation tax on dividends received from Ensco International plc unless the ADS holder carries on a trade in the U.K. through a permanent establishment in the U.K. and the dividends form part of the profits of a trade carried on through or from the permanent establishment or if the ADSs are used by, for or held by or for, the permanent establishment. In these circumstances, the non-U.K. resident corporate ADS holder may, depending on its individual circumstances and if the exemption discussed below is not available, be subject to U.K. corporation tax on dividends received from Ensco International plc.

       The full rate of corporation tax payable with respect to dividends received from Ensco International plc in financial years 2009 and 2010 is 28%, although smaller companies may be entitled to claim the small companies rate of tax. If dividends paid by Ensco International plc fall within an exemption 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 ADS holder will be exempt from U.K. corporation tax. Generally, the conditions for exemption from U.K. corporation tax on dividends paid by Ensco International plc should be satisfied, although the conditions which must be satisfied in any particular case will depend on the individual circumstances of the corporate ADS holders.


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       ADS holders that are regarded as small companies should generally be exempt from U.K. corporation tax on dividends received from Ensco International plc, unless the dividends are made as part of a tax advantage scheme. ADS holders that are not regarded as small companies should generally be exempt from U.K. corporation tax on dividends received from Ensco International plc on the basis that the Class A ordinary shares underlying the ADSs should be regarded as non-redeemable ordinary shares. Alternatively, ADS holders that are not small companies should also generally be exempt from U.K. corporation tax on dividends received from Ensco International plc if they hold ADSs which represent less than 10% of the issued share capital of Ensco International plc, would be entitled to less than 10% of the profits available for distribution to holders of the issued share capital of Ensco International plc and would be entitled on a winding up to less than 10% of the assets of Ensco International plc available for distribution to holders of its issued share capital. In certain limited circumstances, the exemption from U.K. corporation tax will not apply to such ADS holders if a dividend is made as part of a scheme which 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 ADS holders on the disposal of ADSs 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 ADS holders.

       A disposal of ADSs by an individual ADS holder who is resident or ordinarily resident in the U.K. may, depending on his or her individual circumstances, give rise to a taxable gain or an allowable loss for the purposes of U.K. capital gains tax. An individual ADS holder 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 ADSs during that period of temporary non-residence may be liable to U.K. capital gains tax on a taxable gain accruing on the disposal on his or her return to the U.K. under certain anti-avoidance rules.

       An individual ADS holder who is neither resident nor ordinarily resident in the U.K. will not be subject to U.K. capital gains tax on capital gains arising on the disposal of their ADSs unless the ADS holder carries on a trade, profession or vocation in the U.K. through a branch or agency in the U.K. and the ADSs 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 ADS holder through the branch or agency. In these circumstances, the non-U.K. resident ADS holder may, depending on his or her individual circumstances, be subject to U.K. capital gains tax on taxable gains arising from a disposal of their ADSs. The rate of U.K. capital gains tax on taxable gains is 18% in the tax year 2009/2010.

       U.K. Corporation Tax - A disposal of ADSs by a corporate ADS holder which is resident in the U.K. may give rise to a taxable gain or an allowable loss for the purposes of U.K. corporation tax. A corporate ADS holder that is not resident in the U.K. will not be liable for U.K. corporation tax on taxable gains accruing on the disposal of its ADSs unless it carries on a trade in the U.K. through a permanent establishment in the U.K. and the ADSs 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 ADS holder through the permanent establishment. In these circumstances, the non-U.K. resident ADS holder may, depending on its individual circumstances, be subject to U.K. corporation tax on taxable gains arising from a disposal of its ADSs.

       The full rate of U.K. corporation tax on taxable gains in financial years 2009 and 2010 is 28%, although small companies may be entitled to claim the small companies rate of tax. Corporate ADS holders will be entitled to an indexation allowance in computing the amount of a taxable gain accruing on a disposal of the ADSs, 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 substantial shareholding exemption set out in s.192A and Schedule 7AC of the U.K. Taxation of Chargeable Gains Act 1992 are satisfied in relation to a taxable gain accruing to a corporate ADS holder, the taxable gain will be exempt from U.K. corporation tax.

       The conditions of the substantial shareholding exemption which must be satisfied will depend on the individual circumstances of the corporate ADS holder. One of the conditions of the substantial shareholding exemption which must be satisfied is that the corporate ADS holder must have held a substantial shareholding in Ensco International plc throughout a twelve-month period beginning not more than two years before the day on which the disposal takes place. Ordinarily, a corporate ADS holder will not be regarded as holding a substantial shareholding in Ensco International plc unless it (whether alone, or together with other group companies) directly holds not less than 10% of Ensco International plc ordinary share capital (not represented by ADRs).


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    U.K. Stamp Duty and Stamp Duty Reserve Tax

       The discussion below relates to holders of Class A ordinary shares or ADSs wherever resident (but not to holders such as market makers, brokers, dealers and intermediaries, to whom special rules apply).

       Transfer of Class A Ordinary Shares and Uncertified ADSs - Provided that any instrument of transfer is not executed in the U.K. and remains at all times outside the U.K. and the transfer does not relate to any matter or thing done or to be done in the U.K., no U.K. stamp duty is payable on the acquisition or transfer of (i) Class A ordinary shares not represented by ADSs and (ii) uncertificated ADSs (i.e., not evidenced by ADRs) held in a direct registration system.

       ADSs held in book-entry form on the facilities of The Depository Trust Company are not considered to be in a direct registration system. However, an unconditional agreement for such transfer, or a conditional agreement which subsequently becomes unconditional, will be liable to U.K. SDRT generally at the rate of 0.5% of the consideration for the transfer; but such liability will be cancelled if the agreement is completed by a duty stamped instrument of transfer within six years of the date of the agreement, or if the agreement was conditional, the date the agreement became unconditional. Where U.K. stamp duty is paid, any SDRT previously paid will be repaid on the making of an appropriate claim. U.K. Stamp duty and SDRT are normally paid by the purchaser.

       Transfer of ADSs Evidenced by ADRs - No U.K. stamp duty need, in practice, be paid on the acquisition or transfer of ADSs evidenced by ADRs provided that any instrument of transfer or contract for sale is not executed in the U.K. and remains at all times outside the U.K. and the transfer does not relate to any matter or thing done or to be done in the U.K. An agreement for the transfer of ADSs evidenced by ADRs will not give rise to a SDRT liability.

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."

Issuer Purchases of Equity Securities

       The following table provides a summary of repurchases of our shares during the quarter ended December 31, 2009:
 

      Total Number Approximate
      of Shares Dollar Value
      Purchased as of Shares that
  Total   Part of Publicly May Yet Be
  Number of   Announced Purchased
  Shares Average Price Plans or Under Plans
          Period Purchased Paid per Share Programs or Programs
 
October 1 - October 31       690             $39.03     --         $562,000,000  
November 1 - November 30    3,045          $46.38    --        $562,000,000  
December 1 - December 31    1,393          $41.90    --        $562,000,000  

Total    5,128          $44.17    --           


       During the quarter ended December 31, 2009, repurchases of our shares were from employees in connection with the settlement of income tax withholding obligations arising from the vesting of share awards.

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       The Board of Directors of Ensco Delaware previously authorized the repurchase of up to $1,500.0 million of our shares. From inception of our share repurchase programs during 2006 through December 31, 2008, we repurchased an aggregate 16.5 million shares at a cost of $937.6 million (an average cost of $56.79 per share). No shares were repurchased under the share repurchase programs during 2009. In December 2009, the then-Board of Directors of Ensco International Limited, a predecessor of Ensco International plc, continued the prior authorization and, subject to shareholder approval, authorized management to repurchase up to $562.4 million of ADSs from time to time pursuant to share repurchase agreements with two investment banks. The then-sole shareholder of Ensco International Limited approved such share repurchase agreements for a five-year term. Although such amount remained available for repurchase as of December 31, 2009, the Company will not repurchase any shares without further consultation with and approval by the Board of Directors of Ensco International plc.

       The chart below presents a comparison of the five-year cumulative total return, assuming $100 invested on December 31, 2004 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.*

                  Cumulative Total Return                 
    12/04    12/05    12/06    12/07    12/08    12/09   
 
Ensco International plc   100.00   140.08   158.45   189.06   90.22   127.30  
S & P 500   100.00   104.91   121.48   128.16   80.74   102.11  
Dow Jones U.S. Oil Equipment & Services   100.00   151.75   172.19   249.58   101.59   167.77  

                            

* $100 invested on December 31, 2004 in shares or index, including reinvestment of dividends for
    fiscal year ending December 31.

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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 included in "Item 8. Financial Statements and Supplementary Data."

                         Year Ended December 31,                          
   2009         2008        2007        2006         2005    
  (in millions, except per share amounts)
Consolidated Statement of Income Data                      
Revenues $ 1,945.9 $ 2,393.6 $ 2,058.2 $ 1,748.7   $991.1  
Operating expenses                      
   Contract drilling (exclusive of depreciation)   725.5   752.0   644.1   543.5   434.9  
   Depreciation  205.9   186.5   177.5   168.5   147.5  
   General and administrative  64.0   53.8   59.5   44.6   32.0  

Operating income  950.5   1,401.3   1,177.1   992.1   376.7  
Other income (expense), net  8.8   (4.2 ) 37.8   (5.9 ) (24.0 )
Provision for income taxes  178.4   237.3   244.8   241.3   94.8  

Income from continuing operations  780.9   1,159.8   970.1   744.9   257.9  
Income (loss) from discontinued operations, net(1)  3.6   (3.1 ) 28.8   30.3   27.5  
Cumulative effect of accounting change, net(2)  --   --   --   .6   --  

Net income   784.5   1,156.7   998.9   775.8   285.4  
Net income attributable to noncontrolling interests      (5.1 ) (5.9 ) (6.9 ) (6.1 ) (.5 )

Net income attributable to Ensco $ 779.4 $ 1,150.8 $ 992.0 $ 769.7   $284.9  

Earnings (loss) per share - basic                     
   Continuing operations     $ 5.45 $ 8.06 $ 6.52 $ 4.83   $  1.69  
   Discontinued operations   .03   (.02 ) .19   .20   .18  
   Cumulative effect of accounting change  --   --   --   .00   --  

      $ 5.48 $ 8.04 $ 6.71 $ 5.03   $  1.87  

Earnings (loss) per share - diluted                     
   Continuing operations $ 5.45 $ 8.04 $ 6.50 $ 4.81   $  1.68  
   Discontinued operations   .03   (.02 ) .19   .20   .18  
   Cumulative effect of accounting change  --   --   --   .00   --  

  $ 5.48 $ 8.02 $ 6.69 $ 5.01   $  1.86  

Net income attributable to Ensco shares  
   Basic $ 769.7 $ 1,138.2 $ 984.7 $ 765.4   $283.9  
   Diluted $ 769.7 $ 1,138.2 $ 984.7 $ 765.4   $283.9  
Weighted-average shares outstanding  
   Basic  140.4   141.6   146.7   152.2   151.7  
   Diluted  140.5   141.9   147.2   152.8   152.3  
Cash dividends per share $ .10 $ .10 $ .10 $ .10   $    .10  


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Consolidated Balance Sheet and
   Cash Flow Statement Data
   Working capital   $1,167.9   $   973.0   $   625.8   $   602.3   $   347.0  
   Total assets   6,747.2   5,830.1   4,968.8   4,334.4   3,617.9  
   Long-term debt, net of current portion  257.2   274.3   291.4   308.5   475.4  
   Ensco shareholders' equity  5,499.2   4,676.9   3,752.0   3,216.0   2,540.0  
   Cash flow from continuing operations  1,221.7   1,125.4   1,211.2   922.9   336.7  

 
(1)   See Note 11 to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" for information on discontinued operations.
(2)   On January 1, 2006, we recognized a cumulative adjustment related to the adoption of certain provisions of FASB ASC 718 (previously SFAS No. 123(R) (revised 2004) "Share-Based Payment").




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

INTRODUCTION

Our Business

       We are a leading provider of offshore contract drilling services to the oil and gas industry. We own and operate a fleet of 47 drilling rigs, including 42 jackup rigs, four ultra-deepwater semisubmersible rigs and one barge rig. We are concentrated in premium jackup rigs, but are currently in the process of developing a fleet of ultra-deepwater semisubmersible rigs, capable of drilling at depths of 8,500 feet or greater. Our 47 drilling rigs are located throughout the world and concentrated in the major geographic regions of Asia Pacific (which includes Asia, the Middle East and Australia), Europe and Africa, and North and South America.

       We provide our drilling services to major international, government-owned and independent oil and gas companies 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. Drilling contracts are, for the most part, awarded on a competitive bid basis. We do not provide "turnkey" or other risk-based drilling services.

       During 2008, our revenues, operating income and net income reached record levels as a result of strong rig demand, high utilization and increased day rates in all geographic regions. The decline in oil and natural gas prices from their record highs reached during 2008 and the deterioration of the global economy resulted in significantly reduced levels of jackup rig demand during 2009. Accordingly, our jackup rig operating results declined substantially from record-high levels generated during 2008 due to a decline in utilization of our jackup rigs in all geographic regions.

       Operating results in our Deepwater segment improved during 2009. ENSCO 7500 operated in Australia at a day rate of approximately $550,000 for the majority of the year. ENSCO 8500 and ENSCO 8501 commenced operations in the Gulf of Mexico in June and October 2009, respectively. Additionally, ENSCO 8502 was delivered in January 2010 and is expected to commence operations in the Gulf of Mexico under a two-year drilling contract during the third quarter of 2010.


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       We also continued construction of ENSCO 8503, ENSCO 8504, ENSCO 8505 and ENSCO 8506. These rigs are scheduled for delivery during the fourth quarter of 2010, the second half of 2011 and the first and second half of 2012, respectively. We have funded our ultra-deepwater semisubmersible fleet expansion initiative with cash flows generated from continuing operations. We believe our strong balance sheet, including $1,141.4 million of cash and cash equivalents as of December 31, 2009, and over $2,900.0 million of contract backlog will enable us to sustain an adequate level of liquidity during 2010 and beyond.

Redomestication

       On December 23, 2009, we completed a reorganization of the corporate structure of the group of companies controlled by our predecessor, Ensco Delaware, pursuant to which an indirect, wholly-owned subsidiary merged with Ensco Delaware, and Ensco International plc became our publicly-held parent company. We are now incorporated under English law as a public limited company.

       The redomestication changed Ensco's corporate structure, which included a change of our place of incorporation from Delaware to the U.K. and the relocation of our principal executive offices to London, England. The redomestication, among other things, established a corporate headquarters in the U.K. where we already have substantial operations and which is more centrally located within our area of worldwide operations. The U.K. has a stable and developed legal regime with established standards of corporate governance, including provisions addressing the rights of shareholders, and a favorable tax regime that should improve our ability to maintain a competitive worldwide effective income tax rate, among other anticipated benefits. We expect that the reorganization will also result in operational and administrative efficiencies over the long-term and enhance our ability to expand in the U.K., Europe and beyond.

       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 SEC reporting requirements, the mandates of the Sarbanes-Oxley Act and the applicable corporate governance rules of the NYSE, and we will continue to report our consolidated financial results in U.S. dollars and in accordance with GAAP. We also must comply with additional reporting requirements of English law.


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Our Industry

       Historically, operating results in the offshore contract drilling industry have been cyclical and directly related to the demand for drilling rigs and the available supply of drilling rigs.

   Drilling Rig Demand

       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. 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 OPEC and other oil and natural gas producers,
  technological advancements that impact the methods or cost of oil and natural gas exploration and development,
  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.


       The significant decline in oil and natural gas prices during the latter half of 2008 and the general deterioration in the global economy led to an abrupt reduction in demand for jackup rigs during 2009. Although oil prices gradually improved throughout 2009, incremental drilling activity was limited. Day rates softened as contractors attempted to lock-in drilling programs and maintain their existing contract backlog amid growing concerns over oil and natural gas prices and pressure from operators to reduce day rates. While we are encouraged by the number of recent rig inquiries in certain markets, it remains unclear whether they will result in incremental jackup rig demand.


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       Demand for ultra-deepwater semisubmersible rigs remained stable during 2009 despite the decline in oil and natural gas prices from record highs and global economic concerns. Deepwater projects are typically more expensive and longer in duration than shallow-water jackup projects. Accordingly, deepwater operators tend to adopt a longer-term view of commodity prices and the global economy.

       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 of high demand for drilling rigs, various industry participants ordered the construction of over 175 new jackup and semisubmersible rigs, over 80 of which were delivered during the last three years.

       Jackup rig supply continues to increase as a result of newbuild construction programs which were initiated prior to the 2008 decline in oil and natural gas prices and global economic crisis. It has been reported that 58 newbuild jackup rigs are currently under construction, half of which are scheduled for delivery during 2010. The majority of jackup rigs scheduled for delivery are not contracted.

       Newbuild jackup rigs will likely reduce utilization and day rates as rigs are absorbed into the fleet, especially in light of current levels of jackup rig demand. We expect the Asia Pacific region to be impacted most by the delivery of newbuild jackup rigs, as a significant portion of rig construction is occurring in the Asia Pacific region. It is time consuming and expensive to move drilling rigs between markets in response to changes in supply and demand and, accordingly, the supply of rigs in the Asia Pacific region, or other regions where newbuild rigs are delivered, may not adjust quickly and could lead to sudden changes in utilization and day rates. It is unclear whether, or to what extent, other markets will be adversely affected by newbuild rigs.

       Semisubmersible rig supply also continues to increase as a result of newbuild construction programs. It has been reported that 37 newbuild semisubmersible rigs are currently under construction, over half of which are scheduled for delivery during 2010. The majority of semisubmersible rigs scheduled for delivery are contracted. Based on the current level of demand for semisubmersible rigs, especially ultra-deepwater semisubmersible rigs, we anticipate that newbuild semisubmersible rigs will be absorbed into the market without a significant effect on utilization and day rates.

       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 jackup or semisubmersible rigs in a particular market and cause fluctuations in utilization and day rates.


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BUSINESS ENVIRONMENT

Deepwater

       Demand for ultra-deepwater semisubmersible rigs on a worldwide basis exceeded supply resulting in high utilization levels and day rates during 2007 and 2008. Although lower oil and natural gas prices resulted in a modest decline in demand for ultra-deepwater semisubmersible rigs during 2009, utilization and day rates were generally stable.

       The deepwater market is becoming increasingly bifurcated between the high-specification, ultra-deepwater rig market and the market for other deepwater rigs. We anticipate continued high utilization of the worldwide ultra-deepwater semisubmersible rig fleet for the foreseeable future. We expect operators to continue to upgrade their fleets to ultra-deepwater semisubmersible rigs during periods of moderating day rates and as new discoveries occur at deeper water depths. Future ultra-deepwater semisubmersible rig day rates will depend in large part on projected oil and natural gas prices and the global economy.

       In addition to ENSCO 8500, which commenced a four-year drilling contract in June 2009, ENSCO 8501, which commenced a three-and-a-half-year drilling contract in October 2009, and ENSCO 8502, which was delivered in January 2010 and is expect to commence drilling under a two-year contract during the third quarter of 2010, we have four ENSCO 8500 Series® rigs under construction with scheduled delivery dates during the fourth quarter of 2010, the second half of 2011 and the first and second half of 2012. ENSCO 8503 has secured a long-term drilling contract in the Gulf of Mexico. The remaining ENSCO 8500 Series® rigs under construction are without contracts. Our ENSCO 7500 ultra-deepwater semisubmersible rig is currently operating under contract in Australia.

Asia Pacific

       During 2007, demand for Asia Pacific jackup rigs exceeded the supply of available rigs resulting in high utilization levels and increasing day rates. During the first half of 2008, Asia Pacific jackup rig utilization remained high and day rates stabilized as strong rig demand was offset by new rig deliveries. During the latter half of 2008, jackup rig demand was significantly impacted by the decline in oil and natural gas prices and global economic crisis, resulting in a significant reduction in utilization and day rates during 2009. With limited contract opportunities currently available and an expected increase in the supply of available jackup rigs from newbuild deliveries and expiring drilling contracts, we anticipate that Asia Pacific jackup rig utilization and day rates will remain under pressure in the near-term.

Europe and Africa

       Our Europe and Africa offshore drilling operations are mainly conducted in northern Europe. During 2007, a strong backlog of firm commitments and contract extension options in northern Europe resulted in little or no jackup rig availability. This supply and demand imbalance resulted in near full utilization and a substantial increase in day rates. During 2008, shortfalls in rig availability in this region led to sustained high utilization levels and day rates. Although utilization and day rates remained high during early 2009, the decline in oil and natural gas prices during the latter half of 2008 resulted in several cancelled tenders and unexercised contract extension options. Tender activity in the region during 2009 was minimal, and we expect this trend to continue in the near-term. We anticipate this market will experience excess rig availability and utilization and day rates will remain under pressure as a significant portion of the North Sea jackup fleet is scheduled to roll-off existing contracts in the coming months.

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North and South America

       The majority of our North and South America offshore drilling operations are conducted in Mexico, where demand for rigs increased during 2007 and 2008 as Petróleos Mexicanos ("PEMEX"), the national oil company of Mexico, accelerated drilling activities in an attempt to offset continued depletion of its major oil and natural gas fields. During 2009, demand for jackup rigs in Mexico remained high despite global economic conditions. A significant number of PEMEX jackup rig contracts expire during 2010, and PEMEX may extend these contracts and/or tender for incremental rigs. We expect future day rates in Mexico to face pressure as drilling contractors with idle rigs in other geographic regions pursue the available contract opportunities.

       We also conduct a portion of our North and South America jackup operations in the Gulf of Mexico. During 2007, oil and gas companies continued to shift their focus to more economically attractive prospects in the deeper waters of the Gulf of Mexico and elsewhere resulting in a decline in utilization and day rates. During 2008, damage caused by Hurricanes Gustav and Ike reduced the supply of available jackup rigs, however, the reduction was more than offset by a decrease in demand resulting from the decline in oil and natural gas prices and global economic crisis. The region's jackup market remained extremely weak during 2009 with drilling activity reaching historic lows during later portions of the year. Although it is likely that drilling activity in this region will increase during 2010, we do not expect meaningful improvement in day rates in the near-term.

RESULTS OF OPERATIONS

       The following table summarizes our consolidated operating results for each of the years in the three-year period ended December 31, 2009 (in millions):
 

         2009         2008   2007   
 
Revenues     $1,945.9   $2,393.6   $2,058.2  
Operating expenses  
     Contract drilling (exclusive of depreciation)    725.5    752.0    644.1  
     Depreciation       205.9     186.5     177.5  
     General and administrative    64.0    53.8    59.5  

Operating income    950.5    1,401.3    1,177.1  
Other income (expense), net    8.8    (4.2 )  37.8  
Provision for income taxes     178.4     237.3     244.8  

Income from continuing operations    780.9    1,159.8    970.1  
Income (loss) from discontinued operations, net    3.6    (3.1 )  28.8  

Net income    784.5    1,156.7    998.9  
Net income attributable to noncontrolling interests    (5.1 )  (5.9 )  (6.9 )

Net income attributable to Ensco   $779.4   $1,150.8   $992.0  


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       During 2009, revenues declined by $447.7 million, or 19%, and operating income declined by $450.8 million, or 32%, as compared to the prior year. The revenue and operating income declines were primarily due to a decline in jackup rig utilization in all geographic regions, partially offset by the commencement of ENSCO 8500 and ENSCO 8501 drilling operations and an increase in average day rates earned by our jackup rigs contracted in Mexico and ENSCO 7500.

       During 2008, revenues increased by $335.4 million, or 16%, and operating income increased by $224.2 million, or 19%, as compared to the prior year. The increases were primarily due to improved average day rates earned by our Asia Pacific and Europe and Africa jackup rigs and ENSCO 7500 and improved utilization of our Gulf of Mexico jackup rigs. The increase in operating income was partially offset by increased personnel costs and repair and maintenance expense across the majority of our fleet.

       A significant number of our drilling contracts are of a long-term nature. Accordingly, the effects of a decline in demand for contract drilling services on our operating results and cash flows typically occurs gradually over several quarters as long-term contracts expire. The significant decline in oil and natural gas prices and the deterioration of the global economy resulted in a dramatic decline in demand for contract drilling services during the later portions of 2008 and 2009, which will negatively impact our operating results and cash flows during 2010. While we have contract backlog of over $1,300.0 million for 2010, it is unlikely that revenue, operating income and cash flow levels achieved during 2009 will be sustained during 2010.

Rig Locations, Utilization and Average Day Rates

       As discussed below, we manage our business through four operating segments. However, our rigs are mobile and our jackup rigs occasionally move between our geographic region segments. The following table summarizes our offshore drilling rigs by segment as of December 31, 2009, 2008 and 2007:

 
  2009 2008     2007
               
Deepwater(1)  3   2   1  
Asia Pacific   20   20   20
Europe and Africa  10   10   10  
North and South America   13   13   13  
Under construction(1)(2)   5   6   4  

Total(3)   51   51   48  

 
   (1)   In June 2009, we accepted delivery of ENSCO 8501, which commenced drilling operations in the Gulf of Mexico under a three-and-a-half year contract in October 2009. In September 2008, we accepted delivery of ENSCO 8500, which commenced drilling operations in the Gulf of Mexico under a four-year contract in June 2009.
   (2)   During 2008, we entered into agreements to construct ENSCO 8504, ENSCO 8505 and ENSCO 8506 with deliveries expected during the second half of 2011 and the first and second half of 2012, respectively.
   (3)   The total number of rigs for each period excludes rigs reclassified as discontinued operations.


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       The following table summarizes our rig utilization and average day rates from continuing operations by operating segment for each of the years in the three-year period ended December 31, 2009:

 
  2009 2008     2007
               
Rig utilization(1)  
Deepwater  85%   95%   97%  
Asia Pacific(3)   70%   95%   99%  
Europe and Africa  77%   96%   93%  
North and South America  67%   97%   77%  

Total   72%   96%   91%  

 
Average day rates(2)  
Deepwater  $425,190   $334,688   $199,432
Asia Pacific(3)   143,315   152,981   131,384
Europe and Africa   198,595   221,164   198,551
North and South America   119,951   98,166   107,147

Total   $162,300   $155,441   $142,704

 
(1)   Rig utilization is derived by dividing the number of days under contract, including days associated with compensated mobilizations, by the number of days in the period.
(2)   Average day rates are derived by dividing contract drilling revenues, adjusted to exclude certain types of non-recurring reimbursable revenues and lump sum revenues, by the aggregate number of contract days, adjusted to exclude contract days associated with certain mobilizations, demobilizations, shipyard contracts and standby contracts.
(3)   Rig utilization and average day rates for the Asia Pacific operating segment include our jackup rigs only. The ENSCO I barge rig has been excluded.


       Detailed explanations of our operating results, including discussions of revenues, contract drilling expense and depreciation expense by operating segment, are provided below.

   Operating Income

       We are in the process of developing a fleet of ultra-deepwater semisubmersible rigs and established a separate business unit to manage our deepwater operations during 2008. Our jackup rigs and barge rig are managed by major geographic region. Accordingly, our business consists of four operating segments: (1) Deepwater, (2) Asia Pacific, (3) Europe and Africa and (4) North and South America. Each of our four operating segments provides one service, contract drilling.

       The following tables summarize our operating income for each of the years in the three-year period ended December 31, 2009. 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."

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Year Ended December 31, 2009
(in millions)

        North      
      Europe and Operating    
    Asia and South Segments Reconciling   Consolidated
  Deepwater Pacific  Africa  America     Total         Items          Total    
               
Revenues     $   254.1     $   724.0     $569.1      $398.7     $1,945.9     $          --        $1,945.9    
Operating expenses
   Contract drilling (exclusive
      of depreciation)
    108.1     249.0     208.8      159.6     725.5     --        725.5    
   Depreciation     22.2     88.0     44.5      49.9     204.6     1.3        205.9    
   General and administrative     --     --     --      --     --     64.0        64.0    

Operating income     $   123.8     $   387.0     $315.8      $189.2     $1,015.8     $    (65.3)       $   950.5    

 

Year Ended December 31, 2008
(in millions)

        North      
      Europe and Operating    
    Asia and South Segments Reconciling   Consolidated
  Deepwater Pacific  Africa  America     Total         Items          Total    
               
Revenues     $     84.4     $1,052.9     $804.1      $452.2     $2,393.6     $         --         $2,393.6    
Operating expenses
   Contract drilling (exclusive
      of depreciation)
    31.2     316.0     246.7      158.1     752.0     --         752.0    
   Depreciation     9.1     85.2     43.0      47.3     184.6     1.9         186.5    
   General and administrative     --     --     --      --     --     53.8         53.8    

Operating income     $     44.1     $   651.7     $514.4      $246.8     $1,457.0     $   (55.7)        $1,401.3    

 

Year Ended December 31, 2007
(in millions)

        North      
      Europe and Operating    
    Asia and South Segments Reconciling   Consolidated
  Deepwater Pacific  Africa  America     Total         Items          Total    
               
Revenues     $  72.8     $   912.7     $670.8      $401.9     $2,058.2     $         --         $2,058.2    
Operating expenses
   Contract drilling (exclusive
      of depreciation)
    28.8     265.0     208.4      141.9     644.1     --         644.1    
   Depreciation     9.3     81.1     40.4      42.6     173.4     4.1         177.5    
   General and administrative     --     --     --      --     --     59.5         59.5    

Operating income     $  34.7     $   566.6     $422.0      $217.4     $1,240.7     $    (63.6)        $1,177.1    


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   Deepwater

       During 2009, Deepwater revenues increased by $169.7 million as compared to the prior year. The increase in revenues was due to the commencement of ENSCO 8500 and ENSCO 8501 drilling operations, an increase in the day rate earned by ENSCO 7500 and the recognition of ENSCO 7500 mobilization revenues deferred during the rig's mobilization to Australia. In October 2008, we amended the existing ENSCO 7500 drilling contract and agreed to relocate the rig to Australia where we commenced drilling operations in April 2009 at a day rate of approximately $550,000. Revenues earned during the mobilization period were deferred and are being recognized ratably over the firm commitment period of the contract. The aforementioned revenue increases were partially offset by the deferral of ENSCO 7500 revenues during the rig's mobilization to Australia during the first quarter of 2009. Contract drilling expense increased by $76.9 million as compared to the prior year due to the commencement of ENSCO 8500 and ENSCO 8501 drilling operations, ENSCO 7500 mobilization expense and incremental expenses associated with operating ENSCO 7500 in Australia as compared to the Gulf of Mexico. Depreciation expense increased by $13.1 million primarily due to ENSCO 8500 and ENSCO 8501 as noted above.

       During 2008, Deepwater revenues increased by $11.6 million, or 16%, as compared to the prior year. The increase in revenues was primarily due to a 68% increase in the ENSCO 7500 average day rate, partially offset by the deferral of ENSCO 7500 revenues during the fourth quarter of 2008 when the rig commenced mobilization to Australia as noted above. Contract drilling expense increased by $2.4 million, or 8%, as compared to the prior year, primarily due to increased personnel costs and repair and maintenance expense, partially offset by the deferral of costs during the ENSCO 7500 mobilization. The increase in personnel costs was due to the staffing of an office in Houston, Texas during 2008 to support our newly-established Deepwater business unit and increased ENSCO 7500 staffing levels to facilitate training in preparation for delivery of our ENSCO 8500 Series® rigs.

   Asia Pacific

       During 2009, Asia Pacific revenues declined by $328.9 million, or 31%, as compared to the prior year. The decline in revenues was primarily due to a decline in utilization to 70% from 95% during the prior year. The decline in utilization occurred due to lower levels of spending by oil and gas companies, coupled with excess rig availability in the region. Contract drilling expense declined by $67.0 million, or 21%, as compared to the prior year, primarily due to the impact of lower utilization and a decline in repair and maintenance expense. Depreciation expense increased by 3% as compared to the prior year, primarily due to the ENSCO 53 capital enhancement project completed during the second quarter of 2009 and depreciation on minor upgrades and improvements to our Asia Pacific fleet completed during 2008 and 2009.

       During 2008, Asia Pacific revenues increased by $140.2 million, or 15%, as compared to the prior year. The increase in revenues was primarily due to a 16% increase in jackup rig average day rates and the increased size of our Asia Pacific fleet, partially offset by a decline in jackup rig utilization to 95% from 99% during the prior year. The increase in average day rates resulted from stronger demand due to higher levels of spending by oil and gas companies coupled with limited rig availability in the region. The addition of ENSCO 108 to the fleet during the first quarter of 2007 resulted in an additional $28.1 million of revenues and $4.8 million of contract drilling expense during 2008 as compared to the prior year. The decline in utilization was the result of scheduled maintenance projects on ENSCO 53, ENSCO 54, ENSCO 56, ENSCO 57 and ENSCO 96. Contract drilling expense increased by $51.0 million, or 19%, as compared to the prior year, primarily due to increased personnel costs and increased repair and maintenance expense associated with the aforementioned maintenance projects and, to a lesser extent, the addition of ENSCO 108 to the fleet. Depreciation expense increased by 5% as compared to the prior year. The increase was primarily attributable to depreciation associated with ENSCO 108, depreciation associated with ENSCO 96 and ENSCO 104 capital enhancement projects completed during the fourth quarter of 2007 and depreciation on minor upgrades and improvements to our Asia Pacific fleet completed during 2007 and 2008.

   Europe and Africa

       During 2009, Europe and Africa revenues declined by $235.0 million, or 29%, as compared to the prior year. The decline in revenues was primarily due to a decline in utilization to 77% from 96% during the prior year. The decline in utilization occurred due to lower levels of spending by oil and gas companies. Contract drilling expense declined by $37.9 million, or 15%, as compared to the prior year, due to a decline in mobilization expense and the impact of lower utilization. Depreciation expense increased by 3% as compared to the prior year due to depreciation on minor upgrades and improvements to our Europe and Africa fleet completed during 2008 and 2009.

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       During 2008, Europe and Africa revenues increased by $133.3 million, or 20%, as compared to the prior year. The increase in revenues was primarily attributable to an 11% increase in average day rates, an increase in utilization to 96% from 93% during the prior year and the relocation of ENSCO 105 to the region. The increase in average day rates was attributable to limited rig availability in the region coupled with improved demand resulting from increased spending by oil and gas companies. The increase in utilization was primarily due to the mobilization of ENSCO 100 from Nigeria to the North Sea during 2007. The relocation of ENSCO 105 to the Europe and Africa region during the second quarter of 2007 contributed an additional $30.5 million of revenues and $9.0 million of contract drilling expense as compared to the prior year. Contract drilling expense increased by $38.3 million, or 18%, as compared to the prior year, primarily due to increased mobilization and repair and maintenance expense, the addition of ENSCO 105 to the fleet and increased personnel costs, partially offset by a reduction in reimbursable expense. Depreciation expense increased by 6% as compared to the prior year. The increase was primarily attributable to depreciation associated with the ENSCO 85 capital enhancement project completed during the first quarter of 2008, depreciation associated with ENSCO 105 and depreciation on minor upgrades and improvements to our Europe and Africa fleet completed during 2007 and 2008.

   North and South America

       During 2009, North and South America revenues declined by $53.5 million, or 12%, as compared to the prior year. The decline in revenues was primarily due to a decline in utilization to 67% from 97% during the prior year, partially offset by a 22% increase in average day rates. The decline in utilization occurred due to lower levels of spending by oil and gas companies in the Gulf of Mexico. The increase in average day rates was largely due to the relocation of ENSCO 83, ENSCO 89, ENSCO 93 and ENSCO 98 to Mexico and ENSCO 68 to Venezuela, where day rates are generally higher than the Gulf of Mexico. Contract drilling expense increased by 1% as compared to the prior year, due to incremental expenses associated with operating in Mexico and Venezuela as compared to the Gulf of Mexico and an increase in mobilization and repair and maintenance expense, partially offset by the impact of lower utilization. Depreciation expense increased by 5% as compared to the prior year, primarily due to ENSCO 89 and ENSCO 93 capital enhancement projects completed during the second quarter of 2009, the ENSCO 98 capital enhancement project completed during the third quarter of 2009 and depreciation on minor upgrades and improvements to our North and South America fleet completed during 2008 and 2009.

       During 2008, North and South America revenues increased by $50.3 million, or 13%, as compared to the prior year. The increase in revenues was primarily due to an increase in utilization to 97% from 77% during the prior year, partially offset by an 8% decline in average day rates. The increase in utilization was attributable to reduced rig supply in the Gulf of Mexico, as drilling contractors mobilized rigs to other regions, and an increase in customer demand. Although we realized day rate increases on new contracts during the majority of 2008, day rates earned during 2008 were generally lower than day rates earned during early 2007. The increase in revenues was also partially offset by ENSCO 105, which generated $7.1 million of revenues and $2.1 million of contract drilling expense during the first quarter of 2007 prior to relocation from the region. Contract drilling expense increased by $16.2 million, or 11%, as compared to the prior year, primarily due to increased personnel costs and the impact of increased utilization, partially offset by a decline in mobilization expense and the relocation of ENSCO 105 during 2007. Depreciation expense increased by 11% as compared to the prior year. The increase was primarily attributable to depreciation associated with the ENSCO 83 and ENSCO 93 capital enhancement projects completed during the second quarter of 2007 and first quarter of 2008, respectively, and depreciation on minor upgrades and improvements to our North and South America fleet completed during 2007 and 2008, partially offset by the reduced size of our North and South America fleet.

   Other

       During 2009, general and administrative expense increased by $10.2 million, or 19%, as compared to the prior year. The increase was primarily attributable to $7.6 million of professional fees incurred in connection with our redomestication during the fourth quarter of 2009 and a $1.9 million expense incurred in connection with a separation agreement with our former Senior Vice President of Operations.

       During 2008, general and administrative expense declined by $5.7 million, or 10%, as compared to the prior year. The decline was primarily attributable to an $11.3 million expense incurred during the prior year in connection with a retirement agreement with our former Chairman and Chief Executive Officer, partially offset by increased professional fees and personnel costs and costs associated with our branding initiative.


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Other Income (Expense), Net

       The following table summarizes other income (expense), net, for each of the years in the three-year period ended December 31, 2009 (in millions):

   2009         2008         2007  
  
Interest income     $2.2   $14.0   $26.3  
Interest expense, net:  
     Interest expense    (20.9 )  (21.6 )  (32.3 )
     Capitalized interest    20.9    21.6    30.4  

     --    --    (1.9 )
Other, net    6.6    (18.2 )  13.4  

    $8.8   $(4.2 ) $37.8  


       During 2009 and 2008, interest income declined as compared to their respective prior years due to lower average interest rates, partially offset by an increase in cash balances invested. Interest expense declined during 2009 and 2008 as compared to their respective prior years due to a decline in outstanding debt. All interest expense incurred during 2009 and 2008 was capitalized in connection with the construction of our ENSCO 8500 Series® rigs.

       A portion of the revenues earned and expenses incurred by our non-U.S. subsidiaries are denominated in currencies other than the U.S. dollar ("foreign currencies"). These transactions are remeasured in U.S. dollars based on a combination of both current and historical exchange rates. Other, net, included $2.6 million of net foreign currency exchange gains, $10.4 million of net foreign currency exchange losses and $9.2 million of net foreign currency exchange gains during 2009, 2008 and 2007, respectively.

       Other, net, also included net unrealized gains of $1.8 million and unrealized losses of $8.1 million associated with the valuation of our auction rate securities during 2009 and 2008, respectively. The fair value measurement of our auction rate securities is discussed in Note 8 to our consolidated financial statements. During 2007, other, net, included a $3.1 million net gain resulting from the settlement of litigation we initiated in relation to a non-operational dispute with a third party service provider.

Provision for Income Taxes

       Income tax rates imposed in the tax jurisdictions in which our subsidiaries conduct operations vary, as does the tax base to which the rates are applied. In some cases, tax rates may be applicable to gross revenues, statutory or negotiated deemed profits or other bases utilized under local tax laws, rather than to net income. In addition, our drilling rigs frequently move from one tax jurisdiction to another. As a result, our consolidated effective income tax rate may vary substantially from one reporting period to another, depending on the relative components of our earnings generated in tax jurisdictions with higher tax rates or lower tax rates.

       Income tax expense was $178.4 million, $237.3 million and $244.8 million and our effective tax rate was 18.6%, 17.0% and 20.1% during the years ended December 31, 2009, 2008 and 2007, respectively. The increase in our 2009 effective tax rate as compared to the prior year was primarily related to an $8.8 million non-recurring current income tax expense incurred in connection with certain restructuring activities undertaken immediately following our redomestication in December 2009. Excluding the impact from this non-recurring item, our 2009 effective tax rate was 17.7%, generally consistent with the prior year. The decline in our 2008 effective tax rate as compared to the prior year was primarily due to an increase in earnings generated by our non-U.S. subsidiaries whose earnings are being indefinitely reinvested and taxed at lower rates.


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Discontinued Operations

   ENSCO 69

       From May 2007 to June 2009, ENSCO 69 was contracted to Petrosucre, a subsidiary of Petróleos de Venezuela S.A., the national oil company of Venezuela ("PDVSA"). During portions of 2008 and 2009, PDVSA subsidiaries reportedly lacked funds and generally were not paying their contractors and service providers. In January 2009, we suspended drilling operations on ENSCO 69 after Petrosucre failed to satisfy its contractual obligations and meet commitments relative to the payment of past due invoices. Petrosucre then took over complete control of ENSCO 69 drilling operations utilizing Petrosucre employees and a portion of the Venezuelan rig crews we had utilized. Petrosucre initially advised us that it was temporarily taking over operations on the rig, and our supervisory rig personnel remained onboard to observe Petrosucre's operations.

       On June 4, 2009, after Petrosucre's failure to satisfy its contractual payment obligations, failure to reach a mutually acceptable agreement with us and denial of our request to demobilize ENSCO 69 from Venezuela, Petrosucre advised that it would not return the rig and would continue to operate it without our consent. Petrosucre further advised that it would release ENSCO 69 after a six-month period, subject to a mutually agreed accord addressing the resolution of all remaining obligations under the ENSCO 69 drilling contract. On June 6, 2009, we terminated our contract with Petrosucre and removed all remaining Ensco employees from the rig.

       Due to Petrosucre's failure to satisfy its contractual obligations and meet payment commitments, and in consideration of the Venezuelan government's recent nationalization of assets owned by international oil and gas companies and oilfield service companies, we concluded it was remote that ENSCO 69 would be returned to us by Petrosucre and operated again by Ensco. Therefore, we recorded the disposal of ENSCO 69 during the second quarter of 2009 and recognized a pre-tax loss of $18.1 million representing the rig's net book value of $17.3 million and inventory and other assets totaling $800,000. The disposal was classified as loss on disposal of discontinued operations, net, in our consolidated statement of income for the year ended December 31, 2009. ENSCO 69 operating results were reclassified as discontinued operations in our consolidated statements of income for each of the years in the three-year period ended December 31, 2009.

       In November 2009, we executed an agreement with Petrosucre to mitigate our losses and resolve issues relative to outstanding amounts owed by Petrosucre for drilling operations performed by Ensco through the date of termination of the drilling contract in June 2009 (the "agreement"). Although ENSCO 69 will continue to be fully controlled and operated by Petrosucre, the agreement also requires Petrosucre to compensate us for its ongoing use of the rig. We recognized $33.1 million of pre-tax income from discontinued operations for the year ended December 31, 2009 associated with collections under the agreement, consisting of $21.2 million of revenues from Petrosucre's use of the rig during 2009 and $11.9 million from the release of bad debt provisions recorded during 2008.

       Although the agreement obligates Petrosucre to make additional payments during 2010 for its use of the rig during 2009, the associated income was not recognized in our consolidated statement of income for the year ended December 31, 2009, as collectability was not reasonably assured. There can be no assurances relative to the recovery of outstanding contract entitlements, insurance recovery, the return of ENSCO 69 to us by Petrosucre or the imposition of customs duties in relation to the rig's ongoing presence in Venezuela. See Note 12 to our consolidated financial statements for additional information on insurance recovery and legal remedies related to ENSCO 69.

   ENSCO 74

       In September 2008, ENSCO 74 was lost as a result of Hurricane Ike. Portions of its legs remained underwater adjacent to the customer's platform, and we conducted extensive aerial and sonar reconnaissance but did not locate the rig hull. In March 2009, the sunken hull of ENSCO 74 was located approximately 95 miles from the original drilling location when it was struck by an oil tanker. The rig was a total loss, as defined under the terms of our insurance policies. The operating results of ENSCO 74 were reclassified as discontinued operations in our consolidated statements of income for the years ended December 31, 2008 and 2007. See Note 11 and Note 12 to our consolidated financial statements for additional information on the loss of ENSCO 74 and associated contingencies.


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       The following table summarizes income (loss) from discontinued operations for each of the years in the three-year period ended December 31, 2009 (in millions):

   
       2009       2008       2007 
       
Revenues   $ 26.0    $ 93.0    $85.6   
Operating expenses   3.1    59.7    39.9   

Operating income before income taxes   22.9    33.3    45.7   
Income tax expense   7.5    12.9    16.9   
Loss on disposal of discontinued operations, net   (11.8)   (23.5)   --   

Income (loss) from discontinued operations   $   3.6    $  (3.1)   $28.8   


Fair Value Measurements

       Our auction rate securities were measured at fair value as of December 31, 2009 and 2008 using significant Level 3 inputs.

       As a result of continued auction failures, quoted prices for our auction rate securities did not exist as of December 31, 2009 and, accordingly, we concluded that Level 1 inputs were not available. We determined that use of a valuation model was the best available technique for measuring the fair value of our auction rate securities. We used an income approach valuation model to estimate the price that would be received in exchange for our auction rate securities in an orderly transaction between market participants ("exit price") as of December 31, 2009. The exit price was derived as the weighted-average present value of expected cash flows over various periods of illiquidity, using a risk-adjusted discount rate that was based on the credit risk and liquidity risk of our auction rate securities.

       While our valuation model was based on both Level 2 (credit quality and interest rates) and Level 3 inputs, we determined that Level 3 inputs were significant to the overall fair value measurement, particularly the estimates of risk-adjusted discount rates and ranges of expected periods of illiquidity. We reviewed these inputs to our valuation model, evaluated the results and performed sensitivity analysis on key assumptions. Based on our review, we concluded that the fair value measurement of our auction rate securities as of December 31, 2009 was appropriate.

       Based on the results of our fair value measurements, we recognized net unrealized gains of $1.8 million and unrealized losses of $8.1 million for the years ended December 31, 2009 and 2008, respectively. Unrealized gains and losses on our auction rate securities were included in other income (expense), net, in our consolidated statements of income. The carrying values of our auction rate securities, classified as long-term investments on our consolidated balance sheets, were $60.5 million and $64.2 million as of December 31, 2009 and 2008, respectively. We anticipate realizing the $66.8 million (par value) of our auction rate securities on the basis that we intend to hold them until they are redeemed, repurchased or sold in a market that facilitates orderly transactions.

       Auction rate securities measured at fair value using significant Level 3 inputs constituted 65% of our assets measured at fair value and less than 1% of our total assets as of December 31, 2009. See Note 8 to our consolidated financial statements for additional information on our fair value measurements.

LIQUIDITY AND CAPITAL RESOURCES

       Although our business has historically been very cyclical, we have relied on our cash flows 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. A substantial portion of our cash flow is invested in the expansion and enhancement of our fleet of drilling rigs in general and construction of our ENSCO 8500 Series® rigs in particular.


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       During the three-year period ended December 31, 2009, our primary source of cash was an aggregate $3,558.3 million generated from continuing operations. Our primary uses of cash during the same period included an aggregate $2,152.6 million for the construction, enhancement and other improvement of our drilling rigs, including $1,614.6 million invested in the construction of our ENSCO 8500 Series® rigs, and $793.8 million for the repurchase of our shares.

       Detailed explanations of our liquidity and capital resources for each of the years in the three-year period ended December 31, 2009 are set forth below.

Cash Flows and Capital Expenditures

       Our cash flows from continuing operations and capital expenditures on continuing operations for each of the years in the three-year period ended December 31, 2009 were as follows (in millions):
 

     2009      2008   2007 
 
    Cash flows from continuing operations   $1,221.7   $1,125.4   $1,211.2  

   
    Capital expenditures on continuing operations:  
         New rig construction   $   623.4   $   651.5   $   367.7  
         Rig enhancements  153.1   33.7   65.0  
         Minor upgrades and improvements  84.8   86.7   86.7  

    $   861.3   $   771.9   $   519.4  


       During 2009, cash flows from continuing operations increased by $96.3 million, or 9%, as compared to the prior year. The increase resulted primarily from a $205.4 million decline in tax payments and a $77.8 million decline in our investment in trading securities, offset by a $181.3 million decline in cash receipts from contract drilling services.

       During 2008, cash flows from continuing operations declined by $85.8 million, or 7%, as compared to the prior year. The decline resulted primarily from a $72.3 million net investment in trading securities, a $152.8 million increase in cash payments related to contract drilling expenses and a $142.6 million increase in cash payments related to income taxes, partially offset by a $287.3 million increase in cash receipts from contract drilling services.

       We continue to expand the size and quality of our drilling rig fleet. During the three-year period ended December 31, 2009, we invested $1,642.6 million in the construction of new drilling rigs and an additional $251.8 million upgrading the capability and extending the useful lives of our existing fleet. In addition to ENSCO 8500, which was delivered in September 2008 and commenced a four-year drilling contract in June 2009, and ENSCO 8501, which was delivered in June 2009 and commenced a three-and-a-half-year drilling contract in October 2009, ENSCO 8502 was delivered in January 2010 and is expect to commence drilling operations under a two-year contract during the third quarter of 2010. We also added ENSCO 108, a new high-specification jackup rig, to our fleet during 2007.

       We have four ENSCO 8500 Series® ultra-deepwater semisubmersible rigs under construction with scheduled delivery dates during the fourth quarter of 2010, the second half of 2011 and the first and second half of 2012. ENSCO 8503 has secured a long-term drilling contract in the Gulf of Mexico, while the other three ENSCO 8500 Series® rigs under construction are currently without contracts.

       Based on our current projections, we expect capital expenditures during 2010 to include approximately $610.0 million for construction of our ENSCO 8500 Series® rigs, approximately $30.0 million for rig enhancement projects and $100.0 million for minor upgrades and improvements. Depending on market conditions and opportunities, we may make additional capital expenditures to upgrade rigs for customer requirements and construct or acquire additional rigs.


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Financing and Capital Resources

       Our long-term debt, total capital and long-term debt to total capital ratios as of December 31, 2009, 2008 and 2007 are summarized below (in millions, except percentages):

   2009        2008        2007  
 
Long-term debt   $   257.2   $   274.3   $   291.4  
Total capital*   5,756.4   4,951.2   4,043.4  
Long-term debt to total capital   4.5%   5.5%   7.2%  
 
         *   Total capital includes long-term debt plus Ensco shareholders' equity.


       We have a $350.0 million unsecured revolving credit facility (the "Credit Facility") with a syndicate of banks. We had no amounts outstanding under the Credit Facility as of December 31, 2009, 2008 and 2007. We are currently in discussions with multiple banks regarding a new line of credit to replace the Credit Facility upon expiration in June 2010. In addition, we filed a Form S-3 Registration Statement with the SEC on January 13, 2009, which provides us the ability to issue debt and/or equity securities. The registration statement was immediately effective and expires in January 2012. We currently maintain an investment grade credit rating of Baa1 from Moody's Investor's Service and BBB+ from Standard & Poor's Ratings Service.

       As of December 31, 2009, we had an aggregate $125.5 million outstanding under two separate bond issues guaranteed by the United States of America, acting by and through the United States Department of Transportation, Maritime Administration ("MARAD"), that require semiannual principal and interest payments. We also make semiannual interest payments on $150.0 million of 7.20% debentures due in 2027. See Note 4 to our consolidated financial statements for more information on our long-term debt.

       The Board of Directors previously authorized the repurchase of up to $1,500.0 million of our shares. From inception of our share repurchase programs during 2006 through December 31, 2008, we repurchased an aggregate 16.5 million shares at a cost of $937.6 million (an average cost of $56.79 per share). No shares were repurchased under the share repurchase programs during 2009. In December 2009, in conjunction with the redomestication, the remaining repurchase authorization was extended authorizing management to repurchase up to $562.4 million of ADSs from time to time pursuant to share repurchase agreements with two investment banks. Although such amount remained available for repurchase as of December 31, 2009, the Company will not repurchase any shares without further consultation with and approval by the Board of Directors of Ensco International plc.

Contractual Obligations

       We have various contractual commitments related to our new rig construction agreements, long-term debt and operating leases. We expect to fund these commitments from our existing cash and cash equivalents and future operating cash flows. The actual timing of our new rig construction payments may vary based on the completion of various construction milestones, which are beyond our control. The table below summarizes our significant contractual obligations as of December 31, 2009 and the periods in which such obligations are due (in millions):
 

          Payments due by period            
    2011        2013            
    and        and          After         
   2010           2012          2014           2014          Total   
 
New rig construction agreements   $482.4   $644.5    $    --   $      --   $1,126.9  
Principal payments on long-term debt   17.2   34.4    34.4   189.5   275.5  
Interest payments on long-term debt  17.7   32.3    28.3   144.6   222.9  
Operating leases  7.5   5.6    3.5   5.7   22.3  

Total contractual obligations   $524.8   $716.8    $66.2   $339.8   $1,647.6  

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       Our contractual obligations table does not include $17.6 million of unrecognized tax benefits included on our consolidated balance sheet as of December 31, 2009. Substantially all of our unrecognized tax benefits relate to uncertain tax positions that were not under review by taxing authorities. Therefore, we are unable to specify the future periods in which we may be obligated to settle such amounts.

       Additionally, our contractual obligations table does not include foreign currency forward contracts ("derivatives"). As of December 31, 2009, we had derivatives outstanding to exchange an aggregate $350.0 million U.S. dollars for various other currencies, including $216.6 million for Singapore dollars. As of December 31, 2009, our consolidated balance sheet included net derivative assets of $13.2 million. All of our outstanding derivatives mature during the next two years.

Liquidity

       Our liquidity position as of December 31, 2009, 2008 and 2007 is summarized below (in millions, except ratios):
 

   2009        2008          2007  
 
Cash and cash equivalents   $1,141.4   $789.6   $629.5  
Working capital   1,167.9   973.0   625.8  
Current ratio   3.4   3.3   2.2  


       We expect to fund our short-term liquidity needs, including approximately $785.0 million of contractual obligations and anticipated capital expenditures, as well as any dividends, share repurchases or working capital requirements, from our cash and cash equivalents and operating cash flows. We expect to fund our long-term liquidity needs, including contractual obligations, anticipated capital expenditures and dividends, from our cash and cash equivalents, investments, operating cash flows and, if necessary, funds borrowed under our $350.0 million unsecured revolving credit facility or other future financing arrangements.

       Based on our $1,141.4 million of cash and cash equivalents as of December 31, 2009 and our current contractual backlog of over $2,900.0 million, we believe our remaining $1,126.9 million of contractual obligations associated with the construction of our ENSCO 8500 Series® rigs will be funded from existing cash and cash equivalents and future operating cash flows. We may decide to access debt markets to raise additional capital or increase liquidity as necessary.

Effects of Climate Change and Climate Change Regulation

       Greenhouse gas emissions have increasingly become the subject of international, national, regional, state and local attention. Cap and trade initiatives to limit greenhouse gas emissions have been introduced in the European Union. Similarly, numerous bills related to climate change have been introduced in the U.S. Congress, which could adversely impact all industries. In addition, future regulation of greenhouse gas could occur pursuant to future treaty obligations, statutory or regulatory changes or new climate change legislation in the jurisdictions in which we operate. It is uncertain whether any of these initiatives will be implemented, although, based on published media reports, we believe that it is not reasonably likely that the current proposed initiatives in the U.S. will be implemented without substantial modification. If such initiatives are implemented, because we typically operate offshore with relatively minimal greenhouse gas emissions, we do not believe that such initiatives would have a direct, material adverse effect on our operating costs.

       Restrictions on greenhouse gas emissions could have an indirect effect in those industries that use significant amounts of petroleum products, which could potentially result in a reduction in demand for petroleum products and, consequently, our offshore contract drilling services. We are currently unable to predict the manner or extent of any such effect. Further, one of the long-term physical effects of climate change may be an increase in the severity and frequency of adverse weather conditions, such as hurricanes, which may increase our insurance costs or limit insurance availability or reduce the areas in which, or the number of days during which, our customers would contract for our drilling rigs. We are currently unable to predict the manner or extent of any such effect.

MARKET RISK

    Derivative Instruments

       We use derivatives to reduce our exposure to various market risks, primarily foreign currency exchange rate risk. Our functional currency is the U.S. dollar. As is customary in the oil and gas industry, a majority of our revenues are denominated in U.S. dollars, however, a portion of the expenses incurred by our non-U.S. subsidiaries are denominated in currencies other than the U.S. dollar ("foreign currencies"). We maintain a foreign currency exchange rate risk management strategy that utilizes derivatives to reduce our exposure to unanticipated fluctuations in earnings and cash flows caused by changes in foreign currency exchange rates. We occasionally employ an interest rate risk management strategy that utilizes derivative instruments to minimize or eliminate unanticipated fluctuations in earnings and cash flows arising from changes in, and volatility of, interest rates.

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       We utilize derivatives to hedge forecasted foreign currency denominated transactions, primarily to reduce our exposure to foreign currency exchange rate risk associated with the portion of our remaining ENSCO 8500 Series® construction obligations denominated in Singapore dollars and contract drilling expenses denominated in various other currencies. As of December 31, 2009, $264.8 million of the aggregate remaining contractual obligations associated with our ENSCO 8500 Series® construction projects was denominated in Singapore dollars, of which $212.5 million was hedged through derivatives.

       We have net assets and liabilities denominated in numerous foreign currencies and use various methods to manage our exposure to changes in foreign currency exchange rates. We predominantly structure our drilling contracts in U.S. dollars, which significantly reduces the portion of our cash flows and assets denominated in foreign currencies. We also employ various strategies, including the use of derivatives, to match foreign currency denominated assets with equal or near equal amounts of foreign currency denominated liabilities, thereby minimizing exposure to earnings fluctuations caused by changes in foreign currency exchange rates.

       We utilize derivatives and undertake foreign currency exchange rate hedging activities in accordance with our established policies for the management of market risk. We minimize our credit risk relating to the counterparties of our derivatives by transacting with multiple, high-quality financial institutions, thereby limiting exposure to individual counterparties, and by monitoring the financial condition of our counterparties. We do not enter into derivatives for trading or other speculative purposes. We believe that our use of derivatives and related hedging activities reduces our exposure to foreign currency exchange rate risk and interest rate risk and does not expose us to material credit risk or any other material market risk.

       As of December 31, 2009, we had derivatives outstanding to exchange an aggregate $350.0 million for various other currencies, including $216.6 million for Singapore dollars. If we were to incur a hypothetical 10% adverse change in foreign currency exchange rates, net unrealized losses associated with our foreign currency denominated assets and liabilities and related derivatives as of December 31, 2009 would approximate $27.9 million, including $20.9 million related to our Singapore dollar exposures. All of our derivatives mature during the next two years. See Note 5 to our consolidated financial statements for additional information on our derivative instruments.

   Auction Rate Securities

       We have generated a substantial cash balance, portions of which are invested in securities that meet our requirements for quality and return. Investment of our cash exposes us to market risk. We held $66.8 million (par value) of auction rate securities with a carrying value of $60.5 million as of December 31, 2009. We intend to hold these securities until they can be redeemed by issuers, repurchased by brokerage firms or sold in a market that facilitates orderly transactions. Due to significant uncertainties related to the auction rate securities market, we will be exposed to the risk of changes in the fair value of these securities in future periods.

       To measure the fair value of our auction rate securities as of December 31, 2009, we used an income approach valuation model to estimate the price that would be received in exchange for our auction rate securities in an orderly transaction between market participants ("exit price"). The exit price was derived as the weighted-average present value of expected cash flows over various periods of illiquidity, using a risk-adjusted discount rate that was based on the credit risk and liquidity risk of our auction rate securities. If we were to incur a hypothetical 10% adverse change in the periods of illiquidity and a 10% adverse change in the risk-adjusted discount rate, the additional unrealized losses on our auction rate securities as of December 31, 2009 would approximate $2.0 million. See Note 3 to our consolidated financial statements for additional information on our auction rate securities.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

       The preparation of financial statements and related disclosures in conformity with GAAP requires our management to make estimates, judgments and assumptions that affect the amounts reported in our consolidated financial statements and accompanying notes. Our significant accounting policies are included in Note 1 to our consolidated financial statements. These policies, along with our underlying judgments and assumptions made in their application, have a significant impact on our consolidated financial statements. We identify our critical accounting policies as those that are the most pervasive and important to the portrayal of our financial position and operating results, and that require the most difficult, subjective and/or complex judgments by management regarding estimates in matters that are inherently uncertain. Our critical accounting policies are those related to property and equipment, impairment of long-lived assets and goodwill and income taxes.

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   Property and Equipment

       As of December 31, 2009, the carrying value of our property and equipment totaled $4,477.3 million, which represented 66% of total assets. This carrying value reflects the application of our property and equipment accounting policies, which incorporate management's estimates, judgments and assumptions relative to the capitalized costs, useful lives and salvage values of our rigs.

       We develop and apply property and equipment accounting policies that are designed to appropriately and consistently capitalize those costs incurred to enhance, improve and extend the useful lives of our assets and expense those costs incurred to repair or maintain the existing condition or useful lives of our assets. The development and application of such policies requires estimates, judgments and assumptions by management relative to the nature of, and benefits from, expenditures on our assets. We establish property and equipment accounting policies that are designed to depreciate our assets over their estimated useful lives. The judgments and assumptions used by management in determining the useful lives of our property and equipment reflect both historical experience and expectations regarding future operations, utilization and performance of our assets. The use of different estimates, judgments and assumptions in the establishment of our property and equipment accounting policies, especially those involving the useful lives of our rigs, would likely result in materially different asset carrying values and operating results.

       The useful lives of our drilling rigs are difficult to estimate due to a variety of factors, including technological advances that impact the methods or cost of oil and natural gas exploration and development, changes in market or economic conditions and changes in laws or regulations affecting the drilling industry. We evaluate the remaining useful lives of our rigs on a periodic basis, considering operating condition, functional capability and market and economic factors. Our most recent change in estimated useful lives occurred during 1998, when we extended the useful lives of our drilling rigs by an average of five to six years.

       Our fleet of 42 jackup rigs represented 74% of the gross cost and 67% of the net carrying amount of our depreciable property and equipment as of December 31, 2009. Our jackup rigs are depreciated over useful lives ranging from 15 to 30 years. Our fleet of three ultra-deepwater semisubmersible rigs, exclusive of the ENSCO 8500 Series® rigs under construction, represented 21% of the gross cost and 30% of the net carrying amount of our depreciable property and equipment as of December 31, 2009. Our ultra-deepwater semisubmersible rigs are depreciated over a 30-year useful life. The following table provides an analysis of estimated increases and decreases in depreciation expense that would have been recognized for the year ended December 31, 2009 for various assumed changes in the useful lives of our drilling rigs effective January 1, 2009:

 
Increase (decrease) in
useful lives of our
           drilling rigs            
Estimated increase (decrease) in
depreciation expense that would
have been recognized (in millions)
 
10%   $(22.3)  
20%     (37.9)  
(10%)     17.0  
(20%)     44.1  


   Impairment of Long-Lived Assets and Goodwill

       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. Generally, extended periods of idle time and/or inability to contract rigs at economical rates are an indication that a rig may be impaired. However, the offshore drilling industry has historically 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 demand comes back into balance with supply. Impairment situations may arise with respect to specific individual rigs, groups of rigs, such as a specific type of drilling rig, or rigs in a certain geographic location. Our rigs are mobile and may generally be moved from markets with excess supply, if economically feasible. Our jackup and ultra-deepwater semisubmersible rigs are suited for, and accessible to, broad and numerous markets throughout the world.


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       For property and equipment used in our operations, recoverability is generally determined by comparing the net carrying value of an asset to the expected undiscounted future cash flows of the asset. If the carrying value of an asset is not recoverable, the amount of impairment loss is measured as the difference between the net book value of the asset and its estimated fair value. The determination of expected undiscounted cash flow amounts requires significant estimates, judgments and assumptions, including utilization, day rates, expense levels and capital requirements, as well as cash flows generated upon disposition, for each of our drilling rigs. Due to the inherent uncertainties associated with these estimates, we perform sensitivity analysis on key assumptions as part of our recoverability test.

       If the global economy deteriorates and/or other events or changes in circumstances indicate that the carrying value of one or more drilling rigs may not be recoverable, we will conclude that a triggering event has occurred and perform a recoverability test. If, at the time of the recoverability test, management's judgments and assumptions regarding future industry conditions and operations have diminished, it is reasonably possible that we could conclude that one or more of our drilling rigs are impaired.

       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 and estimate each unit's fair value as of the testing date. Our four operating segments represent our reporting units. 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. Due to the inherent uncertainties associated with these estimates, we perform sensitivity analysis on key assumptions as part of our goodwill impairment test.

       If the aggregate fair value of our reporting units exceeds our market capitalization, we evaluate the reasonableness of the implied control premium which includes a comparison to implied control premiums from recent market transactions within our industry or other relevant benchmark data. To the extent that the implied control premium based on the aggregate fair value of our reporting units is not reasonable, we adjust the discount rate used in our discounted cash flow model and reduce the estimated fair values of our reporting units.

       If the estimated fair value of a reporting unit exceeds its carrying value, its goodwill is considered not impaired. If the estimated fair value of a reporting unit is less than its carrying value, we estimate the implied fair value of the reporting unit's goodwill. If the carrying amount of the reporting unit's goodwill exceeds the implied fair value of the goodwill, an impairment loss is recognized in an amount equal to such excess. In the event we dispose of drilling rig operations that constitute a business, goodwill would be allocated in the determination of gain or loss on disposal. Based on our annual goodwill impairment test performed as of December 31, 2009, there was no impairment of goodwill.

       If the global economy deteriorates and/or our expectations relative to future offshore drilling industry conditions decline, we may conclude that the fair value of one or more of our reporting units has more-likely-than-not declined below its carrying amount and perform an interim period goodwill impairment test. If, at the time of the goodwill impairment test, management's judgments and assumptions regarding future industry conditions and operations have diminished, or if the market value of our shares has declined, we could conclude that the goodwill of one or more of our reporting units has been impaired. It is reasonably possible that the judgments and assumptions inherent in our goodwill impairment test may change in response to future market conditions.

       Asset impairment evaluations are, by nature, highly subjective. In most instances, they involve expectations of future cash flows to be generated by our drilling rigs, which reflect management's judgments and assumptions regarding future industry conditions and operations, as well as management's estimates of expected utilization, day rates, expense levels and capital requirements. The estimates, judgments and assumptions used by management in the application of our asset impairment policies reflect both historical experience and an assessment of current operational, industry, market, economic and political environments. The use of different estimates, judgments, assumptions and expectations regarding future industry conditions and operations would likely result in materially different asset carrying values and operating results.


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   Income Taxes

       We conduct operations and earn income in numerous countries and are subject to the laws of numerous tax jurisdictions. As of December 31, 2009, our consolidated balance sheet included a $347.6 million net deferred income tax liability, a $78.5 million liability for income taxes currently payable and a $17.6 million liability for unrecognized tax benefits.

       The carrying values of deferred income tax assets and liabilities reflect the application of our income tax accounting policies and are based on management's estimates, judgments and assumptions regarding future operating results and levels of taxable income. Carryforwards and tax credits are assessed for realization as a reduction of future taxable income by using a more-likely-than-not determination.

       We do not provide U.S. deferred income taxes on the undistributed earnings of Ensco Delaware's non-U.S. subsidiaries because it is our policy and intention to reinvest such earnings indefinitely.

       The carrying values of liabilities for income taxes currently payable and unrecognized tax benefits are based on management's interpretation of applicable tax laws and incorporate management's estimates, judgments and assumptions regarding the use of tax planning strategies in various taxing jurisdictions. The use of different estimates, judgments and assumptions in connection with accounting for income taxes, especially those involving the deployment of tax planning strategies, may result in materially different carrying values of income tax assets and liabilities and operating results.

       We operate in many jurisdictions where tax laws relating to the offshore drilling industry are not well developed. In jurisdictions where available statutory law and regulations are incomplete or underdeveloped, we obtain professional guidance and consider existing industry practices before utilizing tax planning strategies and meeting our tax obligations.

       Tax returns are routinely subject to audit in most jurisdictions and tax liabilities are occasionally finalized through a negotiation process. While we have not historically experienced significant adjustments to previously recognized tax assets and liabilities as a result of finalizing tax returns, there can be no assurance that significant adjustments will not arise in the future. In addition, there are several factors that could cause the future level of uncertainty relating to our tax liabilities to increase, including the following:

 

 
The IRS and HMRC may disagree with our interpretation of tax laws, treaties, or regulations with respect to the redomestication.
 
  During recent years, the portion of our overall operations conducted in non-U.S. tax jurisdictions has increased, and we currently anticipate that this trend will continue.
 
  In order to utilize tax planning strategies and conduct operations efficiently, our subsidiaries frequently enter into transactions with affiliates that are generally subject to complex tax regulations and are frequently reviewed by tax authorities.
 
  We may conduct future operations in certain tax jurisdictions where tax laws are not well developed, and it may be difficult to secure adequate professional guidance.
 
  Tax laws, regulations, agreements and treaties change frequently, requiring us to modify existing tax strategies to conform to such changes.
 


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NEW ACCOUNTING PRONOUNCEMENTS

       In January 2010, the FASB issued Accounting Standards Update 2010-06, "Fair Value Measurements and Disclosures (Topic 820): Improving Disclosures about Fair Value Measurements" ("Update 2010-06"). Update 2010-06 provides amendments to Subtopic 820-10 that require new disclosures about recurring and non-recurring fair value measurements including significant transfers into and out of Level 1 and Level 2 and information on purchases, sales, issuances and settlements on a gross basis in the reconciliation of Level 3 fair value measurements. Furthermore, this update provides amendments to Subtopic 820-10 that clarify existing disclosures with respect to levels of disaggregation of assets and liabilities measured at fair value, in addition to disclosures of inputs and valuation techniques used to measure fair value. Update 2010-06 is effective for interim and annual reporting periods beginning after December 15, 2009, except for certain disclosures related to Level 3 inputs which become effective for interim and annual reporting periods beginning after December 15, 2010. We do not expect the adoption of Update 2010-06 to have a material effect on fair value measurement disclosures.

Item 7A.  Quantitative and Qualitative Disclosures About Market Risk

       Information required under Item 7A. has been incorporated into "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Market Risk."


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Item 8.  Financial Statements and Supplementary Data

MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER
FINANCIAL REPORTING

       Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f) or 15d-15(f). Our internal control over financial reporting system is designed to provide reasonable assurance to our management and Board of Directors regarding the preparation and fair presentation of published financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. Under the supervision and with the participation of management, including the Chief Executive Officer and Chief Financial Officer, we have conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, we have concluded that our internal control over financial reporting is effective as of December 31, 2009 to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.

       KPMG LLP, the independent registered public accounting firm who audited our consolidated financial statements, have issued an audit report on our internal control over financial reporting. KPMG LLP's audit report on our internal control over financial reporting is included herein.


February 25, 2010




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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Shareholders
Ensco International plc:

       We have audited the accompanying consolidated balance sheets of Ensco International plc and subsidiaries as of December 31, 2009 and 2008, and the related consolidated statements of income and cash flows for each of the years in the three-year period ended December 31, 2009. These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

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

       In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Ensco International plc and subsidiaries as of December 31, 2009 and 2008, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2009, in conformity with U.S. generally accepted accounting principles.

       We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Ensco International plc and subsidiaries' internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 25, 2010, expressed an unqualified opinion on the effectiveness of the Company's internal control over financial reporting.




/s/ KPMG LLP

 

Dallas, Texas
February 25, 2010


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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Shareholders
Ensco International plc:

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

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

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

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

       In our opinion, Ensco maintained, in all material respects, effective internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

       We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Ensco International plc and subsidiaries as of December 31, 2009 and 2008, and the related consolidated statements of income and cash flows for each of the years in the three-year period ended December 31, 2009, and our report dated February 25, 2010 expressed an unqualified opinion on those consolidated financial statements.




/s/ KPMG LLP

Dallas, Texas
February 25, 2010


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ENSCO INTERNATIONAL PLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME

(in millions, except per share amounts)

    Year Ended December 31,    
     2009  2008   2007
 
OPERATING REVENUES $ 1,945.9 $ 2,393.6 $ 2,058.2  
 
OPERATING EXPENSES 
     Contract drilling (exclusive of depreciation)   725.5   752.0   644.1  
     Depreciation  205.9   186.5   177.5  
     General and administrative  64.0   53.8   59.5  

   995.4   992.3   881.1  

OPERATING INCOME  950.5   1,401.3   1,177.1  
 
OTHER INCOME (EXPENSE), NET   8.8   (4.2 ) 37.8  

INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES  959.3   1,397.1   1,214.9  
 
PROVISION FOR INCOME TAXES 
     Current income tax expense  158.6   230.9   243.7  
     Deferred income tax expense  19.8   6.4   1.1  

   178.4   237.3   244.8  

INCOME FROM CONTINUING OPERATIONS  780.9   1,159.8   970.1  
 
DISCONTINUED OPERATIONS             
     Income from discontinued operations, net  15.4   20.4   28.8  
     Loss on disposal of discontinued operations, net  (11.8 ) (23.5 ) --  

   3.6   (3.1 ) 28.8  

NET INCOME   784.5   1,156.7   998.9  
 
NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS  (5.1 ) (5.9 ) (6.9 )

NET INCOME ATTRIBUTABLE TO ENSCO $ 779.4 $ 1,150.8 $ 992.0  

EARNINGS (LOSS) PER SHARE - BASIC 
     Continuing operations $ 5.45 $ 8.06 $ 6.52  
     Discontinued operations  .03   (.02 ) .19  

  $ 5.48 $ 8.04 $ 6.71  

EARNINGS (LOSS) PER SHARE - DILUTED 
     Continuing operations $ 5.45 $ 8.04 $ 6.50  
     Discontinued operations  .03   (.02 ) .19  

  $ 5.48 $ 8.02 $ 6.69  

 
NET INCOME ATTRIBUTABLE TO ENSCO SHARES 
     Basic $ 769.7 $ 1,138.2 $ 984.7  
     Diluted $ 769.7 $ 1,138.2 $ 984.7  
 
WEIGHTED-AVERAGE SHARES OUTSTANDING 
     Basic  140.4   141.6   146.7  
     Diluted  140.5   141.9   147.2  
 
CASH DIVIDENDS PER SHARE $ .10 $ .10 $ .10  
 

The accompanying notes are an integral part of these consolidated financial statements.

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ENSCO INTERNATIONAL PLC AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS

(in millions, except share and par value amounts)

         December 31,       
     2009      2008 
                                                                             ASSETS        
CURRENT ASSETS 
    Cash and cash equivalents $ 1,141.4 $ 789.6  
    Accounts receivable, net  324.6   482.7  
    Other  186.8   128.6  

       Total current assets  1,652.8   1,400.9  

 
PROPERTY AND EQUIPMENT, AT COST  6,151.2   5,376.3  
    Less accumulated depreciation  1,673.9   1,505.0  

       Property and equipment, net  4,477.3   3,871.3  

 
GOODWILL  336.2   336.2  
 
LONG-TERM INVESTMENTS  60.5   64.2  
 
OTHER ASSETS, NET  220.4   157.5  

  $ 6,747.2 $ 5,830.1  

 
                                       LIABILITIES AND SHAREHOLDERS' EQUITY 
 
CURRENT LIABILITIES 
    Accounts payable - trade $ 159.1 $ 195.8  
    Accrued liabilities and other   308.6   214.9  
    Current maturities of long-term debt  17.2   17.2  

       Total current liabilities  484.9   427.9  

 
LONG-TERM DEBT  257.2   274.3  
 
DEFERRED INCOME TAXES  377.3   340.5  
 
OTHER LIABILITIES  120.7   103.8  
 
COMMITMENTS AND CONTINGENCIES 
 
ENSCO SHAREHOLDERS' EQUITY 
    Common stock, U.S. $.10 par value, 250.0 million shares authorized,
       181.9 million shares issued as of December 31, 2008
  --   18.2  
    Class A ordinary shares, U.S. $.10 par value, 250.0 million shares authorized,
       150.0 million shares issued as of December 31, 2009
  15.0   --  
    Class B ordinary shares, £1 par value, 50,000 shares authorized and issued
       as of December 31, 2009
  .1   --  
    Additional paid-in capital  602.6   1,761.2  
    Retained earnings  4,879.2   4,114.0  
    Accumulated other comprehensive income (loss)  5.2   (17.0 )
    Treasury shares, at cost, 7.5 million shares and 40.1 million shares  (2.9 ) (1,199.5 )

       Total Ensco shareholders' equity  5,499.2   4,676.9  
 
NONCONTROLLING INTERESTS   7.9   6.7  

       Total equity  5,507.1   4,683.6  

  $ 6,747.2 $ 5,830.1  

The accompanying notes are an integral part of these consolidated financial statements.

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ENSCO INTERNATIONAL PLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in millions)
  Year Ended December 31,  
       2009    2008    2007 
OPERATING ACTIVITIES              
        Net income $ 784.5 $ 1,156.7 $ 998.9  
        Adjustments to reconcile net income to net cash provided 
           by operating activities of continuing operations: 
              Depreciation expense  205.9   186.5   177.5  
              Share-based compensation expense  35.5   27.3   36.9  
              Amortization expense  31.5   32.5   10.9  
              Deferred income tax expense  19.8   6.4   1.1  
              Income from discontinued operations, net  (15.4 ) (20.4 ) (28.8 )
              Loss on disposal of discontinued operations, net  11.8   23.5   --  
              Other  .3   4.3   (6.2 )
              Changes in operating assets and liabilities: 
                 Decrease (increase) in accounts receivable  185.0   (110.7 ) (45.8 )
                 Decrease (increase) in trading securities  5.5   (72.3 ) --  
                 Increase in other assets  (72.6 ) (40.5 ) (133.6 )
                 Increase (decrease) in liabilities  29.9   (67.9 ) 200.3  

                      Net cash provided by operating activities of continuing
                         operations
  1,221.7   1,125.4   1,211.2  

INVESTING ACTIVITIES 
        Additions to property and equipment  (861.3 ) (771.9 ) (519.4 )
        Proceeds from disposal of discontinued operations  4.9   45.1   --  
        Proceeds from disposition of assets  2.7   5.2   7.6  

                     Net cash used in investing activities  (853.7 ) (721.6 ) (511.8 )

FINANCING ACTIVITIES 
        Reduction of long-term borrowings  (17.2 ) (19.0 ) (165.3 )
        Cash dividends paid  (14.2 ) (14.3 ) (14.8 )
        Proceeds from exercise of share options  9.6   27.3   35.8  
        Repurchase of shares  (6.5 ) (259.7 ) (527.6 )
        Other  (5.9 ) 1.5   .9  

                      Net cash used in financing activities  (34.2 ) (264.2 ) (671.0 )

 
Effect of exchange rate changes on cash and cash equivalents  .5   (15.0 ) (.8 )
Net cash provided by operating activities of discontinued operations  17.5   35.5   36.1  

INCREASE IN CASH AND CASH EQUIVALENTS  351.8   160.1   63.7  
 
CASH AND CASH EQUIVALENTS, BEGINNING OF YEAR  789.6   629.5   565.8  

 
CASH AND CASH EQUIVALENTS, END OF YEAR $ 1,141.4 $ 789.6 $ 629.5  


The accompanying notes are an integral part of these consolidated financial statements.

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ENSCO INTERNATIONAL PLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 

1.  DESCRIPTION OF THE BUSINESS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES


   Business

       We are one of the leading providers of offshore contract drilling services to the international oil and gas industry. We have one of the largest and most capable offshore drilling rig fleets in the world comprised of 47 drilling rigs, including 42 jackup rigs, four ultra-deepwater semisubmersible rigs and one barge rig. Additionally, we have four ultra-deepwater semisubmersible rigs under construction. We drill and complete offshore oil and natural gas wells for major international, government-owned and independent oil and gas companies on a "day rate" contract basis, under which we provide our drilling rigs and rig crews and receive a fixed amount per day for drilling the 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.

       Our contract drilling operations are integral to the exploration, development and production of oil and natural gas. Our business levels and corresponding operating results are significantly affected by worldwide levels of offshore exploration and development spending by oil and gas companies. Such spending may fluctuate substantially from year-to-year and from region-to-region based on various social, political, economic and environmental factors. See "Note 13 - Segment Information" for additional information on our operations by segment and geographic region.

   Redomestication

       On December 23, 2009, we completed a reorganization of the corporate structure of the group of companies controlled by our predecessor, ENSCO International Incorporated ("Ensco Delaware"), pursuant to which an indirect, wholly-owned subsidiary merged with Ensco Delaware, and Ensco International plc became our publicly-held parent company incorporated under English law (the "redomestication"). In connection with the redomestication, each issued and outstanding share of common stock of Ensco Delaware was converted into the right to receive one American depositary share ("ADS" or "share"), each representing one Class A ordinary share, par value U.S. $0.10 per share, of Ensco International plc. The ADSs are governed by a deposit agreement with Citibank, N.A. as depositary and trade on the New York Stock Exchange (the "NYSE") under the symbol "ESV," the symbol for Ensco Delaware common stock before the redomestication. We are now incorporated under English law as a public limited company and have relocated our principal executive offices to London, England. Unless the context requires otherwise, the terms "Ensco," "Company," "we," "us" and "our" refer to Ensco International plc together with all subsidiaries and predecessors.

       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 (the "SEC") reporting requirements, the mandates of the Sarbanes-Oxley Act and the applicable corporate governance rules of the NYSE, and we will 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.

   Principles of Consolidation

       The accompanying consolidated financial statements include the accounts of Ensco International plc and its majority-owned subsidiaries. All significant intercompany accounts and transactions have been eliminated. Certain previously reported amounts have been reclassified to conform to the current year presentation.

   Pervasiveness of Estimates

       The preparation of financial statements in conformity with GAAP requires management to make certain estimates, judgments and assumptions that affect the reported amounts of assets and liabilities, the related revenues and expenses and disclosures of gain and loss contingencies as of the date of the financial statements. Actual results could differ from those estimates.


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   Foreign Currency Remeasurement

       Our functional currency is the U.S. dollar. As is customary in the oil and gas industry, a majority of our revenues are denominated in U.S. dollars, however, a portion of the expenses incurred by our non-U.S. subsidiaries are denominated in currencies other than the U.S. dollar ("foreign currencies"). These transactions are remeasured in U.S. dollars based on a combination of both current and historical exchange rates. Transaction gains and losses, including certain gains and losses on our derivative instruments, are included in other income (expense), net, in our consolidated statement of income. We incurred net foreign currency exchange gains of $2.6 million for the year ended December 31, 2009, net foreign currency exchange losses of $10.4 million for the year ended December 31, 2008 and net foreign currency exchange gains of $9.2 million for the year ended December 31, 2007.

   Cash Equivalents and Short-Term Investments

       Highly liquid investments with maturities of three months or less at the date of purchase are considered cash equivalents. Highly liquid investments with maturities of greater than three months but less than one year as of the date of purchase are classified as short-term investments.

   Property and Equipment

       All costs incurred in connection with the acquisition, construction, enhancement and improvement of assets are capitalized, including allocations of interest incurred during periods that our drilling rigs are under construction or undergoing major enhancements and improvements. Repair and maintenance costs are charged to contract drilling expense in the period in which they occur. Upon sale or retirement of assets, the related cost and accumulated depreciation are removed from the balance sheet and the resulting gain or loss is included in contract drilling expense.

       Our property and equipment is depreciated on the straight-line method, after allowing for salvage values, over the estimated useful lives of our assets. Drilling rigs and related equipment are depreciated over estimated useful lives ranging from 4 to 30 years. Buildings and improvements are depreciated over estimated useful lives ranging from 2 to 30 years. Other equipment, including computer and communications hardware and software costs, is depreciated over estimated useful lives ranging from 2 to 6 years.

       We evaluate the carrying value of our property and equipment for impairment when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. For property and equipment used in our operations, recoverability is generally determined by comparing the net carrying value of an asset to the expected undiscounted future cash flows of the asset. If the carrying value of an asset is not recoverable, the amount of impairment loss is measured as the difference between the net book value of the asset and its estimated fair value. Property and equipment held for sale is recorded at the lower of net book value or net realizable value.

       We recorded no impairment charges during the three-year period ended December 31, 2009. However, if the global economy were to deteriorate and/or the offshore drilling industry were to incur a significant prolonged downturn, it is reasonably possible that 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.

   Goodwill

       We are in the process of developing a fleet of ultra-deepwater semisubmersible rigs and established a separate business unit to manage our deepwater operations during 2008. Our jackup rigs and barge rig are managed by major geographic region. Accordingly, our business consists of four operating segments: (1) Deepwater, (2) Asia Pacific, (3) Europe and Africa and (4) North and South America. Each of our four operating segments provides one service, contract drilling.


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       Our four operating segments represent our reporting units. As a result of our 2008 reorganization to four operating segments and reporting units, we reassigned goodwill to our reporting units based on a relative fair value allocation approach as follows (in millions):

   
Deepwater       $ 143.6
Asia Pacific         84.6
Europe and Africa         61.4
North and South America         46.6

Total       $ 336.2


       Goodwill is not allocated to operating segments in the measure of segment assets regularly reported to and used by management. No goodwill was acquired or disposed of during the three-year period ended December 31, 2009.

       We test goodwill for impairment on an annual basis as of December 31 of each year or when events or changes in circumstances indicate that a potential impairment exists. The goodwill impairment test requires us to identify reporting units and estimate each 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.

       We determined there was no impairment of goodwill as of December 31, 2009. However, if the global economy deteriorates and the offshore drilling industry were to incur a significant prolonged downturn, it is reasonably possible that our expectations of future cash flows may decline and ultimately result in impairment of our goodwill. Additionally, a significant decline in the market value of our shares could result in a goodwill impairment.

   Operating Revenues and Expenses

       Substantially all of our drilling contracts ("contracts") are performed on a day rate basis, and the terms of such contracts are typically for a specific period of time or the period of time required to complete a specific task, such as drill a well. Contract revenues and expenses are recognized on a per day basis, as the work is performed. Day rate revenues are typically earned, and contract drilling expense is typically incurred, on a uniform basis over the terms of our contracts.

       In connection with some contracts, we receive lump-sum fees or similar compensation for the mobilization of equipment and personnel prior to the commencement of drilling services or the demobilization of equipment and personnel upon contract completion. Fees received for the mobilization or demobilization of equipment and personnel are included in operating revenues. The costs incurred in connection with the mobilization and demobilization of equipment and personnel are included in contract drilling expense.

       Mobilization fees received and costs incurred are deferred and recognized on a straight-line basis over the period that the related drilling services are performed. Demobilization fees and related costs are recognized as incurred upon contract completion. Costs associated with the mobilization of equipment and personnel to more promising market areas without contracts are expensed as incurred.

       Deferred mobilization costs were included in other current assets and other assets, net, and totaled $52.7 million and $47.5 million as of December 31, 2009 and 2008, respectively. Deferred mobilization revenue was included in accrued liabilities and other, and other liabilities and totaled $99.3 million and $88.0 million as of December 31, 2009 and 2008, respectively.

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       In connection with some contracts, we receive up-front lump-sum fees or similar compensation for capital improvements to our drilling rigs. Such compensation is deferred and recognized as revenue over the period that the related drilling services are performed. The cost of such capital improvements is capitalized and depreciated over the useful life of the asset. Deferred revenue associated with capital improvements was included in accrued liabilities and other, and other liabilities and totaled $22.5 million and $2.2 million as of December 31, 2009 and 2008, respectively.

       We must obtain certifications from various regulatory bodies in order to operate our drilling rigs and must maintain such certifications through periodic inspections and surveys. The costs incurred in connection with maintaining such certifications, including inspections, tests, surveys and drydock, as well as remedial structural work and other compliance costs, are deferred and amortized over the corresponding certification periods. Deferred regulatory certification and compliance costs were included in other current assets and other assets, net, and totaled $9.7 million and $6.5 million as of December 31, 2009 and 2008, respectively.

       In certain countries in which we operate, taxes such as sales, use, value-added, gross receipts and excise may be assessed by the local government on our revenues. We generally record our tax-assessed revenue transactions on a net basis in our consolidated statement of income.

   Derivative Instruments

       We use foreign currency forward contracts ("derivatives") to reduce our exposure to various market risks, primarily foreign currency exchange rate risk. See "Note 5 - Derivative Instruments" for additional information on how and why we use derivatives.

       All derivatives are recorded on our consolidated balance sheet at fair value. Accounting for the gains and losses resulting from changes in the fair value of derivatives depends on the use of the derivative and whether it qualifies for hedge accounting. Derivatives qualify for hedge accounting when they are formally designated as hedges and are effective in reducing the risk exposure that they are designated to hedge. Our assessment of hedge effectiveness is formally documented at hedge inception, and we review hedge effectiveness and measure any ineffectiveness throughout the designated hedge period on at least a quarterly basis.

       Changes in the fair value of derivatives that are designated as hedges of the fair value of recognized assets or liabilities or unrecognized firm commitments ("fair value hedges") are recorded currently in earnings and included in other income (expense), net, in our consolidated statement of income. Changes in the fair value of derivatives that are designated as hedges of the variability in expected future cash flows associated with existing recognized assets or liabilities or forecasted transactions ("cash flow hedges") are recorded in accumulated other comprehensive income (loss) ("AOCI"). Amounts recorded in AOCI associated with cash flow hedges are subsequently reclassified into contract drilling, depreciation or interest expense as earnings are affected by the underlying hedged forecasted transactions.

       Gains and losses on a cash flow hedge, or a portion of a cash flow hedge, that no longer qualifies as effective due to an unanticipated change in the forecasted transaction are recognized currently in earnings and included in other income (expense), net, in our consolidated statement of income based on the change in the fair value of the derivative. When a forecasted transaction is no longer probable of occurring, gains and losses on the derivative previously recorded in AOCI are reclassified currently into earnings and included in other income (expense), net, in our consolidated statement of income.


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       We occasionally enter into derivatives that hedge the fair value of recognized assets or liabilities, but do not designate such derivatives as hedges or the derivatives otherwise do not qualify for hedge accounting. In these situations, there generally is a natural hedging relationship where changes in the fair value of the derivatives offset changes in the fair value of the underlying hedged items. Changes in the fair value of these derivatives are recognized currently in earnings in other income (expense), net, in our consolidated statement of income.

       Derivatives with asset fair values are reported in other current assets or other assets, net, depending on maturity date. Derivatives with liability fair values are reported in accrued liabilities and other, or other liabilities depending on maturity date.

   Income Taxes

       We conduct operations and earn income in numerous countries and are subject to the laws of taxing jurisdictions within those countries, including U.K. and U.S. tax laws. Current income taxes are recognized for the amount of taxes payable or refundable based on the laws and income tax rates in the taxing jurisdictions in which operations are conducted and income is earned.

       Deferred tax assets and liabilities are recognized for the anticipated future tax effects of temporary differences between the financial statement basis and the tax basis of our assets and liabilities using the enacted tax rates in effect at year-end. A valuation allowance for deferred tax assets is recorded when it is more-likely-than-not that the benefit from the deferred tax asset will not be realized.

       In many of the jurisdictions in which we operate, tax laws relating to the offshore drilling industry are not well developed and change frequently. Furthermore, we may enter into transactions with affiliates or employ other tax planning strategies that generally are subject to complex tax regulations. As a result of the foregoing, the tax liabilities and assets we recognize in our financial statements may differ from the tax positions taken, or expected to be taken, in our tax returns. Our tax positions are evaluated for recognition using a more-likely-than-not threshold, and those tax positions requiring recognition are measured as the largest amount of tax benefit that is greater than 50% likely of being realized upon effective settlement with a taxing authority that has full knowledge of all relevant information. Interest and penalties relating to income taxes are included in current income tax expense in our consolidated statement of income. See "Note 10 - Income Taxes" for additional information on our unrecognized tax benefits.

       Our drilling rigs frequently move from one taxing jurisdiction to another based on where they are contracted to perform drilling services. The movement of drilling rigs among taxing jurisdictions may involve a transfer of drilling rig ownership among our subsidiaries. The pre-tax profit resulting from intercompany rig sales is eliminated and the carrying value of rigs sold in intercompany transactions remains at the historical net depreciated cost prior to the transaction. Our consolidated financial statements do not reflect the asset disposition transaction of the selling subsidiary or the asset acquisition transaction of the acquiring subsidiary. Income taxes resulting from the transfer of drilling rig ownership among subsidiaries, as well as the tax effect of any reversing temporary differences resulting from the transfers, are deferred and amortized on a straight-line basis over the remaining useful life of the rig.

       In some instances, we may determine that certain temporary differences will not result in a taxable or deductible amount in future years, as it is more-likely-than-not we will commence operations and depart from a given taxing jurisdiction without such temporary differences being recovered or settled. Under these circumstances, no future tax consequences are expected and no deferred taxes are recognized in connection with such operations. We evaluate these determinations on a periodic basis and, in the event our expectations relative to future tax consequences change, the applicable deferred taxes are recognized.


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       It is our policy and intention to indefinitely reinvest all remaining and future undistributed earnings of Ensco Delaware's non-U.S. subsidiaries in such subsidiaries. Accordingly, no U.S. deferred taxes are provided on the undistributed earnings of Ensco Delaware's non-U.S. subsidiaries. See "Note 10 - Income Taxes" for additional information on the undistributed earnings of Ensco Delaware's non-U.S. subsidiaries.

   Share-Based Compensation

       We sponsor several share-based compensation plans that provide equity compensation to our employees, officers and directors. Share-based compensation cost is measured at fair value on the date of grant and recognized on a straight-line basis over the requisite service period (usually the vesting period). The amount of compensation cost recognized in our consolidated statement of income is based on the awards ultimately expected to vest and, therefore, reduced for estimated forfeitures. All changes in estimated forfeitures are based on historical experience and are recognized as a cumulative adjustment to compensation cost in the period in which they occur. See "Note 9 - Benefit Plans" for additional information on our share-based compensation.

   Fair Value Measurements

       On January 1, 2008, we adopted certain provisions of FASB ASC 820-10 (previously SFAS No. 157, "Fair Value Measurements"). This standard establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy assigns the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities ("Level 1") and the lowest priority to unobservable inputs ("Level 3"). Level 2 measurements are inputs that are observable for assets or liabilities, either directly or indirectly, other than quoted prices included within Level 1.

       Our auction rate securities, marketable securities held in our supplemental executive retirement plans ("SERP") and derivatives are measured at fair value. Our auction rate securities are measured at fair value using an income approach valuation model (Level 3 inputs) to estimate the price that will be received in exchange for our auction rate securities in an orderly transaction between market participants ("exit price"). The exit price is derived as the weighted-average present value of expected cash flows over various periods of illiquidity, using a risk-adjusted discount rate that is based on the credit risk and liquidity risk of our auction rate securities. See "Note 3 - Long-Term Investments" for additional information on our auction rate securities, including a description of the securities and underlying collateral, a discussion of the uncertainties relating to their liquidity and our accounting treatment.

       Assets held in our SERP are measured at fair value based on quoted market prices (Level 1 inputs). Our derivatives are measured at fair value based on market prices that are generally observable for similar assets and liabilities at commonly quoted intervals (Level 2 inputs). See "Note 5 - Derivative Instruments" for additional information on our derivative instruments, including a description of our foreign currency hedging activities and related methods used to manage foreign currency exchange rate risk.

       See "Note 8 - Fair Value Measurements" for additional information on the fair value measurement of our financial assets and liabilities.


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   Earnings Per Share

       On January 1, 2009, we adopted certain provisions of FASB ASC 260-10-45 (previously FASB Staff Position EITF 03-6-1, "Determining Whether Instruments Granted in Share-Based Payment Transactions are Participating Securities"). This standard addresses whether instruments granted in share-based payment transactions are participating securities prior to vesting and, therefore, need to be included in the earnings allocation in computing earnings per share ("EPS") under the two-class method. Non-vested share awards granted to our employees and non-employee directors contain nonforfeitable dividend rights and, therefore, are now considered participating securities. We have prepared our current period basic and diluted EPS computations and retrospectively revised our comparative prior period computations to exclude net income allocated to non-vested share awards.

       The following table is a reconciliation of net income attributable to Ensco shares used in our basic and diluted EPS computations for each of the years in the three-year period ended December 31, 2009 (in millions):
 

    2009      2008  2007
 
Net income attributable to Ensco   $779.4   $1,150.8   $992.0  
Net income allocated to non-vested share awards   (9.7 ) (12.6 ) (7.3 )

Net income attributable to Ensco shares  $769.7   $1,138.2   $984.7  


       The following table is a reconciliation of the weighted-average shares used in our basic and diluted earnings per share computations for each of the years in the three-year period ended December 31, 2009 (in millions):
 

  2009  2008  2007 
               
Weighted-average shares - basic   140.4   141.6   146.7  
Potentially dilutive share options  .1   .3   .5  

Weighted-average shares - diluted  140.5   141.9   147.2  


       Antidilutive share options totaling 1.1 million, 746,000 and 503,000 were excluded from the computation of diluted EPS for the years ended December 31, 2009, 2008 and 2007, respectively.

   Noncontrolling Interests

       On January 1, 2009, we adopted certain provisions of FASB ASC 810-10 (previously SFAS No. 160, "Noncontrolling Interests in Consolidated Financial Statements"). This standard clarifies that a noncontrolling interest should be reported as equity in the consolidated financial statements and requires net income attributable to both the parent and the noncontrolling interest to be disclosed separately on the face of the consolidated statement of income. These presentation and disclosure provisions required retrospective application to all prior periods presented.

       Noncontrolling interests are classified as equity on our consolidated balance sheet and net income attributable to noncontrolling interests is presented separately on our consolidated statement of income. In our Asia Pacific operating segment, local third parties hold a noncontrolling ownership interest in three of our subsidiaries. No changes in the ownership interests of these subsidiaries occurred during the three-year period ended December 31, 2009.

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       Income from continuing operations attributable to Ensco for each of the years in the three-year period ended December 31, 2009 was as follows (in millions):
 

  2009    2008  2007 
 
Income from continuing operations   $780.9   $1,159.8   $970.1  
Income from continuing operations attributable to
   noncontrolling interests
  (5.1 ) (5.9 ) (6.9 )

Income from continuing operations attributable to Ensco  $775.8   $1,153.9   $963.2  


       Income (loss) from discontinued operations, net, for each of the years in the three-year period ended December 31, 2009 was attributable to Ensco.

2.  PROPERTY AND EQUIPMENT

       Property and equipment as of December 31, 2009 and 2008 consisted of the following (in millions):

 
   2009     2008 
 
Drilling rigs and equipment $ 4,801.1 $ 3,829.8  
Other  47.0   45.5  
Work in progress  1,303.1   1,501.0  

  $ 6,151.2 $ 5,376.3  


       Work in progress as of December 31, 2009 primarily consisted of $1,262.5 million related to the construction of our ENSCO 8500 Series® ultra-deepwater semisubmersible rigs and costs associated with various modification and enhancement projects. ENSCO 8502 was delivered in January 2010 and the related construction costs will remain classified as work in progress until the rig is placed into service during the third quarter of 2010. Work in progress as of December 31, 2008 primarily consisted of $1,445.2 million related to the construction of our ENSCO 8500 Series® rigs and costs associated with various modification and enhancement projects.

3.  LONG-TERM INVESTMENTS

       As of December 31, 2009 and 2008, we held $66.8 million and $72.3 million (par value), respectively, of long-term debt instruments with variable interest rates that periodically reset through an auction process ("auction rate securities"). Our auction rate securities were originally acquired in January 2008 and have final maturity dates ranging from 2025 to 2047.

       Auctions for our auction rate securities began to fail in February 2008 as there were more sellers than buyers at the scheduled interest rate auctions and parties desiring to sell their auction rate securities were unable to do so. When an auction fails, the interest rate is adjusted according to the provisions of the associated security agreement. Through December 31, 2009, auctions for our auction rate securities continued to fail with the exception of the successful auction of $4.7 million of our securities during June 2008. Auction rate securities totaling $5.5 million and $6.0 million were redeemed at par during the years ended December 31, 2009 and 2008, respectively. Additionally, $2.5 million of our auction rate securities were redeemed at par in January 2010.


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       Our investments in auction rate securities as of December 31, 2009 were diversified across fifteen separate issues and each issue maintains scheduled interest rate auctions in either 28-day or 35-day intervals. The majority of our auction rate securities are currently rated Aaa by Moody's, AAA by Standard & Poor's and/or AAA by Fitch. An aggregate $64.3 million (par value), or 96%, of our auction rate securities were issued by state agencies and are supported by student loans for which repayment is substantially guaranteed by the U.S. government under the Federal Family Education Loan Program ("FFELP").

       Upon acquisition in January 2008, we designated our auction rate securities as trading securities as it was our intent to sell them in the near-term. Due to illiquidity in the auction rate securities market, we intend to hold our auction rate securities until they can be redeemed by issuers, repurchased by brokerage firms or sold in a market that facilitates orderly transactions. Although we will hold our auction rate securities longer than originally anticipated, we continue to designate them as trading securities.

       Our auction rate securities were measured at fair value as of December 31, 2009 and 2008, and net unrealized gains of $1.8 million and unrealized losses of $8.1 million were included in other income (expense), net, in our consolidated statements of income for the years ended December 31, 2009 and 2008, respectively. See "Note 8 - Fair Value Measurements" for additional information on the fair value measurement of our auction rate securities.

       The carrying value of our auction rate securities was $60.5 million and $64.2 million as of December 31, 2009 and 2008, respectively. We are currently unable to determine whether issuers of our auction rate securities will attempt and/or be able to refinance them and have classified our auction rate securities as long-term investments on our consolidated balance sheets. Cash flows from purchases and sales of our auction rate securities are classified as operating activities in our consolidated statement of cash flows.

4.  LONG-TERM DEBT

       Long-term debt as of December 31, 2009 and 2008 consisted of the following (in millions):

 
          2009   2008  
           
7.20% Debentures due 2027  $148.9   $148.8  
6.36% Bonds due 2015   76.0   88.7  
4.65% Bonds due 2020   49.5   54.0  

    274.4   291.5  
Less current maturities  (17.2 ) (17.2 )

Total long-term debt   $257.2   $274.3  


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    Debentures Due 2027

       In November 1997, Ensco Delaware issued $150.0 million of unsecured 7.20% Debentures due November 15, 2027 (the "Debentures") in a public offering. Interest on the Debentures is payable semiannually in May and November and may be redeemed at any time at our option, in whole or in part, at a price equal to 100% of the principal amount thereof plus accrued and unpaid interest, if any, and a make-whole premium. The indenture under which the Debentures were issued contains limitations on the incurrence of indebtedness secured by certain liens and limitations on engaging in certain sale/leaseback transactions and certain merger, consolidation or reorganization transactions. The Debentures are not subject to any sinking fund requirements. On December 22, 2009, in connection with the redomestication, Ensco International plc entered into a supplemental indenture to unconditionally guarantee the principal and interest payments on the Debentures.

    Bonds Due 2015 and 2020

       In January 2001, a subsidiary of Ensco Delaware issued $190.0 million of 15-year bonds to provide long-term financing for ENSCO 7500. The bonds will be repaid in 30 equal semiannual principal installments of $6.3 million ending in December 2015. Interest on the bonds is payable semiannually, in June and December, at a fixed rate of 6.36%. In October 2003, a subsidiary of Ensco Delaware issued $76.5 million of 17-year bonds to provide long-term financing for ENSCO 105. The bonds will be repaid in 34 equal semiannual principal installments of $2.3 million ending in October 2020. Interest on the bonds is payable semiannually, in April and October, at a fixed rate of 4.65%.

       Both bond issuances are guaranteed by the United States of America, acting by and through the United States Department of Transportation, Maritime Administration ("MARAD"), and Ensco Delaware issued separate guaranties to MARAD, guaranteeing the performance of obligations under the bonds. On February 19, 2010, the documents governing MARAD's guarantee commitments were amended to address certain changes arising from the redomestication and to include Ensco International plc as an additional guarantor of the debt obligations.

    Revolving Credit Facility

       In June 2005, Ensco Delaware executed a $350.0 million unsecured revolving credit facility (the "Credit Facility") with a syndicate of lenders for a five-year term, expiring in June 2010. The Credit Facility was amended on December 22, 2009 to address certain changes arising from the redomestication and to include Ensco International plc as an additional guarantor.

       Advances under the Credit Facility bear interest at LIBOR plus an applicable margin rate (currently .35% per annum), depending on our credit rating. We pay a facility fee (currently .10% per annum) on the total $350.0 million commitment, which is also based on our credit rating, and pay an additional utilization fee on outstanding advances if such advances equal or exceed 50% of the total $350.0 million commitment. We had no amounts outstanding under the Credit Facility as of December 31, 2009 and 2008.

    Maturities

       The aggregate maturities of our long-term debt, excluding unamortized discounts of $1.1 million, as of December 31, 2009 were as follows (in millions):

   
2010       $ 17.2
2011         17.2
2012         17.2
2013         17.2
2014         17.2
Thereafter         189.5

Total       $ 275.5


       Interest expense totaled $20.9 million, $21.6 million and $32.3 million for the years ended December 31, 2009, 2008 and 2007, respectively. All interest expense incurred during the years ended December 31, 2009 and 2008 was capitalized in connection with the construction of our ENSCO 8500 Series® rigs. During the year ended December 31, 2007, $30.4 million of interest expense was capitalized.

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5.  DERIVATIVE INSTRUMENTS

       On January 1, 2009, we adopted certain disclosure provisions of FASB ASC 815-10-50 (previously SFAS No. 161, "Disclosures about Derivative Instruments and Hedging Activities"). These provisions require enhanced disclosures about (a) how and why an entity uses derivative instruments, (b) how derivative instruments and related hedged items are accounted for under FASB ASC 815 (previously SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities") and (c) how derivative instruments and related hedged items affect an entity's financial position, operating results and cash flows.

       We use derivatives to reduce our exposure to various market risks, primarily foreign currency exchange rate risk. We maintain a foreign currency risk management strategy that utilizes derivatives to reduce our exposure to unanticipated fluctuations in earnings and cash flows caused by changes in foreign currency exchange rates. Although no interest rate related derivative instruments were outstanding as of December 31, 2009 and 2008, we occasionally employ an interest rate risk management strategy that utilizes derivative instruments to minimize or eliminate unanticipated fluctuations in earnings and cash flows arising from changes in, and volatility of, interest rates. We minimize our credit risk relating to the counterparties of our derivatives by transacting with multiple, high-quality financial institutions, thereby limiting exposure to individual counterparties, and by monitoring the financial condition of our counterparties. We do not enter into derivatives for trading or other speculative purposes.

       All derivatives were recorded on our consolidated balance sheets at fair value. Accounting for the gains and losses resulting from changes in the fair value of derivatives depends on the use of the derivative and whether it qualifies for hedge accounting. See "Note 1 - Description of the Business and Summary of Significant Accounting Policies" for additional information on how derivatives are accounted for under FASB ASC 815.

       As of December 31, 2009 and 2008, our consolidated balance sheets included net foreign currency derivative assets of $13.2 million and net foreign currency derivative liabilities of $20.3 million, respectively. See "Note 8 - Fair Value Measurements" for additional information on the fair value measurement of our derivatives. Derivatives recorded at fair value on our consolidated balance sheets as of December 31, 2009 and 2008 consisted of the following (in millions):
 

                        Assets                                      Liabilities              
             2009            2008             2009            2008   
Derivatives Designated as Hedging Instruments                                        
Foreign currency forward contracts - current(1)             $10.2               $  .3                $1.1                $25.8        
Foreign currency forward contracts - non-current(2)             3.8               5.1                --                .0        

              14.0               5.4                1.1                25.8        

Derivatives not Designated as Hedging Instruments                                        
Foreign currency forward contracts - current(1)               .3                 .1                  .0                    .0        

                .3                 .1                  .0                    .0        

Total             $14.3               $5.5                $1.1                $25.8        

 
(1)   Derivative assets and liabilities that have maturity dates equal to or less than twelve months from the respective balance sheet dates were included in other current assets and accrued liabilities and other, respectively, on our consolidated balance sheets.
(2)   Derivative assets and liabilities that have maturity dates greater than twelve months from the respective balance sheet dates were included in other assets, net, and other liabilities, respectively, on our consolidated balance sheets.


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       We utilize derivatives to hedge forecasted foreign currency denominated transactions ("cash flow hedges"), primarily to reduce our exposure to foreign currency exchange rate risk associated with the portion of our remaining ENSCO 8500 Series® construction obligations denominated in Singapore dollars and contract drilling expenses denominated in various other currencies. As of December 31, 2009, we had cash flow hedges outstanding to exchange an aggregate $288.5 million for various currencies, including $195.9 million for Singapore dollars, $54.1 million for British pounds, $25.4 million for Australian dollars and $13.1 million for other currencies.

       Gains and losses on derivatives designated as cash flow hedges included in our consolidated statements of income for each of the years in the three-year period ended December 31, 2009 were as follows (in millions):
 

  Gain (Loss)
Recognized in
Other Comprehensive
Income (Loss) ("OCI")
on Derivatives
          (Effective Portion)          
(Loss) Gain
Reclassified
from AOCI
into Income
        (Effective Portion)        
(Loss) Gain Recognized
in Income on
Derivatives (Ineffective
Portion and Amount
Excluded from
Effectiveness Testing)
(1)
  2009   2008   2007   2009   2008   2007   2009   2008   2007
 
Foreign currency forward contracts(2) $13.5      $(16.4)     $8.2      $(8.0)     $(2.9)     $ 7.9      $(2.9)     $(1.0)     $ .7   
Interest rate lock contracts(3) --      --      --      (.7)     (.7)     (1.0)     --      --      --   

Total $13.5      $(16.4)     $8.2      $(8.7)     $(3.6)     $ 6.9      $(2.9)     $(1.0)     $ .7   

 
(1)   Gains and losses recognized in income for ineffectiveness and amounts excluded from effectiveness testing were included in other income (expense), net, in our consolidated statements of income.
(2)   Gains and losses on derivative instruments reclassified from AOCI into income (effective portion) were included in contract drilling expense in our consolidated statements of income.
(3)   Losses on derivatives reclassified from AOCI into income (effective portion) were included in other income (expense), net, in our consolidated statements of income.


       We have net assets and liabilities denominated in numerous foreign currencies and use various methods to manage our exposure to foreign currency exchange rate risk. We predominantly structure our drilling contracts in U.S. dollars, which significantly reduces the portion of our cash flows and assets denominated in foreign currencies. We occasionally enter into derivatives that hedge the fair value of recognized foreign currency denominated assets or liabilities but do not designate such derivatives as hedging instruments. In these situations, a natural hedging relationship generally exists whereby changes in the fair value of the derivatives offset changes in the fair value of the underlying hedged items. As of December 31, 2009, we had derivatives not designated as hedging instruments outstanding to exchange an aggregate $61.5 million for various currencies, including $20.7 million for Singapore dollars, $17.7 million for Australian dollars, $9.6 million for British pounds and $13.5 million for other currencies.


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       Net gains of $4.6 million, net losses of $3.5 million and net gains of $2.0 million associated with our derivatives not designated as hedging instruments were included in other income (expense), net, in our consolidated statements of income for the years ended December 31, 2009, 2008 and 2007, respectively.

       If we were to incur a hypothetical 10% adverse change in foreign currency exchange rates, net unrealized losses associated with our foreign currency denominated assets and liabilities and related derivatives as of December 31, 2009 would approximate $27.9 million, including $20.9 million related to our Singapore dollar exposures. All of our outstanding derivatives mature during the next two years.

       As of December 31, 2009, the estimated amount of net gains associated with derivative instruments, net of tax, that will be reclassified to earnings during the next twelve months was as follows (in millions):
 

 
   
Net gains to be reclassified to contract drilling expense $ 3.9  
Net losses to be reclassified to other income (expense), net   (.6 )

Net gains to be reclassified to earnings $ 3.3  

 

6.  COMPREHENSIVE INCOME

       Accumulated other comprehensive income (loss) as of December 31, 2009, 2008 and 2007 was comprised of net gains and losses on derivative instruments, net of tax. The components of our comprehensive income, net of tax, for each of the years in the three-year period ended December 31, 2009 were as follows (in millions):

 
     2009    2008    2007
 
Net Income   $784.5      $1,156.7    $  998.9   
Other comprehensive income:  
     Net change in fair value of derivatives   13.5      (16.4)   8.2   
     Reclassification of unrealized gains and losses on
          derivative instruments from other comprehensive
           loss (income) into net income
  8.7      3.6    (6.9)  

              Net other comprehensive income (loss)  22.2      (12.8)   1.3   

Comprehensive income   806.7      1,143.9    1,000.2   
Comprehensive income attributable to noncontrolling interests   (5.1)     (5.9)   (6.9)  

Comprehensive income attributable to Ensco   $801.6      $1,138.0    $  993.3   


7.  SHAREHOLDERS' EQUITY

       In conjunction with the redomestication in December 2009, each issued and outstanding share of common stock of Ensco Delaware was converted into the right to receive one American depositary share, each representing one Class A ordinary share, par value U.S. $0.10 per share, of Ensco International plc. In total, 150.0 million Class A ordinary shares were issued, with 142.6 million exchanged for shares of common stock of Ensco Delaware. The remaining 7.4 million Class A ordinary shares were held as treasury shares on our December 31, 2009 consolidated balance sheet. Prior to the redomestication, Ensco International plc also issued 50,000 Class B ordinary shares, par value £1 per share, to Ensco Delaware. The Class B ordinary shares have no voting rights or rights to dividends or distributions.

       Prior to the redomestication, Ensco Delaware retired 40.2 million treasury shares with a historical cost totaling $1,203.9 million under authorization from our Board of Directors. Pursuant to its certificate of incorporation in effect prior to the redomestication, Ensco Delaware had 20.0 million authorized shares of preferred stock, U.S. $1 par value, and none had been issued as of December 31, 2008.


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       Activity in our various shareholders' equity accounts for each of the years in the three-year period ended December 31, 2009 was as follows (in millions):
 

          Accumulated    
          Other    
      Additional   Comprehensive    
    Paid-In   Retained Income Treasury      Noncontrolling
   Shares   Par Value      Capital      Earnings     (Loss)        Shares           Interest   
                               

BALANCE, December 31, 2006   178.7      $17.9      $1,621.3       $1,994.5   $  (5.5)       $  (412.2)    $ 3.4      
  Cumulative effect of adoption of FIN 48   --    --    --    5.8   --        --     --      
  Net income   --    --    --    992.0   --        --     6.9      
  Cash dividends paid   --    --    --    (14.8 ) --        --     --      
  Distributions to noncontrolling interests   --    --    --    --   --        --     (5.7)     
  Shares issued under share-based compensation                              
    plans, net   1.6    .1    35.7    --   --        --     --      
  Tax benefit from share-based                              
    compensation   --    --    6.6    --   --        --     --      
  Repurchase of shares   --    --    --    --   --        (527.6)    --      
  Share-based compensation cost   --    --    36.9    --   --        --     --      
  Net other comprehensive income   --    --    --    --   1.3        --     --      

BALANCE, December 31, 2007   180.3    18.0    1,700.5    2,977.5   (4.2)       (939.8)    4.6      
  Net income   --    --    --    1,150.8   --        --     5.9      
  Cash dividends paid   --    --    --    (14.3 ) --        --      --      
  Distributions to noncontrolling interests   --    --    --    --   --        --     (3.8)     
  Shares issued under share-based compensation                              
    plans, net   1.6    .2    27.1    --   --        --     --      
  Tax benefit from share-based                              
    compensation   --    --    5.3    --   --        --     --      
  Repurchase of shares   --    --    --    --   --        (259.7)    --      
  Share-based compensation cost   --    --    28.3    --   --        --     --      
  Net other comprehensive loss   --    --    --    --   (12.8)       --     --      

BALANCE, December 31, 2008   181.9    18.2    1,761.2    4,114.0   (17.0)       (1,199.5)    6.7      
  Net income   --    --    --    779.4   --        --     5.1      
  Cash dividends paid   --    --    --    (14.2 ) --        --     --      
  Distributions to noncontrolling interests   --    --    --    --   --        --     (3.9)     
  Shares issued under share-based compensation                              
    plans, net   .9    .1    9.5    --   --        --     --      
  Tax deficiency from share-based                              
    compensation   --    --    (2.4)   --   --        --     --      
  Repurchase of shares   --    --    --    --   --        (6.5)    --      
  Retirement of treasury shares   (40.2)   (4.0)   (1,200.0)   --   --        1,203.9     --      
  Share-based compensation cost   --    --    34.3    --   --        --     --      
  Net other comprehensive income   --    --    --    --   22.2        --     --      
  Cancellation of shares of common stock
     during redomestication
  (142.6)   (14.3)   --    --   --        --     --      
  Issuance of ordinary shares pursuant
     to the redomestication
  150.1    15.1    --    --   --        (.8)    --      

BALANCE, December 31, 2009   150.1    $ 15.1    $   602.6    $4,879.2   $     5.2       $    (2.9)    $ 7.9      


       The Board of Directors previously authorized the repurchase of up to $1,500.0 million of our shares. From inception of our share repurchase programs during 2006 through December 31, 2008, we repurchased an aggregate 16.5 million shares at a cost of $937.6 million (an average cost of $56.79 per share). No shares were repurchased under the share repurchase programs during 2009. In December 2009, in conjunction with the redomestication, the remaining repurchase authorization was extended authorizing management to repurchase up to $562.4 million of ADSs from time to time pursuant to share repurchase agreements with two investment banks. Although such amount remained available for repurchase as of December 31, 2009, the Company will not repurchase any shares without further consultation with and approval by the Board of Directors of Ensco International plc.


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8.  FAIR VALUE MEASUREMENTS

       The following fair value hierarchy table categorizes information regarding our financial assets and liabilities measured at fair value on a recurring basis as of December 31, 2009 and 2008 (in millions):
 

  Quoted Prices in   Significant    
  Active Markets   Other Significant  
  for   Observable Unobservable  
  Identical Assets   Inputs Inputs  
      (Level 1)           (Level 2)        (Level 3)         Total  
 
As of December 31, 2009                            
 
Auction rate securities       $    --         $    --       $60.5                $60.5  
Supplemental executive retirement plan assets       18.7         --       --                18.7  
Derivatives, net       --         13.2       --                13.2  

Total financial assets       $18.7         $13.2       $60.5                $92.4  

 
As of December 31, 2008                            
 
Auction rate securities       $    --         $    --       $64.2                $64.2  
Supplemental executive retirement plan assets       13.9         --       --                13.9  

Total financial assets       $13.9         $    --       $64.2                $78.1  

 
Derivatives, net       $    --         $20.3       $   --                 $20.3  

Total financial liabilities       $    --         $20.3       $   --                 $20.3  


    Auction Rate Securities

       As of December 31, 2009 and 2008, we held long-term debt instruments with variable interest rates that periodically reset through an auction process totaling $66.8 million and $72.3 million (par value), respectively. These auction rate securities were classified as long-term investments on our consolidated balance sheets. Our auction rate securities were originally acquired in January 2008 and have maturity dates ranging from 2025 to 2047. Our auction rate securities were measured at fair value on a recurring basis using significant Level 3 inputs as of December 31, 2009 and 2008. The following table summarizes the fair value measurements of our auction rate securities using significant Level 3 inputs, and changes therein, for each of the years in the two-year period ended December 31, 2009 (in millions):
 

    2009               2008  
 
Beginning Balance   $64.2    $     --   
    (Sales) purchases, net   (5.5)   72.3   
    Unrealized gains (losses)*   1.8    (8.1)  
    Realized losses   --    --   
    Transfers in and/or out of Level 3   --    --   

Ending balance   $60.5    $64.2   

 
* Unrealized gains (losses) are included in other income (expense), net, in our consolidated statement of income.


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       Before utilizing Level 3 inputs in our fair value measurements, we considered whether observable inputs were available. As a result of continued auction failures, quoted prices for our auction rate securities did not exist as of December 31, 2009. Accordingly, we concluded that Level 1 inputs were not available. Brokerage statements received from the five broker/dealers that held our auction rate securities included their estimated market value as of December 31, 2009. Four broker/dealers valued our auction rate securities at par and the fifth valued our auction rate securities at 88% of par. Due to the lack of transparency into the methodologies used to determine the estimated market values, we have concluded that estimated market values provided on our brokerage statements do not constitute valid inputs, and we do not utilize them in measuring the fair value of our auction rate securities.

       We determined that use of a valuation model was the best available technique for measuring the fair value of our auction rate securities. We used an income approach valuation model to estimate the price that would be received in exchange for our auction rate securities in an orderly transaction between market participants ("exit price") as of December 31, 2009. The exit price was derived as the weighted-average present value of expected cash flows over various periods of illiquidity, using a risk-adjusted discount rate that was based on the credit risk and liquidity risk of our auction rate securities.

       While our valuation model was based on both Level 2 (credit quality and interest rates) and Level 3 inputs, we determined that our Level 3 inputs were significant to the overall fair value measurement of our auction rate securities, particularly the estimates of risk-adjusted discount rates and ranges of expected periods of illiquidity. We believe that we have the ability to maintain our investment in these securities until they are redeemed, repurchased or sold in a market that facilitates orderly transactions.

    Supplemental Executive Retirement Plan Assets and Liabilities

       The ENSCO Supplemental Executive Retirement Plans (the "SERP") are non-qualified plans where eligible employees and non-employee directors may defer a portion of their compensation for use after retirement. Assets held in the SERP were marketable securities measured at fair value on a recurring basis using Level 1 inputs and were included in other assets, net, on our consolidated balance sheets as of December 31, 2009 and 2008. The fair value measurement of assets held in the SERP was based on quoted market prices.

    Derivatives

       Our derivatives were measured at fair value on a recurring basis using Level 2 inputs as of December 31, 2009 and 2008. See "Note 5 - Derivative Instruments" for additional information on our derivatives, including a description of our foreign currency hedging activities and related methodologies used to manage foreign currency exchange rate risk. The fair value measurement of our derivatives was based on market prices that are generally observable for similar assets or liabilities at commonly quoted intervals.

    Other Financial Instruments

       The carrying values and estimated fair values of our debt instruments as of December 31, 2009 and 2008 were as follows (in millions):
 

  December 31, December 31,
                   2009                                 2008                
    Estimated   Estimated
  Carrying   Fair Carrying   Fair
    Value      Value     Value      Value  
       
7.20% Debentures  $148.9        $155.9        $148.8        $140.3       
6.36% Bonds, including current maturities  76.0        85.8        88.7        103.9       
4.65% Bonds, including current maturities  49.5        53.8        54.0        62.1       


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       The estimated fair value of our 7.20% Debentures was determined using quoted market prices. The estimated fair values of our 6.36% Bonds and 4.65% Bonds were determined using an income approach valuation model. The estimated fair value of our cash and cash equivalents, receivables, trade payables and other liabilities approximated their carrying values as of December 31, 2009 and 2008.

9.  BENEFIT PLANS

    Non-Vested Share Awards

       During 2005, our shareholders approved the 2005 Long-Term Incentive Plan (the "LTIP") to provide for the issuance of non-vested share awards, share option awards and performance awards. Under the LTIP, 10.0 million shares were reserved for issuance as awards to officers, non-employee directors and key employees who are in a position to contribute materially to our growth, development and long-term success. The LTIP originally provided for the issuance of non-vested share awards up to a maximum of 2.5 million new shares. In May 2009, our shareholders approved an amendment to the LTIP to increase the maximum number of non-vested share awards from 2.5 million to 6.0 million. As of December 31, 2009, there were 3.3 million shares available for issuance of non-vested share awards under the LTIP. Non-vested share awards may be issued as new shares or issued out of treasury at the Company's discretion.

       Under the LTIP, grants of non-vested share awards generally vest at rates of 20% or 33% per year, as determined by a committee or subcommittee of the Board of Directors. Prior to the adoption of the LTIP, non-vested share awards were issued under a predecessor plan and generally vested at a rate of 10% per year. All non-vested share awards have voting and dividend rights effective on the date of grant. Compensation expense is measured using the market value of our shares on the date of grant and is recognized on a straight-line basis over the requisite service period (usually the vesting period).

       During 2007, we entered into a retirement agreement with our former CEO and non-executive Chairman of our Board of Directors. The agreement provided that, upon retirement, he would receive a grant of 92,000 non-vested share awards which vest at a rate of one-third per year upon each of the first three anniversaries of his retirement date. Furthermore, the agreement modified the vesting term of 28,750 unvested share options and 105,000 non-vested share awards previously granted to him so that such awards vested upon his retirement. We recognized an additional $10.4 million of non-vested share award compensation expense during 2007 as a result of the retirement agreement, of which $5.0 million related to the modification of his previous awards.


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       The following table summarizes non-vested share award related compensation expense recognized during each of the years in the three-year period ended December 31, 2009 (in millions):

 

       2009          2008          2007  
 
Contract drilling   $16.8     $11.4     $  5.5    
General and administrative   11.4   7.6   17.5  

Non-vested share award related compensation expense              
   included in operating expenses   28.2   19.0   23.0  
Tax benefit   (7.0 ) (4.7 ) (7.1 )

Total non-vested share award related compensation              
   expense included in net income   $21.2   $14.3   $15.9  

 

       The following table summarizes the value of non-vested share awards granted and vested during each of the years in the three-year period ended December 31, 2009:

 
    2009     2008     2007  
 
Weighted-average grant-date fair value of                    
   non-vested share awards granted (per share)   $40.91   $67.99   $60.18  
Total fair value of non-vested share awards              
   vested during the period (in millions)   $18.6     $17.9     $19.8    


       The following table summarizes non-vested share award activity for the year ended December 31, 2009 (shares in thousands):

    Weighted-
    Average
    Grant-Date
  Shares Fair Value
 
Non-vested as of January 1, 2009   1,755   $60.27    
   Granted  613   40.91    
   Vested  (495 ) 58.89    
   Forfeited  (62 ) 56.94    

Non-vested as of December 31, 2009  1,811   $54.21    

 

       As of December 31, 2009, there was $78.0 million of total unrecognized compensation cost related to non-vested share awards, which is expected to be recognized over a weighted-average period of 3.2 years.


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   Share Option Awards

       Under the LTIP, share option awards ("options") may be issued to our officers, non-employee directors and key employees who are in a position to contribute materially to our growth, development and long-term success. A maximum 7.5 million shares were reserved for issuance as options under the LTIP. Options granted to officers and employees generally become exercisable in 25% increments over a four-year period or 33% increments over a three-year period and, to the extent not exercised, expire on the seventh anniversary of the date of grant. Options granted to non-employee directors are immediately exercisable and, to the extent not exercised, expire on the seventh anniversary of the date of grant. The exercise price of options granted under the LTIP equals the market value of the underlying shares on the date of grant. As of December 31, 2009, options to purchase 1.2 million shares were outstanding under the LTIP and 5.3 million shares were available for issuance as options. Upon option exercise, new shares may be issued or shares may be issued out of treasury at the Company's discretion.

       The following table summarizes option related compensation expense recognized during each of the years in the three-year period ended December 31, 2009 (in millions):

 
    2009      2008      2007   
 
Contract drilling   $  1.7      $  3.3      $  5.8      
General and administrative   3.7      5.0      7.8    

Option related compensation expense included in              
   operating expenses   5.4      8.3      13.6    
Tax benefit   (1.6)     (2.3)     (3.8)   

Total option related compensation expense included              
   in net income    $  3.8       $  6.0       $  9.8    


       The fair value of each option is estimated on the date of grant using the Black-Scholes option valuation model. The following weighted-average assumptions were utilized in the Black-Scholes model for each of the years in the three-year period ended December 31, 2009:
 

         2009          2008          2007  
 
Risk-free interest rate   1.8 % -- 4.8 %
Expected term (in years)   3.9   --   4.7  
Expected volatility   53.3 % --   29.8 %
Dividend yield   .2 % --   .2 %


       Expected volatility is based on the historical volatility in the market price of our shares over the period of time equivalent to the expected term of the options granted. The expected term of options granted is derived from historical exercise patterns over a period of time equivalent to the contractual term of the options granted. We have not experienced significant differences in the historical exercise patterns among officers, employees and non-employee directors for them to be considered separately for valuation purposes. The risk-free interest rate is based on the implied yield of U.S. Treasury zero-coupon issues on the date of grant with a remaining term approximating the expected term of the options granted.


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       The following table summarizes option activity for the year ended December 31, 2009 (shares and intrinsic value in thousands, term in years):

 
    Weighted- Weighted-  
    Average Average  
      Exercise Contractual Intrinsic
  Shares      Price           Term      Value
 
Outstanding as of January 1, 2009   1,544   $45 .15        
        Granted  115   41 .29        
        Exercised  (344 ) 28 .03        
        Forfeited  (48 ) 52 .06        
        Expired  (54 ) 53 .60        

Outstanding as of December 31, 2009  1,213   $48 .98 3 .8 $1,043     

Exercisable as of December 31, 2009  794   $47 .87 3 .4 $1,043     

 

       The following table summarizes the value of options granted and exercised during each of the years in the three-year period ended December 31, 2009:

 
    2009       2008       2007    
 
Weighted-average grant-date fair value of                    
   options granted (per share)   $17.17   $   --    $20.44  
Intrinsic value of options exercised during              
   the year (in millions)   $  3.6     $25.5   $30.0    


       The following table summarizes information about options outstanding as of December 31, 2009 (shares in thousands):

 
                                        Options Outstanding                                             Options Exercisable            
       Weighted-Average      
  Number      Remaining Weighted-Average Number Weighted-Average
   Exercise Prices Outstanding   Contractual Life     Exercise Price     Exercisable    Exercise Price   
                       
 $23.12  - $33.55   163    2.4 years    $33.54   163      $33.54     
   41.29  -   47.12   381    4.2 years    45.10   228      46.48     
   50.09  -   52.82   369    3.5 years    50.31   243      50.32     
   57.38  -   60.74   300    4.4 years    60.67   160      60.69     

  1,213    3.8 years    $48.98   794      $47.87     

 

       As of December 31, 2009, there was $4.7 million of total unrecognized compensation cost related to options, which is expected to be recognized over a weighted-average period of 1.5 years.


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Performance Awards

       On November 3, 2009, our Board of Directors approved amendments to the LTIP which, among other things, provide for a type of performance award payable in Ensco shares, cash or a combination thereof upon attainment of specified performance goals based on relative total shareholder return and absolute and relative return on capital employed. The performance goals are determined by a committee or subcommittee of the Board of Directors. The LTIP provides for the issuance of up to a maximum of 2.5 million new shares for the payment of performance awards, all of which were available for the payment of performance awards as of December 31, 2009. Performance awards that are paid in Ensco shares may be issued as new shares or issued out of treasury at the Company's discretion.

       In November 2009, performance awards were issued to certain of our officers who are in a position to contribute materially to our growth, development and long-term success. Performance awards generally vest at the end of a three-year measurement period based on attainment of performance goals. Our performance awards are liability awards with compensation expense measured based on the estimated probability of attainment of the specified performance goals and recognized on a straight-line basis over the requisite service period. The estimated probable outcome of attainment of the specified performance goals is based on historical experience and any subsequent changes in this estimate are recognized as a cumulative adjustment to compensation cost in the period in which the change in estimate occurs.

       We recognized $1.9 million of compensation expense for performance awards during the year ended December 31, 2009, which was included in general and administrative expense in our consolidated statement of income. No performance award compensation expense was recognized during the years ended December 31, 2008 and 2007. As of December 31, 2009, there was $11.2 million of total unrecognized compensation cost related to unvested performance awards, which is expected to be recognized over a weighted-average period of 1.5 years.

    Savings Plan

       We have a profit sharing plan (the “ENSCO Savings Plan”) which covers eligible employees, as defined. Profit sharing contributions require Board of Directors approval and may be paid in cash or shares. We recorded profit sharing contribution provisions of $14.2 million, $16.6 million and $14.2 million for the years ended December 31, 2009, 2008 and 2007, respectively.

       The ENSCO Savings Plan includes a 401(k) savings plan feature which allows eligible employees to make tax deferred contributions to the plan. We generally make matching cash contributions that vest over a three-year period based on the amount of employee contributions and rates set by our Board of Directors. We match 100% of the amount contributed by the employee up to a maximum of 5% of eligible salary. Matching contributions totaled $4.1 million, $5.0 million and $5.0 million for the years ended December 31, 2009, 2008 and 2007, respectively. We have 1.0 million shares reserved for issuance as matching contributions under the ENSCO Savings Plan.

10.  INCOME TAXES

       Ensco Delaware, our predecessor company, was domiciled in the U.S. and subject to a statutory rate of 35% through December 23, 2009, the effective date of the redomestication. We were subject to the U.K. statutory rate of 28% for the remaining nine days of 2009. The income tax information for the years ended December 31, 2009, 2008 and 2007 has been presented from the perspective of an enterprise domiciled in the U.S.

       We generated $286.5 million, $383.2 million and $319.5 million of income from continuing operations before income taxes in the U.S. and $672.8 million, $1,013.9 million and $895.4 million of income from continuing operations before income taxes in non-U.S. countries for the years ended December 31, 2009, 2008 and 2007, respectively.


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       The following table summarizes components of the provision for income taxes from continuing operations for each of the years in the three-year period ended December 31, 2009 (in millions):

 
    2009     2008      2007 
               
Current income tax expense:              
      U.S.  $  63.8   $113.8   $101.3  
      Non-U.S.  94.8   117.1   142.4  

   158.6   230.9   243.7  

 
Deferred income tax expense (benefit): 
      U.S.  24.2   11.7   5.0  
      Non-U.S.  (4.4 ) (5.3 ) (3.9 )

   19.8   6.4   1.1  

 
      Total income tax expense  $178.4   $237.3   $244.8  

 

       The following table summarizes significant components of deferred income tax assets (liabilities) as of December 31, 2009 and 2008 (in millions):

   2009       2008   
           
Deferred tax assets:          
      Deferred revenue  $   34.1   $     9.7  
      Employee benefits, including share-based compensation  25.6   21.2  
      Other  18.3   24.2  

      Total deferred tax assets  78.0   55.1  

Deferred tax liabilities: 
      Property and equipment  (348.9 ) (320.2 )
      Intercompany transfers of property   (45.5 ) (36.6 )
      Deferred costs  (23.5 ) (18.5 )
      Other  (7.7 ) (.4 )

      Total deferred tax liabilities  (425.6 ) (375.7 )

           Net deferred tax liability  $(347.6 ) $(320.6 )

         
Net current deferred tax asset  $   29.7   $   19.9  
Net noncurrent deferred tax liability  (377.3 ) (340.5 )

          Net deferred tax liability  $(347.6 ) $(320.6 )

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       The income tax rates imposed in the taxing jurisdictions in which our non-U.S. subsidiaries conduct operations vary, as does the tax base to which the rates are applied. In some cases, tax rates may be applicable to gross revenues, statutory or negotiated deemed profits or other bases utilized under local tax laws, rather than to net income. In addition, our drilling rigs frequently move from one taxing jurisdiction to another. As a result, our consolidated effective income tax rate may vary substantially from year-to-year, depending on the relative components of our earnings generated in taxing jurisdictions with higher tax rates and lower tax rates.

       In December 2009, we incurred an $8.8 million current income tax expense in connection with certain restructuring activities undertaken immediately following our redomestication. Our consolidated effective income tax rate on continuing operations for each of the years in the three-year period ended December 31, 2009, differs from the U.S. statutory income tax rate as follows:
 

   2009         2008            2007 
               
U.S. statutory income tax rate   35.0 % 35.0 % 35.0 %
Non-U.S. taxes  (18.1 ) (19.3 ) (14.2 )
Amortization of deferred charges
   associated with intercompany rig sales
  1.7   1.1   (.1 )
Redomestication related income taxes  .9   --   --  
Net (benefit) expense in connection with resolutions             
   of tax issues and adjustments relating to prior years  (.9 ) .5   (.6 )
Other  --   (.3 ) --  

Effective income tax rate  18.6 % 17.0 % 20.1 %

 

    Unrecognized Tax Benefits

       On January 1, 2007, we adopted the recognition and disclosure provisions of FASB ASC 740-10-25 (previously FIN 48, "Accounting for Uncertainty in Income Taxes (as amended)"). Our tax positions are evaluated for recognition using a more-likely-than-not threshold, and those tax positions requiring recognition are measured as the largest amount of tax benefit that is greater than 50% likely of being realized upon effective settlement with a taxing authority that has full knowledge of all relevant information. As a result of adopting this standard, we reported a $5.8 million increase to our January 1, 2007 balance of retained earnings. As of December 31, 2009, we had $17.6 million of unrecognized tax benefits, of which $12.2 million would impact our effective income tax rate if recognized. A reconciliation of the beginning and ending amount of unrecognized tax benefits for the years ended December 31, 2009 and 2008 is as follows (in millions):
 

   2009       2008  
 
Balance, beginning of year   $26.8   $13.5  
   Increases in unrecognized tax benefits as a result
      of tax positions taken during the current year
  2.0   7.2  
   Increases in unrecognized tax benefits as a result
      of tax positions taken during prior years
  --   12.7  
   Decreases in unrecognized tax benefits as a result
      of tax positions taken during prior years
  (2.7 ) (1.3 )
   Settlements with taxing authorities  (8.7 ) (.9 )
   Lapse of applicable statutes of limitations  (.8 ) (3.3 )
   Impact of foreign currency exchange rates  1.0   (1.1 )

Balance, end of year   $17.6   $26.8  


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       Accrued interest and penalties totaled $15.8 million and $12.9 million as of December 31, 2009 and 2008, respectively, and were included in other liabilities on our consolidated balance sheets. We recognized net expense of $3.3 million, net benefits of $6.8 million and net expense of $2.3 million associated with interest and penalties during the years ended December 31, 2009, 2008 and 2007, respectively. Interest and penalties are included in current income tax expense in our consolidated statement of income.

       Tax years as early as 2002 remain subject to examination in the tax jurisdictions in which we operated. We participate in the U.S. Internal Revenue Service's Compliance Assurance Process which, among other things, provides for the resolution of tax issues in a timely manner and generally eliminates the need for lengthy post-filing examinations. Our 2008 and 2009 U.S. federal tax returns remain subject to examination.

       During the third quarter of 2009, in connection with the audit of prior year tax returns, we reached a settlement with the tax authority in one of our non-U.S. jurisdictions which resulted in an $8.7 million reduction in unrecognized tax benefits and a $4.4 million net income tax benefit, inclusive of interest and penalties.

       During 2008, in connection with an examination of a prior period tax return, we recognized a $5.4 million liability for unrecognized tax benefits associated with certain tax positions taken in prior years, which resulted in an $8.9 million net income tax expense, inclusive of interest and penalties.

       During 2008, statutes of limitations applicable to certain of our tax positions lapsed resulting in a $2.9 million decline in unrecognized tax benefits and an $11.5 million net income tax benefit, inclusive of interest and penalties.

       During 2007, new information became available in one of our non-U.S. jurisdictions that enabled us to conclude that an uncertain tax position established in prior years had been effectively settled. As a result, we recognized an aggregate $11.1 million current tax benefit, inclusive of interest and penalties.

       Statutes of limitations applicable to certain of our tax positions will lapse during 2010. Therefore, it is reasonably possible that our unrecognized tax benefits will decline during the next twelve months by $2.4 million, which includes $900,000 of accrued interest and penalties.

    Intercompany Transfer of Drilling Rigs

       In connection with restructuring activities undertaken immediately following the redomestication, we transferred ownership of four of our ENSCO 8500 Series® rigs among two of our subsidiaries in December 2009. The income tax liability resulting from the transfer totaled $30.8 million and will be paid by the selling subsidiary during 2010. The related income tax expense was deferred and is being amortized on a straight-line basis over the remaining useful lives of the associated rigs, which range from 29 to 30 years. Similarly, the tax effects of $45.6 million of reversing temporary differences of the selling subsidiary were also deferred and are being amortized on the same basis and over the same periods as described above.

       In December 2007, we transferred ownership of three drilling rigs among two of our subsidiaries resulting in an income tax liability of $96.5 million which was paid during 2008. The $96.5 million of income taxes paid and the tax effects of $54.8 million of reversing temporary differences of the selling subsidiary were deferred and are being amortized over the remaining useful lives of the related drilling rigs, which ranged from three to eight years.

       As of December 31, 2009 and 2008, the unamortized balance associated with deferred charges for income taxes incurred in connection with intercompany transfers of drilling rigs totaled $99.0 million and $91.3 million, respectively, and was included in other assets, net, on our consolidated balance sheets. Current income tax expense for the years ended December 31, 2009, 2008 and 2007 included $23.1 million, $23.1 million and $2.9 million, respectively, of amortization of income taxes incurred in connection with intercompany transfers of drilling rigs.


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       As of December 31, 2009 and 2008, the deferred tax liability associated with temporary differences of transferred drilling rigs totaled $45.5 million and $36.5 million, respectively, and was included in deferred income taxes on our consolidated balance sheets. Deferred income tax expense for the years ended December 31, 2009, 2008 and 2007 included benefits of $7.0 million, $7.2 million and $3.9 million, respectively, of amortization of deferred reversing temporary differences associated with intercompany transfers of drilling rigs.

    Undistributed Earnings

       We do not provide deferred taxes on the undistributed earnings of Ensco Delaware because our policy and intention is to reinvest such earnings indefinitely or until such time that they can be distributed in a tax-free manner. We do not provide deferred taxes on the undistributed earnings of Ensco Delaware's non-U.S. subsidiaries because our policy and intention is to reinvest such earnings indefinitely.

       During 2007, a non-U.S. subsidiary declared a $1,200.0 million dividend to Ensco Delaware, which included the distribution of its $922.1 million of earnings and the return of $277.9 million of previously invested capital. We utilized foreign tax credits to offset substantially all U.S. tax obligations associated with the 2007 repatriation of earnings by Ensco Delaware's non-U.S. subsidiary.

       The earnings distribution was undertaken because it provided, with minimal U.S. tax impact, substantial funding flexibility for management initiatives, including the continuation and/or extension of our ongoing share repurchase program and greater options relative to future fleet expansion efforts. This distribution was made in consideration of unique circumstances and, accordingly, does not change our intention to reinvest the undistributed earnings of Ensco Delaware's non-U.S. subsidiaries indefinitely. Furthermore, both our U.S. and non-U.S. subsidiaries have significant net assets, liquidity, contract backlog and other financial resources available to meet their operational and capital investment requirements and otherwise allow management to continue to maintain its policy of reinvesting the undistributed earnings of Ensco Delaware and Ensco Delaware's non-U.S. subsidiaries indefinitely.

       As of December 31, 2009, the aggregate undistributed earnings of Ensco Delaware and Ensco Delaware's non-U.S. subsidiaries totaled $2,614.1 million and were indefinitely reinvested. Should we make a distribution in the form of dividends or otherwise, we may be subject to additional income taxes. The unrecognized deferred tax liability related to the undistributed earnings of Ensco Delaware and Ensco Delaware's non-U.S. subsidiaries was $523.1 million as of December 31, 2009.

11.  DISCONTINUED OPERATIONS

    ENSCO 69

       From May 2007 to June 2009, ENSCO 69 was contracted to Petrosucre, a subsidiary of Petróleos de Venezuela S.A., the national oil company of Venezuela ("PDVSA"). During portions of 2008 and 2009, PDVSA subsidiaries reportedly lacked funds and generally were not paying their contractors and service providers. In January 2009, we suspended drilling operations on ENSCO 69 after Petrosucre failed to satisfy its contractual obligations and meet commitments relative to the payment of past due invoices. Petrosucre then took over complete control of ENSCO 69 drilling operations utilizing Petrosucre employees and a portion of the Venezuelan rig crews we had utilized. Petrosucre initially advised us that it was temporarily taking over operations on the rig, and our supervisory rig personnel remained onboard to observe Petrosucre's operations.

       On June 4, 2009, after Petrosucre's failure to satisfy its contractual payment obligations, failure to reach a mutually acceptable agreement with us and denial of our request to demobilize ENSCO 69 from Venezuela, Petrosucre advised that it would not return the rig and would continue to operate it without our consent. Petrosucre further advised that it would release ENSCO 69 after a six-month period, subject to a mutually agreed accord addressing the resolution of all remaining obligations under the ENSCO 69 drilling contract. On June 6, 2009, we terminated our contract with Petrosucre and removed all remaining Ensco employees from the rig.


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       Due to Petrosucre's failure to satisfy its contractual obligations and meet payment commitments, and in consideration of the Venezuelan government's recent nationalization of assets owned by international oil and gas companies and oilfield service companies, we concluded it was remote that ENSCO 69 would be returned to us by Petrosucre and operated again by Ensco. Therefore, we recorded the disposal of ENSCO 69 during the second quarter of 2009 and recognized a pre-tax loss of $18.1 million representing the rig's net book value of $17.3 million and inventory and other assets totaling $800,000. The disposal was classified as loss on disposal of discontinued operations, net, in our consolidated statement of income for the year ended December 31, 2009. ENSCO 69 operating results were reclassified as discontinued operations in our consolidated statements of income for each of the years in the three-year period ended December 31, 2009.

       In November 2009, we executed an agreement with Petrosucre to mitigate our losses and resolve issues relative to outstanding amounts owed by Petrosucre for drilling operations performed by Ensco through the date of termination of the drilling contract in June 2009 (the "agreement"). Although ENSCO 69 will continue to be fully controlled and operated by Petrosucre, the agreement also requires Petrosucre to compensate us for its ongoing use of the rig. We recognized $33.1 million of pre-tax income from discontinued operations for the year ended December 31, 2009 associated with collections under the agreement, consisting of $21.2 million of revenues from Petrosucre's use of the rig during 2009 and $11.9 million from the release of bad debt provisions recorded during 2008.

       Although the agreement obligates Petrosucre to make additional payments during 2010 for its use of the rig during 2009, the associated income was not recognized in our consolidated statement of income for the year ended December 31, 2009, as collectability was not reasonably assured. There can be no assurances relative to the recovery of outstanding contract entitlements, insurance recovery, the return of ENSCO 69 to us by Petrosucre or the imposition of customs duties in relation to the rig's ongoing presence in Venezuela. See "Note 12 - Commitments and Contingencies" for additional information on ENSCO 69.

    ENSCO 74

       In September 2008, ENSCO 74 was lost as a result of Hurricane Ike. Portions of its legs remained underwater adjacent to the customer's platform, and we conducted extensive aerial and sonar reconnaissance but did not locate the rig hull. In March 2009, the sunken hull of ENSCO 74 was located approximately 95 miles from the original drilling location when it was struck by an oil tanker. The rig was a total loss, as defined under the terms of our insurance policies. The operating results of ENSCO 74 were reclassified as discontinued operations in our consolidated statements of income for the years ended December 31, 2008 and 2007. See "Note 12 - Commitments and Contingencies" for additional information on the loss of ENSCO 74 and associated contingencies.


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       The following table summarizes income (loss) from discontinued operations for each of the years in the three-year period ended December 31, 2009 (in millions):
 

   2009          2008      2007   
 
Revenues     $ 26.0            $93.0          $85.6   
Operating expenses     3.1       59.7     39.9  

Operating income before income taxes     22.9       33.3     45.7  
Income tax expense     7.5       12.9     16.9  
Loss on disposal of discontinued operations, net     (11.8 )     (23.5 )   --  

     Income (loss) from discontinued operations     $   3.6       $ (3.1 )   $28.8  

 

       Debt and interest expense are not allocated to our discontinued operations.

12.  COMMITMENTS AND CONTINGENCIES

    Leases

       We are obligated under leases for certain of our offices and equipment. Rental expense relating to operating leases was $14.2 million, $13.9 million and $12.0 million during the years ended December 31, 2009, 2008 and 2007, respectively. Future minimum rental payments under our noncancellable operating lease obligations are as follows: $7.5 million during 2010; $3.4 million during 2011; $2.2 million during 2012; $1.9 million during 2013 and $7.3 million thereafter.

    Capital Commitments

       The following table summarizes the aggregate contractual commitments related to our four ENSCO 8500 Series® rigs currently under construction (in millions):
 

   
2010       $ 482.4
2011         425.5
2012         219.0

    Total       $ 1,126.9


       The actual timing of these expenditures may vary based on the completion of various construction milestones, which are, to a large extent, beyond our control.

    FCPA Internal Investigation

       Following disclosures by other offshore service companies announcing internal investigations involving the legality of amounts paid to and by customs brokers in connection with temporary importation of rigs and vessels into Nigeria, the Audit Committee of our Board of Directors and management commenced an internal investigation in July 2007. The investigation initially focused on our payments to customs brokers relating to the temporary importation of ENSCO 100, our only rig that operated offshore Nigeria during the pertinent period.


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       As is customary for companies operating offshore Nigeria, we had engaged independent customs brokers to process customs clearance of routine shipments of equipment, materials and supplies and to process the ENSCO 100 temporary importation permits, extensions and renewals. One or more of the customs brokers that our subsidiary in Nigeria used to obtain the ENSCO 100 temporary import permits, extensions and renewals also provided this service to other offshore service companies that have undertaken Foreign Corrupt Practices Act ("FCPA") compliance internal investigations.

       The principal purpose of our investigation was to determine whether any of the payments made to or by our customs brokers were inappropriate under the anti-bribery provisions of the FCPA or whether any violations of the recordkeeping or internal accounting control provisions of the FCPA occurred. Our Audit Committee engaged a Washington, D.C. law firm with significant experience in investigating and advising upon FCPA matters to assist in the internal investigation.

       Following notification to the Audit Committee and to KPMG LLP, our independent registered public accounting firm, in consultation with the Audit Committee's external legal counsel, we voluntarily notified the United States Department of Justice and the SEC that we had commenced an internal investigation. We expressed our intention to cooperate with both agencies, comply with their directives and fully disclose the results of the investigation. The internal investigation process has involved extensive reviews of documents and records, as well as production to the authorities, and interviews of relevant personnel. In addition to the temporary importation of ENSCO 100, the investigation has examined our customs clearance of routine shipments and immigration activities in Nigeria.

       Our internal investigation has essentially been concluded. Meetings to review the results of the investigation and discuss associated matters were held with the authorities on February 24, 2009, September 14, 2009 and February 9, 2010. We expect to discuss a possible negotiated disposition with the authorities in the near-term.

       Although we believe the U.S. authorities will take into account our voluntary disclosure, our cooperation with the agencies and the remediation and compliance enhancement activities that are underway, we are unable to predict the ultimate disposition of this matter, whether we will be charged with violation of the anti-bribery, recordkeeping or internal accounting control provisions of the FCPA or whether the scope of the investigation will be extended to other issues in Nigeria or to other countries. We also are unable to predict what potential corrective measures, fines, sanctions or other remedies, if any, the agencies may seek against us or any of our employees.

       In November 2008, our Board of Directors approved enhanced FCPA compliance recommendations issued by the Audit Committee's external legal counsel, and the Company embarked upon an enhanced compliance initiative that included appointment of a Chief Compliance Officer and a Director - Corporate Compliance. We engaged consultants to assist us in implementing the compliance recommendations approved by our Board of Directors, which include an enhanced compliance policy, increased training and testing, prescribed contractual provisions for our service providers that interface with foreign government officials, due diligence for the selection of such service providers and an increased Company-wide awareness initiative that includes periodic issuance of FCPA Alerts.

       Since ENSCO 100 completed its contract commitment and departed Nigeria in August 2007, this matter is not expected to have a material effect on or disrupt our current operations. As noted above, we are unable to predict the outcome of this matter or estimate the extent to which we may be exposed to any resulting potential liability, sanctions or significant additional expense.

    ENSCO 74 Loss

       In September 2008, ENSCO 74 was lost as a result of Hurricane Ike in the Gulf of Mexico. Portions of its legs remained underwater adjacent to the customer's platform, and we conducted extensive aerial and sonar reconnaissance but did not locate the rig hull. The rig was a total loss, as defined under the terms of our insurance policies.

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       In March 2009, the sunken rig hull of ENSCO 74 was located approximately 95 miles from the original drilling location when it was struck by an oil tanker. Following discovery of the sunken rig hull, we removed the accessible hydrocarbons onboard the rig and began planning for removal of the wreckage. As an interim measure, the wreckage has been appropriately marked, and the U.S. Coast Guard has issued a Notice to Mariners. We are currently communicating with various government agencies to address removal of the wreckage and related debris.

       Physical damage to our rigs caused by a hurricane, the associated "sue and labor" costs to mitigate the insured loss and removal, salvage and recovery costs are all covered by our property insurance policies subject to a $50.0 million per occurrence retention (deductible). The insured value of ENSCO 74 was $100.0 million, and we have received the net $50.0 million due under our policies for loss of the rig.

       Coverage for ENSCO 74 sue and labor costs and wreckage and debris removal costs under our property insurance policies is limited to $25.0 million and $50.0 million, respectively. Supplemental wreckage and debris removal coverage is provided under our liability insurance policies, subject to an annual aggregate limit of $500.0 million. We also have a customer contractual indemnification that provides for reimbursement of any ENSCO 74 wreckage and debris removal costs that are not recovered under our insurance policies.

       We believe it is probable that we will be required to remove the leg sections of ENSCO 74 remaining adjacent to the customer's platform because they may interfere with the customer's future operations. We also believe it is probable that we will be required to remove the ENSCO 74 rig hull and related debris from the seabed due to the navigational risk it imposes. We estimate the leg removal costs to range from $16.0 million to $30.0 million and the hull and related debris removal costs to range from $36.0 million to $55.0 million. We expect the cost of removal of the legs and the hull and related debris to be fully covered by our insurance without any additional retention.

       A $16.0 million liability, representing the low end of the range of estimated leg removal costs, and a corresponding receivable for recovery of those costs, was recorded as of December 31, 2009. A $36.0 million liability, representing the low end of the range of estimated hull and related debris removal costs, and a corresponding receivable for recovery of those costs, was recorded as of December 31, 2009. As of December 31, 2009, $1.7 million of wreck and debris removal costs had been incurred, primarily related to the removal of hydrocarbons from the rig. The aggregate $50.3 million liability for leg and hull and related debris removal costs and aggregate $52.0 million receivable for recovery of those costs were included in accrued liabilities and other, and other assets, net, respectively, on our December 31, 2009 consolidated balance sheet.

       On March 17, 2009, we received notice from legal counsel representing certain underwriters in a subrogation claim alleging that ENSCO 74 caused a pipeline to rupture during Hurricane Ike. On September 4, 2009, civil litigation was filed seeking damages for the cost of repairs and business interruption in an amount in excess of $26.0 million. Based on information currently available, primarily the adequacy of available defenses, we have not concluded that it is probable that a liability exists with respect to this matter.

       On March 18, 2009, the owner of the oil tanker that struck the hull of ENSCO 74 commenced civil litigation against us seeking monetary damages of $10.0 million for losses incurred when the tanker struck the sunken hull of ENSCO 74. Based on information currently available, primarily the adequacy of available defenses, we have not concluded that it is probable a liability exists with respect to this matter.

       On June 9, 2009, we received notice from legal counsel representing another pipeline owner which allegedly sustained damages to a subsea pipeline caused by ENSCO 74 in the aftermath of Hurricane Ike. On September 18, 2009, the owner of the pipeline commenced civil litigation against us seeking unspecified damages in relation to the cost of repairing damage to the pipeline, loss of revenues, survey and other damages. Based on information currently available, we have concluded that it is remote that a liability exists with respect to this matter.


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       On July 23, 2009, we received notice from legal counsel representing another tanker owner alleging that the sunken hull of the ENSCO 74 caused hull damage to a tanker in January 2009 resulting in unspecified damages and losses. We presently are unable to determine whether the alleged damage to this tanker was caused by ENSCO 74 or the extent of the cost and losses associated with the damage. Based on information currently available, we have not concluded that it is probable that a liability exists with respect to this matter.

       We filed a petition for exoneration or limitation of liability under U.S. admiralty and maritime law on September 2, 2009. The petition seeks exoneration from or limitation of liability for any and all injury, loss or damage caused, occasioned or occurred in relation to the ENSCO 74 loss in September 2008. On November 2, 2009, the owners of two other subsea pipelines presented claims in the exoneration/limitation of liability proceedings seeking monetary damages incurred by reason of damage to pipelines allegedly caused by ENSCO 74 in the aftermath of Hurricane Ike. One claim is in the amount of $14.0 million, while the other is for unspecified damages. Based on information currently available, we have concluded that it is remote that liabilities exist with respect to these matters.

       We have liability insurance policies that provide coverage for third-party claims such as the tanker and pipeline claims, subject to a $10.0 million per occurrence self-insured retention and an annual aggregate limit of $500.0 million. We believe all liabilities associated with the ENSCO 74 loss during Hurricane Ike resulted from a single occurrence under the terms of the applicable insurance policies. However, legal counsel for certain liability underwriters have asserted that the liability claims arise from separate occurrences. In the event of multiple occurrences, the self-insured retention is $15.0 million for two occurrences and $1.0 million for each occurrence thereafter.

       The exoneration/limitation proceedings currently include the claim of the owner of the tanker that struck ENSCO 74 in March 2009 and the four pipeline claims. Although we do not expect final disposition of the claims associated with the ENSCO 74 loss 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.

    ENSCO 69

       We have filed an insurance claim under our package policy, which includes coverage for certain political risks, and are evaluating legal remedies against Petrosucre for contractual and other ENSCO 69 related damages. ENSCO 69 has an insured value of $65.0 million under our package policy, subject to a $10.0 million deductible.

       By letter dated September 30, 2009, legal counsel acting for the package policy underwriters denied coverage under the package policy and reserved rights. We have retained coverage counsel who are reviewing the letter from underwriters' counsel. We were unable to conclude that collection of insurance proceeds associated with the loss of ENSCO 69 was probable as of December 31, 2009. Accordingly, no ENSCO 69 related insurance recoveries were recognized in our consolidated statement of income for the year ended December 31, 2009.

    ENSCO 29 Wreck Removal

       A portion of the ENSCO 29 platform drilling rig was lost over the side of a customer's platform as a result of Hurricane Katrina during 2005. Although beneficial ownership of ENSCO 29 was transferred to our insurance underwriters when the rig was determined to be a total loss, management believes we may be legally required to remove ENSCO 29 wreckage and debris from the seabed and currently estimates the removal cost to range from $5.0 million to $15.0 million. Our property insurance policies include coverage for ENSCO 29 wreckage and debris removal costs up to $3.8 million. We also have liability insurance policies that provide specified coverage for wreckage and debris removal costs in excess of the $3.8 million coverage provided under our property insurance policies.

       Our liability insurance underwriters have issued letters reserving rights and effectively denying coverage by questioning the applicability of coverage for the potential ENSCO 29 wreckage and debris removal costs. During 2007, we commenced litigation against certain underwriters alleging breach of contract, wrongful denial, bad faith and other claims which seek a declaration that removal of wreckage and debris is covered under our liability insurance, monetary damages, attorneys' fees and other remedies. The litigation is in an early stage.

       While we anticipate that any ENSCO 29 wreckage and debris removal costs incurred will be largely or fully covered by insurance, a $1.2 million provision, representing the portion of the $5.0 million low end of the range of estimated removal cost we believe is subject to liability insurance coverage, was recognized during 2006.

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    Asbestos Litigation

       During 2004, we and certain current and former subsidiaries were named as defendants, along with numerous other third-party companies as co-defendants, in three multi-party lawsuits filed in Mississippi. The lawsuits sought 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 period 1965 through 1986.

       In compliance with the Mississippi Rules of Civil Procedure, the individual claimants in the original multi-party lawsuits whose claims were not dismissed were ordered to file either new or amended single plaintiff complaints naming the specific defendant(s) against whom they intended to pursue claims. As a result, out of more than 600 initial multi-party claims, we have been named as a defendant by 65 individual plaintiffs. Of these claims, 62 claims or lawsuits are pending in Mississippi state courts and three are pending in the U.S. District Court as a result of their removal from state court.

       To date, written discovery and plaintiff depositions have taken place in eight cases involving us. While several cases have been selected for trial during 2010 and 2011, none of the cases pending against us in Mississippi state court are included within those selected cases.

       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, we have eight other asbestos or lung injury claims pending against us in litigation in various other jurisdictions. Although we do not expect the final disposition of the Mississippi and other 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.

    Working Time Directive

       Legislation known as the U.K. Working Time Directive ("WTD") was introduced during 2003 and may be applicable to our employees and employees of other drilling contractors that work offshore in U.K. territorial waters or in the U.K. sector of the North Sea. Certain trade unions representing offshore employees have claimed that drilling contractors are not in compliance with the WTD in respect of paid time off (vacation time) for employees working offshore on a rotational basis (generally equal time working and off).

       A Labor Tribunal in Aberdeen, Scotland, rendered decisions in claims involving other offshore drilling contractors and offshore service companies in February 2008. The Tribunal decisions effectively held that employers of offshore workers in the U.K. sector employed on an equal time on/time off rotation are obligated to accord such rotating personnel two-weeks annual paid time off from their scheduled offshore work assignment period. Both sides of the matter, employee and employer groups, appealed the Tribunal decision. The appeals were heard by the Employment Appeal Tribunal ("EAT") in December 2008.


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       In an opinion rendered in March 2009, the EAT determined that the time off work enjoyed by U.K. offshore oil and gas workers, typically 26 weeks per year, meets the amount of annual leave employers must provide to employees under the WTD. The employer group was successful in all arguments on appeal, as the EAT determined that the statutory entitlement to annual leave under the WTD can be discharged through normal field break arrangements for offshore workers. As a consequence of the EAT decision, an equal on/off time offshore rotation has been deemed to be fully compliant with the WTD. The employee group (led by a trade union) appealed the EAT decision to the highest court in Scotland (the Court of Session). A hearing on the appeal is expected in late 2010 or early 2011.

       During 2007, we received inquiries from and responded to the Danish and Dutch authorities regarding applicability of the WTD as adopted by Denmark and The Netherlands to employees on our rigs operating in the Danish and Dutch sectors of the North Sea.

       Based on information currently available, we do not expect the ultimate resolution of these matters to have a material adverse effect on our financial position, operating results or cash flows.

    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.

13.  SEGMENT INFORMATION

       We are in the process of developing a fleet of ultra-deepwater semisubmersible rigs and established a separate business unit to manage our deepwater operations during 2008. Our jackup rigs and barge rig are managed by major geographic region. Accordingly, our business consists of four operating segments: (1) Deepwater, (2) Asia Pacific, (3) Europe and Africa and (4) North and South America. Each of our four operating segments provides one service, contract drilling.


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       Segment information for each of the years in the three-year period ended December 31, 2009 is presented below. 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." Assets not allocated to our operating segments were also included in "Reconciling Items." As of December 31, 2009, 2008 and 2007, total asset reconciling items consisted primarily of cash and cash equivalents and goodwill.


Year Ended December 31, 2009
(in millions)

        North      
      Europe and Operating    
    Asia and South Segments Reconciling   Consolidated
  Deepwater Pacific  Africa  America     Total         Items          Total    
               
Revenue     $   254.1     $   724.0     $569.1     $398.7     $1,945.9     $        --       $1,945.9      
Operating expenses
   Contract drilling (exclusive
      of depreciation)
    108.1     249.0     208.8     159.6     725.5     --       725.5      
   Depreciation     22.2     88.0     44.5     49.9     204.6     1.3       205.9      
   General and administrative     --     --     --     --     --     64.0       64.0      

Operating income     $   123.8     $   387.0     $315.8     $189.2     $1,015.8     $   (65.3)      $   950.5      

Total assets     $2,444.6     $1,290.6     $779.9     $856.0     $5,371.1     $1,376.1       $6,747.2      
Capital expenditures     644.4     45.7     66.2     102.3     858.6     2.7       861.3      


Year Ended December 31, 2008
(in millions)

        North      
      Europe and Operating    
    Asia and South Segments Reconciling   Consolidated
  Deepwater Pacific  Africa  America     Total         Items          Total    
               
Revenue     $     84.4     $1,052.9     $804.1     $452.2     $2,393.6     $         --       $2,393.6      
Operating expenses
   Contract drilling (exclusive
      of depreciation)
    31.2     316.0     246.7     158.1     752.0     --       752.0      
   Depreciation     9.1     85.2     43.0     47.3     184.6     1.9       186.5      
   General and administrative     --     --     --     --     --     53.8       53.8      

Operating income     $     44.1     $   651.7     $514.4     $246.8     $1,457.0     $   (55.7)      $1,401.3      

Total assets     $1,759.9     $1,327.7     $806.7     $773.1     $4,667.4     $1,162.7       $5,830.1      
Capital expenditures     657.8     42.6     22.7     46.1     769.2     2.7       771.9      


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Year Ended December 31, 2007
(in millions)

        North      
      Europe and Operating    
    Asia and South Segments Reconciling   Consolidated
  Deepwater Pacific  Africa  America     Total         Items          Total    
               
Revenue     $  72.8     $   912.7     $670.8     $401.9     $2,058.2     $         --       $2,058.2      
Operating expenses
   Contract drilling (exclusive
      of depreciation)
    28.8     265.0     208.4     141.9     644.1     --       644.1      
   Depreciation     9.3     81.1     40.4     42.6     173.4     4.1       177.5      
   General and administrative     --     --     --     --     --     59.5       59.5      

Operating income     $  34.7     $   566.6     $422.0     $217.4     $1,240.7     $   (63.6)      $1,177.1      

Total assets     $973.8     $1,386.6     $773.6     $808.8     $3,942.8     $1,026.0       $4,968.8      
Capital expenditures     352.4     50.6     22.0     93.0     518.0     1.4       519.4      


   Information about Geographic Areas

       As of December 31, 2009, our Deepwater operating segment consisted of two ultra-deepwater semisubmersible rigs located in the Gulf of Mexico, one ultra-deepwater semisubmersible rig located in Australia and five ultra-deepwater semisubmersible rigs under construction in Singapore, including ENSCO 8502 which was delivered in January 2010. Our Asia Pacific operating segment consisted of 19 jackup rigs and one barge rig deployed in various locations throughout Asia, the Middle East, Australia and New Zealand. Our Europe and Africa operating segment consisted of eight jackup rigs deployed in various territorial waters of the North Sea, one jackup rig located offshore Tunisia and one jackup rig located offshore Greece. Our North and South America operating segment consisted of seven jackup rigs located in the Gulf of Mexico, five jackup rigs located offshore Mexico and one rig located offshore Venezuela.

       For purposes of our geographic areas disclosures, we attribute revenues to the geographic location where such revenues are earned and assets to the geographic location of the drilling rig as of the end of the applicable year. For new construction projects, assets are attributed to the location of future operation if known or to the location of construction if the ultimate location of operation is undetermined. Information by country for those countries that account for more than 10% of total revenues or 10% of our long-lived assets was as follows (in millions):

 
                  Revenues                                 Long-lived Assets              
 2009     2008     2007   2009   2008     2007 
                           
United Kingdom  $   353.2   $   478.3   $   392.5   $   457.4   $   309.0   $   425.5  
United States   267.0   485.8   474.7   1,806.7   1,663.6   1,640.3  
Indonesia  75.7   254.2   116.1   50.2   153.9   325.4  
Singapore  --   --   --   720.1   550.5   17.1  
Other countries  1,250.0   1,175.3   1,074.9   1,442.9   1,194.3   950.6  

     Total  $1,945.9   $2,393.6   $2,058.2   $4,477.3   $3,871.3   $3,358.9  


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14.  SUPPLEMENTAL FINANCIAL INFORMATION

   Consolidated Balance Sheet Information

       Accounts receivable, net, as of December 31, 2009 and 2008 consisted of the following (in millions):

 
   2009              2008 
                    
Trade   $310.1   $483.5  
Other  17.9   19.7  

   328.0   503.2  
Allowance for doubtful accounts  (3.4 ) (20.5 )

   $324.6   $482.7  


       Other current assets as of December 31, 2009 and 2008 consisted of the following (in millions):

 
   2009              2008 
     
Inventory  $  53.1   $  47.0  
Prepaid taxes  39.6   16.4  
Deferred tax assets   30.0   20.3  
Deferred mobilization costs   29.0   24.4  
Prepaid expenses  13.6   9.4  
Other  21.5   11.1  

   $186.8   $128.6  


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       Other assets, net, as of December 31, 2009 and 2008 consisted of the following (in millions):

 
   2009          2008 
           
Prepaid taxes on intercompany transfers of property  $  99.0   $  91.3  
Wreckage and debris removal receivables  55.8   18.8  
Deferred mobilization costs   23.7   23.1  
Supplemental executive retirement plan assets  18.7   13.9  
Other  23.2   10.4  

   $220.4   $157.5  

 

       Accrued liabilities and other as of December 31, 2009 and 2008 consisted of the following (in millions):

 
   2009          2008 
     
Taxes  $  97.3   $  48.2  
Deferred revenue  89.0   67.7  
Wreckage and debris removal  50.3   15.0  
Personnel costs   48.6   50.5  
Derivative liabilities   1.1   25.8  
Other  22.3   7.7  

   $308.6   $214.9  

 

       Other liabilities as of December 31, 2009 and 2008 consisted of the following (in millions):

 
   2009                    2008    
     
Deferred revenue   $  51.2   $  34.4  
Unrecognized tax benefits (inclusive of interest and penalties)  33.4               39.7  
Supplemental executive retirement plan liabilities  21.0   13.9  
Other  15.1   15.8  

   $120.7   $103.8  


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   Consolidated Statement of Income Information

       Repair and maintenance expense related to continuing operations for each of the years in the three-year period ended December 31, 2009 was as follows (in millions):

 
   2009        2008           2007    
     
           Repair and maintenance expense   $124.6   $123.6   $97.7  


   Consolidated Statement of Cash Flows Information

       Cash paid for interest and income taxes for each of the years in the three-year period ended December 31, 2009 was as follows (in millions):

     2009      2008    2007 
       
Interest, net of amounts capitalized   $      .1   $      .5   $    4.6  
Income taxes  153.8   348.6   213.2  
 

       Capitalized interest totaled $20.9 million, $21.6 million and $30.4 million during the years ended December 31, 2009, 2008 and 2007, respectively. Capital expenditure accruals totaling $83.8 million, $105.1 million and $96.1 million for the years ended December 31, 2009, 2008 and 2007, respectively, were excluded from investing activities in our consolidated statement of cash flows.


   Concentration of Credit Risk

       We are exposed to credit risk relating to our receivables from customers, our cash and cash equivalents and investments and our use of derivatives in connection with the management of foreign currency exchange rate risk. We minimize our credit risk relating to receivables from customers, which consist primarily of major international, government-owned and independent oil and gas companies, by performing ongoing credit evaluations. We also maintain reserves for potential credit losses, which to date have been within management's expectations. We minimize our credit risk relating to cash and investments by focusing on diversification and quality of instruments. Cash balances are maintained in major, highly-capitalized commercial banks. Cash equivalents consist of a portfolio of high-grade instruments. Custody of cash and cash equivalents is maintained at several major financial institutions, and we monitor the financial condition of those financial institutions. Substantially all of our investments were issued by state agencies and are substantially guaranteed by the U.S. government under FFELP. We minimize our credit risk relating to the counterparties of our derivatives by transacting with multiple, high-quality counterparties, thereby limiting exposure to individual counterparties, and by monitoring the financial condition of our counterparties.

       During the year ended December 31, 2009, one customer provided $249.6 million, or 13%, of consolidated revenues which were attributable to our Europe and Africa and Asia Pacific operating segments. During the years ended December 31, 2008 and 2007, no customer provided more than 10% of consolidated revenues.

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15.  UNAUDITED QUARTERLY FINANCIAL DATA

       The following table summarizes our unaudited quarterly consolidated income statement data for the years ended December 31, 2009 and 2008 (in millions, except per share amounts):

 
 
2009 First       
Quarter       
Second       
Quarter       
Third       
Quarter       
Fourth       
Quarter       
    Year 
           
Operating revenues     $509.3     $511.6     $425.4     $499.6     $1,945.9    
Operating expenses     
   Contract drilling (exclusive of depreciation)     163.7     177.8     183.3     200.7     725.5    
   Depreciation     47.2     49.3     53.3     56.1     205.9    
   General and administrative     12.0     16.0     13.6     22.4     64.0    

Operating income     286.4     268.5     175.2     220.4     950.5    
Other income (expense), net     (4.3 )   6.9     3.6     2.6     8.8    

Income from continuing operations before income taxes     282.1     275.4     178.8     223.0     959.3    
Provision for income taxes     56.3     49.1     28.4     44.6     178.4    

Income from continuing operations     225.8     226.3     150.4     178.4     780.9    
(Loss) income from discontinued operations, net     (3.7 )   (24.9 )   .4     31.8     3.6    

Net income     222.1     201.4     150.8     210.2     784.5    
Net income attributable to noncontrolling interests     (1.4 )   (1.1 )   (1.1 )   (1.5 )   (5.1 )  

Net income attributable to Ensco     $220.7     $200.3     $149.7     $208.7     $779.4    

 
Earnings (loss) per share - basic    
   Continuing operations     $  1.58     $  1.59   $  1.05     $  1.24     $     5.45    
   Discontinued operations     (.02 )   (.18 )   .00     .22     .03    

      $  1.56     $  1.41     $  1.05     $  1.46     $     5.48    

 
Earnings (loss) per share - diluted    
   Continuing operations     $  1.58     $  1.59   $  1.05     $  1.24     $     5.45    
   Discontinued operations     (.02 )   (.18 )   .00     .22     .03    

      $  1.56     $  1.41     $  1.05     $  1.46     $     5.48    


106


Table of Contents

 
2008 First       
Quarter       
Second       
Quarter       
Third       
Quarter       
Fourth       
Quarter       
      Year 
           
Operating revenues     $559.9     $609.4     $619.5     $604.8     $2,393.6    
Operating expenses     
   Contract drilling (exclusive of depreciation)     178.6     203.0     185.2     185.2     752.0    
   Depreciation     45.7     46.7     47.0     47.1     186.5    
   General and administrative     12.7     13.8     15.2     12.1     53.8    

Operating income     322.9     345.9     372.1     360.4     1,401.3    
Other income (expense), net     4.5     6.8     (6.5 )   (9.0 )   (4.2 )  

Income from continuing operations before income taxes     327.4     352.7     365.6     351.4     1,397.1    
Provision for income taxes     58.6     64.6     68.8     45.3     237.3    

Income from continuing operations     268.8     288.1     296.8     306.1     1,159.8    
Income (loss) from discontinued operations, net     4.9     9.8     (13.1 )   (4.7 )   (3.1 )  

Net income     273.7     297.9     283.7     301.4     1,156.7    
Net income attributable to noncontrolling interests     (1.7 )   (1.2 )   (1.4 )   (1.6 )   (5.9 )  

Net income attributable to Ensco     $272.0     $296.7     $282.3     $299.8     $1,150.8    

 
Earnings (loss) per share - basic    
   Continuing operations     $  1.86     $  1.99   $  2.07     $  2.15     $     8.06    
   Discontinued operations     .03     .07     (.09 )   (.03 )   (.02 )  

      $  1.89     $  2.06     $  1.98     $  2.12     $     8.04    

 
Earnings (loss) per share - diluted    
   Continuing operations     $  1.85     $  1.98   $  2.06     $  2.14     $     8.04    
   Discontinued operations     .03     .07     (.09 )   (.03 )   (.02 )  

      $  1.88     $  2.05     $  1.97     $  2.11     $     8.02