Edgar Filing: Ensco plc

form10k2010.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549 `

FORM 10-K

(Mark One)

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE

SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2010

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE

SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission File Number 1-8097

Ensco plc

(Exact name of registrant as specified in its charter)

England and Wales

(State or other jurisdiction of

incorporation or organization)

6 Chesterfield Gardens

London, England

(Address of principal executive offices)

98-0635229

(I.R.S. Employer

Identification No.)

W1J5BQ

(Zip Code)

Registrant's telephone number, including area code: +44 (0) 20 7659 4660

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

Title of each class

Class A Ordinary Shares, U.S. $0.10 par value

American Depositary Shares, each representing one Class A Ordinary Share,

U.S. $0.10 par value per Class A Ordinary Share

Name of each exchange on which registered

New York Stock Exchange*

New York Stock Exchange

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

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer as defined in Rule 405 of the Securities Act. Yes ý No o

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o No ý

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15 (d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (S232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ý No o

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act:

Large accelerated filer ý Accelerated filer o

Non-accelerated filer o (Do not check if a smaller reporting company) Smaller reporting company o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).

Yes o No ý

The aggregate market value of our American depositary shares, each representing one Class A ordinary share, (based upon the closing price on the New York Stock Exchange on June 30, 2010 of $39.28) of Ensco plc held by nonaffiliates of the registrant at that date was approximately $3,939,320,000.

As of February 22, 2011, there were 143,397,356 American depositary shares of the registrant issued and outstanding, each representing one Class A ordinary share.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Company's Proxy Statement for the 2011 General Meeting of Shareholders are incorporated by reference into Part III of this report.



TABLE OF CONTENTS


PART I	ITEM 1.	BUSINESS	5
	ITEM 1A.	RISK FACTORS	16
	ITEM 1B.	UNRESOLVED STAFF COMMENTS	38
	ITEM 2.	PROPERTIES	39
	ITEM 3.	LEGAL PROCEEDINGS	41
	ITEM 4.	REMOVED AND RESERVED	45


PART II	ITEM 5.	MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED SHAREHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES	46
	ITEM 6.	SELECTED FINANCIAL DATA	51
	ITEM 7.	MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	53
	ITEM 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	75
	ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	76
	ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	120
	ITEM 9A.	CONTROLS AND PROCEDURES	120
	ITEM 9B.	OTHER INFORMATION	120


PART III	ITEM 10.	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE	121
	ITEM 11.	EXECUTIVE COMPENSATION	121
	ITEM 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED SHAREHOLDER MATTERS	122
	ITEM 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE	122
	ITEM 14.	PRINCIPAL ACCOUNTING FEES AND SERVICES	122

PART IV

ITEM 15.

EXHIBITS, FINANCIAL STATEMENT SCHEDULES

SIGNATURES

123

133

FORWARD-LOOKING STATEMENTS

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

Forward-looking statements include words or phrases such as "anticipate," "believe," "estimate," "expect," "intend," "plan," "project," "could," "may," "might," "should," "will" and words and phrases of similar import. The forward-looking statements include, but are not limited to, statements regarding future operations; market conditions; cash generation; the impact of the BP Macondo well incident in the U.S. Gulf of Mexico (including the expected departure of deepwater rigs from the U.S Gulf of Mexico); contributions from our ultra-deepwater semisubmersible rig fleet expansion program; high-grading the rig fleet by investing in new equipment and divesting selected assets; expense management; industry trends or conditions; the overall business environment; future levels of, or trends in, utilization, day rates, revenues, operating expenses, contract term, contract backlog, capital expenditures, insurance, financing and funding; future rig construction (including construction in progress and completion thereof), enhancement, upgrade or repair and timing thereof; future delivery, mobilization, contract commencement, relocation or other movement of rigs and timing thereof; future availability or suitability of rigs and the timing thereof; our intention to explore alternative strategies to keep underutilized rigs operating, statements regarding the likely outcome of litigation, legal proceedings, investigations or insurance or other claims and the timing thereof; the timing and closing of the proposed merger with Pride International, Inc. ("Pride") and related transactions, including the contemplated financing of the transaction; the consideration payable in connection with the proposed merger with Pride; and the anticipated effects and results of the proposed merger with Pride, including expected benefits, synergies, expense savings and operational and administrative efficiencies.

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

	•	changes in U.S. or non-U.S. laws, including tax laws, that could effectively reduce or eliminate the benefits we expect to achieve from the December 2009 reorganization of the Company's corporate structure (the "redomestication"), adversely affect our status as a non-U.S. corporation or otherwise adversely affect our anticipated consolidated effective income tax rate,
	•	regulatory or legislative activity that would impact U.S. Gulf of Mexico operations, potentially resulting in claims of a force majeure situation under our drilling contracts,
	•	an inability to realize expected benefits from the redomestication,
	•	the impact of the BP Macondo well incident in the U.S. Gulf of Mexico upon future deepwater and other offshore drilling operations in general, and as respects current and 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 equipment and operations), future lease sales, laws and regulations that have or may impose increased financial responsibility and oil spill abatement contingency plan capability requirements and other governmental activities that may impact deepwater and other offshore operations in the U.S. Gulf of Mexico in general, and our existing drilling contracts for ENSCO 8500, ENSCO 8501, ENSCO 8502, ENSCO 8503 and our U.S. Gulf of Mexico jackup rigs in particular,
	•	industry conditions and competition, including changes in rig supply and demand or new technology,
	•	risks associated with the global economy and its impact on capital markets and liquidity,
	•	prices of oil and natural gas and their impact upon future levels of drilling activity and expenditures,

	•	worldwide expenditures for oil and natural gas drilling,
	•	further declines in drilling activity, which may cause us to idle or stack additional rigs,
	•	excess rig availability or supply resulting from delivery of newbuild drilling rigs,
	•	concentration of our rig fleet in premium jackups,
	•	concentration of our active ultra-deepwater semisubmersible drilling rigs in the U.S. Gulf of Mexico,
	•	cyclical nature of the industry,
	•	risks associated with offshore rig operations or rig relocations,
	•	inability to collect receivables,
	•	availability of transport vessels to relocate rigs,
	•	the ultimate resolution of the ENSCO 69 pending litigation and related package policy political risk insurance recovery,
	•	changes in the timing of revenue recognition resulting from the deferral of certain revenues for mobilization of our drilling rigs, time waiting on weather or time in shipyards, which are recognized over the contract term upon commencement of drilling operations,
	•	operational risks, including excessive unplanned downtime due to rig or equipment failure, damage or repair in general and hazards created by severe storms and hurricanes in particular,
	•	changes in the dates our rigs will enter a shipyard, be delivered, return to service or enter service,
	•	risks inherent to shipyard rig construction, repair or enhancement, including risks associated with concentration of our remaining three ENSCO 8500 Series® rig construction contracts and the two new jackup rig construction contracts in a single shipyard in Singapore, unexpected delays in equipment delivery and engineering or design issues following shipyard delivery,
	•	changes in the dates new contracts actually commence,
	•	renegotiation, nullification, cancellation or breach of contracts or letters of intent with customers or other parties, including failure to negotiate definitive contracts following announcements or receipt of letters of intent,
	•	environmental or other liabilities, risks or losses, whether related to hurricane damage, losses or liabilities (including wreckage or debris removal) in the Gulf of Mexico or otherwise, that may arise in the future which are not covered by insurance or indemnity in whole or in part,
	•	limited availability or high cost of insurance coverage for certain perils such as hurricanes in the Gulf of Mexico or associated removal of wreckage or debris,

	•	self-imposed or regulatory limitations on drilling locations in the Gulf of Mexico during hurricane season,
	•	impact of current and future government laws and regulation affecting the oil and gas industry in general and our operations in particular, including taxation, as well as repeal or modification of same,
	•	our ability to attract and retain skilled personnel,
	•	governmental action and political and economic uncertainties, which may result in expropriation, nationalization, confiscation or deprivation of our assets or result in claims of a force majeure situation,
	•	terrorism or military action impacting our operations, assets or financial performance,
	•	outcome of litigation, legal proceedings, investigations or insurance or other claims,
	•	adverse changes in foreign currency exchange rates, including their impact on the fair value measurement of our derivative instruments,
	•	potential long-lived asset or goodwill impairments,
	•	potential reduction in fair value of our auction rate securities and the ultimate resolution of our pending arbitration proceedings,
	•	the ability to consummate the proposed merger with Pride, including the receipt of necessary shareholder approvals of both parties,
	•	failure, difficulties and delays in obtaining regulatory clearances and approvals for the proposed merger with Pride,
	•	failure, difficulties and delays in achieving expected synergies and cost savings associated with the proposed merger with Pride, or
	•	failure, difficulties and delays in meeting conditions required for closing set forth in the Pride merger agreement, including the ability to obtain necessary financing and the potential terms thereof.

In addition to the numerous factors described above, you should carefully read and consider "Item 1A. Risk Factors" in Part I and "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" in Part II of this Form 10-K.

PART I

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.

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 and South 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.

Contract Drilling Operations

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

We currently own and operate 40 jackup rigs, five ultra-deepwater semisubmersible rigs and one barge rig. Of the 40 jackup rigs, 17 are located in the Asia Pacific geographic region, ten are located in the Europe and Africa geographic region and 13 are located in the North and South America geographic region.

Our ENSCO 7500 ultra-deepwater semisubmersible rig is 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.

Our drilling contracts are the result of negotiations with our customers, and most contracts are awarded upon competitive bidding. Our drilling contracts generally contain the following commercial terms:

	•	contract duration extending over a specific period of time or a period necessary to drill one or more wells,
	•	term extension options in favor of our customer, generally exercisable upon advance notice to us, at mutually agreed, indexed or fixed rates,
	•	provisions permitting early termination of the contract (i) if the rig is lost or destroyed or (ii) by the customer if operations are suspended for a specified period of time due to breakdown of major rig equipment, unsatisfactory performance, "force majeure" events beyond the control of either party or other specified conditions,

	•	some of our drilling contracts permit early termination of the contract by the customer for convenience (without cause), generally exercisable upon advance notice and in some cases without making an early termination payment to us,
	•	payment of compensation to us (generally in U.S. dollars although some contracts require a portion of the compensation to be paid in local currency) on a "day work" basis such that we receive a fixed amount for each day ("day rate") that the drilling unit is operating under contract (lower rates or no payments ("zero rate") generally apply during periods of equipment breakdown and repair or in the event operations are suspended or interrupted by other specified conditions, some of which may be beyond our control),
	•	payment by us of the operating expenses of the drilling unit, including crew labor and incidental rig supply costs, and
	•	provisions in term contracts allowing us to recover certain labor and other operating cost increases from our customers through day rate adjustment or otherwise.

Financial information regarding our operating segments and geographic regions is presented in Note 13 to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data." Additional financial information regarding our operating segments is presented in "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations."

Backlog Information

Our contract drilling backlog reflects firm commitments, typically represented by signed drilling contracts, and was calculated by multiplying the contracted operating day rate by the firm contract period. The contracted operating day rate excludes certain types of non-recurring revenues for rig mobilization, demobilization, contract preparation and other customer reimbursables.

The following table summarizes our contract backlog of business as of February 1, 2011 and 2010 (in millions):

	2011(*)		2010(*)

Deepwater	$1,723	.4	$1,689	.9
Asia Pacific	388	.6	466	.5
Europe and Africa	651	.0	363	.4
North and South America	305	.7	435	.3
Total	$3,068	.7	$2,955	.1

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

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 Asia Pacific backlog declined by $77.9 million primarily due to limited tender activity during 2010 and lower contracted day rates. Our Europe and Africa backlog increased by $287.6 million primarily due to an extension of the current ENSCO 102 contract through May 2016, in addition to incremental tender activity in the region. Our North and South America backlog declined by $129.6 million primarily due to revenues realized on our long-term contracts in Mexico. The table summarizes our annual backlog by operating segment as of February 1, 2011 (in millions):

	2011 (*)		2012		2013		2014 and Beyond		Total

Deepwater	$ 535	.5	$731	.8	$428	.3	$27	.8	$1,723	.4
Asia Pacific	304	.2	84	.3		.1		--	388	.6
Europe and Africa	282	.2	115	.6	74	.1	179	.1	651	.0
North and South America	247	.8	57	.9		--		--	305	.7
Total	$1,369	.7	$989	.6	$502	.5	$206	.9	$3,068	.7
(*) Backlog for the year ended December 31, 2011 includes revenues realized during January 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 Petróleos 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.

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.

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.

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.

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.

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.

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.

Item 1A. Risk Factors

Risks Related to Our Business

There are numerous factors that affect our business and operating results, many of which are beyond our control. The following is a description of significant factors that might cause our future operating results to differ materially from those currently expected. The risks described below are not the only risks facing our Company. Additional risks and uncertainties not specified herein, not currently known to us or currently deemed to be immaterial also may materially adversely affect our business, financial position, operating results and/or cash flows.

THE SUCCESS OF OUR BUSINESS LARGELY DEPENDS ON THE LEVEL OF ACTIVITY IN THE OIL AND GAS INDUSTRY WHICH CAN BE SIGNIFICANTLY AFFECTED BY VOLATILE OIL AND NATURAL GAS PRICES.

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

Worldwide military, political, environmental and economic events also contribute to oil and natural gas price volatility. Numerous other factors may affect oil and natural gas prices and the level of demand for our services, including:

	•	demand for oil and natural gas,
	•	the ability of OPEC to set and maintain production levels and pricing,
	•	the level of production by non-OPEC countries,
	•	U.S. and non-U.S. tax policy,
	•	laws and government regulations that limit, restrict or prohibit exploration and development of oil and natural gas in various jurisdictions,
	•	advances in exploration and development technology,
	•	disruption to exploration and development activities due to hurricanes and other severe weather conditions and the risk thereof,
	•	the worldwide military or political environment, including uncertainty or instability resulting from an escalation or additional outbreak of armed hostilities or other crises in oil or natural gas producing areas of the Middle East or geographic areas in which we operate, or acts of terrorism, and
	•	global economic conditions.

THE OFFSHORE CONTRACT DRILLING INDUSTRY HISTORICALLY HAS BEEN CYCLICAL, WITH PERIODS OF LOW DEMAND AND EXCESS RIG AVAILABILITY THAT COULD RESULT IN ADVERSE EFFECTS ON OUR BUSINESS.

Financial operating results in the offshore contract drilling industry historically have been very cyclical and primarily are related to the demand for drilling rigs and the available supply of drilling rigs. Demand for rigs is directly related to the regional and worldwide levels of offshore exploration and development spending by oil and gas companies, which is beyond our control. Offshore exploration and development spending may fluctuate substantially from year-to-year and from region-to-region.

The supply of offshore drilling rigs has increased in recent years, however, new rigs require substantial capital investment and a long period of time to construct. There are over 75 new jackup and semisubmersible rigs reported to be on order or under construction with delivery expected by the end of 2013. More than half of these rigs are scheduled for delivery during 2011 representing an approximate 6% increase in the total worldwide fleet of jackups and semisubmersible rigs. There are no assurances that the market in general or a geographic region in particular will be able to fully absorb the supply of new rigs in future periods.

The increase in supply of offshore drilling rigs during 2011 and future periods could result in an oversupply of offshore drilling rigs and could cause a decline in utilization and/or day rates, a situation which could be exacerbated by a decline in demand for drilling rigs. Lower utilization and/or day rates in one or more of the regions in which we operate could adversely affect our revenues, utilization and profitability.

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

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

OUR OFFSHORE DRILLING OPERATIONS COULD BE ADVERSELY IMPACTED BY THE BP MACONDO WELL INCIDENT AND THE RESULTING CHANGES IN REGULATION OF OFFSHORE OIL AND GAS EXPLORATION AND DEVELOPMENT ACTIVITY.

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.

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.

We have filed suit in the U.S. District Court for the Eastern District of Louisiana to seek relief from these actions which we believe violate the U.S. Administrative Procedure Act and the Outer Continental Shelf Lands Act. We are not able to predict the outcome of these legal proceedings, whether enforcement of any new actual or de facto moratorium/suspension and other related restrictions and delays will be enjoined, or whether the U.S. Department of the Interior will seek to implement additional restrictions on or prohibitions of drilling activities in the U.S. Gulf of Mexico. We have nine rigs under contract in the U.S. Gulf of Mexico, including three ultra-deepwater semisubmersible rigs. Our customers may seek to move rigs to locations outside the U.S. Gulf of Mexico, perform activities permitted under the enhanced safety requirements or attempt to terminate our contracts pursuant to their respective force majeure or other provisions.

At this time, we cannot predict the impact of the BP Macondo well incident and resulting changes in the regulation of offshore oil and gas exploration and development activity on our operations or contracts, the extent to which drilling operations subsequent to the moratorium period will be affected, the extent to which the issuance of permits for new or continued drilling will be delayed, the effect on the cost or availability of relevant insurance coverage, the effect on the demand for our services in the U.S. Gulf of Mexico or what actions may be taken by our customers, other industry participants or the U.S. or other governments in response to the incident. Future legislative or regulatory enactments may impose new requirements for well control and blowout prevention equipment that could increase our costs and cause delays in our operations due to unavailability of associated equipment.

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, including laws and regulations that have or may impose increased financial responsibility and oil spill abatement contingency plan capability requirements, could materially adversely affect our financial condition, operating results or cash flows.

WE MAY SUFFER LOSSES IF OUR CUSTOMERS TERMINATE OR SEEK TO RENEGOTIATE OUR CONTRACTS, IF OPERATIONS ARE SUSPENDED OR INTERRUPTED OR IF A RIG BECOMES A TOTAL LOSS.

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

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

RIG CONSTRUCTION, UPGRADE AND ENHANCEMENT PROJECTS ARE SUBJECT TO RISKS, INCLUDING DELAYS AND COST OVERRUNS, WHICH COULD HAVE A MATERIAL ADVERSE EFFECT ON OUR OPERATING RESULTS. THE RISKS ARE CONCENTRATED BECAUSE OUR THREE ULTRA-DEEPWATER SEMISUBMERSIBLE RIGS AND TWO ULTRA-HIGH SPECIFICATION HARSH ENVIRONMENT JACKUP RIGS CURRENTLY UNDER CONSTRUCTION ARE AT A SINGLE SHIPYARD IN SINGAPORE. THESE RIGS DO NOT HAVE DRILLING CONTRACTS.

There are over 75 new jackup and semisubmersible rigs reported to be on order or under construction with expected delivery dates through 2013. As a result, shipyards and third-party equipment vendors are under significant resource constraints to meet delivery obligations. Such constraints may lead to substantial delivery and commissioning delays and/or equipment failures and/or quality deficiencies. Furthermore, new drilling rigs may face start-up or other operational complications following completion of construction work or other unexpected difficulties including equipment failures, design or engineering problems that could result in significant downtime at reduced or zero day rates or the cancellation or termination of drilling contracts.

We currently have three ultra-deepwater semisubmersible rigs and two ultra-high specification harsh environment jackup rigs under construction. In addition, we may construct additional rigs and continue to upgrade the capability and extend the service lives of our existing rigs. Rig construction, upgrade, life extension and repair projects are subject to the risks of delay or cost overruns inherent in any large construction project, including the following:

	•	failure of third-party equipment to meet quality and/or performance standards,
	•	delays in equipment deliveries or shipyard construction,
	•	shortages of materials or skilled labor,
	•	damage to shipyard facilities or construction work in progress, including damage resulting from fire, explosion, flooding, severe weather or terrorism,
	•	unforeseen design or engineering problems,
	•	unanticipated actual or purported change orders,
	•	strikes, labor disputes or work stoppages,
	•	financial or operating difficulties of equipment vendors or the shipyard while constructing, upgrading, refurbishing or repairing a rig or rigs,
	•	unanticipated cost increases,
	•	foreign currency exchange rate fluctuations impacting overall cost,
	•	inability to obtain the requisite permits or approvals,
	•	claims of force majeure events, and
	•	additional risks inherent to shipyard projects in a non-U.S. location.

Our risks are concentrated because our three ultra-deepwater semisubmersible rigs and two ultra-high specification harsh environment jackup rigs currently under construction are at a single shipyard in Singapore. Although based on the design of ENSCO 7500 which has operated without significant downtime since its delivery in 2000, the three ultra-deepwater semisubmersible rigs and the recently delivered ENSCO 8500, ENSCO 8501, ENSCO 8502 and ENSCO 8503 have a common risk of unforeseen design or engineering problems.

ENSCO 8504, ENSCO 8505, ENSCO 8506 and our two ultra-high specification harsh environment jackup rigs have not secured drilling contracts upon completion of their construction. These rigs are scheduled to be delivered during the third quarter of 2011, first and second half of 2012 and first and second half of 2013, respectively. There is no assurance that we will secure drilling contracts for these rigs or that the drilling contracts we may be able to secure will be based upon rates and terms that will provide a reasonable rate of return on these investments. Our failure to secure contractual commitments for these rigs at rates and terms that result in a reasonable return upon completion of construction may result in a material adverse effect on our financial position, operating results and cash flows. If we are able to secure drilling contracts prior to completion, we will be exposed to the risk of delays that could impact the projected financial results or the viability of the contracts and could have a material adverse effect on our financial position, operating results and cash flows.

DETERIORATION OF THE GLOBAL ECONOMY AND/OR A DECLINE IN OIL AND NATURAL GAS PRICES COULD CAUSE OUR CUSTOMERS TO REDUCE SPENDING ON EXPLORATION AND DEVELOPMENT DRILLING. THESE CONDITIONS COULD ALSO CAUSE OUR CUSTOMERS AND/OR VENDORS TO FAIL TO FULFILL THEIR COMMITMENTS AND/OR FUND FUTURE OPERATIONS AND OBLIGATIONS, WHICH COULD HAVE A MATERIAL ADVERSE EFFECT ON OUR BUSINESS.

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

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

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

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

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

We evaluate the carrying value of our property and equipment, primarily our drilling rigs, when events or changes in circumstances indicate that the carrying value of such rigs may not be recoverable. The offshore drilling industry historically has been highly cyclical, and it is not unusual for rigs to be unutilized or underutilized for significant periods of time and subsequently resume full or near full utilization when business cycles change. Likewise, during periods of supply and demand imbalance, rigs are frequently contracted at or near cash break-even rates for extended periods of time until day rates increase when demand comes back into balance with supply. However, if the global economy were to deteriorate and/or the offshore drilling industry were to incur a significant prolonged downturn, impairment charges may occur with respect to specific individual rigs, groups of rigs, such as a specific type of drilling rig, or rigs in a certain geographic location.

We test goodwill for impairment on an annual basis or when events or changes in circumstances indicate that a potential impairment exists. The goodwill impairment test requires us to identify reporting units and estimate each unit's fair value as of the testing date. In most instances, our calculation of the fair value of our reporting units is based on estimates of future discounted cash flows to be generated by our drilling rigs, which reflect management's judgments and assumptions regarding the appropriate risk-adjusted discount rate, as well as future industry conditions and operations, including expected utilization, day rates, expense levels, capital requirements and terminal values for each of our rigs. If the aggregate fair value of our reporting units exceeds our market capitalization, we evaluate the reasonableness of the implied control premium. If we determine the implied control premium is not reasonable, we adjust the discount rate in our discounted cash flow model and reduce the estimated fair values of our reporting units.

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

OUR BUSINESS MAY BE MATERIALLY ADVERSELY AFFECTED IF CERTAIN CUSTOMERS CEASE TO DO BUSINESS WITH US.

We provide our services to major international, government-owned and independent oil and gas companies. During 2010, our five largest customers accounted for 43% of consolidated revenues in the aggregate, with our two largest customers representing 25%. Our financial position, operating results and cash flows may be materially adversely affected if a major customer terminates its contracts with us, fails to renew its existing contracts with us, requires renegotiation of our contracts or declines to award new contracts to us.

FAILURE TO RECRUIT AND RETAIN SKILLED PERSONNEL COULD ADVERSELY AFFECT OUR OPERATIONS AND FINANCIAL RESULTS.

We require skilled personnel to operate our drilling rigs and to provide technical services and support for our business. Competition for skilled and other labor has intensified as additional rigs are added to the worldwide fleet. There are over 75 new jackup and semisubmersible rigs reported to be on order or under construction with delivery expected by the end of 2013, more than half of which are scheduled for delivery during 2011. These rigs will require new skilled and other personnel to operate. In periods of high utilization, it is more difficult and costly to recruit and retain qualified employees. Competition for such personnel could increase our future operating expenses, with a resulting reduction in net income, or impact our ability to fully staff and operate our rigs.

Notwithstanding current global economic conditions, we may be required to maintain or increase existing levels of compensation to retain our skilled workforce. Much of the skilled workforce is nearing retirement age, which may impact the availability of skilled personnel. We also are subject to potential further unionization of our labor force or legislative or regulatory action that may impact working conditions, paid time off or other conditions of employment. If such labor trends continue, they could further increase our costs or limit our ability to fully staff and operate our rigs.

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

We currently have 12 jackup rigs contracted with national oil companies. The terms of these non-U.S. contracts are often non-negotiable and may expose us to greater commercial, political and operational risks than we assume in other contracts such as exposure to greater environmental liability, the risk that the contract may be terminated by our customer without cause on short-term notice, contractually or by governmental action, under certain conditions that may not provide us an early termination payment, collection risks and political risks. While we believe that the financial, commercial and risk allocation terms of these contracts and our operating safeguards mitigate these risks, we can provide no assurance that the increased risk exposure will not have an adverse impact on our future operations or that we will not increase the number of rigs contracted to national oil companies with commensurate additional contractual risks.

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

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

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

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

Revenues from non-U.S. operations were 75%, 86% and 79% of our total 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 vendor/supplier corruption,
	•	changes in political conditions, and
	•	changes in monetary policies.

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

A portion of the costs and expenditures incurred by our non-U.S. operations, including a portion of the construction payments for the ENSCO 8500 Series® rigs, are settled in local currencies, exposing us to risks associated with fluctuation in the value of these currencies relative to the U.S. dollar. We use foreign currency forward contracts to reduce this exposure. However, the relative weakening in the value of the U.S. dollar in relation to the local currencies in these countries may increase our costs and expenditures.

Our non-U.S. operations are also subject to various laws and regulations in countries in which we operate, including laws and regulations relating to the operation of drilling rigs and the requirement for equipment thereon. Governments in some non-U.S. countries have become increasingly active in regulating and controlling the ownership of oil, natural gas and mineral concessions and companies holding concessions, the exploration of oil and natural gas and other aspects of the oil and gas industry in their countries. In addition, government action, including initiatives by OPEC, may continue to cause oil and/or natural gas price volatility. In some areas of the world, government activity has adversely affected the amount of exploration and development work performed by major international oil companies and may continue to do so. Moreover, certain countries accord preferential treatment to local contractors or joint ventures, which can place us at a competitive disadvantage. There can be no assurance that such laws and regulations or activities will not have a material adverse effect on our future operations.

THE POTENTIAL FOR GULF OF MEXICO HURRICANE RELATED WINDSTORM DAMAGE OR LIABILITIES COULD RESULT IN UNINSURED LOSSES AND MAY CAUSE US TO ALTER OUR OPERATING PROCEDURES DURING HURRICANE SEASON, WHICH COULD ADVERSELY AFFECT OUR BUSINESS.

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

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

Upon renewal of our annual insurance policies effective July 1, 2010, we obtained $450.0 million of annual coverage for ultra-deepwater semisubmersible rig hull and machinery losses arising from Gulf of Mexico windstorm damage with a $50.0 million per occurrence self-insured retention (deductible). However, due to the significant premium, high self-insured retention and limited coverage, we decided not to purchase windstorm insurance for our jackup rigs remaining in the Gulf of Mexico. Accordingly, we have retained the risk for loss or damage of our nine jackup rigs remaining in the Gulf of Mexico arising out of windstorm damage.

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

We have established operational procedures designed to mitigate risk to our jackup rigs in the Gulf of Mexico during hurricane season. In addition to procedures designed to better secure the drilling package on jackup rigs, improve jackup leg stability and increase the air gap to position the hull above waves, our procedures involve analysis of prospective drilling locations, which may include enhanced bottom surveys. These procedures may result in a decision to decline to operate on a customer designated location during hurricane season notwithstanding that the location, water depth and other standard operating conditions are within a rig's normal operating range. Our procedures and the associated regulatory requirements addressing Mobile Offshore Drilling Unit operations in the Gulf of Mexico during hurricane season, coupled with our decision to retain (self-insure) certain windstorm related risks, may result in a significant reduction in the utilization of our jackup rigs in the Gulf of Mexico.

As noted above, we have a $50.0 million per occurrence deductible for windstorm loss or damage to our ultra-deepwater semisubmersible rigs in the Gulf of Mexico and have elected not to purchase loss or damage insurance coverage for our nine jackup rigs in the area. Moreover, we have retained the risk for the first $50.0 million of liability exposure for removal of wreckage and debris resulting from windstorm related exposures associated with our rigs in the Gulf of Mexico. These and other retained exposures for property loss or damage and wreckage and debris removal or other liabilities associated with Gulf of Mexico hurricanes could have a material adverse effect on our financial position, operating results and cash flows if we sustain significant uninsured or underinsured losses or liabilities as a result of Gulf of Mexico hurricanes.

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

In September 2008, ENSCO 74 was lost as a result of Hurricane Ike in the Gulf of Mexico. Portions of its legs remained underwater adjacent to the customer's platform, and we conducted extensive aerial and sonar reconnaissance but did not locate the rig hull. In March 2009, the sunken rig hull of ENSCO 74 was located approximately 95 miles from the original drilling location when it was struck by an oil tanker. 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 are involved in civil litigation in the U.S. District Court for the Southern District of Texas in which the owners of the tanker SKS Satilla are seeking monetary damages of $10.0 million for losses incurred when the tanker struck the sunken hull of ENSCO 74. We are involved in civil litigation in the U.S. District Court for the Southern District of Texas in which the owner of a pipeline, High Island Offshore System, LLC, alleges that ENSCO 74 damaged the pipeline in the aftermath of Hurricane Ike and is seeking damages for the cost of repairs and business interruption in excess of $26.0 million.

We also are involved in civil litigation in the Fifteenth Judicial Court for the Parish of Lafayette and in the Nineteenth Judicial Court for the Parish of Baton Rouge, State of Louisiana in which the owner of a pipeline, Sea Robin Pipeline Company, LLC, is seeking unspecified damages in relation to the cost of repairing damage to the pipeline, loss of revenues, survey and other damages allegedly caused by ENSCO 74 in the aftermath of Hurricane Ike.

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

We filed a petition for exoneration or limitation of liability under U.S. admiralty and maritime law in the U.S. District Court for the Southern District of Texas on September 2, 2009. The petition seeks exoneration from or limitation of liability for any and all injury, loss or damage caused, occasioned or occurred in relation to the ENSCO 74 loss in September 2008. The exoneration/limitation proceedings currently includes the SKS Satilla claim and the four pipeline claims described above, which effectively supersedes their prior civil litigation filings. The matter has been scheduled for trial in March 2012. See Note 12 to our consolidated financial statements for additional information on the loss of ENSCO 74 and associated contingencies.

We are exposed to costs associated with removal of the ENSCO 74 legs that remain underwater adjacent to the customer's platform, in addition to the removal of related debris. Although we expect the cost of removal of the leg sections and related debris to be covered by available insurance and contractual indemnification, we may not be fully protected from such costs, liability or exposure (without any additional deductible or self-insured retention). Our liability insurance may not fully protect us from cost, liability or exposure associated with the loss of ENSCO 74. As respects liabilities to third-parties, including the aforementioned tanker and pipeline claims, our applicable insurance is subject to a $10.0 million per occurrence self-insured retention and an annual aggregate policy limit of $500.0 million. We believe all liabilities associated with the ENSCO 74 loss during Hurricane Ike resulted from a single occurrence under the terms of the applicable insurance policies. However, legal counsel for certain liability underwriters have asserted that the liability claims arise from separate occurrences. In the event of multiple occurrences, the self-insured retention is $15.0 million for two occurrences and $1.0 million for each occurrence thereafter.

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

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

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

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

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

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

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

COMPLIANCE WITH OR BREACH OF ENVIRONMENTAL LAWS CAN BE COSTLY AND COULD LIMIT OUR OPERATIONS.

Our operations are subject to laws and regulations controlling the discharge of materials into the environment, pollution, contamination and hazardous waste disposal or otherwise relating to the protection of the environment. Environmental laws and regulations specifically applicable to our business activities could impose significant liability on us for damages, clean-up costs, fines and penalties in the event of oil spills or similar discharges of pollutants or contaminants into the environment or improper disposal of hazardous waste generated in the course of our operations. To date, such laws and regulations have not had a material adverse effect on our operating results, and we have not experienced an accident that has exposed us to material liability arising out of or relating to discharges of pollutants into the environment. However, the legislative 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 OPA 90 and other U.S. federal statutes applicable to us and our operations, as well as similar statutes in Texas, Louisiana, other coastal states and other non-U.S. jurisdictions, address oil spill prevention and control and significantly expand liability, fine and penalty exposure across many segments of the oil and gas industry. Such statutes and related regulations impose a variety of obligations on us related to the prevention of oil spills, disposal of waste and liability for resulting damages. For instance, OPA 90 imposes strict and, with limited exceptions, joint and several liability upon each responsible party for oil removal costs as well as a variety of fines, penalties and damages. Failure to comply with these statutes and regulations, including OPA 90, may subject us to civil or criminal enforcement action, which may not be covered by contractual indemnification or insurance and could have a material adverse effect on our financial position, operating results and cash flows.

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 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.

LAWS AND GOVERNMENTAL REGULATIONS MAY ADD TO COSTS, LIMIT OUR DRILLING ACTIVITY OR REDUCE DEMAND FOR OUR DRILLING SERVICES.

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

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

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

LEGAL PROCEEDINGS COULD AFFECT US ADVERSELY.

We are involved in litigation, including various claims, disputes and regulatory proceedings that arise in the ordinary course of business, many of which are uninsured and relate to commercial, employment or regulatory activities. We also are concluding an internal investigation relating to compliance with the anti-bribery, recordkeeping and accounting provisions of the U.S. Foreign Corrupt Practices Act ("FCPA") that focuses on activities related to our former operations in Nigeria and the associated accounting entries and internal accounting controls and have self-reported to the appropriate U.S. government authorities. See Note 12 to our consolidated financial statements for additional information on our legal proceedings and other contingent liabilities.

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

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

As of December 31, 2010, we held $50.1 million (par value) of auction rate securities. Auctions for most of our auction rate securities began to fail in February 2008, as there were more sellers than buyers at scheduled interest rate auctions and parties desiring to sell their auction rate securities were unable to do so. When an auction fails, the interest rate is adjusted according to the provisions of the associated security agreement. The majority of our auction rate securities are currently rated Aaa by Moody's, AAA by Standard & Poor's and/or AAA by Fitch. 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.

Auction failures and the resulting lack of liquidity have affected the entire auction rate securities market, and we are currently unable to determine whether these conditions will continue for an extended duration. While it is estimated that the majority of the auction rate securities market has been refinanced, student loan supported auction rate securities remain mostly constrained and illiquid. 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.

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

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

Risks Related to the Proposed Merger with Pride

Our expectations regarding our business may be impacted by the following risk factors related to the pending merger with Pride:

FAILURE TO COMPLETE THE MERGER WITH PRIDE COULD NEGATIVELY AFFECT OUR SHARE PRICE AND OUR FUTURE BUSINESS AND OPERATING RESULTS.

Completion of the merger with Pride is not assured and is subject to risks, including the risks that approval of the transaction by our shareholders and the stockholders of Pride is not obtained or that certain other closing conditions are not satisfied. If the merger is not completed, our ongoing business may be adversely affected and will be subject to several risks, including the following:

•

having to pay certain significant costs relating to the merger without receiving the benefits of the merger including, in certain circumstances, a termination fee of up to $260.0 million to Pride;

•

the attention of our management will have been diverted to the merger instead of on our operations and pursuit of other opportunities that may have been beneficial to us; and

•

resulting negative customer perception could adversely affect our ability to compete for, or to obtain, new and renewal business in the marketplace.

WE WILL INCUR SUBSTANTIAL TRANSACTION AND MERGER-RELATED COSTS IN CONNECTION WITH THE MERGER AND OUR SHAREHOLDERS WILL BE DILUTED BY THE MERGER.

We expect to incur a number of non-recurring transaction and merger-related costs associated with completing the merger with Pride, combining the operations of the two companies and achieving desired synergies. These fees and costs will be substantial. Additional unanticipated costs may be incurred in the integration of the businesses of Ensco and Pride. Although we expect that the elimination of certain duplicative costs, as well as the realization of other efficiencies related to the integration of the two businesses, will offset the incremental transaction and merger-related costs over time, this net benefit may not be achieved in the near-term, or at all.

IF THE MERGER IS COMPLETED, WE WILL BE SUBJECT TO ADDITIONAL RISKS.

The success of the merger will depend, in part, on our ability to realize anticipated benefits from combining the businesses of Ensco and Pride. However, to realize these anticipated benefits, we must successfully integrate the operations and personnel of Pride into our business, including the expected relocation of our U.S. headquarters to Houston from Dallas. If we are not able to achieve these objectives, the anticipated benefits of the merger may not be realized fully or at all or may take longer to realize than expected. Because Ensco and Pride have operated independently and, until the completion of the merger, will continue to operate independently, it is possible that the integration process could take longer than anticipated and could result in the loss of valuable employees or the disruption of each company’s ongoing businesses or inconsistencies in standards, controls, procedures, practices, policies and compensation arrangements, which could adversely affect our ability to achieve the anticipated benefits of the merger. Our results of operations after the merger could also be adversely affected by any issues attributable to either company’s operations that arise or are based on events or actions that occur prior to the closing of the merger. Further, the size of the merger may make integration difficult, expensive and disruptive, adversely affecting our operating results after the merger. Failure to achieve the anticipated benefits could result in increased costs or decreases in the amount of expected revenues and could adversely affect our future business, financial condition, operating results and prospects. In addition, we may not be able to eliminate duplicative costs or realize other efficiencies from integrating the businesses to offset part or all of the transaction and merger-related costs that have and will be incurred.

Our performance following the merger could be adversely affected if we are unable to retain certain key employees. The loss of key personnel may also negatively impact the productivity and profitability of certain projects and can result in lost rig contracting opportunities during periods of unanticipated demand. Our inability to bid on new and attractive projects, or maintain productivity and profitability on existing projects, including those developed by Pride, due to the loss of key employees could negatively affect our profitability and operating results.

In addition, the approval or regulatory requirements of certain government or regulatory agencies in connection with the merger could contain terms, conditions, or restrictions, such as the divestiture of assets, that would be detrimental to us after the merger. Additionally, even after the statutory waiting period under the antitrust laws and even after completion of the merger, governmental authorities could seek to block or challenge the merger as they deem necessary or desirable in the public interest. In addition, in some jurisdictions, a competitor, customer or other third party could initiate a private action under the antitrust laws challenging or seeking to enjoin the merger, before or after it is completed. Ensco or Pride may not prevail and may incur significant costs in defending or settling any such action under the antitrust laws.

THE MERGER AGREEMENT CONTAINS PROVISIONS THAT LIMIT EACH PARTY’S ABILITY TO PURSUE ALTERNATIVES TO THE MERGER, COULD DISCOURAGE A POTENTIAL COMPETING ACQUIRER OF EITHER PRIDE OR ENSCO FROM MAKING A FAVORABLE ALTERNATIVE TRANSACTION PROPOSAL AND, IN CERTAIN CIRCUMSTANCES, COULD REQUIRE PAYMENT OF A $260.0 MILLION TERMINATION FEE.

Under the merger agreement, Pride or Ensco Delaware may be required to pay to Ensco or Pride, respectively, a termination fee of up to $260.0 million if the merger agreement is terminated under certain circumstances. If such a termination fee is payable, the payment of this fee could have material and adverse consequences to the financial condition and operating results of the company making such payment.

Under the merger agreement, Ensco and Pride are restricted from entering into alternative transactions. Unless and until the merger agreement is terminated, subject to specified exceptions, both Ensco and Pride are restricted from soliciting, initiating, knowingly and intentionally encouraging or facilitating, or negotiating, any inquiry, proposal or offer for a competing acquisition proposal with any person. Additionally, under the merger agreement, in the event of a potential change by the board of directors of either party of its recommendation with respect to the merger, such party must provide the other with two business days to propose an adjustment to the terms and conditions of the merger agreement. Ensco and Pride may terminate the merger agreement and enter into an agreement with respect to a superior proposal only if specified conditions have been satisfied, including compliance with the no solicitation provisions of the merger agreement. These provisions could discourage a third party that may have an interest in acquiring all or a significant part of Ensco or Pride from considering or proposing that acquisition, even if such third party were prepared to pay consideration with a higher per share cash or market value than the market value proposed to be received or realized in the merger, or might result in a potential competing acquirer proposing to pay a lower price than it would otherwise have proposed to pay because of the added expense of the termination fee that may become payable in certain circumstances. As a result of these restrictions, neither Ensco nor Pride may be able to enter into an agreement with respect to a more favorable alternative transaction without incurring potentially significant liability to the other.

IF OUR FINANCING FOR THE MERGER BECOMES UNAVAILABLE, THE MERGER MAY NOT BE COMPLETED AND WE MAY BE IN BREACH OF THE MERGER AGREEMENT.

We intend to finance a portion of the cash component of the merger consideration with debt financing. On February 6, 2011, Ensco 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. We intend to fund the cash component of the merger consideration through internal cash resources, the Bridge Term Facility and potentially the proceeds of other sources of debt financing.

In the event that the financing contemplated by the Bridge Term Facility is not available, other financing may not be available on acceptable terms, in a timely manner or at all. If other financing becomes necessary and we are unable to secure such additional financing, we could be in breach of the merger agreement assuming all other conditions to closing are satisfied, may be obligated to pay damages to Pride or may be compelled to specifically perform its obligations to consummate the transaction.

WE EXPECT TO INCUR SUBSTANTIAL ADDITIONAL INDEBTEDNESS TO FINANCE THE MERGER AND PRIDE’S EXISTING INDEBTEDNESS WILL REMAIN OUTSTANDING UPON COMPLETION OF THE MERGER, WHICH MAY DECREASE OUR BUSINESS FLEXIBILITY AND INCREASE OUR BORROWING COSTS.

Upon completion of the 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. Our increased indebtedness and higher debt-to-equity ratio in comparison to that of Ensco on a recent historical basis may have the effect, among other things, of reducing our flexibility to respond to changing business and economic conditions and increasing borrowing costs. In addition, the terms and conditions of such indebtedness may not be favorable to us, and as such, could further increase the cost of the merger, as well as the overall burden of such indebtedness upon us and our business flexibility. Unfavorable debt financing terms may also adversely affect our operating results.

PENDING LITIGATION AGAINST PRIDE AND ENSCO COULD RESULT IN AN INJUNCTION PREVENTING THE CONSUMMATION OF THE MERGER OR MAY ADVERSELY AFFECT OUR BUSINESS, FINANCIAL CONDITION OR OPERATING RESULTS FOLLOWING THE MERGER.

In connection with the merger, various lawsuits have been filed in the Delaware Court of Chancery and in the District Courts of Harris County, Texas against Pride, its directors and Ensco and/or certain of its subsidiaries alleging violations of various fiduciary duties in approving the merger and that Ensco and/or Pride aided and abetted such alleged violations. Among other remedies, the plaintiffs seek to enjoin the merger. While Ensco and Pride believe these suits are without merit and intend to vigorously defend against such claims, the outcome of any such litigation is inherently uncertain. Any and all applicable insurance policies may not provide sufficient coverage for the defense costs and claims under these lawsuits, and individual director and officer rights of indemnification with respect to these lawsuits will continue after the completion of the merger. The defense or settlement of any lawsuit or claim that remains unresolved at the time the merger closes may adversely affect our business, financial condition or operating results.

WE MAY BE UNABLE TO OBTAIN THE REGULATORY CLEARANCES AND APPROVALS REQUIRED TO COMPLETE THE PROPOSED MERGER WITH PRIDE OR, IN ORDER TO DO SO, WE MAY BE REQUIRED TO COMPLY WITH MATERIAL RESTRICTIONS OR CONDITIONS.

The merger is subject to review by the Antitrust Division and the FTC under the HSR Act and by other governmental entities under non-U.S. antitrust or competition merger control statutes. The expiration or termination of the waiting period (and any extension of the waiting period) applicable to the merger under the HSR Act is a condition to closing the merger. The merger may also be subject to the regulatory requirements of other municipal, state and federal, domestic or foreign, governmental agencies and authorities. We can provide no assurance that all required regulatory approvals will be obtained or that these approvals will not contain terms, conditions or restrictions, such as the divestiture of assets or lines of business, that would be detrimental to us after the effective time of the merger.

Additionally, even after the statutory waiting period, and any extensions of such period agreed to by the parties, under the HSR Act has expired, and even after completion of the merger, governmental authorities could seek to block or challenge the merger as they deem necessary or desirable in the public interest. In addition, in some jurisdictions, a competitor, customer or other third party could initiate a private action under the antitrust laws challenging or seeking to enjoin the merger, before or after it is completed. We may not prevail and may incur significant costs in defending or settling any action under the antitrust laws.

ANY DELAY IN COMPLETING THE MERGER MAY SUBSTANTIALLY REDUCE THE BENEFITS EXPECTED TO BE OBTAINED FROM THE MERGER.

In addition to obtaining the required governmental clearances and approvals, the merger is subject to a number of other conditions beyond the control of Pride and Ensco that may prevent, delay or otherwise materially adversely affect its completion. We cannot predict whether or when the conditions required to complete the merger will be satisfied. The requirements for obtaining the required clearances and approvals could delay the effective time of the merger for a significant period of time or prevent it from occurring. Any delay in completing the merger may materially adversely affect the synergies and other benefits that we expect to achieve if the merger and the integration of our respective businesses are completed within the expected timeframe.

OUR FUTURE RESULTS OF OPERATIONS COULD BE ADVERSELY AFFECTED IF THE GOODWILL RECORDED IN THE MERGER SUBSEQUENTLY REQUIRES IMPAIRMENT.

When we acquire a business, generally goodwill is recorded as an asset on our balance sheet and is equal to the excess amount we pay for the business, including the fair value of liabilities assumed, over the fair value of the tangible and identified intangible assets of the business we acquire. FASB ASC 350 requires that goodwill and other intangible assets that have indefinite useful lives not be amortized, but instead be tested at least annually for impairment, and that intangible assets that have finite useful lives be amortized over their useful lives. FASB ASC 350 provides specific guidance for testing goodwill and other indefinite lived intangible assets for impairment. FASB ASC 350 requires our management to make certain estimates, judgments and assumptions when allocating goodwill to reporting units and determining the fair value of those reporting units, including, among other things, appropriate risk-adjusted discount rates, as well as future industry conditions and operations, expected utilization, day rates, expense levels, capital requirements and terminal values for each of our rigs. Absent any impairment indicators, we perform our impairment tests annually during the fourth quarter. Any future impairments would negatively impact our results of operations for the period in which the impairment is recognized.

PRIDE’S BUSINESS, AND ANY OTHER BUSINESSES THAT WE MAY ACQUIRE AFTER COMPLETION OF THE MERGER, MAY BE DIFFICULT TO INTEGRATE, DISRUPT OUR BUSINESS, DILUTE SHAREHOLDER VALUE OR DIVERT MANAGEMENT ATTENTION.

Risks with respect to our merger with Pride, and any other recent and future acquisitions, include:

•

difficulties in the integration of the operations and personnel of Pride;

•

diversion of management’s attention away from other business concerns; and

•

the assumption of any undisclosed or other potential liabilities of the acquired company.

OUR SHAREHOLDERS WILL BE DILUTED BY THE MERGER.

The merger will dilute the ownership position of our current shareholders. We will issue approximately 86.0 million Class A ordinary shares represented by Ensco ADSs (based on the number of outstanding shares of Pride common stock and restricted stock unit awards as of February 4, 2011 and based on the assumption that no employee stock options to purchase shares of Pride common stock are exercised prior to completion of the merger). Our shareholders and Pride stockholders are expected to hold approximately 62.0% and 38.0%, respectively, of our ADSs outstanding immediately after the merger based on these same assumptions.

Risks Related to Our Redomestication to the U.K.

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

Based on current U.K. corporation tax law and the current U.K.-U.S. income tax treaty, as amended, we expect that the redomestication will not result in any material U.K. corporation tax liability to Ensco plc. Further, we believe that we have satisfied all stamp duty reserve tax ("SDRT") payment and filing obligations in connection with the issuance and deposit of our Class A ordinary shares into the ADS facility pursuant to the deposit agreement governing the ADS facility.

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

Subject to certain exemptions and other forms of relief, a U.K. resident company, such as Ensco plc, is liable to corporation tax on the income profits (whether or not distributed) of any controlled company which is resident in a foreign jurisdiction and is subject to a lower level of taxation on those profits. A controlled company will be regarded as being subject to a lower level of taxation if the amount of foreign income tax on its profits is less than three-quarters of the corresponding corporation tax that would be payable in the U.K. if the company were resident in the U.K. Any such foreign income tax on the profits of the controlled company is generally creditable for U.K. corporation tax purposes.

HMRC has, subject to certain conditions and limitations based on our facts and circumstances, granted exemption from the Controlled Foreign Companies (“CFC”) regime in respect of all material subsidiaries of Ensco plc under the “motive test” exclusion for a period after the merger ending December 31, 2012, which period may be reduced or altered by subsequent legislation. The present U.K. Government is consulting on a potentially major reform of the CFC regime and has stated its intention to introduce interim reform in 2011 and full reform in 2012. However, the U.K. Government has not yet put any of these reform proposals into effect and there can be no certainty about the nature and extent of any future changes to the current CFC regime.

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

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

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

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

We believe the redomestication should improve our ability to maintain a competitive consolidated effective income tax rate because the U.K. corporate tax rate is lower than the U.S. corporate tax rate and because the U.K. has implemented a dividend exemption system that generally does not subject non-U.K. earnings to U.K. tax when such earnings are repatriated to the U.K. in the form of dividends from non-U.K. subsidiaries. In 2010, the new U.K. Government announced its intention that there will be a phased reduction in the headline rate of U.K. corporation tax from 27% to 24% by 2014, its lowest ever rate.

The U.K. has implemented controlled foreign companies rules (the "CFC rules") under which, in certain circumstances, the income profits of controlled non-U.K. resident companies which are subject to a lower level of taxation may be subject to U.K. corporation tax, subject to credit relief for foreign tax on those profits. The HMRC has granted us an exemption from the CFC rules in respect of our material non-U.K. operations under the “motive test” exemption until December 31, 2012, subject to certain conditions and limitations based on our facts and circumstances.

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

In June 2010, the new U.K. Government announced in its Emergency Budget that it aims to create the most competitive corporate tax system in the G20, and that as a first step it will reform the U.K.'s CFC rules, which it recognized as a key priority for U.K. multinationals. The U.K. Government's policy is that the U.K.'s corporate tax system should focus more on profits from U.K. activity in determining the tax base, rather than attributing the worldwide income of a group to the U.K. It has been announced that legislation for new CFC rules will be introduced in the spring of 2012, allowing time to consider how to make the rules more competitive, to enhance long-term stability and to provide adequate protection of the U.K. tax base. The U.K. Government launched a consultation on the reform of the CFC rules in November 2010 which will continue until late February 2011, and it intends to publish draft legislation in respect of the same during the second half of 2011. At the same time, the U.K. Government also launched a consultation on certain interim improvements to the current CFC rules, to make the rules easier to operate and, where possible, increase competitiveness. The U.K. Government published draft legislation in respect of the same on December 9, 2010. Legislation on interim improvements to the CFC rules will be introduced during the first half of 2011. The effect of any changes to the CFC rules on our effective rate of income taxation will not be clear until the new legislation is published and enacted in its entirety. However, it is anticipated that these reforms will generally be favorable to us, as compared to the current CFC rules. Nevertheless, as the U.K.'s current CFC rules for the most part do not apply to our material overseas operations until December 31, 2012, our ability to efficiently manage those operations with a view to managing our effective income tax rates may be restricted by virtue of the new CFC rules from January 1, 2013. In the event that the U.K. Government adopts changes to the CFC rules that have the effect of increasing our consolidated effective income tax rate, our results of operations may be adversely affected unless we are able to identify and implement any mitigating actions.

We cannot provide any assurances as to what our effective income tax rates will be because of, among other things, uncertainty regarding the nature and extent of our business activities in any particular jurisdiction in the future and the tax laws of such jurisdictions, as well as potential changes in U.K. and U.S. tax laws. Our actual effective income tax rates may vary from our expectations and those variances may be material. Additionally, the tax laws of other jurisdictions could change in the future, and such changes could cause a material change in our consolidated effective income tax rate.

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

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

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

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

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

THE EXPECTED FINANCIAL, LOGISTICAL AND OPERATIONAL BENEFITS OF THE REDOMESTICATION MAY NOT BE REALIZED.

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

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

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

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

INVESTOR ENFORCEMENT OF CIVIL JUDGMENTS AGAINST US MAY BE MORE DIFFICULT.

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

WE HAVE LESS FLEXIBILITY AS A U.K. PUBLIC LIMITED COMPANY WITH RESPECT TO CERTAIN ASPECTS OF CAPITAL MANAGEMENT THAN U.S. CORPORATIONS DUE TO INCREASED SHAREHOLDER APPROVAL REQUIREMENTS.

Directors of a Delaware and other U.S. corporation may issue, without further shareholder approval, shares of common stock authorized in its certificate of incorporation that were not already issued or reserved. The business corporation laws of Delaware and other U.S. states also provide substantial flexibility in establishing the terms of preferred stock. However, English law provides that a board of directors may only allot shares with the prior authorization of shareholders, such authorization being up to the aggregate nominal amount of shares and for a maximum period of five years, each as specified in the articles of association or relevant shareholder resolution. Such authorization would need to be renewed by our shareholders upon its expiration (i.e., at least every five years). An ordinary resolution was adopted prior to the effective time of the redomestication in December 2009 to authorize the allotment of additional shares for a five-year term and renewal of such authorization for additional five-year terms may be sought more frequently.

English law also generally provides shareholders preemptive rights when new shares are issued for cash. However, it is possible for the articles of association or shareholders in a general meeting to exclude preemptive rights. Such an exclusion of preemptive rights may be for a maximum period of up to five years from the date of adoption of the articles of association, if the exclusion is contained in the articles of association, or from the date of the shareholder resolution, if the exclusion is by shareholder resolution. In either case, this exclusion would need to be renewed upon its expiration (i.e., at least every five years). A special resolution was adopted to exclude preemptive rights prior to the effective time of the redomestication in December 2009 for a five-year term and renewal of such exclusion for additional five-year terms may be sought more frequently.

English law prohibits us from conducting "on-market purchases" as our shares will not be traded on a recognized investment exchange in the U.K. English law also generally prohibits a company from repurchasing its own shares by way of "off-market purchases" without the prior approval of 75% of its shareholders by special resolution. Such approval lasts for a maximum period of up to five years. A special resolution was adopted in December 2009 to permit "off-market purchases" prior to the effective time of the redomestication. This special resolution will need to be renewed upon expiration (i.e., at least every five years) to permit "off-market purchases" and renewal for additional five-year terms may be sought more frequently.

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

THE REDOMESTICATION WILL RESULT IN ADDITIONAL ONGOING COSTS.

The redomestication has resulted in an increase in some of our ongoing expenses and will require us to incur some new expenses. Some costs, including those related to relocation and employment of expatriate officers and other employees in our U.K. offices and holding Board of Directors meetings in the U.K., are expected to be higher than would be the case if our principal executive offices remained in the U.S. We also have incurred and expect to continue to incur additional expenses, including professional fees, to comply with U.K. corporate and tax laws.

THE MARKET FOR ADSs REPRESENTING CLASS A ORDINARY SHARES MAY DIFFER FROM THE MARKET FOR COMMON STOCK OF U.S. CORPORATIONS.

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

Item 1B. Unresolved Staff Comments

None.

Item 2. Properties

Contract Drilling Fleet

The following table provides certain information about the rigs in our drilling fleet by operating segment as of February 15, 2011:

Rig Name

Rig Type

Year Built/

Rebuilt

Design

Maximum

Water Depth/

Drilling Depth

Current

Location

Current

Customer

Deepwater

ENSCO 7500

Semisubmersible

2000

Dynamically Positioned

8,000'/30,000'

Singapore

Shipyard/mob/sea trials

ENSCO 8500

Semisubmersible

2008

Dynamically Positioned

8,500'/35,000'

Gulf of Mexico

Eni/Anadarko

ENSCO 8501

Semisubmersible

2009

Dynamically Positioned

8,500'/35,000'

Gulf of Mexico

Nexen/Noble Energy

ENSCO 8502

Semisubmersible(1)

2010

Dynamically Positioned

8,500'/35,000'

Gulf of Mexico

Nexen

ENSCO 8503

Semisubmersible(1)

2010

Dynamically Positioned

8,500'/35,000'

French Guiana

Mob/Tullow/Cobalt

ENSCO 8504

Semisubmersible(2)

2011

Dynamically Positioned

8,500'/35,000'

Singapore

Under construction(3)

ENSCO 8505

Semisubmersible(2)

2012

Dynamically Positioned

8,500'/35,000'

Singapore

Under construction(3)

ENSCO 8506

Semisubmersible(2)

2012

Dynamically Positioned

8,500'/35,000'

Singapore

Under construction(3)

Asia Pacific

ENSCO 52

Jackup

1983/1997

F&G L-780 MOD II-C

300'/25,000'

Malaysia

Petronas Carigali

ENSCO 53

Jackup

1982/2009

F&G L-780 MOD II-C

300'/25,000'

Malaysia

Talisman

ENSCO 54

Jackup

1982/1997

F&G L-780 MOD II-C

300'/25,000'

U.A.E.

ADOC/Bunduq

ENSCO 56

Jackup

1982/1997

F&G L-780 MOD II-C

300'/25,000'

Indonesia

Pertamina

ENSCO 67

Jackup

1976/2005

MLT 84-CE

400'/30,000'

Indonesia

Pertamina

ENSCO 76

Jackup

2000

MLT Super 116-C

350'/30,000'

Saudi Arabia

Saudi Aramco

ENSCO 84

Jackup

1981/2005

MLT 82 SD-C

250'/25,000'

Bahrain

Cold stacked

ENSCO 88

Jackup

1982/2004

MLT 82 SD-C

250'/25,000'

Qatar

Ras Gas

ENSCO 94

Jackup

1981/2001

Hitachi 250-C

250'/25,000'

Qatar

Ras Gas

ENSCO 95

Jackup

1981/2005

Hitachi 250-C

250'/25,000'

Bahrain

Cold stacked

ENSCO 96

Jackup

1982/1997

Hitachi 250-C

250'/25,000'

Bahrain

Available

ENSCO 97

Jackup

1980/1997

MLT 82 SD-C

250'/25,000'

Bahrain

Available

ENSCO 104

Jackup

2002

KFELS MOD V-B

400'/30,000'

Indonesia

ConocoPhillips

ENSCO 106

Jackup

2005

KFELS MOD V-B

400'/30,000'

Malaysia

Petronas Carigali

ENSCO 107

Jackup

2006

KFELS MOD V-B

400'/30,000'

Vietnam

Premier Oil

ENSCO 108

Jackup

2007

KFELS MOD V-B

400'/30,000'

Brunei

Total

ENSCO 109

Jackup

2008

KFELS MOD V- Super B

350'/35,000'

Australia

Apache

ENSCO I

Barge

1999

Barge

--/18,000'

Singapore

Cold stacked

TBD 1

Jackup(2)

2013

KFELS Super A

400'/40,000'

Singapore

Under construction(3)

TBD 2

Jackup(2)

2013

KFELS Super A

400'/40,000'

Singapore

Under construction(3)

Europe and Africa

ENSCO 70

Jackup

1981/1996

Hitachi K1032N

250'/30,000'

Denmark

Maersk

ENSCO 71

Jackup

1982/1995

Hitachi K1032N

225'/25,000'

Denmark

Maersk

ENSCO 72

Jackup

1981/1996

Hitachi K1025N

225'/25,000'

United Kingdom

RWE

ENSCO 80

Jackup

1978/1995

MLT 116-CE

225'/30,000'

United Kingdom

Sterling

ENSCO 85

Jackup

1981/1995

MLT 116-C

300'/25,000'

Tunisia

Available

ENSCO 92

Jackup

1982/1996

MLT 116-C

225'/25,000'

United Kingdom

Available/contracted

ENSCO 100

Jackup

1987/2009

MLT 150-88-C

350'/30,000'

United Kingdom

Shipyard

ENSCO 101

Jackup

2000

KFELS MOD V-A

400'/30,000'

United Kingdom

Maersk

ENSCO 102

Jackup

2002

KFELS MOD V-A

400'/30,000'

United Kingdom

ConocoPhillips

ENSCO 105

Jackup

2002

KFELS MOD V-B

400'/30,000'

Tunisia

Available

Rig Name

Rig Type

Year Built/

Rebuilt

Design

Maximum

Water Depth/

Drilling Depth

Current

Location

Current

Customer

North & South America

ENSCO 68

Jackup

1976/2004

MLT 84-CE

400'/30,000'

Gulf of Mexico

Chevron

ENSCO 69

Jackup

1976/1995

MLT 84-Slot

300'/25,000'

Gulf of Mexico

Cold stacked

ENSCO 75

Jackup

1999

MLT Super 116-C

400'/30,000'

Gulf of Mexico

Apache

ENSCO 81

Jackup

1979/2003

MLT 116-C

350'/30,000'

Gulf of Mexico

Shipyard

ENSCO 82

Jackup

1979/2003

MLT 116-C

300'/30,000'

Gulf of Mexico

Chevron

ENSCO 83

Jackup

1979/2007

MLT 82 SD-C

250'/25,000'

Mexico

Pemex

ENSCO 86

Jackup

1981/2006

MLT 82 SD-C

250'/30,000'

Gulf of Mexico

Apache

ENSCO 87

Jackup

1982/2006

MLT 116-C

350'/25,000'

Gulf of Mexico

Apache

ENSCO 89

Jackup

1982/2005

MLT 82 SD-C

250'/25,000'

Mexico

Pemex

ENSCO 90

Jackup

1982/2002

MLT 82 SD-C

250'/25,000'

Gulf of Mexico

Stone

ENSCO 93

Jackup

1982/2008

MLT 82 SD-C

250'/25,000'

Mexico

Pemex

ENSCO 98

Jackup

1977/2003

MLT 82 SD-C

250'/25,000'

Mexico

Pemex

ENSCO 99

Jackup

1985/2005

MLT 82 SD-C

250'/30,000'

Gulf of Mexico

ExxonMobil

(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 subsequent to completion of drilling operations under their respective sublet agreements.

(2)

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

(3)

We are currently marketing ENSCO 8504, ENSCO 8505, ENSCO 8506 and two ultra-high specification harsh environment jackup rigs and anticipate they will be contracted in advance of delivery. For additional information on our rigs under construction, see "Cash Flow and Capital Expenditures" included in "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations."

The equipment on our drilling rigs includes engines, drawworks, derricks, pumps to circulate the drilling fluid, well control systems, drill string and related equipment. The engines power a top-drive mechanism that turns the drill string and drill bit so that the hole is drilled by grinding subsurface materials, which are then returned to the rig by the drilling fluid. The intended water depth, well depth and drilling conditions are the principal factors that determine the size and type of rig most suitable for a particular drilling project.

Jackup rigs stand on the ocean floor with their hull and drilling equipment elevated above the water on connected leg supports. Jackup rigs are generally preferred over other rig types in shallow water depths of 400 feet or less, primarily because jackup rigs provide a more stable drilling platform with above water well control equipment. Our jackup rigs are of the independent leg design where each leg can be fixed into the ocean floor at varying depths and equipped with a cantilever that allows the drilling equipment to extend outward from the hull over fixed platforms enabling safe drilling of both exploratory and development wells. The jackup rig hull supports the drilling equipment, jacking system, crew quarters, storage and loading facilities, helicopter landing pad and related equipment and supplies.

Semisubmersible rigs are floating offshore drilling units with pontoons and columns that partially submerge to a predetermined depth when sea water is permitted to enter the hull. Semisubmersible rigs can be held in a fixed location over the ocean floor either by being anchored to the sea bottom with mooring chains or dynamically positioned by computer-controlled propellers or "thrusters." ENSCO 7500, which is capable of drilling in water depths up to 8,000 feet, is a dynamically positioned rig that also can be adapted for moored operations. The rig uses a riser system to manage the drilling fluid and well control equipment located on the ocean floor. The ENSCO 8500 Series® rigs are enhanced versions of the ENSCO 7500, capable of drilling in up to 8,500 feet of water, and can be upgraded to 10,000 foot water-depth capability if required. Enhancements over ENSCO 7500 include a two million pound quad derrick, upgraded riser tensioning systems, offline pipe handling capability, increased drilling capacity, greater variable deck load, increased capacity in rig crew living quarters, improved automatic station keeping and the ability to modify the rig with an additional drilling platform. With these features, we believe the ENSCO 8500 Series® rigs are especially well-suited for deepwater development and exploratory well drilling.

Over the life of a typical rig, many of the major systems are replaced due to normal wear and tear or technological advancements in drilling equipment. All of our rigs are in good condition. As of February 15, 2011 we owned all of the rigs in our fleet.

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

Item 3. Legal Proceedings

Shareholder Class Actions

On February 10, 2011, a lawsuit styled Saratoga Advantage Trust vs. Pride International, Inc., et al, was filed in the Court of Chancery of the State of Delaware. This is a purported shareholder class action brought on behalf of the holders of Pride International, Inc. common stock against Pride, Pride’s directors and Ensco plc arising out of the proposed sale of Pride to Ensco in a stock and cash transaction valued at $41.60 per share of Pride common stock. The lawsuit alleges that the proposed transaction undervalues Pride’s shares, that Pride and the individual (director) defendants violated their fiduciary duties and that Ensco aided and abetted the breach of fiduciary duties. The lawsuit seeks injunctive relief, a declaration of breach of fiduciary duties, an order requiring the individual defendants to properly exercise their fiduciary duties, and a declaration that the proposed transaction is void or, if consummated, ordering rescission, and attorneys’ fees and costs. 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.

On February 11, 2011, similar actions were filed in the District Court of Harris County Texas styled Abrams v. Pride International, Inc., et al., and Astor BK Realty Trust v. Pride International, Inc. These also are purported shareholder class actions against Pride and its individual directors, which name ENSCO Ventures LLC and ENSCO International Incorporated as parties defendant. These actions generally allege that the defendants violated their fiduciary duties and seek to enjoin the proposed transaction unless and until Pride adopts and implements a procedure or process to obtain a transaction that provides the best possible terms and value for Pride’s shareholders and issues a statement containing full and accurate disclosure. The causes of action against the individual (director) defendants are based upon alleged breach of fiduciary duties and the causes of action against Pride and the Ensco entities are based upon aiding and abetting such breaches of fiduciary duties. The prayers for relief seek to enjoin the defendants from consummating the proposed transaction unless and until the individual (directors) defendants adopt and implement the aforesaid procedure or process, a declaration that the transaction is void or, if consummated, rescinded, monetary damages as well as costs, fees and expenses. At this time, we are unable to predict the outcome of these matters or estimate the extent to which we may be exposed to any resulting liability.

On February 17, 2011, a similar action was filed in the Court of Chancery of the State of Delaware styled Elizabeth Wiggs-Jacques vs. Pride International, Inc., et al. This also is a purported shareholder class action against Pride and its individual directors, which names ENSCO International Incorporated and ENSCO Ventures LLC as parties defendant. This lawsuit generally alleges that the defendants violated their fiduciary duties and that the proposed merger is unfair to Pride’s stockholders. The causes of action against the individual (director) defendants are based upon alleged breach of fiduciary duties and the causes of action against Pride and the Ensco entities are based upon aiding and abetting such breaches of fiduciary duties. The prayer for relief generally seeks to enjoin the defendants from consummating the proposed transaction unless and until Pride adopts and implements a procedure or process to obtain the highest possible price or, if consummated, rescind the transaction or award monetary damages, as well as costs, fees and expenses. 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 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 actions. We expect to receive a determination by the United States Department of Justice in the near-term.

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 March 2009, the sunken rig hull of ENSCO 74 was located approximately 95 miles from the original drilling location when it was struck by the oil tanker SKS Satilla. 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.

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

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

On September 18, 2009, Sea Robin Pipeline Company, LLC, commenced civil litigation against us in the Fifteenth Judicial Court for the Parish of Lafayette and in the Nineteenth Judicial Court for the Parish of Baton Rouge, State of Louisiana seeking unspecified damages in relation to the cost of repairing damage to the pipeline, loss of revenues, survey and other damages. Based on information currently available, we have concluded that it is remote that a liability exists with respect to this matter.

The owners of two other subsea pipelines have also presented claims filed on behalf of Stingray Pipeline Company, LLC, and Tennessee Gas Pipeline seeking monetary damages incurred by reason of damage to pipelines allegedly caused by ENSCO 74 during Hurricane Ike. The Stingray claim is in the amount of $14.0 million, and the Tennessee Gas Pipeline claim is for unspecified damages. Based on information currently available, we have concluded that it is remote that liabilities exist with respect to these matters.

We filed a petition for exoneration or limitation of liability under U.S. admiralty and maritime law in the U.S. District Court for the Southern District of Texas on September 2, 2009. The petition seeks exoneration from or limitation of liability for any and all injury, loss or damage caused, occasioned or occurred in relation to the ENSCO 74 loss in September 2008. The exoneration/limitation proceedings currently include the tanker claim and the four pipeline claims described above, which effectively supersedes their prior civil litigation filings. 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.

ENSCO 69

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

By letter dated September 30, 2009, legal counsel acting for the package policy underwriters denied coverage under the package policy and reserved rights. On March 15, 2010, underwriters commenced litigation in the U.K. High Court of Justice, Commercial Court, for purposes of enforcing mediation under the disputes clause of our package policy and precluding us from pursuing litigation in the United States. On that date, we commenced litigation styled ENSCO International Incorporated vs. Certain Underwriters at Lloyds, et al, in the District Court, Dallas County, Texas 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.

On April 26, 2010, we obtained a temporary injunction from the Texas Court that effectively prohibits the insurance underwriters from pursuing litigation they filed in the U.K. On July 27, 2010, we agreed with underwriters to submit the matter to arbitration, which will be held in Houston, Texas. The U.K. litigation has been dismissed and the Dallas District Court litigation has been stayed. Until these proceedings are concluded, there can be no assurances as to the ultimate outcome. See Note 11 to our consolidated financial statements 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 to range from $5.0 million to $15.0 million. Our property insurance policies include coverage for ENSCO 29 wreckage and debris removal costs up to $3.8 million. We also have liability insurance policies that provide specified coverage for wreckage and debris removal costs in excess of the $3.8 million coverage provided under our property insurance policies.

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

Asbestos Litigation

During 2004, we and certain current and former subsidiaries were named as defendants, along with numerous other third-party companies as co-defendants, in three multi-party lawsuits filed in the Circuit Courts of Jones County (Second Judicial District) and Jasper County (First Judicial District), Mississippi. The lawsuits sought an unspecified amount of monetary damages on behalf of individuals alleging personal injury or death, primarily under the Jones Act, purportedly resulting from exposure to asbestos on drilling rigs and associated facilities during the period 1965 through 1986.

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

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.

The three cases removed from state court have been assigned to the Multi-District Litigation 875, which is currently before the U.S. District Court for the Eastern District of Pennsylvania. Although actions were taken by the plaintiffs in these three cases to bring the cases back to Mississippi state court, the U.S. District Court denied the plaintiffs' motion by order dated December 10, 2009.

We were recently notified that the Houston firm representing the plaintiffs in all 65 claims had dissolved effective as of November 30, 2010. Currently, the plaintiffs are represented by local Mississippi counsel, and we expect that additional counsel located in Tyler, Texas, will be entering as counsel of record. The impact, if any, of the substitution of counsel is unknown at this time.

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.

Other Matters

On July 9, 2010, Ensco Offshore Company, a subsidiary of Ensco plc filed suit in the U.S. District Court for the Eastern District of Louisiana in New Orleans against the U.S. Department of the Interior, the U.S. Bureau of Ocean Energy Management, Regulation and Enforcement ("BOEM") and other defendants seeking a ruling that the defendants violated the U.S. Administrative Procedures Act and the Outer Continental Shelf Lands Act by imposing a six-month deepwater drilling moratorium in the U.S. Gulf of Mexico, by imposing new substantive safety and certification requirements for both shallow-water and deepwater drilling in the U.S. Gulf of Mexico without following the required notice-and-comment procedures and by unreasonably delaying approval of applications to drill in the U.S. Gulf of Mexico. The complaint was amended on July 20, 2010 to address the actions taken by the U.S. Department of the Interior on July 12, 2010 to impose a second moratorium/suspension that generally applied to deepwater drilling in the U.S. Gulf of Mexico and documentary and permitting requirements with respect to both shallow-water and deepwater development and production drilling and related activities in the U.S. Gulf of Mexico that lack proper legislative authorization. We filed a motion to amend the complaint again on December 22, 2010.

The lawsuit continues to seek a more well-defined regulatory process for instituting new safety measures and operational and permitting requirements for U.S. Gulf of Mexico shallow-water and deepwater offshore drilling so as to comply with the U.S. Administrative Procedures Act and the Outer Continental Shelf Lands Act. On September 29, 2010, a partial summary judgment motion was heard in the U.S. District Court for the Eastern District of Louisiana. The court granted Ensco’s motion for summary judgment as to Count III (challenging the validity of NTL-5) and dismissed its claims regarding the first and second moratorium (Counts I and II) on the grounds of mootness due to the U.S. Government’s decision to purportedly terminate the second moratorium on the same day (October 12, 2010) as the final briefs were submitted.

Following a hearing held on January 12, 2011, our motion for reconsideration of the dismissal of Counts I and II was denied, both our motion for an injunction addressing Count IV (unreasonable delay in processing permits) and the government’s motion to dismiss or for summary judgment on that count and on Counts V and VI (relating to documentary and permitting requirements for development and production activities) were denied, and the government’s opposition to our motion to file a new amended complaint (which, inter alia, adds ATP Oil & Gas Corporation as a co-plaintiff) was denied. The judge also ordered that the matter be brought to trial expeditiously and moved the trial date from July 25, 2011 to May 16, 2011. On February 17, 2011, the Court rescinded and vacated its previous order and granted Ensco's motion for a preliminary injunction compelling the BOEM to process five pending drilling permit applications related to Ensco rigs within 30 days. There can be no assurances as to the ultimate outcome of these proceedings.

During 2009, we filed arbitration claims with the Financial Industry Regulatory Authority (“FINRA”) alleging fraud, conflict of interest and breach of contract against Citigroup Global Markets, Inc. and Merrill Lynch, Pierce, Fenner & Smith, Inc. and breach of contract against Jefferies & Company, Inc. and Oppenheimer & Co., Inc. in connection with the sale of certain auction rate securities to us for the aggregate remaining principal amount of $50.1 million. Since the filing of these claims, Oppenheimer has repurchased, at par value, all of the auction rate securities purchased through them. The claims against Jefferies were heard in November 2010 by an arbitration panel appointed by FINRA, which concluded that Ensco was not entitled to recover the damages which were sought. Currently, the claims against Merrill Lynch are scheduled to be heard commencing in April 2011. There can be no assurances as to the outcomes of our remaining outstanding claims.

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

Item 4. Removed and Reserved

PART II

Item 5.

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

Market Information

The following table provides the high and low sales price of shares of common stock, U.S. $.10 par value, Ensco Delaware until December 22, 2009 and of our ADSs thereafter for each period indicated during the last two fiscal years:

	First Quarter	Second Quarter	Third Quarter	Fourth Quarter	Year

2010 High	$46.98	$52.32	$47.28	$53.93	$53.93
2010 Low	$37.45	$33.33	$38.91	$43.08	$33.33

2009 High	$32.37	$42.47	$43.14	$51.30	$51.30
2009 Low	$22.04	$25.05	$32.26	$39.73	$22.04

Our ADSs are traded on the NYSE with the ticker symbol "ESV." We had 975 holders of record of our ADSs on February 1, 2011.

Dividends

We began paying a $.025 per share quarterly cash dividend during the third quarter of 1997 and continued to pay this quarterly dividend through March 31, 2010. During the second quarter of 2010, the Board of Directors of Ensco plc declared a regular quarterly cash dividend of $.35 per share, and we have continued to pay this quarterly cash dividend through December 31, 2010. Cash dividends totaling $1.075 and $.10 per share were paid during 2010 and 2009, respectively. We currently intend to continue paying quarterly dividends for the foreseeable future. However, our Board of Directors may change the timing and amount of payment of dividends on our shares depending on several factors including our profitability, liquidity, financial condition, reinvestment opportunities and capital requirements.

Exchange Controls

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

U.K. Taxation

The following paragraphs are intended to be a general guide to current U.K. tax law and HMRC practice applying as of the date of this report (both of which are subject to change at any time, possibly with retrospective effect) in respect of the taxation of capital gains, the taxation of dividends paid by Ensco plc and stamp duty and SDRT on the transfer of Class A ordinary shares, uncertificated ADSs and ADSs evidenced by American depositary receipts ("ADRs"). In addition, the following paragraphs relate only to persons who are beneficial owners of the ADSs ("ADS holders").

These paragraphs may not relate to certain classes of holders of the ADSs, such as employees or directors of Ensco plc or its affiliates, persons who are connected with Ensco plc, insurance companies, charities, collective investment schemes, pension schemes or persons who hold ADSs other than as an investment, or U.K. resident individuals who are not domiciled in the U.K.

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

U.K. Taxation of Dividends

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

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

The rate of U.K. income tax which is payable with respect to dividends received by higher rate taxpayers in the tax year 2010/2011 is 32.5%. Individuals whose total income subject to income tax exceeds £150,000 will be subject to income tax in respect of dividends in excess of that amount at the rate of 42.5% in the tax year 2010/2011. An individual's dividend income is treated as the top slice of their total income which is subject to income tax. Individual ADS holders who are resident in the U.K. will be entitled to a tax credit equal to one-ninth of the amount of the dividend received from Ensco plc, which will be taken into account in computing the gross amount of the dividend which is subject to income tax. The tax credit will be credited against the ADS holder's liability (if any) to income tax on the gross amount of the dividend. An individual ADS holder who is not subject to U.K. income tax on dividends received from Ensco plc will not be entitled to claim payment of the tax credit in respect of such dividends. The right to a tax credit for an individual ADS holder who is not resident in the U.K. will depend on his or her individual circumstances.

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

The full rate of corporation tax payable with respect to dividends received from Ensco plc in financial year 2011 is 27%, although small companies may be entitled to claim the small companies rate of tax. If dividends paid by Ensco plc fall within an exemption from U.K. corporation tax set out in Part 9A of the U.K. Corporation Tax Act 2009, the receipt of the dividend by a corporate ADS holder will be exempt from U.K. corporation tax. Generally, the conditions for exemption from U.K. corporation tax on dividends paid by Ensco plc should be satisfied, although the conditions which must be satisfied in any particular case will depend on the individual circumstances of the corporate ADS holders.

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

U.K. Taxation of Capital Gains

U.K. Withholding Tax - Capital gains accruing to non-U.K. resident ADS holders on the disposal of ADSs will not be subject to any withholding or deduction for or on account of U.K. tax, irrespective of the residence or the individual circumstances of the ADS holders.

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

An individual ADS holder who is neither resident nor ordinarily resident in the U.K. will not be subject to U.K. capital gains tax on capital gains arising on the disposal of their ADSs unless the ADS holder carries on a trade, profession or vocation in the U.K. through a branch or agency in the U.K. and the ADSs were acquired, used in or for the purposes of the branch or agency or used in or for the purposes of the trade, profession or vocation carried on by the ADS holder through the branch or agency. In these circumstances, the non-U.K. resident ADS holder may, depending on his or her individual circumstances, be subject to U.K. capital gains tax on taxable gains arising from a disposal of their ADSs. The rate of U.K. capital gains tax on taxable gains is 28% in the tax year 2010/2011.

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

The full rate of U.K. corporation tax on taxable gains in the financial year 2011 is 27%, although small companies may be entitled to claim the small companies rate of tax. Corporate ADS holders will be entitled to an indexation allowance in computing the amount of a taxable gain accruing on a disposal of the ADSs, which will provide relief for the effects of inflation by reference to movements in the U.K. retail price index. If the conditions of the substantial shareholding exemption set out in s.192A and Schedule 7AC of the U.K. Taxation of Chargeable Gains Act 1992 are satisfied in relation to a taxable gain accruing to a corporate ADS holder, the taxable gain will be exempt from U.K. corporation tax.

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

U.K. Stamp Duty and Stamp Duty Reserve Tax

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

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

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

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

Equity Compensation Plans

For information on shares issued or to be issued in connection with our equity compensation plans, see "Part III, Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters."

Issuer Purchases of Equity Securities

The following table provides a summary of our repurchases of our ADSs during the quarter ended December 31, 2010:

			Total Number	Approximate
			of ADSs	Dollar Value
			Purchased as	of ADSs that
	Total		Part of Publicly	May Yet Be
	Number of		Announced	Purchased
	ADSs	Average Price	Plans or	Under Plans
Period	Purchased	Paid per ADS	Programs	or Programs

October 1 - October 31	862	$44.92	--	$562,000,000
November 1 - November 30	1,481	$49.24	--	$562,000,000
December 1 - December 31	2,062	$49.92	--	$562,000,000
Total	4,405	$48.71	--

During the quarter ended December 31, 2010, repurchases of our ADSs were primarily made by an affiliated employee benefit trust from employees and non-employee directors in connection with the settlement of income tax withholding obligations arising from the vesting of share awards. Such ADSs remain available for reissuance in connection with employee and non-employee director share awards.

The Board of Directors of Ensco Delaware previously authorized the repurchase of up to $1,500.0 million of our 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 our 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.

The chart below presents a comparison of the five-year cumulative total return, assuming $100 invested on December 31, 2005 and the reinvestment of dividends, for our shares, the Standard & Poor's 500 Stock Price Index and the Dow Jones U.S. Oil Equipment & Services Index.*

	Cumulative Total Return
		12/05	12/06	12/07	12/08	12/09	12/10

Ensco plc		100.00	113.12	134.96	64.40	90.88	124.61
S & P 500		100.00	115.80	122.16	76.96	97.33	111.99
Dow Jones U.S. Oil Equipment & Services		100.00	113.47	164.47	66.94	110.56	140.78

*	$100 invested on December 31, 2005 in shares or index, including reinvestment of dividends for fiscal year ending December 31.

Item 6. Selected Financial Data

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

	Year Ended December 31,
	2010		2009		2008		2007		2006
	(in millions, except per share amounts)
Consolidated Statement of Income Data
Revenues	$1,696.8		$1,888.9		$2,242.6		$1,899.3		$1,632.6
Operating expenses
Contract drilling (exclusive of depreciation)	768.1		709.0		736.3		613.4		519.8
Depreciation	216.3		189.5		172.6		165.5		155.0
General and administrative	86.1		64.0		53.8		59.5		44.6
Operating income	626.3		926.4		1,279.9		1,060.9		913.2
Other income (expense), net	18.2		8.8		(4.2	)	37.8		(5.9	)
Provision for income taxes	96.0		180.0		222.4		235.1		225.7
Income from continuing operations	548.5		755.2		1,053.3		863.6		681.6
Income from discontinued operations, net(1)	37.4		29.3		103.4		135.3		93.6
Cumulative effect of accounting change, net(2)	--		--		--		--		.6
Net income	585.9		784.5		1,156.7		998.9		775.8
Net income attributable to noncontrolling interests	(6.4	)	(5.1	)	(5.9	)	(6.9	)	(6.1	)
Net income attributable to Ensco	$ 579.5		$ 779.4		$1,150.8		$ 992.0		$ 769.7
Earnings per share – basic
Continuing operations	$ 3.80		$ 5.28		$ 7.32		$ 5.80		$ 4.42
Discontinued operations	.26		.20		.72		.91		.61
Cumulative effect of accounting change	--		--		--		--		.00
	$ 4.06		$ 5.48		$ 8.04		$ 6.71		$ 5.03
Earnings per share - diluted
Continuing operations	$ 3.80		$ 5.28		$ 7.31		$ 5.78		$ 4.40
Discontinued operations	.26		.20		.71		.91		.61
Cumulative effect of accounting change	--		--		--		--		.00
	$ 4.06		$ 5.48		$ 8.02		$ 6.69		$ 5.01
Net income attributable to Ensco shares
Basic	$ 572.1		$ 769.7		$1,138.2		$ 984.7		$ 765.4
Diluted	$ 572.1		$ 769.7		$1,138.2		$ 984.7		$ 765.4
Weighted-average shares outstanding
Basic	141.0		140.4		141.6		146.7		152.2
Diluted	141.0		140.5		141.9		147.2		152.8
Cash dividends per share	$ 1.075		$ .10		$ .10		$ .10		$ .10

Consolidated Balance Sheet and Cash Flow Statement Data
Working capital	$1,087.7	$1,167.9	$ 973.0	$ 625.8	$ 602.3
Total assets	7,051.5	6,747.2	5,830.1	4,968.8	4,334.4
Long-term debt, net of current portion	240.1	257.2	274.3	291.4	308.5
Ensco shareholders' equity	5,959.5	5,499.2	4,676.9	3,752.0	3,216.0
Cash flow from continuing operations	816.7	1,185.6	1,014.7	1,094.3	847.8

(1)

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

(2)

On January 1, 2006, we recognized a cumulative adjustment related to the adoption of certain provisions of FASB ASC 718.

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.

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 North and South America region 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

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.

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.

Asia Pacific

During the first half of 2008, Asia Pacific jackup rig utilization remained high and day rates stabilized as strong rig demand was offset by new rig deliveries. During the latter half of 2008, jackup rig demand was significantly impacted by the decline in oil and natural gas prices and the deterioration of the global economy, resulting in a significant reduction in utilization and day rates during 2009. The Asia Pacific 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, Asia Pacific jackup rig utilization and day rates may remain under pressure in the near-term.

Europe and Africa

Our Europe and Africa offshore drilling operations are mainly conducted in Northern Europe. During 2008, shortfalls in rig availability in this region 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 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 in the region. However, with limited tender activity for work beginning in early 2011 and an excess supply of standard duty jackup rigs, Europe and Africa jackup rig utilization and day rates may remain under pressure in the near-term.

North and South America

A significant portion of our North and South America offshore drilling 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 North and South America 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

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 utilization and average day rates of our Europe and Africa and Asia Pacific jackup rig fleets coupled with a decline in average day rates of our North and South America jackup rig fleet, partially offset by a significant increase in revenues and operating income generated by our ultra-deepwater semisubmersible rig fleet.

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

As discussed below, we manage our business through four operating segments. Our jackup rigs are mobile and occasionally move between operating segments in response to market conditions and contract opportunities. The following table summarizes our offshore drilling rigs by segment and rigs under construction as of December 31, 2010, 2009 and 2008:

	2010	2009	2008

Deepwater(1)	5	3	2
Asia Pacific(2)	18	17	17
Europe and Africa	10	10	10
North and South America	13	13	13
Under construction(1)	3	5	6
Total(3)	49	48	48

(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 July 2010, we acquired an ultra-high specification jackup rig. The rig was renamed ENSCO 109 and is currently operating offshore Australia.

(3)

The total number of rigs for each period excludes rigs reclassified to discontinued operations.

The following table summarizes our rig utilization and average day rates from continuing operations by operating segment for each of the years in the three-year period ended December 31, 2010:

	2010	2009	2008

Rig utilization(1)
Deepwater	81%	85%	95%
Asia Pacific(3)	71%	74%	95%
Europe and Africa	71%	77%	96%
North and South America(4)	90%	72%	97%
Total	77%	75%	96%
Average day rates(2)
Deepwater	$375,098	$425,190	$334,688
Asia Pacific(3)	112,601	142,894	148,214
Europe and Africa	129,914	198,595	221,164
North and South America(4)	83,818	120,230	104,282
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)		ENSCO I, the only barge rig in our fleet, is currently cold-stacked in Singapore and has been excluded from rig utilization and average day rates for our Asia Pacific operating segment.
(4)		ENSCO 69 has been excluded from rig utilization and average day rates for our North and South America 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 operating segment, are provided below.

Operating Income

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 is not allocated to our operating segments for purposes of measuring segment operating income and were included in "Reconciling Items."

Year Ended December 31, 2010

				North
			Europe	and	Operating
		Asia	And	South	Segments	Reconciling	Consolidated
	Deepwater	Pacific	Africa	America	Total	Items	Total

Revenues	$475.2	$502.2	$341.2	$378.2	$1,696.8	$ --	$1,696.8
Operating expenses Contract drilling (exclusive of depreciation)	176.1	234.2	191.5	166.3	768.1	--	768.1
Depreciation	44.8	75.9	47.5	46.8	215.0	1.3	216.3
General and administrative	--	--	--	--	--	86.1	86.1
Operating income (loss)	$254.3	$192.1	$102.2	$165.1	$ 713.7	$(87.4)	$ 626.3

Year Ended December 31, 2009

				North
			Europe	and	Operating
		Asia	And	South	Segments	Reconciling	Consolidated
	Deepwater	Pacific	Africa	America	Total	Items	Total

Revenues	$254.1	$645.0	$569.1	$420.7	$1,888.9	$ --	$1,888.9
Operating expenses Contract drilling (exclusive of depreciation)	108.1	219.3	208.8	172.8	709.0	--	709.0
Depreciation	22.2	74.1	44.5	47.4	188.2	1.3	189.5
General and administrative	--	--	--	--	--	64.0	64.0
Operating income (loss)	$123.8	$351.6	$315.8	$200.5	$ 991.7	$(65.3)	$ 926.4

Year Ended December 31, 2008

				North
			Europe	and	Operating
		Asia	And	South	Segments	Reconciling	Consolidated
	Deepwater	Pacific	Africa	America	Total	Items	Total

Revenues	$ 84.4	$869.6	$804.1	$484.5	$2,242.6	$ --	$2,242.6
Operating expenses Contract drilling (exclusive of depreciation)	31.2	269.4	246.7	189.0	736.3	--	736.3
Depreciation	9.1	72.0	43.0	46.6	170.7	1.9	172.6
General and administrative	--	--	--	--	--	53.8	53.8
Operating income (loss)	$ 44.1	$528.2	$514.4	$248.9	$1,335.6	$(55.7)	$1,279.9

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.

Asia Pacific

During 2010, Asia Pacific revenues declined by $142.8 million, or 22%, as compared to the prior year. The decline in revenues was primarily due to a 21% decline in average day rates and a decline in utilization to 71% from 74% during the prior year, due to lower levels of spending by oil and gas companies and excess rig availability in the region. Contract drilling expense increased by $14.9 million, or 7%, as compared to the prior year, primarily due to a $12.2 million loss on impairment of ENSCO I, our only barge rig. Depreciation expense increased by 2% as compared to the prior year, primarily due to the addition of ENSCO 109 to our Asia Pacific fleet during the third quarter of 2010.

During 2009, Asia Pacific revenues declined by $224.6 million, or 26%, as compared to the prior year. The decline in revenues was primarily due to a decline in utilization to 74% from 95% during the prior year. The decline in utilization occurred due to lower levels of spending by oil and gas companies and excess rig availability in the region. Contract drilling expense declined by $50.1 million, or 19%, as compared to the prior year, primarily due to the impact of lower utilization and a decline in repair and maintenance expense. Depreciation expense increased by 3% as compared to the prior year, primarily due to a capital enhancement project on ENSCO 53 completed during the second quarter of 2009 and depreciation on minor upgrades and improvements to our Asia Pacific fleet completed during 2008 and 2009.

Europe and Africa

During 2010, Europe and Africa revenues declined by $227.9 million, or 40%, as compared to the prior year. The decline in revenues was primarily due to a 35% decline in average day rates and a decline in utilization to 71% from 77% during the prior year, due to lower levels of spending by oil and gas companies and excess rig availability in the region. Contract drilling expense declined by $17.3 million, or 8%, as compared to the prior year, primarily due to a decline in repair and maintenance expense and personnel costs. Depreciation expense increased by 7% due to a capital enhancement project on ENSCO 100 completed during the fourth quarter of 2009 and depreciation on minor upgrades and improvements to our Europe and Africa fleet completed during 2010.

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

North and South America

During 2010, North and South America revenues declined by $42.5 million, or 10%, as compared to the prior year. The decline in revenues was primarily due to a 30% decline in average day rates, partially offset by an increase in utilization to 90% from 72% in the prior year. The increase in utilization 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 $6.5 million, or 4%, as compared to the prior year, primarily due to a $17.3 million loss recorded on the disposal of ENSCO 69 during 2009, 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 was comparable to the prior year.

During 2009, North and South America revenues declined by $63.8 million, or 13%, as compared to the prior year. The decline in revenues was primarily due to a decline in utilization to 72% from 97% during the prior year, partially offset by a 15% increase in average day rates. The decline in utilization occurred due to lower levels of spending by oil and gas companies in the U.S. Gulf of Mexico. The increase in average day rates was largely due to the relocation of ENSCO 83, ENSCO 89, ENSCO 93 and ENSCO 98 to Mexico and ENSCO 68 to Venezuela, where day rates are generally higher than the U.S. Gulf of Mexico. Contract drilling expense declined by $16.2 million, or 9%, as compared to the prior year, primarily due to the impact of decreased utilization 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 2% as compared to the prior year due to capital enhancement projects on ENSCO 89 and ENSCO 93 completed during the second quarter of 2009, a capital enhancement project on ENSCO 98 completed during the third quarter of 2009 and depreciation on minor upgrades and improvements to our North and South America fleet completed during 2008 and 2009.

Other

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.

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 North and South America 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 Asia Pacific 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 Asia Pacific 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 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.

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 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.

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.

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.

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.

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.

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.

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.

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

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 four operating segments represent our reporting units. In most instances, our calculation of the fair value of our reporting units is based on estimates of future discounted cash flows to be generated by our drilling rigs, which reflect management's judgments and assumptions regarding the appropriate risk-adjusted discount rate, as well as future industry conditions and operations, including expected utilization, day rates, expense levels, capital requirements and terminal values for each of our rigs. Due to the inherent uncertainties associated with these estimates, we perform sensitivity analysis on key assumptions as part of our goodwill impairment test.

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

If the estimated fair value of a reporting unit exceeds its carrying value, its goodwill is considered not impaired. If the estimated fair value of a reporting unit is less than its carrying value, we estimate the implied fair value of the reporting unit's goodwill. If the carrying amount of the reporting unit's goodwill exceeds the implied fair value of the goodwill, an impairment loss is recognized in an amount equal to such excess. In the event we dispose of drilling rig operations that constitute a business, goodwill would be allocated in the determination of gain or loss on disposal. Based on our annual goodwill impairment test performed as of December 31, 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.

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.

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.

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

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

Item 8. Financial Statements and Supplementary Data

MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

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

February 24, 2011

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

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

ENSCO PLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

(in millions, except per share amounts)

	Year Ended December 31,
	2010			2009		2008

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

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 LIABILITIES
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 SHAREHOLDERS' 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.

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.

ENSCO PLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

Business

We are one of the leading providers of offshore contract drilling services to the international oil and gas industry. We have one of the largest and most capable offshore drilling rig fleets in the world comprised of 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.

Pending Merger with Pride

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.

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.

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.

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.

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.

Cash Equivalents and Short-Term Investments

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

Property and Equipment

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

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

We evaluate the carrying value of our property and equipment for impairment when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. For property and equipment used in our operations, recoverability is generally determined by comparing the 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.

Goodwill

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

Deepwater					$143.6
Asia Pacific					84.6
Europe and Africa					61.4
North and South America					46.6
Total					$336.2

Goodwill is not allocated to operating segments in the measure of segment assets regularly reported to and used by management. No goodwill was acquired or disposed of during the three-year period ended December 31, 2010.

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.

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.

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.

Income Taxes

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

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

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

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

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

Share-Based Compensation

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

Fair Value Measurements

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.

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 assets and liabilities.

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	)
Net 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.

Noncontrolling Interests

Noncontrolling interests are classified as equity on our consolidated balance sheet and net income attributable to noncontrolling interests is presented separately on our consolidated statement of income. In our Asia Pacific operating segment, local third parties hold a noncontrolling ownership interest in three of our subsidiaries.

Income 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 progress 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.

3. LONG-TERM INVESTMENTS

As of 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.

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 million 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%.

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

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.

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.

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

7. SHAREHOLDERS' EQUITY

Activity in our various 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

BALANCE, December 31, 2007	180.3	$18.0	$1,700.5	$2,977.5		$ (4.2)	$(939.8)	$ 4.6
Net income	--	--	--	1,150.8		--	--	5.9
Cash dividends paid	--	--	--	(14.3	)	--	--	--
Distributions to noncontrolling interests	--	--	--	--		--	--	(3.8)
Shares issued under share-based compensation
plans, net	1.6	.2	27.1	--		--	--	--
Tax benefit from share-based
compensation	--	--	5.3	--		--	--	--
Repurchase of shares	--	--	--	--		--	(259.7)	--
Share-based compensation cost	--	--	28.3	--		--	--	--
Net other comprehensive loss	--	--	--	--		(12.8)	--	--
BALANCE, December 31, 2008	181.9	18.2	1,761.2	4,114.0		(17.0)	(1,199.5)	6.7
Net income	--	--	--	779.4		--	--	5.1
Cash dividends paid	--	--	--	(14.2	)	--	--	--
Distributions to noncontrolling interests	--	--	--	--		--	--	(3.9)
Shares issued under share-based compensation
plans, net	.9	.1	9.5	--		--	--	--
Tax deficiency from share-based
compensation	--	--	(2.4)	--		--	--	--
Repurchase of shares	--	--	--	--		--	(6.5)	--
Retirement of treasury shares	(40.2)	(4.0)	(1,200.0)	--		--	1,203.9	--
Share-based compensation cost	--	--	34.3	--		--	--	--
Net other comprehensive income	--	--	--	--		22.2	--	--
Cancellation of shares of common stock during redomestication	(142.6)	(14.3)	--	--		--	--	--
Issuance of ordinary shares pursuant to the redomestication	150.1	15.1	--	--		--	(.8)	--
BALANCE, December 31, 2009	150.1	15.1	602.6	4,879.2		5.2	(2.9)	7.9
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

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.

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.

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.

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

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

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

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
Exercise 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.

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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.

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.

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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

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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

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.

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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 North and South America operating segment.

ENSCO 69

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

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

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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ENSCO 74 Loss

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.

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ENSCO 69

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.

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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.

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

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 is not allocated to our operating segments for purposes of measuring segment operating income and were included in "Reconciling Items." Assets not allocated to our operating segments were also included in "Reconciling Items." As of December 31, 2010, 2009 and 2008, total asset reconciling items consisted primarily of cash and cash equivalents and goodwill.

Year Ended December 31, 2010

				North
			Europe	and	Operating
		Asia	and	South	Segments	Reconciling	Consolidated
	Deepwater	Pacific	Africa	America	Total	Items	Total

Revenues	$ 475.2	$ 502.2	$341.2	$378.2	$1,696.8	$ --	$1,696.8
Operating expenses Contract drilling (exclusive of depreciation)	176.1	234.2	191.5	166.3	768.1	--	768.1
Depreciation	44.8	75.9	47.5	46.8	215.0	1.3	216.3
General and administrative	--	--	--	--	--	86.1	86.1
Operating income (loss)	$ 254.3	$ 192.1	$102.2	$165.1	$ 713.7	$ (87.4)	$ 626.3
Total assets	$3,068.2	$1,285.1	$857.8	$715.1	$5,926.2	$1,125.3	$7,051.5
Capital expenditures	632.5	196.4	39.4	2.9	871.2	4.1	875.3

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Year Ended December 31, 2009

				North
			Europe	and	Operating
		Asia	and	South	Segments	Reconciling	Consolidated
	Deepwater	Pacific	Africa	America	Total	Items	Total

Revenues	$ 254.1	$ 645.0	$569.1	$420.7	$1,888.9	$ --	$1,888.9
Operating expenses Contract drilling (exclusive of depreciation)	108.1	219.3	208.8	172.8	709.0	--	709.0
Depreciation	22.2	74.1	44.5	47.4	188.2	1.3	189.5
General and administrative	--	--	--	--	--	64.0	64.0
Operating income (loss)	$ 123.8	$ 351.6	$315.8	$200.5	$ 991.7	$ (65.3)	$ 926.4
Total assets	$2,444.6	$1,290.6	$779.9	$856.0	$5,371.1	$1,376.1	$6,747.2
Capital expenditures	644.4	42.1	66.2	101.8	854.5	2.7	857.2

Year Ended December 31, 2008

				North
			Europe	and	Operating
		Asia	and	South	Segments	Reconciling	Consolidated
	Deepwater	Pacific	Africa	America	Total	Items	Total

Revenues	$ 84.4	$ 869.6	$804.1	$484.5	$2,242.6	$ --	$2,242.6
Operating expenses Contract drilling (exclusive of depreciation)	31.2	269.4	246.7	189.0	736.3	--	736.3
Depreciation	9.1	72.0	43.0	46.6	170.7	1.9	172.6
General and administrative	--	--	--	--	--	53.8	53.8
Operating income (loss)	$ 44.1	$ 528.2	$514.4	$248.9	$1,335.6	$ (55.7)	$1,279.9
Total assets	$1,759.9	$1,327.7	$806.7	$773.1	$4,667.4	$1,162.7	$5,830.1
Capital expenditures	657.8	34.8	22.7	46.2	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 Asia Pacific operating segment consisted of 17 jackup rigs and one barge rig deployed in various locations throughout Asia, the Middle East and Australia. Our Europe and Africa operating segment consisted of eight jackup rigs deployed in various territorial waters of the North Sea and two jackup rigs located offshore Tunisia. Our North and South America operating segment consisted of eight jackup rigs located in the U.S. Gulf of Mexico and five jackup rigs located offshore Mexico.

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.

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

117

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

118

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

119

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.

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

Not applicable.

Item 9A. Controls and Procedures

CONCLUSION REGARDING THE EFFECTIVENESS OF DISCLOSURE CONTROLS AND PROCEDURES

Based on their evaluation as of the end of the period covered by this Annual Report on Form 10-K, our Chief Executive Officer and Chief Financial Officer have concluded that our disclosure controls and procedures, as defined in Rule 13a-15 under the Securities Exchange Act of 1934 (the "Exchange Act"), are effective.

During the fiscal quarter ended December 31, 2010, there were no changes in our internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

See "Item 8. Financial Statements and Supplementary Data" for Management's Report on Internal Control Over Financial Reporting.

Item 9B. Other Information

Not applicable.

120

PART III

Item 10. Directors, Executive Officers and Corporate Governance

The information required by this item with respect to our directors, corporate governance matters and committees of the Board of Directors is contained in our Proxy Statement for the Annual General Meeting of Shareholders ("the Proxy Statement") to be filed with the Commission not later than 120 days after the end of our fiscal year ended December 31, 2010 and incorporated herein by reference.

The information required by this item with respect to our executive officers is set forth in "Executive Officers" in Part I of this Annual Report on Form 10-K.

Information with respect to Section 16(a) of the Exchange Act is included under "Section 16(a) Beneficial Ownership Reporting Compliance" in our Proxy Statement and is incorporated herein by reference.

The guidelines and procedures of the Board of Directors are outlined in our Corporate Governance Policy. The committees of the Board of Directors operate under written charters adopted by the Board of Directors. The Corporate Governance Policy and committee charters are available on our website at www.enscoplc.com in the Corporate Governance section and are available in print without charge by contacting our Investor Relations Department at 214-397-3045.

We have a Code of Business Conduct Policy that applies to all employees, including our principal executive officer, principal financial officer and controller. The Code of Business Conduct Policy is available on our website at www.enscoplc.com in the Corporate Governance section and is available in print without charge by contacting our Investor Relations Department. We intend to disclose any amendments to or waivers from our Code of Business Conduct Policy by posting such information on our website. Our Proxy Statement contains governance disclosures, including information on our Code of Business Conduct Policy, the Ensco Corporate Governance Policy, the director nomination process, shareholder director nominations, shareholder communications to the Board of Directors and director attendance at the Annual General Meeting of Shareholders.

Item 11. Executive Compensation

The information required by this item is contained in our Proxy Statement and incorporated herein by reference.

121

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters

The following table summarizes certain information related to our compensation plans under which our shares are authorized for issuance as of December 31, 2010:

					Number of securities
					remaining available for
	Number of securities				future issuance under
	to be issued upon		Weighted-average		equity compensation
	exercise of		exercise price of		plans (excluding
	outstanding options,		outstanding options,		securities reflected
Plan category	warrants and rights		warrants and rights		in column (a))(1)
	(a)		(b)		(c)
Equity compensation plans approved by security holders		1,321,316		$47.52		4,085,725
Equity compensation plans not approved by security holders(2)		98		23.12		--
Total		1,321,414		$47.52		4,085,725

(1)		Under the LTIP, 4.1 million shares remained available for future issuances of equity awards as of December 31, 2010. Of the 4.1 million shares authorized for future issuances, 4.1 million are authorized for future option issuances, 2.3 million are authorized for future issuances of non-vested share awards and 2.5 million are authorized for future issuances for the payment of performance awards. Our performance award grants may be settled in Ensco shares, cash or a combination thereof.
(2)		In connection with the acquisition of Chiles Offshore Inc. ("Chiles") during 2002, we assumed Chiles' option plan and the outstanding options thereunder. As of December 31, 2010, options to purchase 98 shares, at a weighted-average exercise price of $23.12 per share, were outstanding under this plan. No shares are available for future issuance under this plan, no further options will be granted under this plan and the plan will be terminated upon the earlier of the exercise or expiration date of the last outstanding option.

Additional information required by this item is included in our Proxy Statement and incorporated herein by reference.

Item 13. Certain Relationships and Related Transactions, and Director Independence

The information required by this item is contained in our Proxy Statement and incorporated herein by reference.

Item 14. Principal Accounting Fees and Services

The information required by this item is contained in our Proxy Statement and incorporated herein by reference.

122

PART IV

Item 15. Exhibits, Financial Statement Schedules

(a)	The following documents are filed as part of this report:
	1. Financial Statements

	Reports of Independent Registered Public Accounting Firm	77
	Consolidated Statements of Income	79
	Consolidated Balance Sheets	80
	Consolidated Statements of Cash Flows	81
	Notes to Consolidated Financial Statements	82

2. Financial Statement Schedules:

		The schedules for which provision is made in the applicable accounting regulations of the SEC are not required under the related instructions or are inapplicable or provided elsewhere in the financial statements and, therefore, have been omitted.

3. Exhibits

123

Exhibit

No.

2.1

Agreement and Plan of Merger and Reorganization, dated as of November 9, 2009, between ENSCO International Incorporated and ENSCO Newcastle LLC (incorporated by reference to Annex A to the Registration Statement of ENSCO International Limited on Form S-4 (File No. 333-162975) filed on November 9, 2009).

2.2	-	Agreement and Plan of Merger by and among Ensco plc, Pride International, Inc., ENSCO International Incorporated, and ENSCO Ventures LLC, dated February 6, 2011 (incorporated by reference to Exhibit 2.1 to the Registrant's Current Report on Form 8-K filed on February 7, 2011, File No. 1-8097).
3.1	-	Articles of Association of Ensco International plc (incorporated by reference to Exhibit 99.1 to the Registrant's Current Report on Form 8-K filed on December 16, 2009, File No. 1-8097).

3.2

Certificate of Incorporation on Change of Name (incorporated by reference to Exhibit 3.1 to the Registrant's Current Report on Form 8-K filed on April 1, 2010, File No. 1-8097).

4.1

Deposit Agreement, dated as of September 29, 2009, by and among ENSCO International Limited, Citibank, N.A., as Depositary, and the holders and beneficial owners of American Depositary Shares issued thereunder (incorporated by reference to Exhibit 4.1 to the Registration Statement of ENSCO International Limited on Form S-4 (File No. 333-162975) filed on November 9, 2009).

4.2

Form of American Depositary Receipt for American Depositary Shares representing Deposited Class A Ordinary Shares of Ensco plc (incorporated by reference to Exhibit 4.1 to the Registrant's Current Report on Form 8-K filed on April 1, 2010, File No. 1-8097).

4.3

Indenture, dated November 20, 1997, between the Company and Bankers Trust Company, as Trustee (incorporated by reference to Exhibit 4.1 to the Registrant's Current Report on Form 8-K filed on November 24, 1997, File No. 1-8097).

4.4

First Supplemental Indenture, dated November 20, 1997, between the Company and Bankers Trust Company, as trustee, supplementing the Indenture dated as of November 20, 1997 (incorporated by reference to Exhibit 4.2 to the Registrant's Current Report on Form 8-K filed on November 24, 1997, File No. 1-8097).

4.5

Second Supplemental Indenture dated December 22, 2009, among ENSCO International Incorporated, Ensco International plc and Deutsche Bank Trust Company Americas, as trustee (incorporated by reference to Exhibit 4.1 to the Registrant's Current Report on Form 8-K filed on December 23, 2009, File No. 1-8097).

4.6

Form of Debenture (incorporated by reference to Exhibit 4.4 to the Registrant's Current Report on Form 8-K filed on November 24, 1997, File No. 1-8097).

124

4.7

In accordance with Item 601(b)(4)(iii)(A) of Regulation S-K, certain instruments as respects long-term debt of the Company have been omitted but will be furnished to the Commission upon request.

10.1

Second Amended and Restated Credit Agreement, dated as of May 28, 2010, among Ensco plc, ENSCO International Incorporated, ENSCO Universal Limited, and ENSCO Offshore International Company, as Borrowers, Ensco plc, ENSCO Global Limited, and ENSCO International Incorporated, as Guarantors, the Banks named therein, as Banks, Citibank, N.A., as Administrative Agent, Wells Fargo Bank, National Association and DnB NOR Bank ASA, as Syndication Agents, and Wells Fargo Bank, National Association, Citibank, N.A. and DnB NOR Bank ASA, each as an Issuing Bank (incorporated by reference to Exhibit 10.1 of the Registrant's Current Report on Form 8-K filed on June 3, 2010, File No. 1-8097).

10.2

Second Amended and Restated Guaranty, dated as of May 28, 2010, made by Ensco plc, ENSCO Global Limited, and ENSCO International Incorporated, as Guarantors, in favor of Citibank, N.A., as Administrative Agent under the Credit Agreement (incorporated by reference to Exhibit 10.2 of the Registrant's Current Report on Form 8-K filed on June 3, 2010, File No. 1-8097).

+10.3

ENSCO International Incorporated 1998 Incentive Plan (incorporated by reference to Exhibit 4.1 to the Registrant's Form S-8 filed on July 7, 1998, Registration No. 333-58625).

+10.4

Amendment to the ENSCO International Incorporated 1998 Incentive Plan (incorporated by reference to Exhibit 10.19 to the Registrant's Annual Report on Form 10-K for the year ended December 31, 2002, File No. 1-8097).

+10.5

Amendment to the ENSCO International Incorporated 1998 Incentive Plan (incorporated by reference to Exhibit 10.29 to the Registrant's Annual Report on Form 10-K for the year ended December 31, 2005, File No. 1-8097).

+10.6

Amendment to the ENSCO International Incorporated 1998 Incentive Plan, dated as of May 31, 2006 (incorporated by reference to Exhibit 10.4 to the Registrant's Quarterly Report on Form 10-Q for the quarter ended June 30, 2006, File No. 1-8097).

125

+10.7

Amendment to the ENSCO International Incorporated 1998 Incentive Plan, executed on December 22, 2009 and effective as of December 23, 2009 (incorporated by reference to Exhibit 10.4 to the Registrant's Current Report on Form 8-K filed on December 23, 2009, File No. 1-8097).

+10.8

ENSCO International Incorporated 2000 Stock Option Plan (formerly known as the Chiles Offshore Inc. 2000 Stock Option Plan) (incorporated by reference to Exhibit 4.6 to the Registrant's Registration Statement on Form S-8 filed on August 7, 2002, Registration No. 333-97757).

+10.9

Amendment No. 1 to the ENSCO International Incorporated 2000 Stock Option Plan (incorporated by reference to Exhibit 4.7 to the Registrant's Registration Statement on Form S-8 filed on August 7, 2002, Registration No. 333-97757).

+10.10

Amendment No. 2 to the ENSCO International Incorporated 2000 Stock Option Plan (incorporated by reference to Exhibit 4.8 to the Registrant's Registration Statement on Form S-8 filed on August 7, 2002, Registration No. 333-97757).

+10.11

Amendment No. 3 to the ENSCO International Incorporated 2000 Stock Option Plan (incorporated by reference to Exhibit 10.18 to the Registrant's Annual Report on Form 10-K for the year ended December 31, 2002, File No. 1-8097).

+10.12

Amendment No. 4 to the ENSCO International Incorporated 2000 Stock Option Plan, executed on December 22, 2009 and effective as of December 23, 2009 (incorporated by reference to Exhibit 10.5 to the Registrant's Current Report on Form 8-K filed on December 23, 2009, File No. 1-8097).

+10.13

ENSCO Non-Employee Director Deferred Compensation Plan (incorporated by reference to Exhibit 10.1 to the Registrant's Quarterly Report on Form 10-Q for the quarter ended September 30, 2003, File No. 1-8097).

+10.14

Amendment No. 1 to the ENSCO Non-Employee Director Deferred Compensation Plan, dated as of March 11, 2008 (incorporated by reference to Exhibit 10.3 to the Registrant's Quarterly Report on Form 10-Q for the quarter ended March 31, 2008, File No. 1-8097).

+10.15

Amendment No. 2 to the ENSCO Non-Employee Director Deferred Compensation Plan, dated August 4, 2009 (incorporated by reference to Exhibit 10.4 to the Registrant's Quarterly Report on Form 10-Q for the quarter ended September 30, 2009, File No. 1-8097).

+10.16

Amendment No. 3 to the ENSCO Non-Employee Director Deferred Compensation Plan, executed on December 22, 2009 and effective as of the dates indicated therein (incorporated by reference to Exhibit 10.11 to the Registrant's Current Report on Form 8-K filed on December 23, 2009, File No. 1-8097).

126

+10.17

ENSCO Supplemental Executive Retirement Plan, as amended and restated effective January 1, 2004 (incorporated by reference to Exhibit 10.2 to the Registrant's Quarterly Report on Form 10-Q for the quarter ended September 30, 2003, File No. 1-8097).

+10.18

Amendment No. 1 to the ENSCO Supplemental Executive Retirement Plan (As Amended and Restated Effective January 1, 2004), dated as of March 11, 2008 (incorporated by reference to Exhibit 10.1 to the Registrant's Quarterly Report on Form 10-Q for the quarter ended March 31, 2008, File No. 1-8097).

+10.19

Amendment No. 2 to the ENSCO Supplemental Executive Retirement Plan (As Amended and Restated effective January 1, 2004), dated November 4, 2008 (incorporated by reference to Exhibit 10.57 to the Registrant's Annual Report on Form 10-K for the year ended December 31, 2008, File No. 1-8097).

+10.20

Amendment No. 3 to the ENSCO Supplemental Executive Retirement Plan (As Amended and Restated Effective January 1, 2004), dated August 4, 2009 (incorporated by reference to Exhibit 10.2 to the Registrant's Quarterly Report on Form 10-Q for the quarter ended September 30, 2009, File No. 1-8097).

+10.21

Amendment No. 4 to the ENSCO Supplemental Executive Retirement Plan (As Amended and Restated Effective January 1, 2009), executed on December 22, 2009 and effective as of the dates indicated therein (incorporated by reference to Exhibit 10.10 to the Registrant's Current Report on Form 8-K filed on December 23, 2009, File No. 1-8097).

+10.22

ENSCO Supplemental Executive Retirement Plan and Non-Employee Director Deferred Compensation Plan Trust Agreement, as revised and restated effective January 1, 2004 (incorporated by reference to Exhibit 10.3 to the Registrant's Quarterly Report on Form 10-Q for the quarter ended September 30, 2003, File No. 1-8097).

+10.23

ENSCO 2005 Non-Employee Director Deferred Compensation Plan, effective January 1, 2005 (incorporated by reference to Exhibit 99.2 to the Registrant's Current Report on Form 8-K filed on January 5, 2005, File No. 1-8097).

+10.24

Amendment No. 1 to the ENSCO 2005 Non-Employee Director Deferred Compensation Plan, dated as of March 11, 2008 (incorporated by reference to Exhibit 10.4 to the Registrant's Quarterly Report on Form 10-Q for the quarter ended March 31, 2008, File No. 1-8097).

127

+10.25

Amendment No. 2 to the ENSCO 2005 Non-Employee Director Deferred Compensation Plan, dated as of November 4, 2008 (incorporated by reference to Exhibit 10.60 to the Registrant's Annual Report on Form 10-K for the year ended December 31, 2008, File No. 1-8097).

+10.26

Amendment No. 3 to the ENSCO 2005 Non-Employee Director Deferred Compensation Plan, dated August 4, 2009 (incorporated by reference to Exhibit 10.5 to the Registrant's Quarterly Report on Form 10-Q for the quarter ended September 30, 2009, File No. 1-8097).

+10.27

Amendment No. 4 to the ENSCO 2005 Non-Employee Director Deferred Compensation Plan, executed on December 22, 2009 and effective as of December 23, 2009 (incorporated by reference to Exhibit 10.9 to the Registrant's Current Report on Form 8-K filed on December 23, 2009, File No. 1-8097).

+10.28

ENSCO 2005 Supplemental Executive Retirement Plan (As Amended and Restated effective January 1, 2005), dated November 4, 2008 (incorporated by reference to Exhibit 10.56 to the Registrant's Annual Report on Form 10-K for the year ended December 31, 2008, File No. 1-8097).

+10.29

Amendment No. 1 to the ENSCO 2005 Supplemental Executive Retirement Plan (As Amended and Restated Effective January 1, 2005), dated August 4, 2009 (incorporated by reference to Exhibit 10.3 to the Registrant's Quarterly Report on Form 10-Q for the quarter ended September 30, 2009, File No. 1-8097).

+10.30

Amendment No. 2 to the ENSCO 2005 Supplemental Executive Retirement Plan (As Amended and Restated Effective January 1, 2005) dated November 3, 2009 (incorporated by reference to Exhibit 10.31 to the Registrant's Annual Report on Form 10-K for the year ended December 31, 2009, File No. 1-8097).

+10.31

Amendment No. 3 to the ENSCO 2005 Supplemental Executive Retirement Plan (As Amended and Restated Effective January 1, 2005), executed on December 22, 2009 and effective as of December 23, 2009 (incorporated by reference to Exhibit 10.8 to the Registrant's Current Report on Form 8-K filed on December 23, 2009).

+10.32

ENSCO 2005 Benefit Reserve Trust, effective January 1, 2005 (incorporated by reference to Exhibit 99.3 to the Registrant's Current Report on Form 8-K filed on January 5, 2005, File No. 1-8097).

*+10.33

ENSCO International Incorporated Savings Plan (As Revised and Restated Effective January 1, 2002), incorporating Amendments Nos. 1 - 17 dated November 18, 2010.

128

+10.34

Amended and Restated Trust Deed with respect to the Trust to be known as The Ensco Multinational Savings Plan between Ensco International Incorporated (as Plan Sponsor) and Citco Trustees (Cayman) Limited (as Original Trustee), dated February 16, 2009 (incorporated by reference to Exhibit 10.61 to the Registrant's Annual Report on Form 10-K for the year ended December 31, 2008, File No. 1-8097).

+10.35

Deed of Amendment to the Ensco Multinational Savings Plan between Citco Trustees (Cayman) Limited (as Trustee) and ENSCO International Incorporated (as Plan Sponsor), dated August 4, 2009 (incorporated by reference to Exhibit 10.6 to the Registrant's Quarterly Report on Form 10-Q for the quarter ended September 30, 2009, File No. 1-8097).

+10.36

Deed of Amendment No. 2 to the Ensco Multinational Savings Plan, executed as of December 21, 2009 and effective as of December 23, 2009 (incorporated by reference to Exhibit 10.2 to the Registrant's Current Report on Form 8-K filed on December 23, 2009, File No. 1-8097).

*+10.37

Deed of Amendment No. 3 to the Ensco Multinational Savings Plan, dated as of November 4, 2010.

+10.38

Deed of Assumption, dated December 22, 2009, executed by Ensco International plc (incorporated by reference to Exhibit 10.1 to the Registrant's Current Report on Form 8-K filed on December 23, 2009, File No. 1-8097).

+10.39

ENSCO International Incorporated 2005 Long-Term Incentive Plan (As Revised and Restated on December 22, 2009 and As Assumed by Ensco International plc as of December 23, 2009, including Annex 1 and Annex 2 thereto) (incorporated by reference to Exhibit 10.3 to the Registrant's Current Report on Form 8-K filed on December 23, 2009, File No. 1-8097).

+10.40

Form of ENSCO International Incorporated 2005 Long-Term Incentive Plan Performance Unit Award Agreement Terms and Conditions (incorporated by reference to Exhibit 10.7 to the Registrant's Current Report on Form 8-K filed on November 6, 2009, File No. 1-8097).

+10.41

Form of Ensco Performance-Based Long-Term Incentive Award Summary (incorporated by reference to Exhibit 10.6 to the Registrant's Current Report on Form 8-K filed on November 6, 2009, File No. 1-8097).

+10.42

ENSCO International Incorporated 2005 Cash Incentive Plan, effective January 1, 2005 (incorporated by reference to Exhibit C to the Registrant's Definitive Proxy Statement filed on March 21, 2005, File No. 1-8097).

+10.43

Amendment to the ENSCO International Incorporated 2005 Cash Incentive Plan, dated as of May 21, 2008 (incorporated by reference to Exhibit 10.2 to the Registrant's Quarterly Report on Form 10-Q for the quarter ended June 30, 2008, File No. 1-8097).

129

+10.44

Second Amendment to the ENSCO International Incorporated 2005 Cash Incentive Plan, dated as of November 4, 2008 (incorporated by reference to Exhibit 10.59 to the Registrant's Annual Report on Form 10-K for the year ended December 31, 2008, File No. 1-8097).

+10.45

2009 Performance Criteria for Named Executive Officers under the ENSCO 2005 Cash Incentive Plan (incorporated by reference to “Compensation Discussion and Analysis - Executive Officer Compensation Philosophy - ECIP Cash Bonus” in the Registrant's Definitive Proxy Statement filed on April 5, 2010, File No. 1-8097).

+10.46

ENSCO International Incorporated Form of Indemnification Agreement with Non-Employee Directors (incorporated by reference to Exhibit 10.1 to the Registrant's Current Report on Form 8-K filed on November 6, 2009, File No. 1-8097).

+10.47

ENSCO International Incorporated Form of Indemnification Agreement with Executive Officers (incorporated by reference to Exhibit 10.2 to the Registrant's Current Report on Form 8-K filed on November 6, 2009, File No. 1-8097).

+10.48

ENSCO International Incorporated Form of Indemnification Agreement with Daniel W. Rabun (incorporated by reference to Exhibit 10.3 to the Registrant's Current Report on Form 8-K filed on November 6, 2009, File No. 1-8097).

+10.49

ENSCO International Incorporated Form of Indemnification Agreement with John Mark Burns (incorporated by reference to Exhibit 10.4 to the Registrant's Current Report on Form 8-K filed on November 6, 2009, File No. 1-8097).

+10.50

Form of Indemnification Agreement of ENSCO International Incorporated (incorporated by reference to Exhibit 10.12 to the Registrant's Current Report on Form 8-K filed on December 23, 2009, File No. 1-8097).

+10.51

Form of Deed of Indemnity of Ensco International plc (incorporated by reference to Exhibit 10.13 to the Registrant's Current Report on Form 8-K filed on December 23, 2009, File No. 1-8097).

+10.52

Employment Offer Letter Agreement dated January 13, 2006 and accepted on February 6, 2006 between the Company and Daniel W. Rabun (incorporated by reference to Exhibit 10.1 to the Registrant's Current Report on Form 8-K filed on February 6, 2006, File No. 1-8097).

+10.53

Amendment to the Employment Offer Letter Agreement between ENSCO International Incorporated and Daniel W. Rabun, dated December 22, 2009 (incorporated by reference to Exhibit 10.15 to the Registrant's Current Report on Form 8-K filed on December 23, 2009, File No. 1-8097).

130

+10.54

Amendment and Restatement of the Letter Agreement between ENSCO International Incorporated and William S. Chadwick, Jr., dated December 22, 2009 (incorporated by reference to Exhibit 10.14 to the Registrant's Current Report on Form 8-K filed on December 23, 2009, File No. 1-8097).

+10.55

Employment Offer Letter dated May 19, 2008 and accepted on May 22, 2008 between the Registrant and Mark Burns (incorporated by reference to Exhibit 10.3 to the Registrant's Quarterly Report on Form 10-Q for the quarter ended June 30, 2008, File No. 1-8097).

+10.56

Employment Offer Letter dated June 23, 2008 and accepted July 22, 2008 between the Registrant and Carey Lowe (incorporated by reference to Exhibit 10.1 to the Registrant's Quarterly Report on Form 10-Q for the quarter ended September 30, 2008, File No. 1-8097).

+10.57

Summary of Changes in Compensation of Non-Employee Directors, effective June 1, 2009 (incorporated by reference to Exhibit 10.1 to the Registrant's Quarterly Report on Form 10-Q for the quarter ended June 30, 2009, File No. 1-8097).

+10.58

Retirement Agreement dated February 28, 2007 between the Company and Carl F. Thorne (incorporated by reference to Exhibit 10.1 to the Registrant's Current Report on Form 8-K filed on February 28, 2007, File No. 1-8097).

+10.59	-	Summary of Relocation Benefits of Certain Executive Officers (incorporated by reference to Item 5.02 to the Registrant's Current Report on Form 8-K filed on December 1, 2009, File No. 1-8097).
10.60	-	Bridge Commitment Letter among Ensco plc, Deutsche Bank AG Cayman Islands Branch, Deutsche Bank Securities Inc. and Citigroup Global Markets Inc. dated February 6, 2011 (incorporated by reference to Exhibit 99.1 to the Registrant's Current Report on Form 8-K filed on February 7, 2011, File No. 1-8097).

*21.1

Subsidiaries of the Registrant.

*23.1

Consent of Independent Registered Public Accounting Firm.

**31.1

Certification of the Chief Executive Officer of Registrant pursuant to Rule 13a-14 or 15d-14 of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

**31.2

Certification of the Chief Financial Officer of Registrant pursuant to Rule 13a-14 or 15d-14 of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

131

**32.1

Certification of the Chief Executive Officer of Registrant pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

**32.2

Certification of the Chief Financial Officer of Registrant pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

**101.INS

XBRL Instance Document

**101.SCH

XBRL Taxonomy Extension Schema

**101.CAL

XBRL Taxonomy Extension Calculation Linkbase

**101.DEF

XBRL Taxonomy Extension Definition Linkbase

**101.LAB

XBRL Taxonomy Extension Label Linkbase

**101.PRE

XBRL Taxonomy Extension Presentation Linkbase

Filed herewith

Furnished herewith

Management contracts or compensatory plans and arrangements required to be filed as exhibits pursuant to Item 15(b) of this report.

Certain agreements relating to our long-term debt have not been filed as exhibits as permitted by paragraph (b)(4)(iii)(A) of Item 601 of Regulation S-K since the total amount of securities authorized under any such agreements do not exceed 10% of our total assets on a consolidated basis. Upon request, we will furnish to the SEC all constituent agreements defining the rights of holders of our long-term debt not filed herewith.

132

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized, on February 24, 2011.

		Ensco plc (Registrant)

		By /s/ DANIEL W. RABUN Daniel W. Rabun Chairman, President and Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the Registrant and in the capacities and on the date indicated.

Signatures	Title	Date

/s/ DANIEL W. RABUN Daniel W. Rabun	Chairman, President and Chief Executive Officer	February 24, 2011

/s/ J. RODERICK CLARK J. Roderick Clark	Director	February 24, 2011

/s/ C. CHRISTOPHER GAUT C. Christopher Gaut	Director	February 24, 2011

/s/ GERALD W. HADDOCK Gerald W. Haddock	Director	February 24, 2011

/s/ THOMAS L. KELLY II Thomas L. Kelly II	Director	February 24, 2011

/s/ KEITH O. RATTIE Keith O. Rattie	Director	February 24, 2011

/s/ RITA M. RODRIGUEZ Rita M. Rodriguez	Director	February 24, 2011

/s/ PAUL E. ROWSEY, III Paul E. Rowsey, III	Director	February 24, 2011

/s/ JAMES W. SWENT III James W. Swent III	Senior Vice President and Chief Financial Officer	February 24, 2011

/s/ DAVID A. ARMOUR David A. Armour	Vice President - Finance	February 24, 2011

/s/ DOUGLAS J. MANKO Douglas J. Manko	Controller and Assistant Secretary	February 24, 2011

133