UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
     Washington, D.C. 20549     
 
FORM 8-K
 
CURRENT REPORT
 
PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
 
D ATE OF REPORT (Date of earliest event reported):    January 13 ,  2 012

Ensco plc	
(Exact name of registrant as specified in its charter) 	

England and Wales	 	 	1-8097	 	 	98-0635229	 	 	
(State or other jurisdiction of
incorporation)	 	 	(Commission File Number)	 	 	(I.R.S. Employer
Identification No.)	 	 	

 	6 C hesterfi eld Gardens
London, England W1J 5BQ	 	

 	 	 	(Address of Principal Executive Offices and Zip Code)	 	 	 	 	 	

Re gis trant's telephone number, including area code: 44 (0) 20 7659 4660

Not Applicable	 	

 	 	 	(Former name or former address, if changed since last report)	 	 	 	 	 	

 
Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:	
 
¨	 	Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425) 	
 
¨	 	Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12) 	
 
¨	 	Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b)) 	
 
¨	 	Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))	

 	 	 

 	

 

 

TABLE OF CONTENTS

INFORM ATIO N TO BE INCLUDED IN THE REPORT
Item 8.01 Other Events
         Item 9.01 Financial Statements and Exhibits
SIGNATURE
EXHIBIT INDEX
Consent of Independent Registered Public Accounting Firm
Updated Part II, "Item 8. Financial Statements and Supplementary Data" of our Annual Report on Form 10-K for the year ended
December 31, 2010.
Updated Part II, "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations"
of our Annual Report on Form 10-K for the year ended December 31, 2010.
Updated Part I, "Item 1. Business" of our Annual Report on Form 10-K for the year ended  December 31, 2010.

 

INFORMATION  TO BE INCLUDED IN THE REPORT

Item  8.01    Other Events
 
     Ensco plc (the "Company," "Ensco," "we" or "us") is filing this Current Report on Form 8-K (the "Report") for the purpose of updating our Annual Report on Form 10-K for the year ended December 31, 2010 filed with the Securities and Exchange Commission (the "SEC") on February 24, 2011 (the "Form 10-K"), to retrospectively reflect the reorganization of our reportable segments for all periods presented.  Concurrently with this Report, we are filing a Current Report on Form 8-K for the purpose of updating our Quarterly Report on Form 10-Q for the period ended March 31, 2011 filed with the SEC on April 29, 2011 (the "Form 10-Q"), to retrospectively reflect the reorganization of our reportable segments for all periods presented.
 
     As previously reported, on May 31, 2011 (the "Merger Date"), Ensco plc completed a merger transaction (the "Merger") with Pride International, Inc., a Delaware corporation ("Pride"), ENSCO International Incorporated, a Delaware corporation and an indirect, wholly-owned subsidiary and predecessor of Ensco plc ("Ensco Delaware"), and ENSCO Ventures LLC, a Delaware limited liability company and an indirect, wholly-owned subsidiary of Ensco plc ("Merger Sub"). Pursuant to the merger agreement and subject to the conditions set forth therein, Merger Sub merged with and into Pride, with Pride as the surviving entity and an indirect, wholly-owned subsidiary of Ensco plc.
 
     In connection with the Merger and resulting management reorganization, we evaluated our then-current core assets and operations and organized them into three segments based on water depth operating capabilities. Accordingly, we now consider our business to consist of three reportable segments: (1) Deepwater, which consists of our drillships and semisubmersible rigs capable of drilling in water depths of 4,500 feet or greater, (2) Midwater, which consists of our semisubmersible rigs capable of drilling in water depths of 4,499 feet or less and (3) Jackup, which consists of our jackup rigs capable of operating in water depths up to 400 feet. Each of our three reportable segments provides one service, contract drilling.

     Each Item updated in the Form 10-K is filed as a separate exhibit to this Report.  The specific disclosures updated within each Item are as follows:

 	•	Sections b) and j) of Note 1 and Note 13 to our audited consolidated financial statements as of December 31, 2010 and 2009 and for each of the years in the three-year period ended December 31, 2010, included in Part II, "Item 8. Financial Statements and Supplementary Data" of the Form 10-K (filed as Exhibit 99.1 hereto);	

 	•	The Business Environment and Results of Operations sections, included in Part II, "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" of the Form 10-K (filed as Exhibit 99.2 hereto); and	

 	•	The Contract Drilling Operations and Backlog Information sections included in Part I, "Item 1. Business" of the Form 10-K (filed as Exhibit 99.3 hereto).	

     The updated segment disclosures included in this Report do not impact or change any of our previously filed consolidated balance sheets, consolidated statements of income or consolidated statements of cash flows. The revised Items of the Form 10-K included in this Report have not been updated for any events occurring after the respective dates the Form 10-K was originally filed other than the updated segment disclosures resulting from the aforementioned Merger and reorganization. This Report should be read in conjunction with the Form 10-K (except for Part II, Items 7 and 8 and Part I, Item 1), the Form 10-Q (except for Part I, Items 1 and 2) and our other reports on Form 10-Q and Form 8-K filed during 2011.

2

 
F OR WARD-LOOKING STATEMENTS

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

 	•	our ability to successfully integrate the operations of Ensco and Pride as contemplated and to realize the anticipated benefits of the Merger;	

 	•	our ability to meet our increased debt service obligations as a result of the Merger and to fund planned expenditures, including construction costs for our remaining newbuild construction projects;	

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

 	•	the continued impact of the Macondo well incident on offshore drilling operations, including current and any future actual or de facto drilling permit and operations delays, moratoria or suspensions, new and future regulatory, legislative or permitting requirements (including requirements related to certification and testing of blow-out preventers and other equipment or otherwise impacting operations), future lease sales, changes in laws, rules and regulations that have or may impose increased financial responsibility, additional oil spill abatement contingency plan capability requirements and other governmental actions that may result in claims of force majeure or otherwise adversely affect our existing drilling contracts;	

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

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

3

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

 	• 	downtime and other risks associated with offshore rig operations or rig relocations, including rig or equipment failure, damage and other unplanned repairs, the limited availability of transport vessels, hazards, self-imposed drilling limitations and other delays due to severe storms and hurricanes and the limited availability or high cost of insurance coverage for certain offshore perils, such as hurricanes in the Gulf of Mexico or associated removal of wreckage or debris;	

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

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

 	• 	delays in actual contract commencement dates;	

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

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

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

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

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

 	•	potential long-lived asset or goodwill impairments	

     In addition to the numerous risks, uncertainties and assumptions described above, you should also carefully read and consider "Item 1A. Risk Factors" in Part I and "Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations" in Part II of our annual report on Form 10-K for the year ended December 31, 2010, as updated in our subsequent quarterly reports on Form 10-Q and by this report and the Current Report on Form 8-K being filed concurrently herewith, which are available on the SEC’s website at www.sec.gov.  Each forward-looking statement speaks only as of the date of the particular statement, and we undertake no obligation to publicly update or revise any forward looking statements, except as required by law.

4

 
Item  9.01   Financial Statements and Exhibits
 
        (d)  Exhibits
 
Exhibit No.	 	Description                                                                                                                           	

   23.1	 	Consent of Independent Registered Public Accounting Firm.	
 
   99.1	 	Updated Part II, "Item 8. Financial Statements and Supplementary Data" of our Annual Report on Form 10-K for the year ended December 31, 2010.	
 	 	 	
   99.2	 	Updated Part II, "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" of our Annual Report on Form 10-K for the year ended December 31, 2010.	
 
   99.3	 	Updated Part I, "Item 1. Business" of our Annual Report on Form 10-K for the year ended December 31, 2010.	
 	 	 	
101.INS
 
101.SCH
 
101.CAL
 
101.DEF
 
101.LAB
 
101.PRE
 	 	XBRL Instance Document
 
XBRL Taxonomy Extension Schema
 
XBRL Taxonomy Extension Calculation Linkbase
 
XBRL Taxonomy Extension Definition Linkbase
 
XBRL Taxonomy Extension Label Linkbase
 
XBRL Taxonomy Extension Presentation Linkbase	

 
5

SIGN ATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly cause d this report to be signed on its behalf by the undersigned hereunto duly authorized.

 	 	En sco plc	

 	 	 	
Date:  January 13, 2012	 	/s/ DOUGLAS J. MANKO          
Douglas J. Manko
Controller	

 	 	 	

 	 	 	

 
6

EXHIBIT INDEX

Exhibit No.	 	Description                                                                                                                           	
 
   23.1	 	Consent of Independent Registered Public Accounting Firm.	
 
   99.1	 	Updated Part II, "Item 8. Financial Statements and Supplementary Data" of our Annual Report on Form 10-K for the year ended December 31, 2010.	
 
   99 .2	 	Updated Part II, "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" of our Annual Report on Form 10-K for the year ended December 31, 2010.	
 	 	 	
   99 .3	 	Updated Part I, "Item 1. Business" of our Annual Report on Form 10-K for the year ended December 31, 2010.	
 	 	 	
101.INS
 
101.SCH
 
101.CAL
 
101.DEF
 
101.LAB
 
101.PRE

 
 
 	 	XBRL Instance Document
 
XBRL Taxonomy Extension Schema
 
XBRL Taxonomy Extension Calculation Linkbase
 
XBRL Taxonomy Extension Definition Linkbase
 
XBRL Taxonomy Extension Label Linkbase
 
XBRL Taxonomy Extension Presentation Linkbase	

 
 
7

 

Exhibit 23.1

Consent of Independent Registered Public Accounting Firm

The Board of Directors
Ensco plc:

     We consent to the incorporation by reference in the registration statements on Form S-8 (Nos. 333-174611, 333-58625, 33-40282, 333-97757, 333-125048 and 333-156530) of Ensco plc of our reports dated February 24, 2011 (except for the updated disclosures pertaining to the change in reportable segments as described in Note 13, as to which the date is January 13, 2012) with respect to the consolidated balance sheets of Ensco plc and subsidiaries as of December 31, 2010 and 2009, and the related consolidated statements of income and cash flows for each of the years in the three-year period ended December 31, 2010 and the effectiveness of internal control over financial reporting as of December 31, 2010, which reports appear in this Current Report on Form 8-K of Ensco plc.

 
 
/s/ KPMG LLP
 
Dallas, Texas
January 13, 2012

 

 

 

 

Exhibit 99.1

Item 8.    Fina nci al Statements and Supplementary Data
 
     As further discussed in Note 13 to our consolidated financial statements herein, our consolidated financial statements for all periods presented herein have been updated to retrospectively reflect the reorganization of our reportable segments resulting from the merger transaction with Pride International, Inc. (the "Merger") completed on May 31, 2011, pursuant to which Pride International became an indirect, wholly-owned subisidary of Ensco plc.  This filing includes updates only to the portions of Item 1, Item 7 and Item 8 of the Form 10-K that specifically relate to the updated segment disclosures resulting from the Merger and management reorganization and does not otherwise modify or update any other disclosures set forth in the Form 10-K.
 
MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
 
     Our management is responsible for establishing and maintaining adequate internal control over financial r epo rting, 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, 2010 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 ove r financial reporting. KPMG LLP's audit report on our internal control over financial reporting is included herein.

 
February 24, 2011

 
1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Shareholders
Ensco plc:
 
     We have audited the accompanying consolidated balance sheets of Ensco plc and subsidiaries as of December 31, 2010 and 2009, and the related consolidated statements of income and cash flows for each of the years in the three-year period ended December 31, 2010. 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 plc and subsidiaries as of December 31, 2010 and 2009, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2010, 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 plc and subsidiaries' internal control over financial reporting as of December 31, 2010, 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 24, 2011, expressed an unqualified opinion on the effectiveness of the Company's internal control over financial reporting.

/s/ KPMG LLP

Dallas, Texas
 
February 24, 2011, except for the change in reportable segments as described in Note 13, as to which the date is January 13, 2012

2

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Shareholders
Ensco plc:

     We have audited Ensco plc and subsidiaries' (Ensco) internal control over financial reporting as of December 31, 2010, 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, 2010, 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 plc and subsidiaries as of December 31, 2010 and 2009, and the related consolidated statements of income and cash flows for each of the years in the three-year period ended December 31, 2010, and our report dated February 24, 2011 expressed an unqualified opinion on those consolidated financial statements.

 
/s/ KPMG LLP
Dallas, Texas
February 24, 2011

3

ENSCO PLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(in millions, except per share amounts)
 	  Year Ended December 31,  	
   	      2010	    2009	    2008	
 	 	 	 	 	 	 	 	
OPE RAT ING REVENUES	 	$1,696.8	 	$1,888.9	 	$2,242.6	 	
 	 	 	 	 	 	 	 	
OPERATING EXPENSES	 	 	 	 	 	 	 	
     Contract drilling (exclusive of depreciation)	 	768.1	 	709.0	 	736.3	 	
     Depreciation	 	216.3	 	189.5	 	172.6	 	
     General and administrative	 	86.1	 	64.0	 	53.8	 	
 	 	1,070.5	 	962.5	 	962.7	 	
 
OPERATING INCOME	 	626.3	 	926.4	 	1,279.9	 	
 	 	 	 	 	 	 	 	
OTHER INCOME (EXPENSE), NET	 	18.2	 	8.8	 	(4.2	)	
 
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	 	644.5	 	935.2	 	1,275.7	 	
 	 	 	 	 	 	 	 	
PROVISION FOR INCOME TAXES	 	 	 	 	 	 	 	
     Current income tax expense	 	81.7	 	159.5	 	218.3	 	
     Deferred income tax expense	 	14.3	 	20.5	 	4.1	 	
 	 	96.0	 	180.0	 	222.4	 	
 
INCOME FROM CONTINUING OPERATIONS	 	548.5	 	755.2	 	1,053.3	 	
 	 	 	 	 	 	 	 	
DISCONTINUED OPERATIONS	 	 	 	 	 	 	 	
     (Loss) income from discontinued operations, net	 	(1.2	)	29.3	 	126.9	 	
     Gain (loss) on disposal of discontinued operations, net	 	38.6	 	--	 	(23.5	)	
 	 	37.4	 	29.3	 	103.4	 	
 
NET INCOME	 	585.9	 	784.5	 	1,156.7	 	
 	 	 	 	 	 	 	 	
NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS	 	(6.4	)	(5.1	)	(5.9	)	
 
NET INCOME ATTRIBUTABLE TO ENSCO	 	$   579.5	 	$   779.4	 	$1,150.8	 	
 
EARNINGS PER SHARE - BASIC	 	 	 	 	 	 	 	
     Continuing operations	 	$     3.80	 	$     5.28	 	$    7.32	 	
     Discontinued operations	 	.26	 	.20	 	.72	 	
 	 	$     4.06	 	$    5.48	 	$    8.04	 	
 
EARNINGS PER SHARE - DILUTED	 	 	 	 	 	 	 	
     Continuing operations	 	$     3.80	 	$     5.28	 	$    7.31	 	
     Discontinued operations	 	.26	 	.20	 	.71	 	
 	 	$     4.06	 	$     5.48	 	$    8.02	 	
 
NET INCOME ATTRIBUTABLE TO ENSCO SHARES	 	 	 	 	 	 	 	
     Basic	 	$   572.1	 	$   769.7	 	$1,138.2	 	
     Diluted	 	$   572.1	 	$   769.7	 	$1,138.2	 	
WEIGHTED-AVERAGE SHARES OUTSTANDING	 	 	 	 	 	 	 	
     Basic	 	141.0	 	140.4	 	141.6	 	
     Diluted	 	141.0	 	140.5	 	141.9	 	
 	 	 	 	 	 	 	 	
CASH DIVIDENDS PER SHARE	 	$   1.075	 	$       .10	 	$      .10	 	
 
The a ccom panying notes are an integral part of these consolidated financial statements.
 
4

ENSCO PLC AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(in millions, except share and par value amounts)
 	           December 31,         	
ASSETS	      2010  	      2009  	
 
CURRENT ASSETS	 	 	 	 	 	
    Cash and cash equivalents	 	$1,050.7	 	$1,141.4	 	
    Accounts receivable, net	 	214.6	 	324.6	 	
    Other	 	171.4	 	186.8	 	
       Total current assets	 	1,436.7	 	1,652.8	 	
 	 	 	 	 	 	
PROPERTY AND EQUIPMENT, AT COST	 	6,744.6	 	6,151.2	 	
    Less accumulated depreciation	 	1,694.7	 	1,673.9	 	
       Property and equipment, net	 	5,049.9	 	4,477.3	 	
 	 	 	 	 	 	
GOODWILL	 	336.2	 	336.2	 	
 	 	 	 	 	 	
LONG-TERM INVESTMENTS	 	44.5	 	60.5	 	
 	 	 	 	 	 	
OTHER ASSETS, NET	 	184.2	 	220.4	 	
 	 	$7,051.5	 	$6,747.2	 	
 	 	 	 	 	 	
LIABILITIES AND SHAREHOLDERS' EQUITY
 	 	 	 	 	 	
CURRENT L IABI LITIES	 	 	 	 	 	
    Accounts payable - trade	 	$  163.5	 	$   159.1	 	
    Accrued liabilities and other	 	168.3	 	308.6	 	
    Current maturities of long-term debt	 	17.2	 	17.2	 	
       Total current liabilities	 	349.0	 	484.9	 	
 	 	 	 	 	 	
LONG-TERM DEBT	 	240.1	 	257.2	 	
 	 	 	 	 	 	
DEFERRED INCOME TAXES	 	358.0	 	377.3	 	
 	 	 	 	 	 	
OTHER LIABILITIES	 	139.4	 	120.7	 	
 	 	 	 	 	 	
COMMITMENTS AND CONTINGENCIES	 	 	 	 	 	
 	 	 	 	 	 	
ENSCO SHAR EH OLDERS' EQUITY	 	 	 	 	 	
    Class A ordinary shares, U.S. $.10 par value, 450.0 million shares authorized,
       150.0 million shares issued as of December 31, 2010 and 2009	 	15.0	 	15.0	 	
    Class B ordinary shares, £1 par value, 50,000 shares authorized and issued
       as of December 31, 2010 and 2009	 	.1	 	.1	 	
    Additional paid-in capital	 	637.1	 	602.6	 	
    Retained earnings	 	5,305.0	 	4,879.2	 	
    Accumulated other comprehensive income	 	11.1	 	5.2	 	
    Treasury shares, at cost, 7.1 million shares and 7.5 million shares	 	(8.8	)	(2.9	)	
       Total Ensco shareholders' equity	 	5,959.5	 	5,499.2	 	
 	 	 	 	 	 	
NONCONTROLLING INTERESTS	 	5.5	 	7.9	 	
       Total equity	 	5,965.0	 	5,507.1	 	
 	 	$7,051.5	 	$6,747.2	 	
 
The accompanying notes are an integral part of these consolidated financial statements.
 
5

ENSCO PLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in millions)
 
 	  Year Ended December 31,  	
 	       2010 	    2009 	    2008 	
OPERATING ACTIVITIES	 	 	 	 	 	 	 	
        Net income	 	$  585.9	 	$  784.5	 	$1,156.7	 	
        Adjustments to reconcile net income to net cash provided	 	 	 	 	 	 	 	
           by operating activities of continuing operations:	 	 	 	 	 	 	 	
              Depreciation expense	 	216.3	 	189.5	 	172.6	 	
              Share-based compensation expense	 	44.5	 	35.5	 	27.3	 	
              Amortization expense	 	31.4	 	31.0	 	30.5	 	
              Deferred income tax expense	 	14.3	 	20.5	 	4.1	 	
              Loss on asset impairment	 	 12.2	 	 17.3	 	 --	 	
              Loss (income) from discontinued operations, net	 	1.2	 	(29.3	)	(126.9	)	
              (Gain) loss on disposal of discontinued operations, net	 	(38.6	)	--	 	23.5	 	
              Bad debt expense 	 	 (.8	)	 4.5	 	  16.2	 	
              Other	 	7.4	 	3.0	 	2.1	 	
              Changes in operating assets and liabilities:	 	  	 	 	 	 	 	
                 Decrease (increase) in accounts receivable	 	110.9	 	167.4	 	(110.7	)	
                 Decrease (increase) in trading securities	 	16.7	 	5.5	 	(72.3	)	
                 Increase in other assets	 	(27.3	)	(73.1	)	(40.5	)	
                 (Decrease) increase in liabilities	 	(157.4	)	29.3	 	(67.9	)	
                      Net cash provided by operating activities of continuing  operations	 	816.7	 	1,185.6	 	1,014.7	 	
 
INVESTING ACTIVITIES	 	 	 	 	 	 	 	
        Additions to property and equipment	 	(875.3	)	(857.2	)	(764.2	)	
        Proceeds from disposal of discontinued operations	 	158.1	 	14.3	 	45.1	 	
        Proceeds from disposition of assets	 	1.5	 	2.6	 	4.7	 	
                     Net cash used in investing activities	 	(715.7	)	(840.3	)	(714.4	)	
 
FINANCING ACTIVITIES	 	 	 	 	 	 	 	
        Cash dividends paid	 	(153.7	)	(14.2	)	(14.3	)	
        Reduction of long-term borrowings	 	(17.2	)	(17.2	)	(19.0	)	
        Financing costs	 	(6.2	)	--	 	--	 	
        Repurchase of shares	 	(6.0	)	(6.5	)	(259.7	)	
        Proceeds from exercise of share options	 	 1.4	 	9.6	 	27.3	 	
        Other	 	(10.9	)	(5.9	)	1.5	 	
                      Net cash used in financing activities	 	(192.6	)	(34.2	)	(264.2	)	
 	 	 	 	 	 	 	 	
Effect of exchange rate changes on cash and cash equivalents	 	(.5	)	.5	 	(15.0	)	
Net cash provided by operating activities of discontinued operations	 	1.4	 	40.2	 	139.0	 	
 	 	 	 	 	 	 	 	
(DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS	 	(90.7	)	351.8	 	160.1	 	
 	 	 	 	 	 	 	 	
CASH AND CASH EQUIVALENTS, BEGINNING OF YEAR	 	1,141.4	 	789.6	 	629.5	 	
 	 	 	 	 	 	 	 	
CASH AND CASH EQUIVALENTS, END OF YEAR	 	$1,050.7	 	$1,141.4	 	$  789.6	 	
 
The accompanying notes are an integral part of these consolidated financial statements.
 
6

 
ENSCO PLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

    a) 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 46 drilling rigs, including 40 jackup rigs, five ultra-deepwater semisubmersible rigs and one barge rig. Additionally, we have three ultra-deepwater semisubmersible rigs and two ultra-high specification harsh environment jackup 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.
 
    b) Pending Merger with Pride

     On February 6, 2011, Ensco plc entered into an Agreement and Plan of Merger with Pride International, Inc., a Delaware corporation (“Pride”), Ensco Delaware, and ENSCO Ventures LLC, a Delaware limited liability company and an indirect, wholly-owned subsidiary of Ensco (“Merger Sub”). Pursuant to the merger agreement and subject to the conditions set forth therein, Merger Sub will merge with and into Pride, with Pride as the surviving entity and an indirect, wholly-owned subsidiary of Ensco (the "Merger").  As a result of the merger, which was completed on May 31, 2011 (the "Merger Date"), each outstanding share of Pride’s common stock (other than shares of common stock held directly or indirectly by Ensco, Pride or any wholly-owned subsidiary of Ensco or Pride (which will be cancelled as a result of the merger), those shares with respect to which appraisal rights under Delaware law are properly exercised and not withdrawn and other shares held by certain U.K. residents if determined by Ensco) will be converted into the right to receive $15.60 in cash and 0.4778 Ensco ADSs. Under certain circumstances, U.K. residents may receive all cash consideration as a result of compliance with legal requirements.

     We estimate that the total consideration to be delivered in the merger to be approximately $7,400.0 million, consisting of $2,800.0 million of cash, the delivery of approximately 86.0 million Ensco ADSs (assuming that no Pride employee stock options are exercised before the closing of the merger) with an aggregate value of $4,550.0 million based on the closing price of Ensco ADSs of $52.88 on February 15, 2011 and the estimated fair value of $45.0 million of Pride employee stock options assumed by Ensco.  The value of the merger consideration will fluctuate based upon changes in the price of Ensco ADSs and the number of shares of Pride common stock and employee options outstanding on the closing date. The merger agreement and the merger were approved by the respective Boards of Directors of Ensco and Pride.  Consummation of the merger is subject to the approval of the shareholders of Ensco and the stockholders of Pride, regulatory approvals and the satisfaction or waiver of various other conditions as more fully described in the merger agreement.  Subject to receipt of required approvals, it is anticipated that the closing of the merger will occur during the second quarter of 2011.
 
    c)  Redomestication

     In December 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 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 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 plc together with all subsidiaries and predecessors.

7

 
      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.
 
    d) Basis of Presentation—U.K. Companies Act 2006 Section 435 Statement

     The accompanying consolidated financial statements have been prepared in accordance with GAAP, which the directors consider to be the most meaningful presentation of results of operations and financial position of Ensco plc and its subsidiaries.  The accompanying consolidated financial statements do not constitute statutory accounts required by the U.K. Companies Act 2006, which for year ended December 31, 2010 will be prepared in accordance with generally accepted accounting principles in the U.K. and delivered to the Registrar of Companies in the U.K. following the annual general meeting of shareholders.  The U.K. statutory accounts are expected to include an unqualified auditor’s report, which is not expected to contain any references to matters to which the auditors drew attention by way of emphasis without qualifying the report or any statements under Sections 498(2) or 498(3) of the U.K. Companies Act 2006.
 
    e) Principles of Consolidation

     The accompanying consolidated financial statements include the accounts of Ensco 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.

    f) 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.

    g) 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 $3.5 million and $2.6 million and net foreign currency exchange losses of $10.4 million for the years ended December 31, 2010, 2009 and 2008, respectively.

    h) 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.

8

 
    i) 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 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 carrying 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, 2010, except for the impairment of  ENSCO I as further discussed in "Note 2 - Property and Equipment."  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.

    j) Goodwill
 
     In connection with the Merger and resulting management reorganization, we evaluated our then-current core assets and operations and organized them into three segments based on water depth operating capabilities. Accordingly, we now consider our business to consist of three reportable segments: (1) Deepwater, which consists of our rigs capable of drilling in water depths of 4,500 feet or greater, (2) Midwater, which consists of our semisubmersible rigs capable of drilling in water depths of 4,499 feet or less and (3) Jackup, which consists of our jackup rigs capable of operating in water depths up to 400 feet. Each of our three reportable segments provides one service, contract drilling.

     As a result of our 2011 reorganization to three reportable segments and reporting units resulting from the Merger, we retrospectively reassigned our pre-existing goodwill to our reporting units as follows (in millions):
 
Deepwater	 	 	 	 	$143.6	
Midwater*	 	 	 	 	--	
Jackup	 	 	 	 	192.6	
Total	 	 	 	 	$336.2	
 
*	Prior to the Merger Date, our rig fleet did not consist of midwater rigs.  Therefore, no pre-existing goodwill was reassigned to the Midwater reporting unit as of December 31, 2010.	
 
     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, 2010.

9

 
     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, 2010.  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.

    k) 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, on our consolidated balance sheets and totaled $51.0 million and $52.7 million as of December 31, 2010 and 2009, respectively. Deferred mobilization revenue was included in accrued liabilities and other, and other liabilities on our consolidated balance sheets and totaled $82.8 million and $99.3 million as of December 31, 2010 and 2009, respectively.

     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 on our consolidated balance sheets and totaled $27.4 million and $22.5 million as of December 31, 2010 and 2009, 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, on our consolidated balance sheets and totaled $7.0 million and $9.7 million as of December 31, 2010 and 2009, 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.

10

    l) 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.

     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, on our consolidated balance sheets depending on maturity date. Derivatives with liability fair values are reported in accrued liabilities and other, or other liabilities on our consolidated balance sheets depending on maturity date.

    m) 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.

11

 
     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.
   
     We do not provide deferred taxes on the undistributed earnings of our U.S. subsidiary and predecessor, 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.   See "Note 10 - Income Taxes" for additional information on the undistributed earnings of Ensco Delaware's non-U.S. subsidiaries.
 
    n) Share-Based Compensation

     We sponsor share-based compensation plans that provide equity compensation to our employees, officers and directors. S har e-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.
 
    o) Fair Value Measurements

     We measure certain of our assets and liabilities based on 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.

12

 
     Our auction rate securities, marketable securities held in our supplemental executive retirement plans ("SERP") and derivatives are measured at fair value on a recurring basis.  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 certain of our  asset s and liabilities.

    p) Earnings Per Share
      
     We compute basic and diluted earnings per share ("EPS") in accordance with the two-class method. Net income attributable to Ensco used in our computations of basic and diluted EPS is adjusted to exclude net income allocated to non-vested shares granted to our employees and non-employee directors. Weighted-average shares outstanding used in our computation of diluted EPS includes the dilutive effect of share options using the treasury stock method and excludes non-vested shares.
 
     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, 2010 (in millions):
 
 	     2010	         2009	     2008     	
 	 	 	 	 	 	 	 	
Net income attributable to Ensco	 	579.5	 	$779.4	 	$1,150.8	          	
Net income allocated to non-vested share awards	 	(7.4	)	(9.7	)	(12.6	)	
N et income attributable to Ensco shares	 	572.1	 	$769.7	 	$1,138.2	 	

     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, 2010 (in millions):

 	     2010	         2009	     2008     	
 	 	 	 	 	 	 	 	
Weighted-average shares - basic	 	141.0	 	140.4	 	141.6	          	
Potentially dilutive share options	 	.0	 	.1	 	.3	 	
Weighted-average shares - diluted	 	141.0	 	140.5	 	141.9	 	

     Antidilutive share options totaling 1.1 million for each of the years ended December 31, 2010 and 2009 and 746,000 for the year ended December 31, 2008 were excluded from the computation of diluted EPS.

13

 
    q) Noncontrolling Interests

     Noncontrolling interests are classified as equity on o u r 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.
 
     I nc o me from continuing operations attributable to Ensco for each of the years in the three-year period ended December 31, 2010 was as follows (in millions):

 	2010   	2009    	2008      	
 	 	 	 	
Income from continuing operations	$548.5 	$755.2 	$1,053.3 	
Income from continuing operations attributable to
   noncontrolling interests	 
(6.2)	 
(4.2)	 
(5.1)	
Income from continuing operations attributable to Ensco	$542.3 	$751.0 	$1,048.2	

     Income from discontinued operations, net, attributable to Ensco for each of the years in the three-year period ended December 31, 2010 was as follows:

 	2010   	2009    	2008      	
 	 	 	 	
Income from discontinued operations	$37.4 	$29.3 	$103.4 	
Income from discontinued operations attributable to
   noncontrolling interests	 
(.2)	 
(.9)	 
(.8)	
Income from discontinued operations attributable to Ensco	$37.2 	$28.4 	$102.6 	

2.  PROPERTY AND EQUIPMENT

     Property and equipment as of December 31, 2010 and 2009 consisted of the following (in millions):

 	    2010      	    2009  	
 	 	 	 	 	 	
Drilling rigs and equipment	 	$5,175.2	 	$4,801.1	 	
Other	 	50.4	 	47.0	 	
Work in progress	 	1,519.0	 	1,303.1	 	
 	 	$6,744.6	 	$6,151.2	 	
 
     Work in pro gr ess as of December 31, 2010 primarily consisted of $1,401.1 million related to the construction of our ENSCO 8500 Series® ultra-deepwater semisubmersible rigs and costs associated with various modification and enhancement projects. ENSCO 8503 was delivered in September 2010 and the related construction costs will remain classified as work in progress until the rig is placed into service during the first quarter of 2011.  Work in progress as of December 31, 2009 primarily consisted of $1,262.5 million related to the construction of our ENSCO 8500 Series® rigs and costs associated with various modification and enhancement projects.
 
     In June 2010, we recorded a $12.2 million loss from the impairment of ENSCO I, the only barge rig in our fleet, which is currently cold-stacked in Singapore and is included in our Asia Pacific operating segment. The loss on impairment was included in contract drilling expense in our consolidated statement of income for the year ended December 31, 2010. The impairment resulted from the adjustment of the rig’s carrying value to its estimated fair value based on a change in our expectation that it is more-likely-than-not that the rig will be disposed of significantly before the end of its estimated useful life. ENSCO I was not classified as held-for-sale as of December 31, 2010, as a sale was not deemed probable of occurring within the next twelve months. See “Note 8 – Fair Value Measurements” for additional information on the fair value measurement of ENSCO I.
 
3.  LONG-TERM INVESTMENTS
 
     As o f December 31, 2010 and 2009, we held long-term debt instruments with variable interest rates that periodically reset through an auction process ("auction rate securities") totaling $50.1 million and $66.8 million (par value), respectively.  Our auction rate securities were originally acquired in January 2008 and have final maturity dates ranging from 2025 to 2047.

14

 
     Our investments in auction rate securities as of December 31, 2010 were diversified across eleven 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.  All 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.   Cash flows from purchases and sales of our auction rate securities are classified as operating activities in our consolidated statement of cash flows. 
 
     Our auction rate securities were measured at fair value as of December 31, 2010 and 2009.  Net unrealized gains of $700,000 and $1.8 m illio n and net 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, 2010, 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 values of our auction rate securities were $44.5 million and $60.5 million as of December 31, 2010 and 2009, respectively.   Although $16.7 million, $5.5 million and $6.0 million of our auction rate securities were redeemed at par value during the years ended December 31, 2010, 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.
 
4.  LONG-TERM DEBT

     Long-term debt as of December 31, 2010 and 2009 consisted of the following (in millions):

 	               2010   	  2009	
 	 	 	 	 	 	
7.20% Debentures due 2027	 	$148.9	 	$148.9	 	
6.36% Bonds due 2015	 	63.4	 	76.0	 	
4.65% Bonds due 2020	 	45.0	 	49.5	 	
 	 	257.3	 	274.4	 	
Less current maturities	 	(17.2	)	(17.2	)	
Total long-term debt	 	$240.1	 	$257.2	 	
 
    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. In December 2009, in connection with the redomestication, Ensco 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%.

15

 
     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.  In February 2010, the documents governing MARAD's guarantee commitments were amended to address certain changes arising from the redomestication and to include Ensco plc as an additional guarantor of the debt obligations.

    Revolving Credit Facility
   
     On May 28, 2010, we entered into an amended and restated agreement (the "2010 Credit Facility") with a syndicate of banks that provides for a $700.0 million unsecured revolving credit facility for general corporate purposes. The 2010 Credit Facility has a four-year term, expiring in May 2014, and replaces our $350.0 million five-year credit agreement which was scheduled to mature in June 2010. Advances under the 2010 Credit Facility generally bear interest at LIBOR plus an applicable margin rate (currently 2.0% per annum), depending on our credit rating. We are required to pay an annual undrawn facility fee (currently .25% per annum) on the total $700.0 million commitment, which is also based on our credit rating. We also are required to maintain a debt to total capitalization ratio less than or equal to 50% under the 2010 Credit Facility. We have the right, subject to lender consent, to increase the commitments under the 2010 Credit Facility up to $850.0 million.  We had no amounts outstanding under the 2010 Credit Facility or the prior credit agreement as of December 31, 2010 and 2009, respectively.
 
    Maturities
 
     The aggregate maturities of our long-term debt, excluding unamortized discounts of $1.1 million, as of December 31, 2010 were as follows (in millions):

2011	 	 	 	 	$ 17.2	
2012	 	 	 	 	17.2	
2013	 	 	 	 	17.2	
2014	 	 	 	 	17.2	
2015	 	 	 	 	17.2	
Thereafter	 	 	 	 	172.4	
Total	 	 	 	 	$258.4	

     Interest expense totaled $21.3 million, $20.9 million and $21.6 million for the years ended December 31, 2010, 2009 and 2008, respectively. All interest expense incurred during each of the years in the three-year period ended December 31, 2010 was capitalized in connection with the construction of our ENSCO 8500 Series® rigs.
 
5.  DERIVATIVE INSTRUMENTS
   
     We use derivatives to reduce our exposure to various market risks, primarily foreign currency exchange rate risk. 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. Although no interest rate related derivatives were outstanding as of December 31, 2010 and 2009, we occasionally employ an interest rate risk management strategy that utilizes derivatives 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 our accounting policy for derivatives and "Note 8 - Fair Value Measurements" for additional information on the fair value measurement of our derivatives.

16

 
     As of December 31, 2010 and 2009, our consolidated balance sheets included net foreign currency derivative assets of $16.4 million and $13.2 million, respectively.  All of our derivatives mature during the next 18 months.  Derivatives recorded at fair value in our consolidated balance sheets as of December 31, 2010 and 2009 consisted of the following (in millions):
 
 	            Derivative  Assets  	 	           Derivative Liabilities	
 	        2010	 	  2009	 	        2010	 	            2009	
Derivatives Designated as Hedging Instruments	 	 	 	 	 	 	 	 	
Foreign currency forward contracts - current (1)	$16.8	 	$10.2	 	$.6	 	$1.1	 	
Foreign currency forward contracts - non-current (2)	.1	 	3.8	 	.1	 	--	 	
 	16.9	 	14.0	 	.7	 	1.1	 	
Derivatives not Designated as Hedging Instruments	 	 	 	 	 	 	 	 	
Foreign currency forward contracts - current (1)	  .2	 	  .3	 	  --	 	    .0	 	
 	  .2	 	  .3	 	  --	 	    .0	 	
Total	$17.1	 	$14.3	 	$.7	 	$1.1	 	

(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.	
 
     We utilize derivatives designated as hedging instruments 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, 2010, we had cash flow hedges outstanding to exchange an aggregate $216.4 million for various foreign currencies, including $118.8 million for Singapore dollars, $77.6 million for British pounds, $9.2 million for Australian dollars and $10.8 million for other currencies.
 
     Gains and losses, net of tax, 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, 2010 were as follows (in millions):

 	Gain (Loss)
Recognized in
Other Comprehensive
Income ("OCI")
on Derivatives
  (Effective Portion)  	(Loss) Gain
Reclassified from
AOCI into Income
(Effective Portion)	Gain (Loss) Recognized
in Income on
Derivatives (Ineffective
Portion and Amount
Excluded from
Effectiveness Testing) (1)	
 	2010	 	2009	 	2008	 	2010	 	2009	 	2008	 	2010	 	2009	 	2008	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Interest rate lock contracts (2)  	 $  --    	 	 $   --   	 	 $    --  	 	$  (.6)  	 	$  (.7)  	 	$  (.7)  	 	$  -- 	 	$    --   	 	$    --   	
Foreign currency forward contracts (3)	7.6   	 	13.5  	 	(16.4)	 	2.3   	 	(8.0)  	 	(2.9)  	 	.3 	 	  (2.9)  	 	(1.0)  	
Total	$ 7.6   	 	$13.5  	 	$(16.4)	 	$ 1.7   	 	$(8.7)  	 	$(3.6)  	 	$ .3 	 	$(2.9)  	 	$(1.0)  	
 
(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 derivatives reclassified from AOCI into income (effective portion) were included in other income (expense), net, in our consolidated statements of income.
 	
(3)	 	Gains and losses on derivatives reclassified from AOCI into income (effective portion) were included in contract drilling expense in our consolidated statements of income.	

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     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, 2010, we had derivatives not designated as hedging instruments outstanding to exchange an aggregate $23.5 million for various foreign currencies, including $15.3 million for Australian dollars, $3.0 million for Malaysian ringgits, $2.2 million for Singapore dollars and $3.0 million for other currencies.

     Net gains of $2.9 million and $4.6 million and net losses of $3.5 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, 2010, 2009 and 2008, respectively.

     As of December 31, 2010, the estimated amount of net gains associated with derivatives, net of tax, that will be reclassified to earnings during the next twelve months was as follows (in millions):

Net unrealized gains to be reclassified to contract drilling expense	 	$1.1	 	
Net realized losses to be reclassified to other income (expense), net	 	(.3	)	
Net gains to be reclassified to earnings	 	$ .8	 	
 
6.  COMPREHENSIVE INCOME

     Accumulated other comprehensive income as of December 31, 2010 and 2009 was comprised of gains and losses on derivative instruments, net of tax. The components of comprehensive income, net of tax, for each of the years in the three-year period ended December 31, 2010 were as follows (in millions):

 	    2010         	   2009         	       2008      	
 	 	 	 	 	 	 	 	
Net income	 	$585.9	 	$784.5	 	$1,156.7	 	
Other comprehensive income:	 	 	 	 	 	 	 	
     Net change in fair value of derivatives	 	7.6	 	13.5	 	(16.4	)	
     Reclassification of gains and losses on derivative
           instruments from other comprehensive (income)
           loss into net income	 	(1.7	)	8.7	 	3.6	 	
              Net other comprehensive income (loss)	 	5.9	 	22.2	 	(12.8	)	
Comprehensive income	 	591.8	 	806.7	 	1,143.9	 	
Comprehensive income attributable to noncontrolling interests	 	(6.4	)	(5.1	)	(5.9	)	
Comprehensive income attributable to Ensco	 	$585.4	 	$801.6	 	$1,138.0	 	

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7.  SHAREHOLDERS' EQUITY
 
    Activity in our v ariou s shareholders' equity accounts for each of the years in the three-year period ended December 31, 2010 was as follows (in millions):
 
 	 	 	 	 	Accumulated	 	 	
 	 	 	 	 	Other	 	 	
 	 	 	Additional	 	Comprehensive	 	 	
 	 	Paid-In	  Retained	Income	Treasury     	Noncontrolling	
 	  Shares   	Par Value   	   Capital   	   Earnings	    (Loss)    	   Shares        	   Interest   	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
B AL A NCE, 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    	 	
  Net income	 	-- 	 	-- 	 	-- 	 	579.5	 	--     	 	--  	 	6.4    	 	
  Cash dividends paid	 	-- 	 	-- 	 	-- 	 	(153.7	)	--     	 	--  	 	--    	 	
  Distributions to noncontrolling interests	 	-- 	 	-- 	 	-- 	 	--	 	--     	 	--  	 	(8.8)   	 	
  Shares issued under share-based compensation	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
    plans, net	 	-- 	 	-- 	 	1.4 	 	--	 	--     	 	.1  	 	--    	 	
  Tax deficiency from share-based	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
    compensation	 	-- 	 	-- 	 	(2.2)	 	--	 	--     	 	--  	 	--    	 	
  Repurchase of shares	 	-- 	 	-- 	 	-- 	 	--	 	--     	 	(6.0) 	 	--    	 	
  Share-based compensation cost	 	-- 	 	-- 	 	35.3 	 	--	 	--     	 	--  	 	--    	 	
  Net other comprehensive income	 	-- 	 	-- 	 	-- 	 	--	 	5.9     	 	--  	 	--    	 	
BALANCE, December 31, 2010	 	150.1 	 	$15.1 	 	$   637.1 	 	$5,305.0	 	$ 11.1     	 	$    (8.8) 	 	$ 5.5    	 	

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     The Board of Directors of Ensco Delaware previously authorized the repurchase of up to $1,500.0 million of our ADSs, representing our Class A ordinary shares. In December 2009, the then-Board of Directors of Ensco International Limited, a predecessor of Ensco 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.  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 the years ended December 31, 2010 and 2009.  Although $562.4 million remained available for repurchase as of December 31, 2010, we will not repurchase any shares under our share repurchase program without further consultation with and approval by the Board of Directors of Ensco plc.
 
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, 2010 and 2009 (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, 2010	 	 	 	 	 	 	 	 	 	 	 	 	
Auction rate securities	 	$    --    	 	 	$    --  	 	 	$44.5           	 	 	$44.5	 	
Supplemental executive retirement plan assets	 	23.0    	 	 	--  	 	 	--           	 	 	23.0	 	
Derivatives, net	 	--    	 	 	16.4  	 	 	--           	 	 	16.4	 	
Total financial assets	 	$23.0    	 	 	$16.4  	 	 	$44.5           	 	 	$83.9	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
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	 	
 
    Auction Rate Securities

     As of December 31, 2010 and 2009, we held auction rate securities totaling $50.1 million and $66.8 million (par value), respectively.  See "Note 3 - Long-Term Investments" for additional information on our auction rate securities.
 
     Our auction rate securities were measured at fair value on a recurring basis using significant Level 3 inputs as of December 31, 2010 and 2009. 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 three-year period ended December 31, 2010 (in millions):

   	     2010      	   2009	       2008	
 	 	 	 	 	 	 	 	
Beginning Balance	 	$60.5	 	$64.2	 	 $    --	 	
    Purchases	 	 --	 	 --	 	 83.0	 	
    Sales	 	(16.7	)	(5.5	)	 (10.7	)	
    Unrealized gains (losses)*	 	.7	 	1.8	 	 (8.1	) 	
    Transfers in and/or out of Level 3	 	--	 	--	 	 --	 	
Ending balance	 	$44.5	 	$60.5	 	 $64.2	 	

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

20

 
     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, 2010. Accordingly, we concluded that Level 1 inputs were not available. Brokerage statements received from the three broker/dealers that held our auction rate securities included their estimated market value as of December 31, 2010.  All three broker/dealers valued our auction rate securities at 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 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, 2010.   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 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 of our auction rate securities, particularly the estimates of risk-adjusted discount rates and ranges of expected periods of illiquidity. 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 Plans

     Our Ensco supplemental executive retirement plans (the "SERP") are non-qualified plans that provide for eligible employees to 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, 2010 and 2009.  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, 2010 and 2009.  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, 2010 and 2009 were as follows (in millions):

 	December 31,	December 31,	
 	                 2010                	                2009                	
 	 	Estimated	 	Estimated	
 	Carrying	  Fair	Carrying	  Fair	
 	  Value  	    Value  	  Value  	    Value  	
 	 	 	 	 	
7.20% Debentures	 	$148.9     	 	$165.0     	 	$148.9     	 	$155.9     	 	
6.36% Bonds, including current maturities	 	63.4     	 	71.9     	 	76.0     	 	85.8     	 	
4.65% Bonds, including current maturities	 	45.0     	 	50.6     	 	49.5     	 	53.8     	 	

     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, 2010 and 2009.

21

 
     ENSCO I Impairment
 
     In June 2010, we recorded a $12.2 million loss from the impairment of ENSCO I, the only barge rig in our fleet.  The impairment resulted from the adjustment of the rig’s carrying value to its estimated fair value based on a change in our expectation that it is more-likely-than-not that the rig will be disposed of significantly before the end of its estimated useful life.

     We utilized an income approach valuation model to estimate the price that would be received in exchange for the rig in an orderly transaction between market participants as of June 30, 2010. The resulting exit price was derived as the present value of expected cash flows from the use and eventual disposition of the rig, using a risk-adjusted discount rate.  Level 3 inputs were significant to the overall fair value measurement of ENSCO I, due to the limited availability of observable market data for similar assets.
 
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, 2010, there were 2.3 million shares available for issuance of non-vested share awards under the LTIP. Non-vested share awards may be satisfied by delivery of newly issued shares or by delivery of shares held by a subsidiary or affiliated entity 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).

     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, 2010 (in millions):

 	   2010	     2009	           2008  	
 	 	 	 	 	 	 	 	
Contract drilling	 	$17.2	   	$16.8	   	$11.4	   	
General and administrative	 	13.9	 	11.4	 	7.6	 	
Non-vested share award related compensation expense	 	 	 	 	 	 	 	
   included in operating expenses	 	31.1	 	28.2	 	19.0	 	
Tax benefit	 	(6.3	)	(7.0	)	(4.7	)	
Total non-vested share award related compensation	 	      	 	 	 	 	 	
   expense included in net income	 	$24.8	 	$21.2	 	$14.3	 	

     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, 2010:

 	     2010        	  2009  	        2008  	
 	 	 	 	 	 	 	 	
Weighted-average grant-date fair value of	 	 	   	 	   	 	   	
   non-vested share awards granted (per share)	 	$35.81	 	$40.91	 	$67.99	 	
Total fair value of non-vested share awards	 	 	 	 	 	 	 	
   vested during the period (in millions)	 	$22.1  	 	$18.6  	 	$17.9  	 	

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     The following table summarizes non-vested share award activity for the year ended December 31, 2010 (shares in thousands):

 	 	Weighted-	
 	 	Average	
 	 	Grant-Date	
 	Shares	Fair Value	
 	 	 	 	 	 	
Non-vested as of January 1, 2010	 	1,811	 	$54.21  	 	
   Granted	 	626	 	35.81  	 	
   Vested	 	(576	)	54.59  	 	
   Forfeited	 	(70	)	51.75  	 	
Non-vested as of December 31, 2010	 	1,791	 	$47.75  	 	

     As of December 31, 2010, there was $65.3 million of total unrecognized compensation cost related to non-vested share awards, which is expected to be recognized over a weighted-average period of 2.9 years.

    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, 2010, options to purchase 1.3 million shares were outstanding under the LTIP and 4.1 million shares were available for issuance as options. Upon option exercise, issuance of shares may be satisfied by delivery of newly issued shares or by delivery of shares held by a subsidiary or affiliated entity 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, 2010 (in millions):

 	  2010  	  2009  	  2008  	
 	 	 	 	 	 	 	 	
Contract drilling	 	$  .7   	 	$  1.7   	 	$  3.3  	   	
General and administrative	 	2.8   	 	3.7   	 	5.0  	 	
Option related compensation expense included in	 	 	 	 	 	 	 	
   operating expenses	 	3.5   	 	5.4   	 	8.3  	 	
Tax benefit	 	(.6)  	 	(1.6)  	 	(2.3) 	 	
Total option related compensation expense included	 	 	 	 	 	 	 	
   in net income	  	$ 2.9  	  	$  3.8   	  	$  6.0  	 	

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     The fair value of each option is estimated on the date of grant using the Black-Scholes option valuation model.  No options were granted during the year ended December 31, 2008.  The following weighted-average assumptions were utilized in the Black-Scholes model for each of the years in the two-year period ended December 31, 2010:

 	                                   2010  	                                    2009  	
 	 	 	 	 	 	
Risk-free interest rate	 	1.8	%	1.8	%	
Expected term (in years)	 	4.0	 	3.9	 	
Expected volatility	 	53.1	%	53.3	%	
Dividend yield	 	4.1	%	.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.

     The following table summarizes option activity for the year ended December 31, 2010 (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, 2010	 	1,213	 	$48	.98	 	 	 	 	
        Granted	 	160	 	34	.45	 	 	 	 	
        Exercised	 	(38	)	37	.26	 	 	 	 	
        Forfeited	 	(3	)	53	.12	 	 	 	 	
        Expired	 	(11	)	51	.79	 	 	 	 	
Outstanding as of December 31, 2010	 	1,321	 	$47	.52	3	.3	$9,915   	 	
Exercisable as of December 31, 2010	 	1,022	 	$49	.12	2	.6	$6,036   	 	

     The following table summarizes the value of options granted and exercised during each of the years in the three-year period ended December 31, 2010:

 	        2010   	            2009   	              2008   	
 	 	 	 	 	 	 	 	
Weighted-average grant-date fair value of	 	 	   	 	   	 	   	
   options granted (per share)	 	$11.05	 	$17.17	 	$    --	 	
Intrinsic value of options exercised during	 	 	 	 	 	 	 	
   the year (in millions)	 	$    .4  	 	$  3.6  	 	$25.5	 	

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     The following table summarizes information about options outstanding as of December 31, 2010 (shares in thousands):
 
 	                            Options Outstanding                            	             Options Exercisable             	
 	 	Weighted-Average	 	 	  	
 	Number     	Remaining	Weighted-Average	Number	   Weighted-Average	
Exer ci se Prices	Outstanding   	Contractual Life	  Exercise Price  	Exercisable	         Exercise Price    	
 	 	 	 	 	 	 	
$23.12   - $34.45 	294       	4.1 years                	$34.03        	134            	$33.54          	 	
  41.29  -   47.12	380       	3.2 years                	45.10        	311            	45.94          	 	
  50.09  -   52.82	351       	2.5 years                	50.31        	347            	50.31          	 	
  57.38  -   60.74	296       	3.4 years                	60.71        	230            	60.71          	 	
 	1,321       	3.3 years                	$47.52        	1,022            	 	$49.12          	 	

     As of December 31, 2010, there was $2.9 million of total unrecognized compensation cost related to options, which is expected to be recognized over a weighted-average period of 1.6 years.

    Performance Awards

     In November 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, 2010.  Performance awards that are paid in Ensco shares may be satisfied by delivery of newly issued shares or by delivery of shares held by a subsidiary or affiliated entity at the Company's discretion.

     Performance awards may be 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 classified as 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. The aggregate grant-date fair value of performance awards granted during 2010 and 2009 totaled $4.3 million and $12.1 million, respectively.  The aggregate fair value of performance awards vested during 2010 totaled $2.4 million, all of which was paid in cash.

     During the years ended December 31, 2010 and 2009, we recognized $9.9 million and $1.9 million of compensation expense for performance awards, respectively, which was included in general and administrative expense in our consolidated statements of income.  No performance award compensation expense was recognized during the year ended December 31, 2008.  As of December 31, 2010, there was $10.3 million of total unrecognized compensation cost related to unvested performance awards, which is expected to be recognized over a weighted-average period of 1.7 years.

25

    Savings Plans

     We have profit sharing plans (the "Ensco Savings Plan" and the "Ensco Multinational Savings Plan") which cover eligible employees, as defined.  The Ensco Savings Plan includes a 401(k) savings plan feature which allows eligible employees to make tax deferred contributions to the plan.  Contributions made to the Ensco Multinational Savings Plan may or may not qualify for tax deferral based on each plan participant's local tax requirements.
 
     We generally make matching cash contributions to the profit sharing plans.  We match 100% of the amount contributed by the employee up to a maximum of 5% of eligible salary. Matching contributions totaled $5.0 million, $4.1 million and $5.0 million for the years ended December 31, 2010, 2009 and 2008, respectively.  Profit sharing contributions made into the plans require Board of Directors approval and are generally paid in cash.  We recorded profit sharing contribution provisions of $16.2 million, $14.2 million and $16.6 million for the years ended December 31, 2010, 2009 and 2008, respectively.  Matching contributions and profit sharing contributions become vested in 33% increments upon completion of each initial year of service with all contributions becoming fully vested subsequent to achievement of three or more years of service.  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% during 2010 and for eight days of 2009. Our consolidated effective income tax rate information for the years ended December 31, 2009 and 2008 has been presented from the perspective of an enterprise domiciled in the U.S.
 
     We generated $90.5 million, $292.2 million and $374.1 million of income from continuing operations before income taxes in the U.S. and $554.0 million, $643.0 million and $901.6 million of income from continuing operations before income taxes in non-U.S. countries for the years ended December 31, 2010, 2009 and 2008, respectively.

     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, 2010 (in millions):

 	      2010 	       2009 	      2008 	
 	 	 	 	 	 	 	 	
Current income tax expense:	 	 	 	 	 	 	 	
      U.S.	 	$  9.8	 	$  71.9	 	$103.7	 	
      Non-U.S.	 	71.9	 	87.6	 	114.6	 	
 	 	81.7	 	159.5	 	218.3	 	
 	 	 	 	 	 	 	 	
Deferred income tax expense (benefit):	 	 	 	 	 	 	 	
      U.S.	 	15.2	 	20.5	 	13.9	 	
      Non-U.S.	 	(.9	)	--	 	(9.8	)	
 	 	14.3	 	20.5	 	4.1	 	
 	 	 	 	 	 	 	 	
Total income tax expense	 	$96.0	 	$180.0	 	$222.4	 	

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     The following table summarizes significant components of deferred income tax assets (liabilities) as of December 31, 2010 and 2009 (in millions):

 	 2010      	 2009    	
 	 	 	 	 	 	
Deferred tax assets:	 	 	 	 	 	
      Deferred revenue	 	$   28.9	 	$   34.1	 	
      Employee benefits, including share-based compensation	 	21.1	 	25.6	 	
      Other	 	10.9	 	18.3	 	
      Total deferred tax assets	 	60.9	 	78.0	 	
Deferred tax liabilities:	 	 	 	 	 	
      Property and equipment	 	(335.6	)	(348.9	)	
      Intercompany transfers of property	 	(35.2	)	(45.5	)	
      Deferred costs	 	(24.5	)	(23.5	)	
      Other	 	(14.3	)	(7.7	)	
      Total deferred tax liabilities	 	(409.6	)	(425.6	)	
           Net deferred tax liability	 	$(348.7	)	$(347.6	)	
 	 	 	 	 	 	
Net current deferred tax asset	 	$     9.3	 	$   29.7	 	
Net noncurrent deferred tax liability	 	(358.0	)	(377.3	)	
          Net deferred tax liability	 	$(348.7	)	$(347.6	)	
 
     The realization of certain of our deferred tax assets is dependent on generating sufficient taxable income during future periods in various jurisdictions in which we operate. Although realization of certain of our deferred tax assets is not assured, we believe it is more-likely-than-not that our deferred tax assets will be realized. The amount of deferred tax asset considered realizable could be reduced in the near-term if estimates of future taxable income were reduced.
 
     Subsequent to our redomestication to the U.K. in December 2009, we reorganized our worldwide operations, which included, among other things, the transfer of ownership of several of our drilling rigs among our subsidiaries.
 
     The decline in our 2010 consolidated effective income tax rate to 14.9% from 19.2% in the prior year was primarily due to the aforementioned transfer of drilling rig ownership in connection with the reorganization of our worldwide operations, which resulted in an increase in the relative components of our earnings generated in tax jurisdictions with lower tax rates, and an $8.8 million non-recurring current income tax expense incurred during 2009 in connection with certain restructuring activities undertaken immediately following our redomestication to the U.K.  The increase in our 2009 consolidated effective income tax rate to 19.2% from 17.4% in the prior year was primarily related to the aforementioned non-recurring current income tax expense incurred during 2009.

27

     Our consolidated effective income tax rate on continuing operations for each of the years in the three-year period ended December 31, 2010, differs from the U.K. or U.S. statutory income tax rates as follows:

 	 2010        	 2009        	     2008 	
 	 	 	 	 	 	 	 	
Statutory income tax rate	 	28.0	%	35.0	%	35.0	%	
Non-U.K./U.S. taxes	 	(18.4	)	(17.6	)	(19.2	)	
Amortization of deferred charges
   associated with intercompany rig sales	 	2.7	 	1.8	 	1.3	 	
Redomestication related income taxes	 	.0	 	.9	 	--	 	
Net (benefit) expense in connection with resolutions	 	 	 	 	 	 	 	
   of tax issues and adjustments relating to prior years	 	(.5	)	(.9	)	.5	 	
Other	 	3.1	 	--	 	(.2	)	
Effective income tax rate	 	14.9	%	19.2	%	17.4	%	

    Unrecognized Tax Benefits

     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 of December 31, 2010, we had $13.7 million of unrecognized tax benefits, of which $11.0 million would impact our consolidated effective income tax rate if recognized. A reconciliation of the beginning and ending amount of unrecognized tax benefits for the years ended December 31, 2010 and 2009 is as follows (in millions):

 	 2010      	 2009 	
 	 	 	 	 	 	
Balance, beginning of year	 	$17.6	 	$26.8	 	
   Increases in unrecognized tax benefits as a result
      of tax positions taken during the current year	 	1.0	 	2.0	 	
   Increases in unrecognized tax benefits as a result
      of tax positions taken during prior years	 	--	 	--	 	
   Decreases in unrecognized tax benefits as a result
      of tax positions taken during prior years	 	(.2	)	(2.7	)	
   Settlements with taxing authorities	 	--	 	(8.7	)	
   Lapse of applicable statutes of limitations	 	(1.3	)	(.8	)	
   Impact of foreign currency exchange rates	 	(3.4	)	1.0	 	
Balance, end of year	 	$13.7	 	$17.6	 	

28

 
     Accrued interest and penalties totaled $12.0 million and $15.8 million as of December 31, 2010 and 2009, respectively, and were included in other liabilities on our consolidated balance sheets. We recognized net expense of $1.5 million and $3.3 million and net benefits of $6.8 million associated with interest and penalties during the years ended December 31, 2010, 2009 and 2008, respectively. Interest and penalties are included in current income tax expense in our consolidated statement of income.

     Tax years as early as 2003 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 2009 and 2010 U.S. federal tax returns remain subject to examination.
 
     During 2010, statutes of limitations applicable to certain of our tax positions lapsed resulting in a $1.3 million decline in unrecognized tax benefits and a $2.5 million net income tax benefit, inclusive of interest and penalties.
 
     During 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.
 
     Statutes of limitations applicable to certain of our tax positions will lapse during 2011. Therefore, it is reasonably possible that our unrecognized tax benefits will decline during the next twelve months by $3.9 million, which includes $2.0 million of accrued interest and penalties.

    Intercompany Transfer of Drilling Rigs
 
     Subsequent to our redomestication to the U.K. in December 2009, we reorganized our worldwide operations, which included, among other things, the transfer of ownership of several of our drilling rigs among our subsidiaries during 2010 and 2009.
 
     In April and December of 2010, we transferred ownership of several of our drilling rigs among certain of our subsidiaries, all of which are resident in the same tax jurisdiction and included in a consolidated tax return.  We incurred no income tax liability associated with gains and losses realized on the intercompany transfers by the selling subsidiaries.

29

 
     In December 2009, we transferred ownership of four of our drilling rigs among two of our subsidiaries. The income tax liability associated with the gain on the intercompany transfer totaled $30.8 million and was 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.
 
     As of December 31, 2010 and 2009, the unamortized balance associated with deferred charges for income taxes incurred in connection with intercompany transfers of drilling rigs totaled $74.6 million and $99.0 million, respectively, and was included in other assets, net, on our consolidated balance sheets. Current income tax expense for the years ended December 31, 2010, 2009 and 2008 included $24.4 million, $23.1 million and $23.1 million, respectively, of amortization of income taxes incurred in connection with intercompany transfers of drilling rigs.

     As of December 31, 2010 and 2009, the deferred tax liability associated with temporary differences of transferred drilling rigs totaled $35.2 million and $45.5 million, respectively, and was included in deferred income taxes on our consolidated balance sheets. Deferred income tax expense for the years ended December 31, 2010, 2009 and 2008 included benefits of $10.3 million, $7.0 million and $7.2 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.   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, 2010, the aggregate undistributed earnings of Ensco Delaware and Ensco Delaware's non-U.S. subsidiaries totaled $2,138.0 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 $517.6 million as of December 31, 2010.

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11.  DISCONTINUED OPERATIONS
 
    Rig Sales
 
     We sold jackup rig ENSCO 60 in November 2010 for $25.7 million and recognized a pre-tax gain of $5.7 million, which was included in gain on disposal of discontinued operations, net, in our consolidated statement of income for the year ended December 31, 2010. The rig’s net book value and inventory and other assets on the date of sale totaled $20.0 million.  ENSCO 60 operating results were reclassified to discontinued operations in our consolidated statements of income for each of the years in the three-year period ended December 31, 2010 and previously were included within our Jackup operating segment.

     In April 2010, we sold jackup rig ENSCO 57 for $47.1 million, of which a deposit of $4.7 million was received in December 2009. We recognized a pre-tax gain of $17.9 million in connection with the disposal of ENSCO 57, which was included in gain on disposal of discontinued operations, net, in our consolidated statement of income for the year ended December 31, 2010. The rig’s net book value and inventory and other assets on the date of sale totaled $29.2 million.  ENSCO 57 operating results were reclassified to discontinued operations in our consolidated statements of income for each of the years in the three-year period ended December 31, 2010 and previously were included within our Jackup operating segment.

     In March 2010, we sold jackup rigs ENSCO 50 and ENSCO 51 for an aggregate $94.7 million, of which a deposit of $4.7 million was received in December 2009. We recognized an aggregate pre-tax gain of $33.9 million in connection with the disposals of ENSCO 50 and ENSCO 51, which was included in gain on disposal of discontinued operations, net, in our consolidated statement of income for the year ended December 31, 2010.  The two rigs' aggregate net book value and inventory and other assets on the date of sale totaled $60.8 million. ENSCO 50 and ENSCO 51 operating results were reclassified to discontinued operations in our consolidated statements of income for each of the years in the three-year period ended December 31, 2010 and previously were included within our Jackup operating segment.
 
    ENSCO 69
 
     From May 2007 to June 2009, ENSCO 69 was contracted to Petrosucre.  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.  In June 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 nationalization of certain assets owned by other 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 2009 and reclassified its operating results to discontinued operations.
 
     On August 24, 2010, possession of ENSCO 69 was returned to Ensco. Due to the return of ENSCO 69 from Petrosucre and our ability to significantly influence the future operations of the rig and to incur significant future cash flows related to those operations until the pending insurance claim is resolved and possibly thereafter, ENSCO 69 operating results were reclassified to continuing operations for each of the years in the three-year period ended December 31, 2010.

     There can be no assurances relative to the recovery of outstanding contract entitlements, insurance recovery and related pending litigation or the imposition of customs duties in relation to the rig's recent presence in Venezuela.  See “Note 12 – Commitments and Contingencies” for additional information on contractual matters, insurance and legal proceedings related to ENSCO 69.

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    ENSCO 74
   
     In September 2008, ENSCO 74 was destroyed as a result of Hurricane Ike and the rig was a total loss, as defined under the terms of our insurance policies. The operating results of ENSCO 74 were reclassified to discontinued operations in our consolidated statement of income for the year ended December 31, 2008.  See "Note 12 - Commitments and Contingencies" for additional information on the loss of ENSCO 74 and associated contingencies.
 
     The following table summarizes income from discontinued operations for each of the years in the three-year period ended December 31, 2010 (in millions):

 	  2010  	    2009	2008     	
 	 	 	 	 	 	 	 	 	
Revenues	$12.5	    	 	$83.0	      	 	$244.0	  	
Operating expenses	17.1	 	 	54.2	 	 	89.3	 	
Operating (loss) income before income taxes	(4.6	)	 	28.8	 	 	154.7	 	
Income tax (benefit) expense	(3.4	)	 	(.5	)	 	27.8	 	
Gain (loss) on disposal of discontinued operations, net	38.6	 	 	--	 	 	(23.5	)	
Income from discontinued operations	$37.4	 	 	$29.3	 	 	$103.4	 	

     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 $15.9 million, $14.2 million and $13.9 million during the years ended December 31, 2010, 2009 and 2008, respectively. Future minimum rental payments under our noncancellable operating lease obligations are as follows: $8.2 million during 2011; $3.8 million during 2012; $2.5 million during 2013; $2.1 million during 2014 and $7.4 million thereafter.

    Capital Commitments

     The following table summarizes the aggregate contractual commitments related to our three ENSCO 8500 Series® rigs currently under construction as of December 31, 2010 (in millions):

2011	 	 	 	 	$  435.6	
2012	 	 	 	 	223.9	
Total	 	 	 	 	$659.5	
   
     In February 2011, we entered into agreements to construct two ultra-high specification harsh environment jackup rigs.  The amounts disclosed above exclude construction obligations of $87.6 million for 2011 and $350.2 million for 2013 related to these rigs.
   
     In connection with the aforementioned agreements to construct two new jackup rigs, we agreed with the shipyard contractor to defer $340.0 million of contractual commitments due during 2011 related to the construction of ENSCO 8505 and ENSCO 8506 until the rigs are delivered during the first and second half of 2012, respectively. The amounts disclosed above exclude the aforementioned deferral of contractual commitments.
 
     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.

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    Shareholder Class Actions
 
     In February 2011, four shareholder class action lawsuits were brought on behalf of the holders of Pride International, Inc. ("Pride") common stock against Pride, Pride’s directors and Ensco challenging Pride’s proposed merger with Ensco. The plaintiffs in such actions generally allege that each member of the Pride board of directors breached his or her fiduciary duties to Pride and its stockholders by authorizing the sale of Pride to Ensco for what plaintiffs deem “inadequate” consideration, Pride directly breached and/or aided and abetted the other defendants’ alleged breach of fiduciary duties and/or Ensco aided and abetted the alleged breach of fiduciary duties by Pride and its directors.  These lawsuits generally seek, among other things, to enjoin the defendants from consummating the merger on the agreed-upon terms. At this time, we are unable to predict the outcome of this matter or estimate the extent to which we may be exposed to any resulting liability.
 
    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 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 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. Discussions were held with the authorities to review the results of the investigation and discuss associated matters during 2009 and the first half of 2010.  On May 24, 2010, we received notification from the SEC Division of Enforcement advising that it does not intend to recommend any enforcement action.  We expect to receive a determination by the United States Department of Justice in the near-term. 

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     Although we believe the United States Department of Justice will take into account our voluntary disclosure, our cooperation with the agency 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 United States Department of Justice 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 an oil tanker. As an interim measure, the wreckage was appropriately marked, and the U.S. Coast Guard issued a Notice to Mariners.  During the fourth quarter of 2010, wreck removal operations on the sunken rig hull of ENSCO 74 were completed. As of December 31, 2010, wreckage and debris removal costs had been incurred and paid by Ensco totaling $26.8 million related to removal of the hull, substantially all of which has been recovered through insurance without any additional retention.

      We believe it is probable that we are 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, in addition to the removal of related debris.  We estimate the leg and related debris removal costs to range from $21.0 million to $35.0 million. We expect the cost of removal of the legs and related debris to be fully covered by our insurance without any additional retention.

     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 self-insured retention.  The insured value of ENSCO 74 was $100.0 million, and we have received the net $50.0 million due under our policy for loss of the rig.

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     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.

     A $21.0 million liability, representing the low end of the range of estimated leg and related debris removal costs, and a corresponding receivable for recovery of those costs was recorded as of December 31, 2010 and included in accrued liabilities and other and other assets, net, on our consolidated balance sheet.
 
     In March 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.  In September 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 a liability exists with respect to this matter.

     In March 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.

     We filed a petition for exoneration or limitation of liability under U.S. admiralty and maritime law in September 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 owner of the tanker that struck the hull of ENSCO 74 and the owners of four subsea pipelines have presented claims in the exoneration/limitation proceedings.  The matter is scheduled for trial in March 2012.

     We have liability insurance policies that provide coverage for claims such as the tanker and pipeline claims as well as removal of wreckage and debris in excess of the property insurance policy sublimit, subject to a $10.0 million per occurrence self-insured retention for third-party claims 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.

     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.

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    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.

     In September 2009, legal counsel acting for the package policy underwriters denied coverage under the package policy and reserved rights.  In March 2010, we commenced litigation to recover on our political risk package policy claim. Our lawsuit seeks recovery under the policy for the loss of ENSCO 69 and includes claims for wrongful denial of coverage, breach of contract, breach of the Texas insurance code, failure to timely respond to the claim and bad faith. Our lawsuit seeks actual damages in the amount of $55.0 million (insured value of $65.0 million less a $10.0 million deductible), punitive damages and attorneys' fees. In July 2010, we agreed with underwriters to submit the matter to arbitration.
 
     We were unable to conclude that collection of insurance proceeds associated with ENSCO 69 was probable as of December 31, 2010. Accordingly, no ENSCO 69 related insurance receivables were recorded on our consolidated balance sheet as of December 31, 2010. See "Note 11 - Discontinued Operations" for additional information on ENSCO 69.

    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 could 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 matter is scheduled for trial in April 2011.

     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 2011, none of the cases pending against us in Mississippi state court are included within those selected cases.

     We intend to continue 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 two other asbestos or lung injury claims pending against us in litigation in 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.

     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 time on/time off offshore rotation has been deemed to be fully compliant with the WTD.  The employee group (led by a trade union) was granted leave to appeal to the highest civil court in Scotland (the Court of Session).  A hearing on the appeal occurred in June 2010, and a decision was rendered in October 2010 in favor of the employer group.  The employee group has appealed to the U.K. Supreme Court, and a hearing is scheduled in October 2011.
 
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     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 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
 
     In connection with the Merger and resulting management reorganization, we evaluated our then-current core assets and operations and organized them into three segments based on water depth operating capabilities. Accordingly, we now consider our business to consist of three reportable segments: (1) Deepwater, which consists of our rigs capable of drilling in water depths of 4,500 feet or greater, (2) Midwater, which consists of our semisubmersible rigs capable of drilling in water depths of 4,499 feet or less and (3) Jackup, which consists of our jackup rigs capable of operating in water depths up to 400 feet. Each of our three reportable segments provides one service, contract drilling.  We also own one barge rig, which is included in "Other."

     As a result of our reorganization to three reportable segments, we retrospectively reclassified the segment information included herein to conform to the post-Merger presentation.  Reclassified segment information for each of the years in the three-year period ended December 31, 2010 is presented below (in millions). General and administrative expense and depreciation expense incurred by our corporate office are not allocated to our operating segments for purposes of measuring segment operating income and were included in "Reconciling Items."  We measure segment assets as property and equipment.
 
Year Ended December 31, 2010
 	 	 	 	 	 	 	 	
 	 	 	 	 	Operating	 	 	
 	 	 	 	 	Segments	Reconciling	  Consolidated	
 	Deepwater	Midwater	Jackup	Other	    Total    	    Items    	      Total    	
 	 	 	 	 	 	 	 	
Revenues	 	 	$   475.2	 	 	$    -- 	 	 	$1,221.6	 	 	$     --	 	 	$1,696.8	 	 	$     --	 	 	$1,696.8  	 	 	
Operating expenses
   Contract drilling (exclusive
      of depreciation)	 	 	176.1	 	 	-- 	 	 	578.2	 	 	13.8	 	 	768.1	 	 	--	 	 	768.1  	 	 	
   Depreciation	 	 	44.8	 	 	-- 	 	 	167.8	 	 	2.4	 	 	215.0	 	 	1.3	 	 	216.3  	 	 	
   General and administrative	 	 	--	 	 	-- 	 	 	--	 	 	--	 	 	--	 	 	86.1	 	 	86.1  	 	 	
Operating income (loss)	 	 	$   254.3	 	 	$    -- 	 	 	$   475.6	 	 	$(16.2	)	 	$   713.7	 	 	$(87.4	) 	 	$   626.3  	 	 	
Property and equipment, net	 	 	$2,866.4	 	 	$    -- 	 	 	$2,165.2	 	 	$ 14.4	 	 	$5,046.0	 	 	$   3.9	 	 	$5,049.9  	 	 	
Capital expenditures	 	 	632.5	 	 	-- 	 	 	238.7	 	 	--	 	 	871.2	 	 	4.1	 	 	875.3  	 	 	

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Year Ended December 31, 2009
 	 	 	 	 	 	 	 	
 	 	 	 	 	Operating	 	 	
 	 	 	 	 	Segments	Reconciling	  Consolidated	
 	Deepwater	Midwater	Jackup	Other	    Total    	    Items    	      Total    	
 	 	 	 	 	 	 	 	
Revenues	 	 	$   254.1	 	 	$    -- 	 	 	$1,634.8	 	 	$    --	 	 	$1,888.9	 	 	$     --	 	 	$1,888.9  	 	 	
Operating expenses
   Contract drilling (exclusive
      of depreciation)	 	 	108.1	 	 	-- 	 	 	599.0	 	 	1.9	 	 	709.0	 	 	--	 	 	709.0  	 	 	
   Depreciation	 	 	22.2	 	 	-- 	 	 	162.9	 	 	3.1	 	 	188.2	 	 	1.3	 	 	189.5  	 	 	
   General and administrative	 	 	--	 	 	-- 	 	 	--	 	 	--	 	 	--	 	 	64.0	 	 	64.0  	 	 	
Operating income (loss)	 	 	$   123.8	 	 	$    -- 	 	 	$   872.9	 	 	$ (5.0	)	 	$   991.7	 	 	$(65.3	) 	 	$   926.4  	 	 	
Property and equipment, net	 	 	$2,243.3	 	 	$    -- 	 	 	$2,200.8	 	 	$28.8	 	 	$4,472.9	 	 	$   4.4	 	 	$4,477.3  	 	 	
Capital expenditures	 	 	644.4	 	 	-- 	 	 	209.8	 	 	.3	 	 	854.5	 	 	2.7	 	 	857.2  	 	 	
 
Year Ended December 31, 2008
 	 	 	 	 	 	 	 	
 	 	 	 	 	Operating	 	 	
 	 	 	 	 	Segments	Reconciling	  Consolidated	
 	Deepwater	Midwater	Jackup 	Other	    Total    	    Items    	      Total    	
 	 	 	 	 	 	 	 	
Revenues	 	 	$     84.4	 	 	$    -- 	 	 	$2,144.0	 	 	$14.2	 	 	$2,242.6	 	 	$     --	 	 	$2,242.6  	 	 	
Operating expenses
   Contract drilling (exclusive
      of depreciation)	 	 	31.2	 	 	-- 	 	 	696.5	 	 	8.6	 	 	736.3	 	 	--	 	 	736.3  	 	 	
   Depreciation	 	 	9.1	 	 	-- 	 	 	158.3	 	 	3.3	 	 	170.7	 	 	1.9	 	 	172.6  	 	 	
   General and administrative	 	 	--	 	 	-- 	 	 	--	 	 	--	 	 	--	 	 	53.8	 	 	53.8  	 	 	
Operating income (loss)	 	 	$     44.1	 	 	$    -- 	 	 	$1,289.2	 	 	$  2.3	 	 	$1,335.6	 	 	$(55.7	) 	 	$1,279.9  	 	 	
Property and equipment, net	 	 	$1,641.2	 	 	 $    -- 	 	 	$2,194.0	 	 	$32.2	 	 	$3,867.4	 	 	$   3.9	 	 	$3,871.3  	 	 	
Capital expenditures	 	 	657.8	 	 	-- 	 	 	103.2	 	 	.5	 	 	761.5	 	 	2.7	 	 	764.2  	 	 	
 
    Information about Geographic Areas
   
     As of December 31, 2010, our Deepwater operating segment consisted of four ultra-deepwater semisubmersible rigs located in the U.S. Gulf of Mexico, one ultra-deepwater semisubmersible rig located in Singapore and three ultra-deepwater semisubmersible rigs under construction in Singapore. Our Jackup operating segment consisted of 40 jackup rigs deployed in various locations throughout Asia Pacific, Europe and Africa, and North and South America.  We also own one barge rig, which is included in "Other."
   
     Certain of our drilling rigs currently in the U.S. Gulf of Mexico have been or may be further affected by the regulatory developments and other actions that have or may be imposed by the U.S. Department of the Interior, including the regulations issued on September 30, 2010. The moratoriums/suspensions (which have been lifted), related Notices to Lessees ("NTLs"), delays in processing drilling permits and other actions are being challenged in litigation by Ensco and others. Utilization and day rates for certain of our drilling rigs have been negatively influenced due to regulatory requirements and delays in our customers’ ability to secure permits. Current or future NTLs or other directives and regulations may further impact our customers' ability to obtain permits and commence or continue deepwater or shallow-water operations in the U.S. Gulf of Mexico.  During the year ended December 31, 2010, revenues provided by our drilling operations in the U.S. Gulf of Mexico totaled $421.3 million, or 25% of our consolidated revenues. Of this amount, 65% was provided by our deepwater drilling operations in the U.S. Gulf of Mexico.  Prolonged actual or de facto delays, moratoria or suspensions of drilling activity in the U.S. Gulf of Mexico and associated new regulatory, legislative or permitting requirements in the U.S. or elsewhere could materially adversely affect our financial condition, operating results or cash flows.

39

     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            	
 	 2010 	 2009    	 2008  	    2010  	 2009    	 2008  	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
United States	 	$   421.3  	 	$   263.0   	  	$   461.4  	 	$1,993.3	 	$1,806.7   	 	$1,663.6   	 	
Australia	 	225.3  	 	188.7   	 	97.0  	 	194.9	 	175.0   	 	  274.4   	 	
United Kingdom	 	219.0  	 	353.2   	 	478.3  	 	 429.2	 	457.4   	 	309.0   	 	
Mexico	 	179.8  	 	159.5   	 	53.9  	 	 259.3	 	229.3   	 	41.2   	 	
Indonesia	 	56.8  	 	72.3   	 	254.2  	 	134.6	 	50.2   	 	153.9   	  	
Singapore	 	--  	 	--   	 	--  	 	1,235.6	 	  720.1   	 	550.5   	 	
Other countries	 	  594.6  	 	  852.2   	  	  897.8  	 	803.0	 	1,038.6   	 	  878.7   	 	
     Total	 	$1,696.8  	 	$1,888.9   	  	$2,242.6  	 	$5,049.9	 	$4,477.3   	  	$3,871.3   	 	

14.  SUPPLEMENTAL FINANCIAL INFORMATION

    Consolidated Balance Sheet Information

     Accounts receivable, net, as of December 31, 2010 and 2009 consisted of the following (in millions):

 	 2010           	       2009 	
 	    	             	
Trade	 	$209.9	 	$310.1	 	
Other	 	7.8	 	17.9	 	
 	 	217.7	 	328.0	 	
Allowance for doubtful accounts	 	(3.1	)	(3.4	)	
 	 	$214.6	 	$324.6	 	

     Other current assets as of December 31, 2010 and 2009 consisted of the following (in millions):

 	 2010            	       2009 	
 	 	 	
Inventory	 	$  56.4	 	$  53.1	 	
Prepaid taxes	 	47.4	 	39.6	 	
Deferred mobilization costs	 	19.7	 	29.0	 	
Derivative assets	 	17.0	 	10.5	 	
Prepaid expenses	 	 12.9	 	13.6	 	
Deferred tax assets	 	9.5	 	30.0	 	
Other	 	8.5	 	11.0	 	
 	 	$171.4	 	$186.8	 	

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     Other assets, net, as of December 31, 2010 and 2009 consisted of the following (in millions):

 	 2010  	           2009 	
 	 	 	 	 	 	
Prepaid taxes on intercompany transfers of property	 	$  74.6	 	$  99.0	 	
Deferred mobilization costs	 	31.3	 	23.7	 	
Wreckage and debris removal receivables	 	26.8	 	55.8	 	
Supplemental executive retirement plan assets	 	23.0	 	18.7	 	
Other	 	28.5	 	23.2	 	
 	 	$184.2	 	$220.4	 	

     Accrued liabilities and other as of December 31, 2010 and 2009 consisted of the following (in millions):

 	   2010            	          2009 	
 	 	 	
Personnel costs	 	$  58.0	 	$  48.6	 	
Deferred revenue	 	48.1	 	89.0	 	
Taxes	 	22.1	 	97.3	 	
Wreckage and debris removal	 	21.0	 	50.3	 	
Other	 	19.1	 	23.4	 	
 	 	$168.3	 	$308.6	 	

     Other liabilities as of December 31, 2010 and 2009 consisted of the following (in millions):

 	 2010             	            2009     	
 	 	 	
Deferred revenue	 	$  68.0	 	$  51.2	 	
Unrecognized tax benefits (inclusive of interest and penalties)	 	25.7	             	33.4	 	
Supplemental executive retirement plan liabilities	 	26.0	 	21.0	 	
Other	 	19.7	 	15.1	 	
 	 	$139.4	 	$120.7	 	

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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, 2010 was as follows (in millions):

 	2010     	  2009     	  2008      	
 	 	 	 	
Repair and maintenance expense	 	$120.0	 	$120.6	    	$111.4	     	

    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, 2010 was as follows (in millions):

 	      2010     	2009      	      2008     	
 	 	 	 	
Interest, net of amounts capitalized	 	$      .1	 	$      .1	 	$      .5	 	
Income taxes	 	171.6	 	152.9	 	327.7	 	

     Capitalized interest totaled $21.3 million, $20.9 million and $21.6 million during the years ended December 31, 2010, 2009 and 2008, respectively. Capital expenditure accruals totaling $39.7 million, $83.8 million and $105.1 million for the years ended December 31, 2010, 2009 and 2008, respectively, were excluded from investing activities in our consolidated statements 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, 2010, two customers provided a total of $421.4  million, or 25%, of consolidated revenues which were attributable to our Deepwater and Jackup segments.   During the year ended December 31, 2009, one customer provided $249.6 million, or 13%, of consolidated revenues which were attributable to our Jackup segment.  During the year ended December 31, 2008, 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, 2010 and 2009 (in millions, except per share amounts):

2010	First       
Quarter        	Second       
Quarter        	Third       
Quarter        	Fourth       
Quarter        	       Year 	
 	 	 	 	 	 	
Operating revenues	$448.6	 	 	$411.4	 	 	$428.3	 	 	$408.5	 	 	$1,696.8	 	 	
Operating expenses	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
   Contract drilling (exclusive of depreciation)	182.4	 	 	206.0	 	 	194.1	 	 	185.6	 	 	768.1	 	 	
   Depreciation	51.7	 	 	51.9	 	 	55.6	 	 	57.1	 	 	216.3	 	 	
   General and administrative	20.6	 	 	22.0	 	 	20.6	 	 	22.9	 	 	86.1	 	 	
Operating income	193.9	 	 	131.5	 	 	158.0	 	 	142.9	 	 	626.3	 	 	
Other income (expense), net	3.1	 	 	12.8	 	 	2.7	 	 	(.4	)	 	18.2	 	 	
Income from continuing operations before income taxes	197.0	 	 	144.3	 	 	160.7	 	 	142.5	 	 	644.5	 	 	
Provision for income taxes	35.0	 	 	22.4	 	 	26.7	 	 	11.9	 	 	96.0	 	 	
Income from continuing operations	162.0	 	 	121.9	 	 	134.0	 	 	130.6	 	 	548.5	 	 	
Income (loss) from discontinued operations, net	29.6	 	 	6.0	 	 	(1.9	)	 	3.7	 	 	37.4	 	 	
Net income	191.6	 	 	127.9	 	 	132.1	 	 	134.3	 	 	585.9	 	 	
Net income attributable to noncontrolling interests	(1.8	)	 	(1.6	)	 	(1.6	)	 	(1.4	)	 	(6.4	)	 	
Net income attributable to Ensco	$189.8	 	 	$126.3	 	 	$130.5	 	 	$132.9	 	 	$   579.5	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Earnings (loss) per share – basic	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
   Continuing operations	$  1.12	 	 	$    .85	 	 	$    .92	 	 	$    .90	 	 	$     3.80	 	 	
   Discontinued operations	.21	 	 	.04	 	 	(.01	)	 	.03	 	 	.26	 	 	
 	$  1.33	 	 	$    .89	 	 	$    .91	 	 	$    .93	 	 	$     4.06	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Earnings (loss) per share - diluted	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
   Continuing operations	$  1.12	 	 	$    .85	 	 	$    .92	 	 	$    .90	 	 	$     3.80	 	 	
   Discontinued operations	.21	 	 	.04	 	 	(.01	)	 	.03	 	 	.26	 	 	
 	$  1.33	 	 	$    .89	 	 	$    .91	 	 	$    .93	 	 	$     4.06	 	 	

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2009	First       
Quarter        	Second       
Quarter        	Third       
Quarter        	Fourth       
Quarter        	         Year 	
 	 	 	 	 	 	
Operating revenues	$484.8	 	 	$497.4	 	 	$408.9	 	 	$497.8	 	 	$1,888.9	 	 	
Operating expenses	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
   Contract drilling (exclusive of depreciation)	161.5	 	 	196.3	 	 	175.4	 	 	175.8	 	 	709.0	 	 	
   Depreciation	43.7	 	 	45.3	 	 	48.9	 	 	51.6	 	 	189.5	 	 	
   General and administrative	12.0	 	 	16.0	 	 	13.6	 	 	22.4	 	 	64.0	 	 	
Operating income	267.6	 	 	239.8	 	 	171.0	 	 	248.0	 	 	926.4	 	 	
Other income (expense), net	(4.3	)	 	6.9	 	 	3.6	 	 	2.6	 	 	8.8	 	 	
Income from continuing operations before income taxes	263.3	 	 	246.7	 	 	174.6	 	 	250.6	 	 	935.2	 	 	
Provision for income taxes 	52.2	 	 	47.9	 	 	29.6	 	 	50.3	 	 	180.0	 	 	
Income from continuing operations	211.1	 	 	198.8	 	 	145.0	 	 	200.3	 	 	755.2	 	 	
Income from discontinued operations, net	11.0	 	 	2.6	 	 	5.8	 	 	9.9	 	 	29.3	 	 	
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 per share - basic	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
   Continuing operations	$  1.48	 	 	$  1.39	 	 	$  1.01	 	 	$  1.40	 	 	$     5.28	 	 	
   Discontinued operations	.08	 	 	.02	 	 	.04	 	 	.06	 	 	.20	 	 	
 	$  1.56	 	 	$  1.41	 	 	$  1.05	 	 	$  1.46	 	 	$     5.48	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Earnings per share - diluted	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
   Continuing operations	$  1.48	 	 	$  1.39	 	 	$  1.01	 	 	$  1.40	 	 	$     5.28	 	 	
   Discontinued operations	.08	 	 	.02	 	 	.04	 	 	.06	 	 	.20	 	 	
 	$  1.56	 	 	$  1.41	 	 	$  1.05	 	 	$  1.46	 	 	$     5.48	 	 	
 
16.  SUBSEQUENT EVENT
 
     Pending Merger with Pride
 
     On February 6, 2011, Ensco plc entered into an Agreement and Plan of Merger with Pride International, Inc., a Delaware corporation (“Pride”), Ensco Delaware, and ENSCO Ventures LLC, a Delaware limited liability company and an indirect, wholly-owned subsidiary of Ensco (“Merger Sub”). Pursuant to the merger agreement and subject to the conditions set forth therein, Merger Sub will merge with and into Pride, with Pride as the surviving entity and an indirect, wholly-owned subsidiary of Ensco.  As a result of the merger, each outstanding share of Pride’s common stock (other than shares of common stock held directly or indirectly by Ensco, Pride or any wholly-owned subsidiary of Ensco or Pride (which will be cancelled as a result of the merger), those shares with respect to which appraisal rights under Delaware law are properly exercised and not withdrawn and other shares held by certain U.K. residents if determined by Ensco) will be converted into the right to receive $15.60 in cash and 0.4778 Ensco ADSs. Under certain circumstances, U.K. residents may receive all cash consideration as a result of compliance with legal requirements.

44

 
     We estimate that the total consideration to be delivered in the merger to be approximately $7,400.0 million, consisting of $2,800.0 million of cash, the delivery of approximately 86.0 million Ensco ADSs (assuming that no Pride employee stock options are exercised before the closing of the merger) with an aggregate value of $4,550.0 million based on the closing price of Ensco ADSs of $52.88 on February 15, 2011 and the estimated fair value of $45.0 million of Pride employee stock options assumed by Ensco.  The value of the merger consideration will fluctuate based upon changes in the price of Ensco ADSs and the number of shares of Pride common stock and employee options outstanding on the closing date. The merger agreement and the merger were approved by the respective Boards of Directors of Ensco and Pride.  Consummation of the merger is subject to the approval of the shareholders of Ensco and the stockholders of Pride, regulatory approvals and the satisfaction or waiver of various other conditions as more fully described in the merger agreement.  Subject to receipt of required approvals, it is anticipated that the closing of the merger will occur during the second quarter of 2011.
 
    On February 6, 2011, we entered into a bridge commitment letter (the “Commitment Letter”) with Deutsche Bank AG Cayman Islands Branch (“DBCI”), Deutsche Bank Securities Inc. and Citigroup Global Markets Inc. (“Citi”). Pursuant to the Commitment Letter, DBCI and Citi have committed to provide a $2,750.0 million unsecured bridge term loan facility (the “Bridge Term Facility”) to fund a portion of the cash consideration in the merger.  The Bridge Term Facility would mature 364 days after closing. The commitment is subject to various conditions, including the absence of a material adverse effect on Pride or Ensco having occurred, the maintenance by us of investment grade credit ratings, the execution of satisfactory documentation and other customary closing conditions.
 
    Shareholder Class Actions

     Four shareholder class actions were brought on behalf of the holders of Pride International, Inc. common stock against Pride, Pride’s directors and Ensco plc and certain of its subsidiaries arising out of the proposed sale of Pride to Ensco. See “Note 12 – Commitments and Contingencies” for additional information on these shareholder class actions.

 

45

 

Exhibit 99.2
 
     The following “Management’s Discussion and Analysis of Financial Condition and Results of Operations” should be read in conjunction with our consolidated financial statements included in “Item 8.  Financial Statements and Supplementary Data.”  Any references to Notes in the following “Management’s Discussion and Analysis of Financial Condition and Results of Operations” refer to the Notes to Consolidated Financial Statements included in “Item 8.  Financial Statements and Supplementary Data” (attached as Exhibit 99.1 to this Report).

     As further discussed in Note 13 to our consolidated financial statements, our consolidated financial statements for all periods presented herein have been updated to retrospectively reflect the reorganization of our reportable segments resulting from the merger transaction with Pride International, Inc. (the "Merger") completed on May 31, 2011, pursuant to which Pride International became an indirect, wholly-owned subsidiary of Ensco plc.  This filing includes updates only to the portions of Item 1, Item 7 and Item 8 of the Form 10-K that specifically relate to the updated segment disclosures resulting from the Merger and reorganization and does not otherwise modify or update any other disclosures set forth in the Form 10-K.
 
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 46 drilling rigs, including 40 jackup rigs, five ultra-deepwater semisubmersible rigs and one barge rig.  Additionally, we have three ultra-deepwater semisubmersible rigs and two ultra-high specification harsh environment jackup rigs under construction.  We are concentrated in premium jackup rigs, but are currently in the process of developing a fleet of ultra-deepwater semisubmersible rigs. Our 46 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.
 
     In May 2010, the U.S. Department of the Interior implemented a six-month moratorium/suspension on certain drilling activities in water depths greater than 500 feet in the U.S. Gulf of Mexico. The U.S. Department of the Interior subsequently issued NTLs implementing additional safety and certification requirements applicable to drilling activities in the U.S. Gulf of Mexico, imposed additional requirements with respect to development and production activities in the U.S. Gulf of Mexico and has delayed the approval of applications to drill in both deepwater and shallow-water areas. On July 12, 2010, the U.S. Department of the Interior issued a revised moratorium/suspension on drilling in the U.S. Gulf of Mexico, which was lifted on October 12, 2010 after the adoption on September 30, 2010 of new regulations relating to the design of wells and testing of the integrity of wellbores, the use of drilling fluids, the functionality and testing of well control equipment, including third-party inspections, minimum requirements for personnel, blowout preventers and other safety regulations.  It is uncertain what impact these new regulations may have upon our operations and our customers' ability to obtain new drilling permits.
 
     As a condition to lifting of the moratorium/suspension, the Bureau of Ocean Energy Management, Regulation and Enforcement (the “BOEM”) was directed to require that each operator demonstrate that it has in place written and enforceable commitments that ensure that containment resources are available promptly in the event of a blowout and that the Chief Executive Officer of each operator certify to the BOEM that the operator has complied with applicable regulations. Before deepwater drilling is resumed, the BOEM intends to conduct inspections of each deepwater drilling operation for compliance with regulations, including but not limited to the testing of blowout preventers. It is unclear when these requirements will be satisfied, due in part to the limited staffing of the BOEM.
 
     Certain of our drilling rigs currently in the U.S. Gulf of Mexico have been or may be further affected by the regulatory developments and other actions that have or may be imposed by the U.S. Department of the Interior, including the regulations issued on September 30, 2010. The moratoriums/suspensions (which have been lifted), related NTLs, delays in processing drilling permits and other actions are being challenged in litigation by Ensco and others. Utilization and day rates for certain of our drilling rigs have been negatively influenced due to regulatory requirements and delays in our customers’ ability to secure permits. Current or future NTLs or other directives and regulations may further impact our customers' ability to obtain permits and commence or continue deepwater or shallow-water operations in the U.S. Gulf of Mexico.  
 
1

 
     Operating results in our Deepwater segment improved during 2010, partially offset by lower utilization and day rates incurred as a result of the aforementioned regulatory developments and other actions imposed by the U.S. Department of the Interior. ENSCO 7500 operated in Australia at a day rate of approximately $550,000 for the majority of the year and currently is undergoing an enhancement project in order to commence drilling operations in Brazil under a two-and-a-half year contract during the third quarter of 2011.  ENSCO 8500 and ENSCO 8501 continued to operate under their long-term contracts in the U.S. Gulf of Mexico. ENSCO 8502 was delivered in January 2010 and commenced drilling operations in the U.S. Gulf of Mexico under a short-term sublet agreement during the fourth quarter of 2010. ENSCO 8503 was delivered in September 2010 and is expected to commence drilling operations in French Guiana under a short-term sublet agreement during the first quarter of 2011. ENSCO 8502 and ENSCO 8503 are expected to commence drilling operations in the U.S. Gulf of Mexico under two-year contracts during 2011.
 
     During 2010, we continued construction of ENSCO 8504, ENSCO 8505 and ENSCO 8506.  These rigs currently are uncontracted and scheduled for delivery during the third quarter 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 $1,050.7 million of cash and cash equivalents as of December 31, 2010, and over $3,000.0 million of contract backlog will enable us to sustain an adequate level of liquidity during 2011 and beyond.
 
     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. Although oil prices have stabilized and recently improved, incremental drilling activity during 2010 was limited resulting in continued softness in day rates for standard duty jackup rigs. Accordingly, our jackup rig operating results continued to decline from their 2009 levels due to a decline in day rates for our jackup rigs in all geographic regions.
 
     In conjunction with our long-established strategy of high-grading our jackup rig fleet by investing in newer equipment, we sold three jackup rigs located in the Asia Pacific region and one jackup rig located in the U.S. Gulf of Mexico during 2010.  In addition, we acquired an ultra-high specification jackup rig constructed in 2008.  The rig was renamed ENSCO 109 and is currently operating in Australia.
 
     In February 2011, we entered into agreements with KFELS to construct two ultra-high specification harsh environment jackup rigs.  These rigs currently are uncontracted and scheduled for delivery during the first and second half of 2013, respectively.
 
Pending Merger with Pride

     On February 6, 2011, Ensco plc entered into an Agreement and Plan of Merger with Pride International, Inc., a Delaware corporation (“Pride”), Ensco Delaware, and ENSCO Ventures LLC, a Delaware limited liability company and an indirect, wholly-owned subsidiary of Ensco (“Merger Sub”). Pursuant to the merger agreement and subject to the conditions set forth therein, Merger Sub will merge with and into Pride, with Pride as the surviving entity and an indirect, wholly-owned subsidiary of Ensco.  As a result of the merger, each outstanding share of Pride’s common stock (other than shares of common stock held directly or indirectly by Ensco, Pride or any wholly-owned subsidiary of Ensco or Pride (which will be cancelled as a result of the merger), those shares with respect to which appraisal rights under Delaware law are properly exercised and not withdrawn and other shares held by certain U.K. residents if determined by Ensco) will be converted into the right to receive $15.60 in cash and 0.4778 Ensco ADSs. Under certain circumstances, U.K. residents may receive all cash consideration as a result of compliance with legal requirements.

     We estimate that the total consideration to be delivered in the merger to be approximately $7,400.0 million, consisting of $2,800.0 million of cash, the delivery of approximately 86.0 million Ensco ADSs (assuming that no Pride employee stock options are exercised before the closing of the merger) with an aggregate value of $4,550.0 million based on the closing price of Ensco ADSs of $52.88 on February 15, 2011 and the estimated fair value of $45.0 million of Pride employee stock options assumed by Ensco.  The value of the merger consideration will fluctuate based upon changes in the price of Ensco ADSs and the number of shares of Pride common stock and employee options outstanding on the closing date. The merger agreement and the merger were approved by the respective Boards of Directors of Ensco and Pride.  Consummation of the merger is subject to the approval of the shareholders of Ensco and the stockholders of Pride, regulatory approvals and the satisfaction or waiver of various other conditions as more fully described in the merger agreement.  Subject to receipt of required approvals, it is anticipated that the closing of the merger will occur during the second quarter of 2011.

2

 
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.	
 
     Depressed oil and natural gas prices and the deterioration of the global economy resulted in a modest decline in demand for ultra-deepwater semisubmersible rigs during 2009, however, global utilization and day rates generally were stable due to the long-term nature of deepwater projects.  Demand for ultra-deepwater semisubmersible rigs in the U.S. Gulf of Mexico remained stable during the first half of 2010 but came under pressure as a result of delays in operators’ ability to secure permits due to regulatory developments and other actions imposed by the U.S. Department of the Interior. There is significant uncertainty as to the near-term impact the BP Macondo well incident and associated new regulatory, legislative or permitting requirements may have on deepwater drilling in the U.S. Gulf of Mexico, in addition to the potential impact on the global deepwater market.
 
     Depressed oil and natural gas prices and the deterioration of the global economy led to an abrupt reduction in demand for jackup rigs during 2009. Although oil prices have stabilized and recently improved, incremental drilling activity during 2010 was limited resulting in continued softness in day rates for standard duty jackup rigs.  We are encouraged by improving tender activity due to a modest increase in jackup rig demand for work in 2011 across various regions.  However, it is uncertain as to the impact the BP Macondo well incident and associated new regulatory, legislative or permitting requirements may have on jackup rig demand in general, and in the U.S. Gulf of Mexico in particular.
 
     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.

 
3

    Drilling Rig Supply

     During recent periods of high demand for drilling rigs, various industry participants ordered the construction of over 170 new jackup and semisubmersible rigs, over 100 of which were delivered during the last three years.

     Semisubmersible rig supply continues to increase as a result of newbuild construction programs. It has been reported that over 20 newbuild semisubmersible rigs are currently under construction, over half of which are scheduled for delivery during 2011. The majority of semisubmersible rigs scheduled for delivery are contracted.  We expect newbuild semisubmersible rigs will be absorbed into the global market without a significant effect on utilization and day rates.
 
     Jackup rig supply also continues to increase as a result of newbuild construction programs, the majority of which were initiated prior to the 2008 decline in oil and natural gas prices and the deterioration of the global economy. It has been reported that over 30 newbuild jackup rigs are currently under construction, over half of which are scheduled for delivery during 2011. The majority of jackup rigs scheduled for delivery are not contracted.
 
     Newbuild jackup rigs may reduce utilization and day rates as rigs are absorbed into the fleet, especially in light of current levels of standard duty jackup rig demand.  A significant portion of rig construction is occurring in the Asia Pacific region and it is time consuming and expensive to move drilling rigs between markets in response to changes in supply and demand.  Accordingly, the supply of rigs in the Asia Pacific region, or other regions where newbuild rigs are delivered, may not adjust quickly which could lead to sudden changes in utilization and day rates. It is unlikely that the market in general or any geographic region in particular will be able to fully absorb newbuild jackup rig deliveries in the near-term, especially in consideration of the existing oversupply.

     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.
 
BUSINESS ENVIRONMENT
 
Deepwater

     During 2008, global demand for ultra-deepwater semisubmersible rigs exceeded supply resulting in high utilization levels and day rates.  During 2009, lower oil and natural gas prices resulted in a modest decline in demand for ultra-deepwater semisubmersible rigs with utilization and day rates generally remaining stable due to the long-term nature of deepwater projects.  Although utilization and day rates remained stable during the first half of 2010, a significant number of U.S. Gulf of Mexico deepwater projects have been delayed as a result of delays in operators' ability to secure permits.  Certain well operations were permitted to continue under the moratorium/suspension, such as workovers and completions, forcing operators and contractors to pursue non-conventional, short-term programs.  Most contractors have hesitated to abandon the substantial deepwater reservoir potential in the region, while continuing to monitor developments regarding permitting delays.  Although a limited number of rigs have mobilized from the U.S. Gulf of Mexico to other regions, additional rigs are expected to exit the U.S. Gulf of Mexico in the near-term.  Utilization and day rates could come under pressure if additional deepwater contracts in the U.S. Gulf of Mexico are terminated and/or those rigs are marketed in, or relocated to, other regions.  Future ultra-deepwater semisubmersible rig utilization and day rates will depend, in large part, on projected oil and natural gas prices, the global economy and the near-term impact the BP Macondo well incident and associated new regulatory, legislative or permitting requirements may have on the U.S. Gulf of Mexico and global deepwater markets.
 
Jackup
 
     There was substantial volatility in jackup rig demand during 2008. During the first half of the year, jackup rig demand remained strong due to record high oil and natural gas prices, resulting in high utilization levels and day rates.  However, during the latter half of 2008, oil and natural gas prices declined substantially due primarily to a decrease in demand for oil and natural gas resulting from the deteriorating global economy.  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 have stabilized and recently improved, incremental drilling activity during 2010 was limited resulting in continued softness in day rates for standard duty jackup rigs. Given the deterioration of the global economy and tightening of credit markets, the jackup industry continues to face the challenge of excess rig supply.  Therefore, we expect that jackup rig utilization and day rates may remain under pressure in the near-term.
 
4

 
     During the first half of 2008, jackup rig utilization in the Asia Pacific Rim, including Vietnam, Malaysia, Indonesia and Australia, 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 in the region was significantly impacted by the decline in oil and natural gas prices and the deterioration of the global economy, resulting in a significant reduction in utilization and day rates during 2009.  The Asia Pacific Rim jackup market began to stabilize during 2010 with incremental demand seen as multiple tenders were recently issued for work in 2011 and beyond.  In consideration of an expected increase in the supply of available jackup rigs from newbuild deliveries, jackup rig utilization and day rates in the region may remain under pressure in the near-term.

     During 2008, shortfalls in rig availability in the North Sea led to high utilization levels and day rates.  Depressed oil and natural gas prices and the deterioration of the global economy resulted in several cancelled tenders and unexercised contract extension options in the region during the latter portion of 2009.  Tender activity during 2010 was limited but with a recent increase seen in inquiries for work beginning in mid-2011 resulting from incremental demand.  However, with limited tender activity for work beginning in early 2011 and an excess supply of standard duty jackup rigs, jackup rig utilization and day rates in the North Sea may remain under pressure in the near-term.

     A significant portion of our jackup rig operations are conducted in Mexico, where demand for rigs increased during 2008 and 2009 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 2010, the number of jackup rigs contracted in Mexico declined as contracts expired.  However, additional tender activity for work beginning in 2011 is expected in the near-term as PEMEX attempts to replenish its jackup rig fleet.  We expect future day rates in Mexico to face pressure as jackup rig contracts in the region continue to expire and drilling contractors with idle rigs in the U.S. Gulf of Mexico and other geographic regions pursue the available contract opportunities.

     We also conduct a portion of our jackup rig operations in the U.S. Gulf of Mexico. 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 the deterioration of the global economy. The U.S. Gulf of Mexico jackup rig market remained extremely weak during 2009, with drilling activity reaching historic lows. During early 2010, tender activity in the U.S. Gulf of Mexico improved as operators capitalized on cost-effective terms offered by drilling contractors.  During the latter portion of 2010, certain operators experienced an inability to timely obtain drilling permits which negatively influenced utilization and day rates in the region.  Due to the uncertainty regarding the impact the BP Macondo well incident and associated new regulatory, legislative or permitting requirements may have on jackup rig drilling operations in the region, U.S. Gulf of Mexico jackup rig utilization and day rates may remain under pressure 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, 2010 (in millions):

 	          2010 	         2009 	 2008    	
 	 	 	 	 	 	 	 	 	 	
Revenues	 	$1,696.8	 	 	$1,888.9	 	 	$2,242.6	 	
Operating expenses	 	 	 	 	 	 	 	 	 	
     Contract drilling (exclusive of depreciation)	 	768.1	 	 	709.0	 	 	736.3	 	
     Depreciation	 	216.3	 	 	189.5	 	 	172.6	 	
     General and administrative 	 	86.1	 	 	64.0	 	 	53.8	 	
Operating income 	 	626.3	 	 	926.4	 	 	1,279.9	 	
Other income (expense), net 	 	18.2	 	 	8.8	 	 	(4.2	)	
Provision for income taxes 	 	 96.0	 	 	180.0	 	 	222.4	 	
Income from continuing operations 	 	548.5	 	 	755.2	 	 	1,053.3	 	
Income from discontinued operations, net 	 	37.4	 	 	29.3	 	 	103.4	 	
Net income 	 	585.9	 	 	784.5	 	 	1,156.7	 	
Net income attributable to noncontrolling interests	 	(6.4	)	 	(5.1	)	 	(5.9	)	
Net income attributable to Ensco	 	$  579.5	 	 	$  779.4	 	 	$1,150.8	 	

5

 
     During 2010, revenues declined by $192.1 million, or 10%, and operating income declined by $300.1 million, or 32%, as compared to the prior year. These declines were primarily due to a decline in jackup rig utilization and average day rates in the Europe, Mediterranean and Asia Pacific Rim markets coupled with a decline in jackup rig average day rates in the North America market, partially offset by a significant increase in revenues and operating income generated by our deepwater rigs.
 
     During 2009, revenues declined by $353.7 million, or 16%, and operating income declined by $353.5 million, or 28%, as compared to the prior year. These 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.
 
     A significant number of our drilling contracts are of a long-term nature. Accordingly, a decline in demand for contract drilling services typically affects our operating results and cash flows gradually over many quarters as long-term contracts expire. The significant decline in oil and natural gas prices during the latter half of 2008 and the deterioration of the global economy resulted in a dramatic decline in demand for contract drilling services during 2009 and 2010, which is expected to continue to negatively impact our operating results during 2011.
 
     Furthermore, the BP Macondo well incident and associated new regulatory, legislative or permitting requirements negatively influenced demand for contract drilling services in the U.S. Gulf of Mexico during 2010, which is expected to continue during 2011.
 
     While we have contract backlog of over $1,300.0 million for 2011, it is uncertain whether revenue, operating income and cash flow levels achieved during 2010 will be sustained during 2011.

Rig Locations, Utilization and Average Day Rates
 
     The following table summarizes our offshore drilling rigs by reportable segment and rigs under construction as of December 31, 2010, 2009 and 2008:
 
 	2010	  2009	2008	
 	 	 	 	
Dee p w ater (1)	5  	3  	2  	
Midwater (2)	--  	--  	--  	
Jackup (3)	40  	39  	39  	
Under construction (1)	3  	5  	6  	
Total (4)	48  	47  	47  	
 
     (1)
 	 	ENSCO 8502 was delivered in January 2010 and commenced drilling operations in the U.S. Gulf of Mexico under a short-term sublet agreement during the fourth quarter of 2010. ENSCO 8503 was delivered in September 2010 and is expected to commence drilling operations in French Guiana under a short-term sublet agreement during the first quarter of 2011. ENSCO 8502 and ENSCO 8503 are expected to commence drilling operations in the U.S. Gulf of Mexico under two-year contracts during 2011.
 
During 2009, we accepted delivery of ENSCO 8501, which commenced drilling operations in the U.S. Gulf of Mexico under a three-and-a-half year contract in October 2009.
 	
    (2)	 	In May 2011, midwater rigs were acquired in connection with the Merger.  Therefore, our rig fleet did not consist of midwater rigs as of December 31, 2010, 2009 and 2008.	
 
    (3)	 	In July 2010, we acquired an ultra-high specification jackup rig.  The rig was renamed ENSCO 109 and is currently operating offshore Australia.
 	
    (4)	 	The total number of rigs for each period excludes rigs reclassified to discontinued operations.	

6

 
     The following table summarizes our rig utilization and average day rates from continuing operations by reportable segment for each of the years in the three-year period ended December 31, 2010:
 
 	    2010	    2009	        2008	
 	 	 	 	 	 	 	 	
Rig utilization (1)	 	 	 	 	 	 	 	
Deepwater	 	81%	 	85%	 	95%	 	
Midwater (3)	 	N/A	 	N/A	 	N/A	 	
Jackup (4)	 	77%	 	74%	 	96%	 	
Total	 	77%	 	75%	 	96%	 	
 
Average day rates (2)	 	 	 	 	 	 	 	
Deepwater	 	$375,098	 	$425,190	 	$334,688	 	
Midwater (3)	 	N/A	 	N/A	 	N/A	 	
Jackup (4)	 	106,007	 	151,636	 	152,418	 	
Total	 	$128,784	 	$163,568	 	$155,767	 	

(1)	 	Rig utilization is derived by dividing the number of days under contract by the number of days in the period. Days under contract equals the total number of days that rigs have earned a day rate, including days associated with compensated downtime and mobilizations. For newly constructed or acquired rigs, the number of days in the period begins upon commencement of drilling operations for rigs with a contract or when the rig becomes available for drilling operations for rigs without a contract.
 	
(2)	 	Average day rates are derived by dividing contract drilling revenues, adjusted to exclude certain types of non-recurring reimbursable revenues 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 were not applicable for the Midwater segment as our rig fleet did not consist of midwater rigs during each of the years in the three-year period ended December 31, 2010.
 	
(4)	 	ENSCO 69 has been excluded from rig utilization and average day rates for our Jackup operating segment during the period the rig was controlled and operated by Petrosucre, a subsidiary of Petróleos de Venezuela S.A., the national oil company of Venezuela (January 2009 - August 2010).  See Note 11 to our consolidated financial statements for additional information on ENSCO 69.	
 
     Detailed explanations of our operating results, including discussions of revenues, contract drilling expense and depreciation expense by segment, are provided below.

7

Operating Income

     In connection with the Merger and resulting management reorganization, we evaluated our then-current core assets and operations and organized them into three segments based on water depth operating capabilities. Accordingly, we now consider our business to consist of three reportable segments: (1) Deepwater, which consists of our rigs capable of drilling in water depths of 4,500 feet or greater, (2) Midwater, which consists of our semisubmersible rigs capable of drilling in water depths of 4,499 feet or less and (3) Jackup, which consists of our jackup rigs capable of operating in water depths up to 400 feet. Each of our three reportable segments provides one service, contract drilling.  We also own one barge rig, which is included in “Other.”

     As a result of our reorganization to three reportable segments, we retrospectively reclassified the segment information included herein to conform to the post-Merger presentation.  The following tables summarize our operating income for each of the years in the three-year period ended December 31, 2010 (in millions).  General and administrative expense and depreciation expense incurred by our corporate office are not allocated to our operating segments for purposes of measuring segment operating income and were included in "Reconciling Items."
 
Year Ended December 31, 2010
 	 	 	 	 	 	 	 	
 	 	 	 	 	Operating	 	 	
 	 	 	 	 	Segments	Reconciling	Consolidated	
 	Deepwater	Midwater	Jackup	Other	    Total    	    Items    	      Total      	
 	 	 	 	 	 	 	 	
Revenues	$475.2       	$    --        	$1,221.6      	$    --       	$1,696.8    	$      --    	$1,696.8    	
Operating expenses
   Contract drilling (exclusive
      of depreciation)	176.1       	--        	578.2      	13.8      	768.1    	--    	768.1    	
   Depreciation	44.8       	--        	167.8     	2.4      	215.0    	1.3    	216.3    	
   General and administrative	--       	--        	--      	--      	--    	86.1    	86.1    	
Operating income (loss)	$254.3       	$    --        	$  475.6      	$(16.2)     	$   713.7    	$(87.4)   	$   626.3    	
 
Year Ended December 31, 2009
 	 	 	 	 	 	 	 	
 	 	 	 	 	Operating	 	 	
 	 	 	 	 	Segments	Reconciling	  Consolidated	
 	Deepwater	Midwater	 Jackup	Other	    Total    	    Items    	          Total      	
 	 	 	 	 	 	 	 	
Revenues 	$254.1       	$    --        	$1,634.8      	$     --      	$1,888.9    	$     --    	$1,888.9    	
Operating expenses
   Contract drilling (exclusive
      of depreciation) 	108.1       	--        	599.0      	1.9      	709.0    	--   	709.0    	
   Depreciation 	22.2       	--        	162.9      	3.1      	188.2    	1.3   	189.5    	
   General and administrative 	--        	--        	--      	--      	--    	64.0   	64.0    	
Operating income (loss)	$123.8       	$    --        	$  872.9      	$ (5.0)     	$   991.7    	$(65.3)  	$   926.4    	

Year Ended December 31, 2008
 	 	 	 	 	 	 	 	
 	 	 	 	 	Operating	 	 	
 	 	 	 	 	Segments	Reconciling	  Consolidated	
 	Deepwater	Midwater	Jackup	Other	    Total    	    Items    	          Total      	
 	 	 	 	 	 	 	 	
Revenues 	$  84.4       	$    --        	$2,144.0      	$ 14.2      	$2,242.6    	$    --    	$2,242.6    	
Operating expenses
   Contract drilling (exclusive
      of depreciation) 	31.2       	--        	696.5      	8.6      	736.3    	--   	736.3    	
   Depreciation 	 9.1       	--        	158.3      	3.3      	170.7    	1.9   	172.6    	
   General and administrative 	--        	--        	--      	--      	--    	53.8   	53.8    	
Operating income (loss)	$ 44.1       	$    --        	$1,289.2      	$   2.3      	$1,335.6    	$(55.7)  	$1,279.9    	

8

 
    Deepwater

     During 2010, Deepwater revenues increased by $221.1 million, or 87%, as compared to the prior year. The increase in revenues was due to revenues earned by ENSCO 8500, ENSCO 8501 and ENSCO 8502 which were added to our Deepwater fleet and commenced drilling operations during the second and fourth quarters of 2009 and the third quarter of 2010, respectively, and due to additional revenues earned by ENSCO 7500 associated with the demobilization of the rig to Singapore.  The increase in revenues was partially offset by lower utilization and day rates incurred by ENSCO 8500, ENSCO 8501 and ENSCO 8502 as a result of the aforementioned regulatory developments and other actions imposed by the U.S. Department of the Interior in the U.S. Gulf of Mexico.  Contract drilling expense increased by $68.0 million, or 63%, and depreciation expense increased by $22.6 million due to the commencement of ENSCO 8500, ENSCO 8501 and ENSCO 8502 drilling operations as previously noted.

     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 recognized ratably over the firm commitment period of the contract.  The increase in revenues was 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 U.S. Gulf of Mexico. Depreciation expense increased by $13.1 million, primarily due to the addition of ENSCO 8500 and ENSCO 8501 to our Deepwater fleet as noted above.

    Midwater

     In connection with the Merger, we acquired six midwater rigs.  Prior to the Merger Date, our rig fleet did not consist of midwater rigs.

    Jackup

     During 2010, Jackup revenues declined by $413.2 million, or 25%, as compared to the prior year. The decline in revenues was primarily due to a 30% decline in average day rates due to lower levels of spending by oil and gas companies across all regions, partially offset by an increase in utilization to 77% from 74% during the prior year.  The increase in utilization primarily resulted from the reduced supply of available jackup rigs in the U.S. Gulf of Mexico, including the mobilization of four of our jackup rigs to Mexico during 2009, and lower market day rates in the region. Contract drilling expense declined by $20.8 million, or 3%, as compared to the prior year, primarily due to a $17.3 million loss recorded on the disposal of ENSCO 69 during 2009 and a current year decline in repair and maintenance expense and personnel costs, partially offset by an $11.9 million reduction of our allowance for doubtful accounts during 2009 which was recorded during 2008 and related to ENSCO 69 drilling operations.  Depreciation expense increased by 3% as compared to the prior year, primarily due to additions to our jackup fleet and depreciation on minor upgrades and improvements to our jackup fleet during 2010.

     During 2009, Jackup revenues declined by $509.2 million, or 24%, as compared to the prior year. The decline in revenues was primarily due to a decline in utilization to 74% from 96% during the prior year. The decline in utilization occurred due to lower levels of spending by oil and gas companies and excess rig availability across all regions.  Contract drilling expense declined by $97.5 million, or 62%, as compared to the prior year, primarily due to the impact of lower utilization across all regions and a decline in repair and maintenance expense and an $11.9 million reduction of our allowance for doubtful accounts as noted above, partially offset by a $17.3 million loss recorded on the disposal of ENSCO 69. Depreciation expense increased by 3% as compared to the prior year, primarily due to capital enhancement projects completed during 2009 and depreciation on minor upgrades and improvements to our jackup fleet completed during 2008 and 2009.

9

 
    Other

     Revenues, contract drilling expense and depreciation expense for each of the years in the three-year period ended December 31, 2010 were attributable to ENSCO I, our only barge rig.  ENSCO I completed its then-current drilling contract in 2008 and subsequently cold-stacked in Singapore.  During 2010, contract drilling expense included a $12.2 million loss on impairment of ENSCO I.
 
    Reconciling Items
 
     During 2010, general and administrative expense increased by $22.1 million, or 35%, as compared to the prior year.  This increase was primarily due to increased share-based compensation expense, costs related to operating our new London headquarters and professional fees incurred in connection with various reorganization efforts undertaken as a result of our redomestication to the U.K. in December 2009.
 
     During 2009, general and administrative expense increased by $10.2 million, or 19%, as compared to the prior year.  The increase was primarily due to $7.6 million of professional fees incurred in connection with our redomestication to the U.K. in December 2009 and a $1.9 million expense incurred in connection with a separation agreement with our former Senior Vice President of Operations.
 
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, 2010 (in millions):

 	2010              	  2009              	  2008      	
  	 	 	 	 	 	 	 	 	 	
Interest income	 	$    .7	 	 	 $   2.2	 	 	$ 14.0	 	
Interest expense, net:	 	 	 	 	 	 	 	 	 	
     Interest expense	 	(21.3	)	 	(20.9	)	 	(21.6	)	
     Capitalized interest	 	21.3	 	 	20.9	 	 	21.6	 	
 	 	--	 	 	--	 	 	--	 	
Other, net	 	17.5	 	 	6.6	 	 	(18.2	)	
 	 	  $ 18.2	 	 	   $   8.8	 	 	$  (4.2	)	
 
     During 2010 and 2009, interest income declined as compared to the respective prior years due to lower average interest rates.  Interest expense increased during 2010 as compared to the prior year due to an increase in the amortization of deferred financing fees associated with the renewal of our revolving credit facility, partially offset by a decline in outstanding debt. Interest expense declined during 2009 as compared to the prior year due to a decline in outstanding debt. All interest expense incurred during each of the years in three-year period ended December 31, 2010 was capitalized in connection with the construction of our ENSCO 8500 Series® rigs.
 
     Our functional currency is the U.S. dollar, and a portion of the revenues earned and expenses incurred by some of our 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 net foreign currency exchange gains of $3.5 million and $2.6 million and net foreign currency exchange losses of $10.4 million during 2010, 2009 and 2008, respectively.
 
     During 2010, we recognized a gain of $10.1 million, net of related expenses, for a break-up fee resulting from our unsuccessful tender offer for Scorpion Offshore Ltd.  The net gain was included in other, net, for the year ended December 31, 2010.
 
     Other, net, also included net unrealized gains of $700,000 and $1.8 million and net unrealized losses of $8.1 million associated with the fair value measurement of our auction rate securities during 2010, 2009 and 2008, respectively. The fair value measurement of our auction rate securities is discussed in Note 8 to our consolidated financial statements.

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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. Our drilling rigs frequently move from one taxing jurisdiction to another to perform contract drilling services. In some instances, the movement of drilling rigs among taxing jurisdictions will involve the transfer of ownership of the drilling rigs among our subsidiaries. As a result of the frequent changes in taxing jurisdictions in which our drilling rigs are operated and/or owned, 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.
 
     Subsequent to our redomestication to the U.K. in December 2009, we reorganized our worldwide operations, which included, among other things, the transfer of ownership of several of our drilling rigs among our subsidiaries.
 
     Income tax expense was $96.0 million, $180.0 million and $222.4 million and our consolidated effective income tax rate was 14.9%, 19.2% and 17.4% during the years ended December 31, 2010, 2009 and 2008, respectively. The decline in our 2010 consolidated effective income tax rate to 14.9% from 19.2% in the prior year was primarily due to  the aforementioned transfer of drilling rig ownership in connection with the reorganization of our worldwide operations, which resulted in an increase in the relative components of our earnings generated in tax jurisdictions with lower tax rates, and  an $8.8 million non-recurring current income tax expense incurred during 2009 in connection with certain restructuring activities undertaken immediately following our redomestication to the U.K.   The increase in our 2009 consolidated effective income tax rate to 19.2% from 17.4% in the prior year was primarily related to the aforementioned non-recurring current income tax expense incurred during 2009.  Excluding the impact from this non-recurring item, our 2009 consolidated effective income tax rate was 18.3%.
 
Discontinued Operations

    Rig Sales
      
     In recent years, we have focused on the expansion of our ultra-deepwater semisubmersible rig fleet and high-grading our premium jackup fleet.  Accordingly, we sold jackup rig ENSCO 60 in November 2010 for $25.7 million and recognized a pre-tax gain of $5.7 million, which was included in gain on disposal of discontinued operations, net, in our  consolidated statement of income for the year ended December 31, 2010. The rig’s net book value and inventory and other assets on the date of sale totaled $20.0 million.  ENSCO 60 operating results were reclassified to discontinued operations in our consolidated statements of income for each of the years in the three-year period ended December 31, 2010 and previously were included within our Jackup operating segment.
 
     In April 2010, we sold jackup rig ENSCO 57 for $47.1 million, of which a deposit of $4.7 million was received in December 2009. We recognized a pre-tax gain of $17.9 million in connection with the disposal of ENSCO 57, which was included in gain on disposal of discontinued operations, net, in our  consolidated statement of income for the year ended December 31, 2010. The rig’s net book value and inventory and other assets on the date of sale totaled $29.2 million.  ENSCO 57 operating results were reclassified to discontinued operations in our consolidated statements of income for each of the years in the three-year period ended December 31, 2010 and previously were included within our Jackup operating segment.
 
     In March 2010, we sold jackup rigs ENSCO 50 and ENSCO 51 for an aggregate $94.7 million, of which a deposit of $4.7 million was received in December 2009. We recognized an aggregate pre-tax gain of $33.9 million in connection with the disposals of ENSCO 50 and ENSCO 51, which was included in gain on disposal of discontinued operations, net, in our  consolidated statement of income for the year ended December 31, 2010.  The two rigs' aggregate net book value and inventory and other assets on the date of sale totaled $60.8 million. ENSCO 50 and ENSCO 51 operating results were reclassified to discontinued operations in our consolidated statements of income for each of the years in the three-year period ended December 31, 2010 and previously were included within our Jackup operating segment.

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    ENSCO 69
 
     From May 2007 to June 2009, ENSCO 69 was contracted to Petrosucre.  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.  In June 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 nationalization of certain assets owned by other 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 2009 and reclassified its operating results to discontinued operations.
 
     On August 24, 2010, possession of ENSCO 69 was returned to Ensco. Due to the return of ENSCO 69 from Petrosucre and our ability to significantly influence the future operations of the rig and to incur significant future cash flows related to those operations until the pending insurance claim is resolved and possibly thereafter, ENSCO 69 operating results were reclassified to continuing operations for each of the years in the three-year period ended December 31, 2010.
 
     There can be no assurances relative to the recovery of outstanding contract entitlements, insurance recovery and related pending litigation or the imposition of customs duties in relation to the rig's recent presence in Venezuela.  See Note 12 to our consolidated financial statements for additional information on contractual matters, insurance and legal proceedings related to ENSCO 69.
 
    ENSCO 74
 
     In September 2008, ENSCO 74 was destroyed as a result of Hurricane Ike and the rig was a total loss, as defined under the terms of our insurance policies. The operating results of ENSCO 74 were reclassified to discontinued operations in our consolidated statement of income for the year ended December 31, 2008.  See Note 12 to our consolidated financial statements for additional information on the loss of ENSCO 74 and associated contingencies.
 
     The following table summarizes income from discontinued operations for each of the years in the three-year period ended December 31, 2010 (in millions):

 	        2010 	      2009 	             2008 	
 	 	 	 	
Revenues	 	$12.5	 	$83.0	 	$244.0	 	
Operating expenses	 	17.1	 	54.2	 	89.3	 	
Operating (loss) income before income taxes	 	(4.6	)	28.8	 	154.7	 	
Income tax (benefit) expense	 	(3.4	)	(.5	)	27.8	 	
Gain (loss) on disposal of discontinued operations, net	 	38.6	 	--	 	(23.5	)	
Income from discontinued operations	 	$37.4	 	$29.3	 	$103.4	 	
 
Fair Value Measurements

    Auction Rate Securities
 
     Our auction rate securities were measured at fair value as of December 31, 2010 and 2009 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, 2010 and, accordingly, we concluded that Level 1 inputs were not available.  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, 2010. 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.

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     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, 2010 was appropriate.
 
     Based on the results of our fair value measurements, we recognized net unrealized gains of $700,000 and $1.8 million and net unrealized losses of $8.1 million for the years ended December 31, 2010, 2009 and  2008, respectively, 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 $44.5 million and $60.5 million as of December 31, 2010 and 2009, respectively.  We anticipate realizing the $50.1 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 53% of our assets measured at fair value on a recurring basis and less than 1% of our total assets as of December 31, 2010.  See Note 8 to our consolidated financial statements for additional information on our fair value measurements.
 
    ENSCO I Impairment
 
     In June 2010, we recorded a $12.2 million loss from the impairment of ENSCO I, the only barge rig in our fleet, which is currently cold-stacked in Singapore and is included in our "Other" operating segment. The loss on impairment was included in contract drilling expense in our consolidated statement of income for the year ended December 31, 2010. The impairment resulted from the adjustment of the rig’s carrying value to its estimated fair value based on a change in our expectation that it is more-likely-than-not that the rig will be disposed of significantly before the end of its estimated useful life. ENSCO I was not classified as held-for-sale as of December 31, 2010, as a sale was not deemed probable of occurring within the next twelve months.
 
     We utilized an income approach valuation model to estimate the price that would be received in exchange for the rig in an orderly transaction between market participants as of June 30, 2010. The resulting exit price was derived as the present value of expected cash flows from the use and eventual disposition of the rig, using a risk-adjusted discount rate.  Level 3 inputs were significant to the overall fair value measurement of ENSCO I, due to the limited availability of observable market data for similar assets.  We reviewed those inputs, evaluated the results and performed sensitivity analysis on key assumptions. Based on our review, we concluded that the fair value measurement of ENSCO I as of June 30, 2010 was appropriate.
 
     The estimated fair value of ENSCO I using significant Level 3 inputs constituted less than 1% of our total assets as of December 31, 2010. 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.

     During 2010, our cash flows from operations were negatively influenced by the BP Macondo well incident and associated new regulatory, legislative or permitting requirements, which is expected to continue during 2011.  However, based on $1,050.7 million of cash and cash equivalents on hand as of December 31, 2010 and our current contractual backlog of over $3,000.0 million, we believe our future operations and obligations associated with our newbuild construction will be funded from existing cash and cash equivalents and future operating cash flow.

13

 
     On February 6, 2011, we entered into a definitive merger agreement with Pride.  The merger is expected to close during the second quarter of 2011 and will be financed through a combination of existing cash and cash equivalents, an unsecured bridge term loan facility, potential issuances of debt securities, funds borrowed under our credit facility or other future financing arrangements. Total consideration to be paid to Pride shareholders will be approximately $2,800.0 million of cash and the delivery of approximately 86.0 million Ensco ADSs. Given the number of rigs under construction by both Ensco and Pride, it is contemplated that subsequent to closing of the merger, our cash flows initially will be dedicated to finance newbuild rigs.
 
     During the three-year period ended December 31, 2010, our primary source of cash was an aggregate $3,017.0 million generated from operating activities of continuing operations and $167.5 million of proceeds from the sale of four jackup rigs.  Our primary uses of cash during the same period included an aggregate $2,496.7 million for the construction, enhancement and other improvement of our drilling rigs, including $1,842.4 million invested in the construction of our ENSCO 8500 Series® rigs, $272.2 million for the repurchase of our shares, $186.0 million for the acquisition of an ultra-high specification jackup rig and accompanying inventory and $182.2 million for the payment of dividends.

     Detailed explanations of our liquidity and capital resources for each of the years in the three-year period ended December 31, 2010 are set forth below.

Cash Flows and Capital Expenditures
 
     Our cash flows from operating activities of continuing operations and capital expenditures on continuing operations for each of the years in the three-year period ended December 31, 2010 were as follows (in millions):

 	             2010	             2009	         2008  	
 	 	 	 	 	 	 	
Cash flows from operating activities of continuing operations	$816.7	 	$1,185.6	 	$1,014.7	 	
 	 	 	 	 	 	 	
Capital expenditures on continuing operations:	 	 	 	 	 	 	
     New rig construction	$567.5	 	$   623.4	 	$   651.5	 	
     Rig acquisition	 184.2	 	 --	 	--	 	
     Minor upgrades and improvements	87.3	 	80.8	 	79.0	 	
     Rig enhancements	36.3	 	153.0	 	33.7	 	
 	$875.3	 	$   857.2	 	$   764.2	 	
 
     During 2010, cash flows from continuing operations decreased by $368.9 million, or 31%, as compared to the prior year. The decrease resulted primarily from a $329.0 million decline in cash receipts from contract drilling services and a $44.4 million increase in cash payments related to contract drilling expenses.
 
     During 2009, cash flows from continuing operations increased by $170.9 million, or 17%, as compared to the prior year. The increase resulted primarily from a $186.4 million decline in tax payments and a $77.8 million decline in our investment in trading securities offset by a $90.2 million decline in cash receipts from contract drilling services and an $11.0 million decline in cash received from interest income.
 
     We continue to expand the size and quality of our drilling rig fleet. During the three-year period ended December 31, 2010, we invested $1,842.4 million in the construction of new drilling rigs and an additional $223.0 million upgrading the capability and extending the useful lives of our existing fleet. ENSCO 8500 and ENSCO 8501 were delivered in 2008 and 2009, respectively, and commenced drilling operations in the U.S. Gulf of Mexico under long-term contracts during 2009. ENSCO 8502 was delivered in January 2010 and commenced drilling operations in the U.S. Gulf of Mexico under a short-term sublet agreement during the fourth quarter of 2010. ENSCO 8503 was delivered in September 2010 and is expected to commence drilling operations in French Guiana under a short-term sublet agreement during the first quarter of 2011. ENSCO 8502 and ENSCO 8503 are expected to commence drilling operations in the U.S. Gulf of Mexico under two-year contracts during 2011.

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     We also have three uncontracted ENSCO 8500 Series® ultra-deepwater semisubmersible rigs under construction with scheduled delivery dates during the third quarter of 2011 and the first and second half of 2012. Our ENSCO 7500 ultra-deepwater semisubmersible rig currently is undergoing an enhancement project in a shipyard in Singapore and is expected to commence drilling operations in Brazil under a two-and-a-half year contract during the third quarter of 2011.
 
     In conjunction with our long-established strategy of high-grading our jackup rig fleet by investing in newer equipment, we sold three jackup rigs located in the Asia Pacific region and one jackup rig located in the North and South America region during 2010 for an aggregate $167.5 million in cash.  In addition, we acquired an ultra-high specification jackup rig and accompanying inventory during 2010 with available cash for $186.0 million. The rig, renamed ENSCO 109, was constructed in 2008 and is currently operating in Australia.
 
     In February 2011, we entered into agreements with KFELS to construct two ultra-high specification harsh environment jackup rigs for estimated total construction costs of approximately $230.0 million per rig.  These rigs currently are uncontracted and scheduled for delivery during the first and second half of 2013, respectively.
 
     Based on our current projections, notwithstanding the proposed merger with Pride, we expect capital expenditures during 2011 to include approximately $190.0 million for construction of our ENSCO 8500 Series® rigs, approximately $95.0 million for construction of two ultra-high specification harsh environment jackup rigs, approximately $125.0 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.

Financing and Capital Resources
 
     Our long-term debt, total capital and long-term debt to total capital ratios as of December 31, 2010, 2009 and 2008 are summarized below (in millions, except percentages):

 	 2010       	 2009      	    2008 	
 	 	 	 	 	 	 	 	
Long-term debt	 	$  240.1	 	$  257.2	 	$  274.3	 	
Total capital *	 	6,199.6	 	5,756.4	 	4,951.2	 	
Long-term debt to total capital	 	3.9%	 	4.5%	 	5.5%	 	

*	 	Total capital includes long-term debt plus Ensco shareholders' equity.	
 
     On February 6, 2011, we entered into a bridge commitment letter (the “Commitment Letter”) with Deutsche Bank AG Cayman Islands Branch (“DBCI”), Deutsche Bank Securities Inc. and Citigroup Global Markets Inc. (“Citi”). Pursuant to the Commitment Letter, DBCI and Citi have committed to provide a $2,750.0 million unsecured bridge term loan facility (the “Bridge Term Facility”) to fund a portion of the cash consideration in the merger with Pride. The Bridge Term Facility would mature 364 days after closing. The commitment is subject to various conditions, including the absence of a material adverse effect on Pride or Ensco having occurred, the maintenance by us of investment grade credit ratings, the execution of satisfactory documentation and other customary closing conditions.
 
     On May 28, 2010, we entered into an amended and restated agreement (the "2010 Credit Facility") with a syndicate of banks that provides for a $700.0 million unsecured revolving credit facility for general corporate purposes. The 2010 Credit Facility has a four-year term, expiring in May 2014, and replaces our $350.0 million five-year credit agreement which was scheduled to mature in June 2010.  Advances under the 2010 Credit Facility generally bear interest at LIBOR plus an applicable margin rate (currently 2.0% per annum), depending on our credit rating.  We are required to pay an annual undrawn facility fee (currently .25% per annum) on the total $700.0 million commitment, which is also based on our credit rating.  We also are required to maintain a debt to total capitalization ratio less than or equal to 50% under the 2010 Credit Facility. We have the right, subject to lender consent, to increase the commitments under the 2010 Credit Facility up to $850.0 million.  We had no amounts outstanding under the 2010 Credit Facility or the prior credit agreement as of December 31, 2010, 2009 and 2008.

15

 
     We filed a Form S-3 Registration Statement with the SEC in January 2009, which provides us the ability to issue debt and/or equity securities in one or more offerings.  The registration statement was immediately effective and expires in January 2012.
 
     As of December 31, 2010, we had an aggregate $108.4 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, 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 of Ensco Delaware previously authorized the repurchase of up to $1,500.0 million of our ADSs, representing our Class A ordinary shares. In December 2009, the then-Board of Directors of Ensco International Limited, a predecessor of Ensco 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.  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 the years ended December 31, 2010 and 2009.  Although $562.4 million remained available for repurchase as of December 31, 2010, we will not repurchase any shares under our share repurchase program without further consultation with and approval by the Board of Directors of Ensco 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. Notwithstanding the proposed merger with Pride, the table below summarizes our significant contractual obligations as of December 31, 2010 and the periods in which such obligations are due (in millions):
 
 	                       Payments due by period                          	 	
 	 	2012       	2014        	 	 	
 	 	and       	and         	After       	 	
 	 2011        	 2013         	 2015          	 2015         	 Total 	
 	 	 	 	 	 	 	 	 	 	 	
New rig construction agreements (1)	$ 435.6	 	$223.9 	 	$    --	 	$      --	 	$   659.5	 	
Principal payments on long-term debt	17.2	 	34.4 	 	34.4	 	172.4	 	258.4	 	
Interest payments on long-term debt	16.7	 	30.3 	 	26.2	 	131.5	 	204.7	 	
Operating leases	8.2	 	6.3 	 	4.2	 	5.3	 	24.0	 	
Total contractual obligations (2)(3)	$477.7	 	$294.9 	 	$64.8	 	$309.2	 	$1,146.6	 	
 
     (1)	In February 2011, we entered into agreements to construct two ultra-high specification harsh environment jackup rigs.  The amounts disclosed above exclude construction obligations of $87.6 million for 2011 and $350.2 million for 2013 related to these rigs.
 
In connection with the aforementioned agreements to construct two new jackup rigs, we agreed with the shipyard contractor to defer $340.0 million of contractual commitments due during 2011 related to the construction of ENSCO 8505 and ENSCO 8506 until the rigs are delivered during the first and second half of 2012, respectively. The amounts disclosed above exclude the aforementioned deferral of contractual commitments.	

    (2)	Contractual obligations do not include $13.7 million of unrecognized tax benefits included on our consolidated balance sheet as of December 31, 2010.  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.	
 
    (3)	Contractual obligations do not include foreign currency forward contracts ("derivatives"). As of December 31, 2010, we had derivatives outstanding to exchange an aggregate $239.9 million U.S. dollars for various foreign currencies, including $121.0 million for Singapore dollars.  As of December 31, 2010, our consolidated balance sheet included net derivative assets of $16.4 million. All of our outstanding derivatives mature during the next 18 months.	
 
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Liquidity
 
      Our liquidity position as of December 31, 2010, 2009 and 2008 is summarized below (in millions, except ratios):

 	 2010     	 2009    	       2008 	
 	 	 	 	 	 	 	 	
Cash and cash equivalents	 	$1,050.7	 	$1,141.4	 	$789.6	 	
Working capital	 	1,087.7	 	1,167.9	 	973.0	 	
Current ratio	 	4.1	 	3.4	 	3.3	 	

     We expect to fund our short-term liquidity needs, including approximately $555.0 million of contractual obligations and anticipated capital expenditures, as well as any dividends, stock repurchases or working capital requirements, from our cash and cash equivalents and operating cash flow.  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 flow and, if necessary, funds borrowed under our credit facility or other future financing arrangements.

     Based on our $1,050.7 million of cash and cash equivalents as of December 31, 2010 and our current contractual backlog of over $3,000.0 million, we believe our $1,097.3 million of contractual obligations associated with the construction of our ENSCO 8500 Series® rigs and two ultra-high specification harsh environment jackup rigs will be funded from existing cash and cash equivalents and future operating cash flow. We may decide to access debt markets to raise additional capital or increase liquidity as necessary.

     We expect to fund the proposed merger with Pride from cash and cash equivalents, the Bridge Term Facility and potentially funds borrowed under our credit facility or other future financing arrangements.  In addition, we intend to use such internal cash resources and financing as well as cash and cash equivalents of Pride following the merger to pay advisory, legal, valuation and other professional fees incurred by both Ensco and Pride of approximately $69.0 million, ADS issuance costs of approximately $70.0 million, debt issuance costs of approximately $20.0 million, as well as change in control severance for certain Pride employees of approximately $33.0 million. Upon completion of the proposed merger, we will increase our indebtedness, which will include acquisition debt financing of approximately $2,800.0 million and approximately $1,860.0 million of Pride’s debt obligations will remain outstanding after the merger. In addition, various commitments and contractual obligations in connection with Pride’s normal course of business will remain outstanding after the merger, including obligations associated with Pride’s newbuild program of approximately $1,320.0 million.
 
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 most 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. However, 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, we do not believe that such initiatives would have a direct, material adverse effect on our operating results.

     Restrictions on greenhouse gas emissions or other related legislative or regulatory enactments 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. Furthermore, 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 risk retention, limit insurance availability or reduce the areas in which, or the number of days during which, our customers would contract for our drilling rigs in general and in the Gulf of Mexico in particular. We are currently unable to predict the manner or extent of any such effect.

17

MARKET RISK

    Derivatives

     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 some of our subsidiaries are denominated in currencies other than the U.S. dollar.  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.

     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 foreign currencies.  As of December 31, 2010, $172.7 million of the aggregate remaining contractual obligations associated with our ENSCO 8500 Series® construction projects was denominated in Singapore dollars, of which $115.8 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, 2010, we had derivatives outstanding to exchange an aggregate $239.9 million for various foreign currencies, including $121.0 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, 2010 would approximate $21.8 million, including $11.8 million related to our Singapore dollar exposures.  A portion of these unrealized losses generally would be offset by corresponding gains on certain underlying expected future transactions being hedged.  All of our derivatives mature during the next 18 months.  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 $50.1 million (par value) of auction rate securities with a carrying value of $44.5 million as of December 31, 2010.  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, 2010, 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.  The resulting 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 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 risk-adjusted discount rate and a 10% adverse change in the periods of illiquidity, the additional net unrealized losses on our auction rate securities as of December 31, 2010 would approximate $1.2 million.  See Note 3 to our consolidated financial statements for additional information on our auction rate securities.

18

 
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.

    Property and Equipment

     As of December 31, 2010, the carrying value of our property and equipment totaled $5,049.9 million, which represented 72% 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 40 jackup rigs represented 68% of the gross cost and 59% of the net carrying amount of our depreciable property and equipment as of December 31, 2010.  Our jackup rigs are depreciated over useful lives ranging from 15 to 30 years. Our fleet of five ultra-deepwater semisubmersible rigs, exclusive of the ENSCO 8500 Series® rigs under construction, represented 28% of the gross cost and 38% of the net carrying amount of our depreciable property and equipment as of December 31, 2010.  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, 2010 for various assumed changes in the useful lives of our drilling rigs effective January 1, 2010:

Increase (decrease) in
useful lives of our
           drilling rigs            	Estimated increase (decrease) in
depreciation expense that would
have been recognized (in millions)	
 	 	 	 	
10%	 	$(29.3)	 	
20%	 	  (46.2)	 	
(10%)	 	  13.1	 	
(20%)	 	   42.5 	 	

19

 
    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.
 
     For property and equipment used in our operations, recoverability is generally determined by comparing the 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 carrying 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 three reportable 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, 2010, there was no impairment of goodwill, and none of our reporting units were determined to be at risk of a goodwill impairment in the near-term under the current circumstances.

     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.

20

     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.

    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, 2010, our consolidated balance sheet included a $348.7 million net deferred income tax liability, an $11.9 million liability for income taxes currently payable and a $13.7 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 deferred taxes on the undistributed earnings of our U.S. subsidiary and predecessor, 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.
 
     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 number of  tax jurisdictions in which we conduct operations 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.	

21

 
 NEW ACCOUNTING PRONOUNCEMENTS
 
     In December 2010, the FASB issued Accounting Standards Update 2010-28, "Intangibles – Goodwill and Other (Topic 350): When to Perform Step 2 of the Goodwill Impairment Test for Reporting Units with Zero or Negative Carrying Amounts" ("Update 2010-28"). Update 2010-28 provides amendments to Topic 350 that modify Step 1 of the goodwill impairment test for reporting units with zero or negative carrying amounts by establishing a requirement that Step 2 of the goodwill impairment test be performed for those reporting units if it is more-likely-than-not that a goodwill impairment exists. Update 2010-28 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2010. We do not expect the adoption of Update 2010-28 to have a material effect on our future goodwill impairment tests.
 
     In December 2010, the FASB issued Accounting Standards Update 2010-29, "Business Combinations (Topic 805): Disclosure of Supplementary Pro Forma Information for Business Combinations" ("Update 2010-29"). Update 2010-29 provides amendments to Topic 805 that specify that if a public entity presents comparative financial statements, the entity should disclose revenue and earnings of the combined entity as though the business combination(s) that occurred during the current year had occurred as of the beginning of the comparable prior annual reporting period only. Furthermore, this update provides amendments to Topic 805 that expand the supplemental pro forma disclosures to include a description of the nature and amount of material, nonrecurring pro forma adjustments directly attributable to the business combination included in the reported pro forma revenue and earnings. Update 2010-29 is effective prospectively for business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2010. We expect the effect of adoption of Update 2010-29 to be limited to pro forma disclosures of any future acquisitions.

 

 

 
  22

Exhibit 99.3

     The following “Business” section should be read in conjunction with our consolidated financial statements included in “Item 8.  Financial Statements and Supplementary Data.”  Any references to Notes in the following “Business” section refer to the Notes to Consolidated Financial Statements included in “Item 8.  Financial Statements and Supplementary Data” (attached as Exhibit 99.1 to this Report).

     As further discussed in Note 13 to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" (attached as Exhibit 99.1 to this Report), our consolidated financial statements for all periods presented herein have been updated to retrospectively reflect the reorganization of our reportable segments resulting from the merger transaction with Pride International, Inc. (the "Merger") completed on May 31, 2011, pursuant to which Pride International became an indirect, wholly-owned subsidiary of Ensco plc.  This filing includes updates only to the portions of Item 1, Item 7 and Item 8 of the Form 10-K that specifically relate to the updated segment disclosures resulting from the Merger and reorganization and does not otherwise modify or update any other disclosures set forth in the Form 10-K.
 
Item 1.    Business

 General
 
     Ensco plc is a global offshore contract drilling company. As of February 15, 2011, our offshore rig fleet included 40 jackup rigs, five ultra-deepwater semisubmersible rigs and one barge rig.  Additionally, we have three ultra-deepwater semisubmersible rigs and two ultra-high specification harsh environment jackup 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 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 27 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. During 2010, we acquired an ultra-high specification jackup rig constructed in 2008 and renamed the rig ENSCO 109.  In February 2011, we entered into agreements with KFELS to construct two ultra-high specification harsh environment jackup rigs which are currently uncontracted and scheduled for delivery during the first and second half of 2013, respectively.

     We previously 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 and ENSCO 8501 were delivered in September 2008 and June 2009, respectively, and commenced drilling operations in the U.S. Gulf of Mexico under long-term contracts during 2009. ENSCO 8502 was delivered in January 2010 and commenced drilling operations in the U.S. Gulf of Mexico under a short-term sublet agreement during the fourth quarter of 2010. ENSCO 8503 was delivered in September 2010 and is expected to commence drilling operations in French Guiana under a short-term sublet agreement during the first quarter of 2011. ENSCO 8502 and ENSCO 8503 are expected to commence drilling operations in the U.S. Gulf of Mexico under two-year contracts during 2011.  ENSCO 8504, ENSCO 8505 and ENSCO 8506 currently are uncontracted and expected to be delivered during the third quarter of 2011 and the first and second half of 2012, respectively.

1

 
     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 disposed of five barge rigs and one platform rig during 2005 and our last remaining platform rig during 2006. We also sold three jackup rigs located in the Asia Pacific region and one jackup rig located in the North America region during 2010.

     Our predecessor, ENSCO International Incorporated ("Ensco Delaware"), was formed as a Texas corporation during 1975 and reincorporated in Delaware during 1987.  In December 2009, we completed the reorganization of the corporate structure of the group of companies controlled by Ensco Delaware, pursuant to which an indirect, wholly-owned subsidiary merged with Ensco Delaware, and Ensco plc became our publicly-held parent company incorporated under English law (the "redomestication"). 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 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 (0) 7659 4660.  Our website is located at www.enscoplc.com.
 
Pending Merger with Pride

     On February 6, 2011, Ensco plc entered into an Agreement and Plan of Merger with Pride International, Inc., a Delaware corporation (“Pride”), Ensco Delaware, and ENSCO Ventures LLC, a Delaware limited liability company and an indirect, wholly-owned subsidiary of Ensco (“Merger Sub”). Pursuant to the merger agreement and subject to the conditions set forth therein, Merger Sub will merge with and into Pride, with Pride as the surviving entity and an indirect, wholly-owned subsidiary of Ensco.  As a result of the merger, each outstanding share of Pride’s common stock (other than shares of common stock held directly or indirectly by Ensco, Pride or any wholly-owned subsidiary of Ensco or Pride (which will be cancelled as a result of the merger), those shares with respect to which appraisal rights under Delaware law are properly exercised and not withdrawn and other shares held by certain U.K. residents if determined by Ensco) will be converted into the right to receive $15.60 in cash and 0.4778 Ensco ADSs. Under certain circumstances, U.K. residents may receive all cash consideration as a result of compliance with legal requirements.

     We estimate that the total consideration to be delivered in the merger to be approximately $7,400.0 million, consisting of $2,800.0 million of cash, the delivery of approximately 86.0 million Ensco ADSs (assuming that no Pride employee stock options are exercised before the closing of the merger) with an aggregate value of $4,550.0 million based on the closing price of Ensco ADSs of $52.88 on February 15, 2011 and the estimated fair value of $45.0 million of Pride employee stock options assumed by Ensco.  The value of the merger consideration will fluctuate based upon changes in the price of Ensco ADSs and the number of shares of Pride common stock and employee options outstanding on the closing date. The merger agreement and the merger were approved by the respective Boards of Directors of Ensco and Pride.  Consummation of the merger is subject to the approval of the shareholders of Ensco and the stockholders of Pride, regulatory approvals and the satisfaction or waiver of various other conditions as more fully described in the merger agreement.  Subject to receipt of required approvals, it is anticipated that the closing of the merger will occur during the second quarter of 2011.

2

 
Contract Drilling Operations
 
        In connection with the Merger and resulting management reorganization, we evaluated our then-current core assets and operations and organized them into three segments based on water depth operating capabilities. Accordingly, we now consider our business to consist of three reportable segments: (1) Deepwater, which consists of our rigs capable of drilling in water depths of 4,500 feet or greater, (2) Midwater, which consists of our semisubmersible rigs capable of drilling in water depths of 4,499 feet or less and (3) Jackup, which consists of our jackup rigs capable of operating in water depths up to 400 feet. Each of our three reportable 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 40 jackup rigs, five ultra-deepwater semisubmersible rigs and one barge rig. Of the 40 jackup rigs, 17 are located in the Asia Pacific Rim region, 10 are located in the Europe and Mediterranean region and 13 are located in the North America region.
 
     Our ENSCO 7500 ultra-deepwater semisubmersible rig is undergoing an enhancement project in a shipyard in Singapore and is expected to commence drilling operations in Brazil under a two-and-a-half year contract during the third quarter of 2011.  ENSCO 8500 and ENSCO 8501 are operating under long-term contracts in the U.S. Gulf of Mexico.   ENSCO 8502 was delivered in January 2010 and commenced drilling operations in the U.S. Gulf of Mexico under a short-term sublet agreement during the fourth quarter of 2010. ENSCO 8503 was delivered in September 2010 and is expected to commence drilling operations in French Guiana under a short-term sublet agreement during the first quarter of 2011. ENSCO 8502 and ENSCO 8503 are expected to commence drilling operations in the U.S. Gulf of Mexico under two-year contracts during 2011.
 
     In addition, we have three uncontracted ultra-deepwater semisubmersible rigs and two uncontracted ultra-high specification harsh environment jackup rigs under construction by KFELS at a shipyard in Singapore. The rigs are scheduled for delivery during the third quarter of 2011, the first and second half of 2012 and the first and second half of 2013, respectively.  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,
 	
 	•
 	applicable regulatory and legislative restrictions, 	
 	•	the development and use of alternatives to hydrocarbon-based energy sources, and
 	
 	•	worldwide economic activity.	

3

 
     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 reclassified 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 reclassified 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, 2011 and 2010 (in millions):

 	          2011 (1)	             2010 (1)	
 	 	 	 	 	 	
Deepwater	 	$1,723	.4	$1,689	.9	
Midwater (2)	 	 	--	 	--	
Jackup	 	1,345	.3	1,265	.2	
    Total	 	$3,068	.7	$2,955	.1	

(1)	Backlog includes revenues realized during January of the respective year.
 	
(2)	In May 2011, midwater rigs were acquired in connection with the Merger.  Therefore, our rig fleet did not consist of midwater rigs as of February 1, 2011 and 2010.	

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     Our Deepwater backlog increased by $33.5 million primarily due to a new ENSCO 7500 contract entered into in early 2011, mostly offset by revenues realized during 2010.  Our Jackup backlog increased by $80.1 million primarily due to an extension of the current ENSCO 102 contract through May 2016 and incremental tender activity in the Europe and Mediterranean region, mostly offset by revenues realized on our long-term contracts in Mexico and limited tender activity in the Asia Pacific Rim.  The table summarizes our annual backlog by reportable segment as of February 1, 2011 (in millions):
 
 	       2011  (1)	      2012  	      2013  	       2014
      and Beyond	        Total  	
 	 	 	 	 	 	 	 	 	 	 	 	
Deepwater	 	$   535	.5	$731	.8	$428	.3	$27	.8	$1,723	.4	
Midwater (2)	 	 	--	 	--	 	--	 	--	 	--	
Jackup	 	834	.2	257	.8	74	.2	179	.1	1,345	.3	
    Total	 	$1,369	.7	$989	.6	$502	.5	$206	.9	$3,068	.7	
 
(1)	Backlog for the year ended December 31, 2011 includes revenues realized during January 2011.
 	
(2)	In May 2011, midwater rigs were acquired in connection with the Merger.  Therefore, our rig fleet did not consist of midwater rigs as of February 1, 2011.	
 
     Our drilling contracts generally contain provisions permitting early termination of the contract (i) if the rig is lost or destroyed or (ii) by the customer if operations are suspended for a specified period of time due to breakdown of major rig equipment, unsatisfactory performance, "force majeure" events beyond the control of either party or other specified conditions.  In addition, some of our drilling contracts permit early termination of the contract by the customer for convenience (without cause), generally exercisable upon advance notice to us and in some cases without making an early termination payment to us.  There can be no assurances that our customers will be able to or willing to fulfill their contractual commitments to us.  Therefore, revenues recorded in future periods could differ materially from the backlog amounts presented in the table above.

Major Customers

     We provide our contract drilling services to major international, government-owned and independent oil and gas companies. During 2010, Chevron and Petr ó leos Mexicanos ("PEMEX") represented 14% and 11% of our consolidated revenues, respectively, and our five largest customers accounted for 43% 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.

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Governmental Regulation
 
     Our operations are affected by political developments and by laws and regulations that relate directly to the oil and gas industry, including laws and regulations that have or may impose increased financial responsibility and oil spill abatement contingency plan capability requirements.  Accordingly, we will be directly affected by the approval and adoption of laws and regulations curtailing exploration and development drilling for oil and natural gas for economic, environmental, safety or other policy reasons. It is also possible that these laws and regulations could adversely affect our operations in the future by significantly increasing our operating costs.

Environmental Matters
 
     Our operations are subject to laws and regulations controlling the discharge of materials into the environment, pollution, contamination and hazardous waste disposal or otherwise relating to the protection of the environment. Environmental laws and regulations specifically applicable to our business activities could impose significant liability on us for damages, clean-up costs, fines and penalties in the event of oil spills or similar discharges of pollutants or contaminants into the environment or improper disposal of hazardous waste generated in the course of our operations, which may not be covered by contractual indemnification or insurance and could have a material adverse effect on our financial position, operating results and cash flows. To date, such laws and regulations have not had a material adverse effect on our operating results, and we have not experienced an accident that has exposed us to material liability arising out of or relating to discharges of pollutants into the environment.  However, the legislative and regulatory response to the BP Macondo well incident could substantially increase our customers' liabilities in respect of oil spills and also could increase our liabilities.  In addition to potential increased liabilities, such legislative or regulatory action could impose increased financial, insurance or other requirements that may adversely impact the entire offshore drilling industry.

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

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

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Non-U.S. Operations

     Revenues from non-U.S. operations were 75%, 86% and 79% of our total consolidated revenues during 2010, 2009 and 2008, 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.	

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

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     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. We currently conduct contract drilling operations in certain countries that have experienced substantial fluctuations in the value of their currency compared to the U.S. dollar. In addition, some of the countries in which we operate have occasionally enacted exchange controls. Historically, these risks have been limited by invoicing and receiving payment in U.S. dollars (our functional currency) or freely convertible currency and, to the extent possible, by limiting acceptance of foreign currency to amounts which approximate our expenditure requirements in such currencies. However, there is no assurance that our contracts will contain such terms in the future.
 
     A portion of the costs and expenditures incurred by our non-U.S. operations, including a portion of the construction payments for 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	 	 56	 	Chairman, President and Chief Executive Officer	
 	 	 	 	 	
William S. Chadwick, Jr.	 	 63	 	Executive Vice President - Chief Operating Officer	
 	 	 	 	 	
John Mark Burns	 	 54	 	Senior Vice President	
 	 	 	 	 	
Patrick Carey Lowe	 	 52	 	Senior Vice President	
 	 	 	 	 	
James W. Swent III	 	 60	 	Senior Vice President - Chief Financial Officer	
 	 	 	 	 	
David A. Armour	 	 53	 	Vice President - Finance	
 	 	 	 	 	
John Knowlton	 	 51	 	Vice President - Engineering and Capital Projects	
 	 	 	 	 	
H. E. Malone, Jr.	 	 67	 	Vice President and Assistant Secretary	
 	 	 	 	 	
Cary A. Moomjian, Jr.	 	 63	 	Vice President, General Counsel and Secretary	
 	 	 	 	 	
Sean P. O'Neill	 	 47	 	Vice President - Investor Relations	
 	 	 	 	 	
Michael K. Wiley	 	 51	 	Vice President - Human Resources and Security 	
 	 	 	 	 	
Michael B. Howe	 	 44	 	Treasurer	
 	 	 	 	 	
Douglas J. Manko	 	 36	 	Controller and Assistant Secretary	

     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.

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     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.   Mr. Burns is now responsible for Ensco's worldwide fleet of premium jackup rigs.   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.  In 2007, Mr. Burns was named IADC Drilling Contractor of the Year.   Mr. Burns holds a Bachelor of Arts Degree in Business and Political Science from Sam Houston State University.

     Patrick Carey Lowe joined Ensco in August 2008 as Senior Vice President.  His responsibilities include the Deepwater Business Unit, capital projects and engineering.   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.
 
     John Knowlton joined the Company in June 1998 and was elected to his current position of Vice President – Engineering & Capital Projects in July 2010. Prior to his current position, Mr. Knowlton served the Company as General Manager – North & South America, Operations Manager – Asia Pacific Rim, and Operations Manager overseeing the construction and operation of the Company’s first ultra-deepwater semisubmersible ENSCO 7500. Before joining the Company, Mr. Knowlton served in various domestic and international capacities with Ocean Drilling & Exploration Company and Diamond Offshore Drilling, Inc. Mr. Knowlton holds a Bachelor of Science Degree in Civil Engineering from Tulane University.
 
     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.

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     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 contract drilling 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. , an owner and operator of industrial real estate and provider of supply chain solutions to multinational corporations and regional customers,  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 K. Wiley joined the Company in 1993 as part of Ensco’s acquisition of Penrod and was elected to his current position of Vice President-Human Resources and Security in July 2010. Mr. Wiley has 29 years of combined service time which includes assignments in a variety of disciplines including human resources, finance and accounting while in Singapore and Dallas. Mr. Wiley holds a Bachelor of Business Administration Degree from Texas State University.
 
     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 3,725 personnel worldwide as of February 1, 2011, of which 2,752 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.enscoplc.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.

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