Edgar Filing: Ensco plc

form10k2011.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, 2011

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 x 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 x

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 x 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 x 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 x Accelerated filer o

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

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

Yes o No x

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, 2011 of $53.30) of Ensco plc held by nonaffiliates of the registrant at that date was approximately $10,436,891,000.

As of February 17, 2012, there were 231,049,272 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 2012 General Meeting of Shareholders are incorporated by reference into Part III of this report.



TABLE OF CONTENTS


PART I	ITEM 1.	BUSINESS	4
	ITEM 1A.	RISK FACTORS	13
	ITEM 1B.	UNRESOLVED STAFF COMMENTS	35
	ITEM 2.	PROPERTIES	36
	ITEM 3.	LEGAL PROCEEDINGS	38
	ITEM 4.	MINE SAFETY DISCLOSURES	42


PART II	ITEM 5.	MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED SHAREHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES	43
	ITEM 6.	SELECTED FINANCIAL DATA	48
	ITEM 7.	MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	50
	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	133
	ITEM 9A.	CONTROLS AND PROCEDURES	133
	ITEM 9B.	OTHER INFORMATION	133


PART III	ITEM 10.	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE	134
	ITEM 11.	EXECUTIVE COMPENSATION	134
	ITEM 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED SHAREHOLDER MATTERS	135
	ITEM 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE	135
	ITEM 14.	PRINCIPAL ACCOUNTING FEES AND SERVICES	135

PART IV

ITEM 15.

EXHIBITS, FINANCIAL STATEMENT SCHEDULES

SIGNATURES

136

149

EXPLANATORY NOTE

On May 31, 2011 (the "Merger Date"), Ensco plc completed a merger transaction (the "Merger") with Pride International, Inc., a Delaware corporation ("Pride"), ENSCO International Incorporated, a Delaware corporation and an indirect, wholly-owned subsidiary and predecessor of Ensco plc ("Ensco Delaware"), and ENSCO Ventures LLC, a Delaware limited liability company and an indirect, wholly-owned subsidiary of Ensco plc ("Merger Sub"). Pursuant to the Agreement and Plan of Merger, dated as of February 6, 2011 (as amended, the "Merger Agreement"), among Ensco plc, Pride, Ensco Delaware and Merger Sub, and subject to the conditions set forth therein, Merger Sub merged with and into Pride, with Pride as the surviving entity and an indirect, wholly-owned subsidiary of Ensco plc.

In connection with the integration of Pride’s operations, we are in the process of changing the names of most of Pride’s fleet in accordance with our naming convention. For purposes of this annual report, we used the new names whether or not the name change had been legally completed. For a list of the new and old rig names, see the most recent Fleet Status Report posted in the Investor Relations section of our website at www.enscoplc.com. Information contained on our website is not included as part of, or incorporated by reference into, this report.

FORWARD-LOOKING STATEMENTS

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

Such statements are subject to numerous risks, uncertainties and assumptions that may cause actual results to vary materially from those indicated, including:

•

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

•

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

•

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

•

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

•

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

•

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

•

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

•

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

•

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

•

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

•

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

•

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

•

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

•

delays in actual contract commencement dates;

	•	adverse changes in foreign currency exchange rates, including their effect on the fair value measurement of our derivative instruments;
	•	potential long-lived asset or goodwill impairments; and

•

the additional risks, uncertainties and assumptions described in "Item 1A. Risk Factors" in Part I and in "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" in Part II of this Form 10-K.

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

PART I

Item 1. Business

General

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

We are one of the leading providers of offshore contract drilling services to the international oil and gas industry. We own and operate an offshore drilling rig fleet of 77 rigs, including rigs under construction, spanning most of the strategic, high-growth markets around the globe. Our rig fleet includes seven drillships, 13 dynamically positioned semisubmersible rigs, seven moored semisubmersible rigs, 49 jackup rigs and one barge rig. Our fleet is the world's second largest amongst competitive rigs, our ultra-deepwater fleet is the newest in the industry and our active premium jackup fleet is the largest of any offshore drilling company. We currently have a technologically-advanced drillship, a semisubmersible rig and three ultra-premium harsh environment jackup rigs under construction as part of our ongoing strategy to continually expand and high-grade our fleet.

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

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

Acquisitions

We have assembled one of the largest and most capable offshore drilling rig fleets in the world. We have grown our rig fleet through corporate acquisitions, rig acquisitions and new rig construction. A total of seven drillships, including rigs under construction, 12 semisubmersibles rigs and 34 jackup rigs in our current fleet were obtained through the acquisitions of Penrod Holding Corporation during 1993, Dual Drilling Company during 1996, Chiles Offshore Inc. during 2002 and Pride International, Inc. during 2011. During 2010, we acquired ENSCO 109, an ultra-high specification jackup rig constructed in 2008.

On May 31, 2011 (the "Merger Date"), Ensco plc completed a merger transaction (the "Merger") with Pride International, Inc., a Delaware corporation ("Pride"), ENSCO International Incorporated, a Delaware corporation and an indirect, wholly-owned subsidiary and predecessor of Ensco plc ("Ensco Delaware"), and ENSCO Ventures LLC, a Delaware limited liability company and an indirect, wholly-owned subsidiary of Ensco plc ("Merger Sub"). Pursuant to the merger agreement and subject to the conditions set forth therein, Merger Sub merged with and into Pride, with Pride as the surviving entity and an indirect, wholly-owned subsidiary of Ensco plc. The total consideration delivered in the Merger was $7.4 billion, consisting of $2.8 billion of cash, 85.8 million Ensco ADSs with an aggregate value of $4.6 billion based on the closing price of Ensco ADSs of $53.32 on the Merger Date and the estimated fair value of $35.4 million of vested Pride employee stock options assumed by Ensco.

Drilling Rig Construction and Delivery

We continue to maintain our long-established strategy of high-grading our jackup rig fleet by investing in newer equipment while expanding the size and quality of our deepwater drilling rig fleet. During the five-year period ended December 31, 2011, we invested $2.6 billion in the construction of new drilling rigs.

During 2007, we completed construction of ENSCO 108, an ultra-high specification jackup rig. In February 2011, we entered into agreements with Keppel FELS Limited ("KFELS") to construct two ultra-high specification harsh environment jackup rigs (ENSCO 120 and ENSCO 121). We also entered into an agreement with KFELS in October 2011 to construct a third jackup rig of the same design (ENSCO 122). These rigs are scheduled for delivery during the first and second half of 2013 and the second half of 2014, respectively. ENSCO 120 is committed under a long-term drilling contract in the North Sea, while the other two jackup rigs under construction are uncontracted.

We 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, which are capable of drilling in up to 8,500 feet of water. ENSCO 8500 and ENSCO 8501 were delivered during 2008 and 2009, respectively, and commenced drilling operations under long-term contracts in the U.S. Gulf of Mexico during 2009. ENSCO 8502 was delivered and commenced drilling operations under a long-term contract in the U.S. Gulf of Mexico during 2010. ENSCO 8503 was delivered in 2010 and commenced drilling operations in French Guiana under a short-term sublet agreement during the first quarter of 2011. ENSCO 8503 is expected to commence drilling operations under a long-term contract in the U.S. Gulf of Mexico during the first quarter of 2012. ENSCO 8504 was delivered and commenced drilling operations under a long-term contract in Brunei during the third quarter of 2011. ENSCO 8505 was delivered in January 2012 and is expected to commence drilling operations under a long-term contract in the U.S. Gulf of Mexico during the second quarter of 2012. We also have remaining one ENSCO 8500 Series® ultra-deepwater semisubmersible rig under construction (ENSCO 8506), which is committed under a long-term drilling contract in the U.S. Gulf of Mexico and scheduled for delivery in the second half of 2012.

In connection with the Merger, we acquired seven drillships, two of which were under construction. These newbuild drillships are based on a Samsung Heavy Industries proprietary hull design capable of drilling in water depths of up to 10,000 feet of water. ENSCO DS-6 was delivered in January 2012, and we expect it will be committed under a long-term drilling contract in the near-term. We also have remaining one uncontracted ultra-deepwater drillship under construction (DS-7), with a scheduled delivery date in the second half of 2013.

Divestitures

Our business strategy has been to focus on deepwater, midwater and premium jackup rig assets and operations, and de-emphasize other assets and operations considered to be non-core or that do not meet our standards for financial performance. Accordingly, we sold our marine transportation service vessel fleet, two platform rigs and two barge rigs during 2003. We sold one jackup rig and two platform rigs to KFELS during 2004 in connection with the execution of the ENSCO 107 construction agreement. We disposed of six barge rigs and two platform rigs during 2005 and our last remaining platform rig during 2006. Consistent with this strategy, we sold four jackup rigs during 2010 and one jackup rig during 2011.

Redomestication

Our predecessor, Ensco Delaware, was formed as a Texas corporation during 1975 and reincorporated in Delaware during 1987. In December 2009, we completed the reorganization of the corporate structure of the group of companies controlled by Ensco Delaware, pursuant to which an indirect, wholly-owned subsidiary merged with Ensco Delaware, and Ensco plc became our publicly-held parent company incorporated under English law (the "redomestication"). 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 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) 20 7659 4660. Our website is located at www.enscoplc.com. Information contained on our website is not included as part of, or incorporated by reference into, this report.

Contract Drilling Operations

In connection with the Merger, we acquired seven drillships, including rigs under construction, 12 semisubmersible rigs and seven jackup rigs. As a result, we evaluated our core assets and operations, and organized them into three segments based on water depth operating capabilities. Accordingly, we determined our business to consist of three reportable segments: (1) Deepwater, which consists of our drillships and semisubmersible rigs capable of drilling in water depths of 4,500 feet or greater, (2) Midwater, which consists of our semisubmersible rigs capable of drilling in water depths of 4,499 feet or less and (3) Jackup, which consists of our jackup rigs capable of drilling in water depths up to 400 feet.

We currently own and operate an offshore drilling rig fleet of 77 rigs, including rigs under construction. Our expanded rig fleet includes seven drillships, 13 dynamically positioned semisubmersible rigs, seven moored semisubmersible rigs, 49 jackup rigs and one barge rig. Of our 77 rigs, 20 are located in the North and South America region (excluding Brazil), 11 are located in Brazil, nine are located in the Europe and Mediterranean region, 17 are located in the Middle East and Africa region and 20 are located in the Asia Pacific rim region.

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,

	•	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.

In addition, some of our drilling contracts permit early termination of the contract by the customer for convenience (without cause), generally exercisable upon advance notice and in some cases without making an early termination payment to us.

Financial information regarding our operating segments and geographic regions is presented in Note 14 to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data." Additional financial information regarding our operating segments is presented in "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations."

Backlog Information

Our contract drilling backlog reflects firm commitments, typically represented by signed drilling contracts, and was calculated by multiplying the contracted operating day rate by the firm contract period. The contracted operating day rate excludes certain types of non-recurring revenues for rig mobilization, demobilization, contract preparation, other customer reimbursables, bonus opportunities and amortization of drilling contract intangibles (as discussed in Note 2 to our consolidated financial statements) included in “Item 8. Financial Statements and Supplementary Data.”

The following table summarizes our contract backlog of business as of December 31, 2011 and 2010 (in millions):

	2011(*)		2010(*)

Deepwater	$7,076	.8	$1,723	.4
Midwater	558	.7		--
Jackup	1,909	.9	1,345	.3
Other	120	.8		--
Total	$9,666	.2	$3,068	.7

(*)

Backlog includes drilling contracts signed after each respective balance sheet date but prior to filing each of our annual reports on Form 10-K on February 24, 2012 and February 24, 2011, respectively.

Our Deepwater, Midwater and Other segment backlog increased by $5.4 billion, $558.7 million and $120.8 million, respectively, primarily due to the Merger and recent long-term contracts executed in our Deepwater segment for ENSCO 8504, ENSCO 8505 and ENSCO 8506; partially offset by revenues realized during 2011 in our Deepwater segment. Our Jackup segment backlog increased by $564.6 million, primarily due to new contract additions in our Europe, Middle East and Asia Pacific Rim markets and the addition of backlog in connection with the Merger, partially offset by revenues realized during 2011. The following table summarizes our contract backlog of business as of December 31, 2011 and the periods in which such revenues are expected to be realized (in millions):

	2012 (*)		2013		2014		2015 and Beyond		Total

Deepwater	$2,397	.9	$2,083	.9	$1,271	.3	$1,323	.8	$7,076	.8
Midwater	338	.6	220	.1		--		--	558	.7
Jackup	1,076	.2	447	.1	263	.7	122	.9	1,909	.9
Other	43	.3	35	.6	35	.6	6	.2	120	.8
Total	$3,856	.0	$2,786	.7	$1,570	.6	$1,452	.9	$9,666	.2

(*)

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 2011, Petrobras represented 16% of our consolidated revenues 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 also are factors. We have numerous competitors in the offshore contract drilling industry that have significant resources.

Governmental Regulation

Our operations are affected by political developments and by laws and regulations that relate directly to the oil and gas industry, including laws and regulations that have or may impose increased financial responsibility and oil spill abatement contingency plan capability requirements. Accordingly, we will be directly affected by the approval and adoption of laws and regulations curtailing exploration and development drilling for oil and natural gas for economic, environmental, safety or other policy reasons. It is also possible that these laws and regulations could adversely affect our operations in the future by significantly increasing our operating costs. See "Item 1A. Risk Factors - Increasing regulatory complexity could adversely impact the costs associated with our offshore drilling operations."

Environmental Matters

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

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

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

Non-U.S. Operations

Revenues from non-U.S. operations were 73%, 75% and 86% of our total consolidated revenues during 2011, 2010 and 2009, respectively. Our non-U.S. operations and shipyard rig construction and enhancement projects are subject to political, economic and other uncertainties, including:

	•	terrorist acts, war and civil disturbances,
	•	expropriation, nationalization, deprivation or confiscation of our equipment,
	•	expropriation or nationalization of a customer's property or drilling rights,

	•	repudiation or nationalization of contracts,
	•	assaults on property or personnel,

	•	piracy, kidnapping and extortion demands,
	•	significant governmental influence over many aspects of local economies,
	•	unexpected changes in law and regulatory requirements, including changes in interpretation or enforcement of existing laws,
	•	work stoppages,
	•	complications associated with repairing and replacing equipment in remote locations,
	•	limitations on insurance coverage, such as war risk coverage, in certain areas,
	•	imposition of trade barriers,
	•	wage and price controls,
	•	import-export quotas,
	•	exchange restrictions,
	•	currency fluctuations,
	•	changes in monetary policies,
	•	uncertainty or instability resulting from hostilities or other crises in the Middle East, West Africa, Latin America or other geographic areas in which we operate,
	•	changes in the manner or rate of taxation,
	•	limitations on our ability to recover amounts due,
	•	increased risk of government and vendor/supplier corruption,
	•	changes in political conditions, and
	•	other forms of government regulation and economic conditions that are beyond our control.

See "Item 1A. Risk Factors - Our non-U.S. operations involve additional risks not associated with U.S. operations."

Executive Officers

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

Name	Age	Position

Daniel W. Rabun	57	Chairman, President and Chief Executive Officer

William S. Chadwick, Jr.	64	Executive Vice President and Chief Operating Officer

J. Mark Burns	55	Senior Vice President - Western Hemisphere

John S. Knowlton	52	Senior Vice President - Technical

P. Carey Lowe	53	Senior Vice President - Eastern Hemisphere

Kevin C. Robert	53	Senior Vice President - Marketing

James W. Swent III	61	Senior Vice President and Chief Financial Officer (principal financial officer)

Brady K. Long	39	Vice President - General Counsel and Secretary

Douglas J. Manko	37	Controller (principal accounting officer)

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

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

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 Ensco 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.

J. Mark Burns joined Ensco in June 2008 and was elected to his current position of Senior Vice President – Western Hemisphere in May 2011. Prior to his current position, Mr. Burns served Ensco as Senior Vice President and as President of ENSCO Offshore International Company, a subsidiary of Ensco. Prior to joining Ensco, Mr. Burns served in various international capacities with Noble Corporation (a leading offshore drilling contractor), including his most recent position as Vice President & Division Manager responsible for offshore units located in the Gulf of Mexico. In 2007, Mr. Burns was named IADC Drilling Contractor of the Year. Mr. Burns holds a Bachelor of Arts Degree in Business and Political Science from Sam Houston State University.

John S. Knowlton joined Ensco in June 1998 and was elected to his current position of Senior Vice President – Technical in May 2011. Prior to his current position, Mr. Knowlton served Ensco as Vice President – Engineering & Capital Projects, General Manager – North & South America, Operations Manager – Asia Pacific Rim, and Operations Manager overseeing the construction and operation of our first ultra-deepwater semisubmersible, ENSCO 7500. Before joining Ensco, Mr. Knowlton served in various domestic and international capacities with Ocean Drilling & Exploration Company and Diamond Offshore Drilling, Inc. Mr. Knowlton holds a Bachelor of Science Degree in Civil Engineering from Tulane University.

P. Carey Lowe joined Ensco in August 2008 and was elected to his current position of Senior Vice President – Eastern Hemisphere in May 2011. Prior to his current position, Mr. Lowe served Ensco as Senior Vice President with responsibilities including the Deepwater Business Unit, safety, health and environmental matters, capital projects, engineering and strategic planning. Prior to joining Ensco, Mr. Lowe served as Vice President – Latin America for Occidental Oil & Gas. He also served as President & General Manager, Occidental Petroleum of Qatar Ltd. from 2001 to 2007. Mr. Lowe held various drilling-related management positions with Sedco Forex and Schlumberger Oilfield Services from 1980 to 2000, including Business Manager – Drilling, North and South America and General Manager – Oilfield Services, Saudi Arabia, Bahrain and Kuwait. Following Schlumberger, he was associated with a business-to-business e-procurement company until he joined Occidental during 2001. Mr. Lowe holds a Bachelor of Science Degree in Civil Engineering from Tulane University.

Kevin C. Robert joined Ensco in May 2011 as Senior Vice President – Marketing in connection with the acquisition of Pride. Before joining Ensco, Mr. Robert served as Vice President, Marketing and as Senior Vice President, Marketing and Business Development with Pride from 2005 to 2011. He served as Vice President, EPIC Contracts with Samsung Heavy Industries from 2002 to 2005. Mr. Robert also served as Vice President, Marketing with Marine Drilling Companies, Inc. and Director of Business Development with Pride from 2001 to 2002. He was Managing Member of Maverick Offshore L.L.C. from 1997 to 2000 and was employed by Conoco Inc. from 1981 to 1997. Mr. Robert holds a Bachelor of Science Degree in Chemical Engineering from Louisiana State University.

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

Brady K. Long joined Ensco in May 2011 as Vice President – General Counsel and Secretary in connection with the acquisition of Pride. Prior to joining Ensco, Mr. Long served as Vice President – General Counsel and Secretary with Pride from 2009 to 2011. He served as Vice President, Chief Compliance Officer and Deputy General Counsel with Pride from 2005 to 2009. Mr. Long previously practiced corporate and securities law for BJ Services Company and Bracewell & Giuliani LLP. He holds a Bachelor of Arts Degree from Brigham Young University and a Juris Doctorate Degree from The University of Texas School of Law.

Douglas J. Manko joined Ensco in May 2004 and was elected to his current position of Controller in September 2008. Mr. Manko served as Controller and Assistant Secretary from December 2009 to May 2011. Prior to his current position, he served as 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 approximately 8,000 personnel worldwide as of February 1, 2012. The majority of our personnel work on rig crews and are compensated on an hourly basis.

Available Information

Our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and amendments to these reports that we file or furnish to the SEC in accordance with the Securities Exchange Act of 1934, as amended, are available on our website at www.enscoplc.com. These reports also are available in print without charge by contacting our Investor Relations Department at 713-430-4607 as soon as reasonably practicable after we electronically file the information with, or furnish it to, the SEC. The information contained on our website is not included as part of, or incorporated by reference into, this report.

Item 1A. Risk Factors

Risks Related to Our Business

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

We are subject to a number of operating hazards, including those specific to marine operations. We may not have insurance to cover all these hazards.

Our operations are subject to hazards inherent in the offshore drilling industry, such as blowouts, reservoir damage, loss of production, loss of well control, uncontained formation pressures, lost or stuck drill strings, equipment failures and mechanical breakdowns, punch throughs, craterings, industrial accidents, fires, explosions, oil spills and pollution. These hazards can cause personal injury or loss of life, severe damage to or destruction of property and equipment, pollution or environmental damage, which could lead to claims by third parties or customers, suspension of operations and contract terminations. Our fleet is also subject to hazards inherent in marine operations, either while on-site or during mobilization, such as capsizing, sinking, grounding, collision, damage from severe weather and marine life infestations. Additionally, a security breach of our information systems or other technological failure could lead to a material disruption of our operations, information systems, and/or loss of business information, which could result in an adverse impact to our business. Our drilling contracts provide for varying levels of indemnification from our customers, including with respect to well control and subsurface risks. We also maintain insurance for personal injuries, damage to or loss of equipment and other insurance coverage for various business risks. Our insurance policies typically consist of 12-month policy periods, and the next renewal date for a substantial portion of our insurance program is scheduled for May 31, 2012.

Our insurance program provides coverage, to the extent not otherwise paid by the customer under the indemnification provisions of the drilling contract, for liability due to control-of-well events, liability arising from named windstorms and liability arising from third-party claims, including wrongful death and other personal injury claims by our personnel as well as claims brought on behalf of individuals who are not our employees. Generally, our program provides liability coverage up to $500.0 million, with a retention of $10.0 million or less.

Control-of-well events generally include an unintended flow from the well that cannot be contained by using equipment on site (e.g., a blowout preventer), by increasing the weight of drilling fluid or by diverting the fluids safely into production. Our program provides coverage for third-party liability claims relating to pollution from a control-of-well event up to $650.0 million per occurrence, with the first $150.0 million of such coverage also covering re-drilling of the well and control-of-well costs. Our program also provides coverage for liability resulting from pollution originating from our rig up to $500.0 million per occurrence. We retain the risk for liability not indemnified by the customer in excess of our insurance coverage. In addition, our insurance program covers only sudden and accidental pollution.

Our insurance program also provides coverage for physical damage to, including total loss or constructive total loss of, our rigs, generally excluding damage arising from a named windstorm in the Gulf of Mexico. This coverage is based on an agreed amount for each rig, and has a per occurrence deductible for losses ranging from $15.0 million to $25.0 million. With respect to hull and machinery losses arising from Gulf of Mexico windstorm damage, we obtained $450.0 million of aggregate coverage for ultra-deepwater semisubmersible hull and machinery losses with a $50.0 million per occurrence self-insured retention (deductible). However, due to the significant premium, high self-insured retention and limited coverage, we decided not to purchase windstorm insurance for our jackup rigs remaining in the Gulf of Mexico. Accordingly, we have retained the risk for loss or damage of our 11 jackup rigs remaining in the Gulf of Mexico arising out of windstorm damage. With respect to our ultra-deepwater drillship currently located in the Gulf of Mexico, ENSCO DS-5, we have $150.0 million of named windstorm coverage with a $10.0 million per occurrence deductible. With respect to the ENSCO DS-5, included in the $450.0 million aggregate limit mentioned above, there is $300.0 million of coverage in excess of the $150.0 million aggregate limit.

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

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

We generally indemnify the customer for legal and financial consequences of spills of waste oil, fuels, lubricants, motor oils, pipe dope, paint, solvents, ballast, bilge, garbage, debris, sewage, hazardous waste and other liquids the discharge of which originates from our rigs or equipment above the surface of the water and in some cases from our subsea equipment. Some of our contracts provide that, in the event of any such spill from our rigs, we are responsible for fines and penalties.

The above description of our insurance program and the indemnification provisions of our drilling contracts is only a summary as of the date hereof and is general in nature. In addition, our drilling contracts are individually negotiated, and the degree of indemnification we receive from operators against the liabilities discussed above can vary from contract to contract, based on market conditions and customer requirements existing when the contract was negotiated. Notwithstanding a contractual indemnity from a customer, there can be no assurance that our customers will be financially able to indemnify us or will otherwise honor their contractual indemnity obligations. Our insurance program and the terms of our drilling contracts may change in the future. In addition, the indemnification provisions of our drilling contracts may be subject to differing interpretations, and such provisions may be unenforceable, void or limited by public policy considerations, primarily in situations where the cause of the underlying loss or damage is due to our gross negligence, where punitive damages are attributable to us or where any fines and/or penalties imposed on us for certain conduct are punitive in nature. The question may ultimately need to be decided by a court or other proceeding taking into consideration the specific contract language, the facts and applicable laws. The law with respect to the enforceability of indemnities varies from jurisdiction to jurisdiction and is unsettled under certain laws that are applicable to our contracts.

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

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 11 jackup rigs, four ultra-deepwater semisubmersible rigs and one ultra-deepwater drillship 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 May 31, 2011, we obtained $450.0 million of aggregate coverage for ultra-deepwater semisubmersible 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 11 jackup rigs remaining in the Gulf of Mexico arising out of windstorm damage.

With respect to our ultra-deepwater drillship currently located in the Gulf of Mexico, ENSCO DS-5, we have $150.0 million of named windstorm coverage with a $10.0 million per occurrence deductible. With respect to the ENSCO DS-5, included in the $450.0 million aggregate limit mentioned above, there is $300.0 million of coverage in excess of the $150.0 million aggregate limit.

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 our jackup, ultra-deepwater semisubmersible and drillship 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, a $10.0 million per occurrence deductible for windstorm loss or damage to our drillship in the Gulf of Mexico, and have elected not to purchase loss or damage insurance coverage for our 11 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 success of our business largely depends on the level of activity in the oil and gas industry, which can be significantly affected by volatile oil and natural gas prices.

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

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

While recent economic trends have stabilized, continued effects of the economic recession could lead to a decline in demand for oil and natural gas. Further slowdowns in economic activity would likely reduce worldwide demand for energy and result in an extended period of lower oil and natural gas prices. Any prolonged reduction in oil and natural gas prices will depress the levels of exploration, development and production activity. In addition, continued hostilities in the Middle East and the occurrence or threat of terrorist attacks against the United States or other countries could further the downturn in the economies of the United States and other countries. Moreover, even during periods of high commodity prices, customers may cancel or curtail their drilling programs, or reduce their levels of capital expenditures for exploration and production for a variety of reasons, including their lack of success in exploration efforts. These factors could cause our revenues and margins to decline, as a result of declines in utilization and day rates, and limit our future growth prospects. Any significant decrease in daily rates or utilization of our rigs, particularly our high-specification drillships or semisubmersible rigs, could materially reduce our revenues and profitability. In addition, these risks could increase instability in the financial and insurance markets and make it more difficult for us to access capital and to obtain insurance coverages that we consider adequate or are otherwise required by our contracts.

Deterioration of the global economy and/or a decline in oil and natural gas prices could cause our customers to reduce spending on exploration and development drilling. These conditions 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 result in a material adverse effect on our financial position, operating results or cash flows.

We may incur asset impairments as a result of declining demand for offshore drilling rigs.

As of December 31, 2011, the carrying value of our property and equipment totaled $12.4 billion, which represented 70% of total assets. See Note 4 to our consolidated financial statements for additional information on our property and equipment. We evaluate the carrying value of our property and equipment, primarily our drilling rigs, when events or changes in circumstances indicate that the carrying value of such rigs may not be recoverable. The offshore drilling industry historically has been highly cyclical, and it is not unusual for rigs to be unutilized or underutilized for significant periods of time and subsequently resume full or near full utilization when business cycles change. Likewise, during periods of supply and demand imbalance, rigs are frequently contracted at or near cash break-even rates for extended periods of time until day rates increase when 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.

On May 31, 2011, we completed the acquisition of Pride resulting in the recognition of a preliminary amount of $2.95 billion in goodwill, including measurement period adjustments. As of December 31, 2011, the carrying value of our goodwill totaled $3.3 billion, which represented 18% of total assets. See Note 7 to our consolidated financial statements for additional information on our goodwill.

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

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

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

Our industry is highly competitive, and our contracts are traditionally awarded on a competitive bid basis. Pricing, safety records and competency are key factors in determining which qualified contractor is awarded a job. Rig availability, location and technical ability also can be significant factors in the determination. In addition, recent consolidations within the oil and gas industry have reduced the number of available customers, resulting in increased competition for projects. We may not be able to maintain our competitive position as competition for drilling contracts continues to intensify into the foreseeable future. Our potential inability to compete successfully may reduce our revenues and profitability.

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

The supply of offshore drilling rigs has increased in recent years, however, new rigs require substantial capital investment and a long period of time to construct. There are over 150 newbuild drillships, semisubmersibles and jackup rigs reported to be on order or under construction with delivery expected by the end of 2019. Approximately 45 of these rigs are scheduled for delivery during 2012 representing an approximate 6% increase in the total worldwide fleet of offshore drilling rigs. There are no assurances that the market in general or a geographic region in particular will be able to fully absorb the supply of new rigs in future periods.

The increase in supply of offshore drilling rigs during 2012 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 non-U.S. operations involve additional risks not associated with U.S. operations.

Revenues from non-U.S. operations were 73%, 75% and 86% of our total revenues during 2011, 2010 and 2009, respectively. Our non-U.S. operations and shipyard rig construction and enhancement projects are subject to political, economic and other uncertainties, including:

	•	terrorist acts, war and civil disturbances,
	•	expropriation, nationalization, deprivation or confiscation of our equipment,
	•	expropriation or nationalization of a customer's property or drilling rights,
	•	repudiation or nationalization of contracts,

	•	assaults on property or personnel,
	•	piracy, kidnapping and extortion demands,
	•	significant governmental influence over many aspects of local economies,
	•	unexpected changes in law and regulatory requirements, including changes in interpretation or enforcement of existing laws,
	•	work stoppages,
	•	complications associated with repairing and replacing equipment in remote locations,
	•	limitations on insurance coverage, such as war risk coverage, in certain areas,
	•	imposition of trade barriers,
	•	wage and price controls,
	•	import-export quotas,
	•	exchange restrictions,
	•	currency fluctuations,
	•	changes in monetary policies,
	•	uncertainty or instability resulting from hostilities or other crises in the Middle East, West Africa, Latin America or other geographic areas in which we operate,
	•	changes in the manner or rate of taxation,
	•	limitations on our ability to recover amounts due,
	•	increased risk of government and vendor/supplier corruption,
	•	changes in political conditions, and
	•	other forms of government regulation and economic conditions that are beyond our control.

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

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

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

Our non-U.S. operations also face the risk of fluctuating currency values, which may impact our revenues, operating costs and capital expenditures. We currently conduct contract drilling operations in certain countries that have experienced substantial fluctuations in the value of their currency compared to the U.S. dollar. In addition, some of the countries in which we operate have occasionally enacted exchange controls. Historically, these risks have been limited by invoicing and receiving payment in U.S. dollars (our functional currency) or freely convertible currency and, to the extent possible, by limiting 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 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 shipment of goods, services and technology across international borders subjects us to extensive trade laws and regulations. Our import activities are governed by unique customs laws and regulations in each of the countries where we operate. Moreover, many countries, including the United States, control the export and re-export of certain goods, services and technology and impose related export recordkeeping and reporting obligations. Governments also may impose express or de facto economic sanctions against certain countries, persons and other entities that may restrict or prohibit transactions involving such countries, persons and entities.

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

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

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

There are over 150 new offshore drilling rigs reported to be on order or under construction with expected delivery dates through 2019. 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 one ultra-deepwater drillship, the ENSCO DS-7, one ultra-deepwater semisubmersible rig, the ENSCO 8506, and three ultra-high specification harsh environment jackup rigs under construction. In addition, we may construct additional rigs and continue to upgrade the capability and extend the service lives of our existing rigs. Some of these expenditures are unplanned. In 2012, we expect to spend approximately $1.2 billion on newbuild rig construction projects, and approximately $380.0 million with respect to the enhancement, upgrade and improvement of other 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, terrorism, war or other armed hostilities,
	•	unforeseen design or engineering problems, including those relating to the commissioning of newly designed equipment,
	•	unanticipated actual or purported change orders,
	•	strikes, labor disputes or work stoppages,
	•	financial or operating difficulties of equipment vendors or the shipyard while constructing, enhancing, upgrading, improving or repairing a rig or rigs,
	•	unanticipated cost increases,
	•	foreign currency exchange rate fluctuations impacting overall cost,
	•	inability to obtain the requisite permits or approvals,
	•	client acceptance delays,
	•	disputes with shipyards and suppliers,
	•	latent damages or deterioration to hull, equipment and machinery in excess of engineering estimates and assumptions,
	•	claims of force majeure events, and
	•	additional risks inherent to shipyard projects in a non-U.S. location.

Our risks are concentrated because our ultra-deepwater semisubmersible rig and three 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 for equipment failure since its delivery in 2000, our ENSCO 8500 series ultra-deepwater semisubmersible rigs have a common risk of unforeseen design or engineering problems.

Only one of our rigs currently under construction has secured a drilling contract upon completion of its construction. These rigs are scheduled to be delivered beginning in the second half of 2012 through 2014. There is no assurance that we will secure drilling contracts for these rigs or that the drilling contracts we may be able to secure will be based upon rates and terms that will provide a reasonable rate of return on these investments. Our failure to secure contractual commitments for these rigs at rates and terms that result in a reasonable return upon completion of construction may result in a material adverse effect on our financial position, operating results and cash flows. If we are able to secure drilling contracts prior to completion, we will be exposed to the risk of delays that could impact the projected financial results or the viability of the contracts and could have a material adverse effect on our financial position, operating results and cash flows.

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

We currently have 24 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.

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.

Additionally, in 2010, Pride and its subsidiaries resolved with the U.S. Department of Justice (“DOJ”) and the SEC its previously disclosed investigations into potential violations of the Foreign Corrupt Practices Act ("FCPA"). In connection with the settlements, Pride paid a total of $56.2 million in penalties, disgorgement and interest.

The settlement with the DOJ included a deferred prosecution agreement ("DPA") between Pride and the DOJ and a guilty plea by Pride Forasol, S.A.S., one of Pride’s subsidiaries, to FCPA-related charges. Under the DPA, the DOJ agreed to defer the prosecution of certain FCPA-related charges and agreed not to bring any further criminal or civil charges against Pride or any of its subsidiaries related to either any of the conduct set forth in the statement of facts attached to the DPA or any other information disclosed to the DOJ prior to the execution of the DPA. Pride agreed, among other matters, to continue to cooperate with the DOJ, to continue to review and maintain its anti-bribery compliance program and to submit to the DOJ three annual written reports regarding its progress and experience in maintaining and, as appropriate, enhancing its compliance policies and procedures. In connection with our acquisition of Pride, we agreed to assume the obligations set forth in the DPA. If we comply with the terms of the DPA, the deferred charges against Pride will be dismissed with prejudice. If, during the term of the DPA, the DOJ determines that we have committed a felony under federal law, provided deliberately false information or otherwise breached the DPA, we could be subject to prosecution and penalties for any criminal violation of which the DOJ has knowledge, including the deferred charges.

Pride has received preliminary inquiries from governmental authorities of certain of the countries referenced in its settlements with the DOJ and SEC. We could face additional fines, sanctions and other penalties from authorities in these and other relevant jurisdictions, including prohibition of our participating in or curtailment of business operations in those jurisdictions and the seizure of rigs or other assets. At this early stage of such inquiries, we are unable to determine what, if any, legal liability may result. Our customers in those jurisdictions could seek to impose penalties or take other actions adverse to our interests. We could also face other third-party claims by directors, officers, employees, affiliates, advisors, attorneys, agents, stockholders, debt holders, or other interest holders or constituents of our company. For additional information regarding this investigation and a stockholder demand letter and derivative cases with respect to these matters, please see “Demand Letter, Derivative Cases and Shareholder Class Actions” in Part II, Item 1. Legal Proceedings of this annual report. In addition, disclosure of the subject matter of the investigations and settlements could adversely affect our reputation and our ability to obtain new business or retain existing business from our current clients and potential clients, to attract and retain employees and to access the capital markets.

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

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

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

Hurricanes Katrina and Rita in 2005 and Hurricanes Gustav and Ike in 2008 caused damage to a number of rigs in the Gulf of Mexico. Rigs that were moved off location by the storms damaged platforms, pipelines, wellheads and other drilling rigs. The U.S. Bureau of Ocean Energy Management, Regulation and Enforcement ("BOEMRE") BOEMRE has issued guidelines for jackup rig fitness requirements during hurricane seasons, which are scheduled to be effective through the 2013 hurricane season. As a result of these BOEMRE guidelines, jackup rigs in the U.S. Gulf of Mexico are required to operate with a higher air gap (the space between the water level and the bottom of the rig’s hull) during hurricane season, effectively reducing the water depth in which they can operate. The guidelines also provide for enhanced information and data requirements from oil and gas companies operating in the U.S. Gulf of Mexico. The BOEMRE may take other steps that could increase the cost of operations or reduce the area of operations. Implementation of the BOEMRE guidelines or regulations may subject us to increased costs and limit the operational capabilities of our rigs.

Similarly, as a result of the Macondo well incident in the U.S. Gulf of Mexico, the U.S. Department of the Interior issued NTLs implementing additional safety and certification requirements applicable to drilling activities in the U.S. Gulf of Mexico, and imposed additional requirements with respect to development and production activities in the U.S. Gulf of Mexico, including 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. Current or future NTLs or other directives and regulations may further impact our customers' ability to obtain permits and commence or continue deep or shallow water operations in the U.S. Gulf of Mexico. Future legislative or regulatory enactments may impose new requirements for well control and blowout prevention equipment that could increase our costs and cause delays in our operations due to unavailability of associated equipment.

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.

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

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

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

Geopolitical events have resulted in military action in Afghanistan, Iraq and Libya; terrorist, pirate and other armed attacks globally; the threat by Iran of military action in the Strait of Hormuz; and civil unrest, political demonstrations, mass strikes and government responses in North Africa and the Middle East. Military action by the United States or other nations could escalate; further acts of terrorism, piracy, kidnapping, extortion and acts of war may occur; and violence, civil war and general disorder may initiate or continue in North Africa, the Middle East or elsewhere. Such acts of terrorism, piracy, kidnapping, extortion, violence, civil war, mass strikes and government responses could be directed against companies such as ours. Such developments have caused instability in the world’s financial and insurance markets in the past. In addition, these developments could lead to increased volatility in prices for oil and natural gas and could affect the markets for our products and services. Insurance premiums could increase and coverages may be unavailable in the future. Any or all of these effects could have a material adverse effect on our financial position, operating results or cash flows.

We may suffer losses if our customers terminate or seek to renegotiate our contracts, if operations are suspended or interrupted or if a rig becomes a total loss.

Our drilling contracts often are subject to termination without cause upon 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.

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 2011, our five largest customers accounted for 43% of consolidated revenues in the aggregate, with our largest customer representing 16%. 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 150 new offshore drilling rigs reported to be on order or under construction with delivery expected by the end of 2019. 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.

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

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

The International Convention on Oil Pollution Preparedness, Response and Cooperation, the U.K. Merchant Shipping Act 1995, the U.K. Merchant Shipping (Oil Pollution Preparedness, Response and Cooperation Convention) Regulations 1998, the Clean Water Act and other related legislation and regulations and 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 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.

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

As of December 31, 2011, we had outstanding $5.1 billion in total debt, a significantly higher amount than the $257.3 million of debt outstanding as of December 31, 2010. This debt represented approximately 32% of our total capitalization as of December 31, 2011. Our current indebtedness may have several important effects on our future operations, including:

	•	a portion of our cash flow from operations will be dedicated to the payment of principal and interest;
	•	covenants contained in our debt arrangements require us to meet certain financial tests, which may affect our flexibility in planning for, and reacting to, changes in our business and may limit our ability to dispose of assets or place restrictions on the use of proceeds from such dispositions, withstand current or future economic or industry downturns and compete with others in our industry for strategic opportunities; and
	•	our ability to obtain additional financing to fund working capital requirements, capital expenditures, acquisitions, dividend payments and general corporate or other cash requirements may be limited.

Our ability to maintain a sufficient level of liquidity to meet our financial obligations will be dependent upon our future performance, which will be subject to general economic conditions, industry cycles and financial, business and other factors affecting our operations, many of which are beyond our control. Our future cash flows may be insufficient to meet all of our working capital requirements, debt obligations and contractual commitments, and any insufficiency could negatively impact our business. To the extent we are unable to repay our indebtedness as it becomes due or at maturity with cash on hand or from other sources, we will need to refinance our debt, sell assets or repay the debt with the proceeds from equity offerings.

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

Certain of our employees in non-U.S. markets are represented by labor unions and work under collective bargaining or similar agreements, which are subject to periodic renegotiation. Efforts have been made from time to time to unionize other portions of our workforce. In addition, we have been subjected to strikes or work stoppages and other labor disruptions in certain countries. Additional unionization efforts, new collective bargaining agreements or work stoppages could materially increase our costs, reduce our revenues or limit our flexibility.

Certain legal obligations require us to contribute certain amounts to retirement funds or other benefit plans and restrict our ability to dismiss employees. Future regulations or court interpretations established in the countries in which we conduct our operations could increase our costs and materially adversely affect our business, financial condition, operating results or cash flows.

Risks Related to Our Redomestication to the U.K.

We have not requested a ruling from Her Majesty's Revenue and Customs ("HMRC") 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 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 resident in a foreign jurisdiction and existing as at the time of the redomestication, under the “motive test” exclusion for a period after the redomestication ending December 31, 2012, subject to any changes of legislation. We have also obtained a substantially similar ruling from HMRC in respect of Pride International, Inc. and its material subsidiaries resident in a foreign jurisdiction and existing as at the time of its acquisition by Ensco plc, for a period ending December 31, 2013. The U.K. Government is consulting on a major reform of the CFC regime and has stated its intention to bring such reforms before Parliament in March 2012. While no assurance can be given in respect of the application of legislation that has not yet been enacted, we believe based on the U.K. Government's proposals and draft legislation published in December 2011 that the new CFC rules should not have a material adverse affect on our corporation tax treatment in the U.K. if enacted in their current form. However, to the extent that the draft legislation is enacted in a form different to that currently proposed, this may result in additional U.K. corporation tax liabilities to us following implementation of the revised legislation, which may adversely affect our financial position, operating results or cash flows.

The Internal Revenue Service ("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 us, and the IRS has confirmed to us that it will not challenge our conclusion that the redomestication resulted in Ensco becoming tax resident in the U.K. 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 certain restructuring transactions that it completed after the redomestication. In this event, we may not realize the expected tax benefits of the redomestication, and our financial position, operating results or cash flows 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.

The redomestication may not allow us to maintain a competitive consolidated effective income tax rate.

We believe the redomestication should improve our ability to maintain a competitive consolidated effective income tax rate because the U.K. corporate tax rate is lower than the U.S. corporate tax rate and because the U.K. has implemented a dividend exemption system that generally does not subject non-U.K. earnings to U.K. tax when such earnings are repatriated to the U.K. in the form of dividends from non-U.K. subsidiaries. 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 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 certain of our material non-U.K. resident subsidiaries under the “motive test” exemption until December 31, 2012, and in respect of certain of our other material non-U.K. subsidiaries under a substantially similar exemption until December 31, 2013, subject in both cases to certain conditions and limitations based on our facts and circumstances.

In June 2010, the new U.K. Government announced in its Emergency Budget that it aimed to create the most competitive corporate tax system in the G20, and that as a first step it would 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. Legislation on interim improvements to the CFC rules was enacted in 2011. In December 2011, the U.K. Government published major new CFC reform proposals together with draft legislation and is expected to bring such reforms before Parliament in March 2012. The effect of any changes to the CFC rules on our consolidated effective income tax rate will not be clear until the new legislation is published and enacted in its entirety, currently expected to occur in mid-2012. However, it is anticipated that these reforms generally will 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 subsidiaries until December 31, 2012, in some cases, or December 31, 2013, in others, our ability to efficiently manage those operations with a view to managing our consolidated effective income tax rate may be restricted by virtue of the new CFC rules from January 1, 2013 or January 1, 2014, as the case may be. In the event that the U.K. Government adopts changes to the proposed 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 consolidated effective income tax rate will be because of, among other matters, uncertainty regarding the nature and extent of our business activities in any particular jurisdiction in the future and the tax laws of such jurisdictions, as well as potential changes in U.K. and U.S. tax laws. Our actual consolidated effective income tax rate may vary from our expectations and those variances may be material.

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 consolidated effective income tax rate 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 consolidated effective income tax rate to increase and cause a material adverse effect on our financial position, operating results or cash flows.

Changes in laws, including tax law changes, could adversely affect us and our shareholders.

Changes in tax laws, regulations or treaties or the interpretation or enforcement thereof, in the U.S., the U.K. or elsewhere, could cause material adverse tax consequences of the redomestication and post-redomestication internal restructuring for us and our shareholders and/or our consolidated effective income tax rate (whether associated with the redomestication, the subsequent internal restructuring or otherwise). For example, one intention of the redomestication and subsequent internal restructuring was to improve our structure to allow for 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 and subsequent internal restructuring.

Changes in our consolidated effective income tax rate 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 consolidated effective income tax rate on our worldwide earnings and such change could be significant to our financial results. Our future consolidated effective income tax rate 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 believe that the redomestication has enabled 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 continue to 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, 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 drilling rigs are deployed, the location of the business unit offices that oversee our global offshore contract drilling operations, the locations of our customers’ corporate offices and principal areas of operation and the location of our investors. If events or changes in circumstances occur affecting the aforementioned factors, we may not be able to realize the expected logistical and operational benefits of the redomestication.

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

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

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

Directors of a Delaware and other U.S. corporations may issue, without further shareholder approval, shares of common stock authorized in its certificate of incorporation that were not already issued or reserved. The business corporation laws of Delaware and other U.S. states also provide substantial flexibility in establishing the terms of preferred stock. However, English law provides that a board of directors may only allot shares with the prior authorization of 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 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 16, 2012:

Rig Name

Rig Type

Year Built/

Rebuilt

Design

Maximum

Water Depth/

Drilling Depth

Current

Location

Current Customer

Deepwater

Ensco DS-1

Drillship (1)

1999

Dynamically Positioned

6,000'/30,000'

Angola

TOTAL

Ensco DS-2

Drillship (1)

1999

Dynamically Positioned

6,000'/30,000'

Angola

TOTAL

Ensco DS-3

Drillship (1)

2010

Dynamically Positioned

10,000'/40,000'

Angola

BP/Petrobras

Ensco DS-4

Drillship (1)

2010

Dynamically Positioned

10,000'/40,000'

Brazil

Ensco DS-5

Drillship (1)

2011

Dynamically Positioned

10,000'/40,000'

Gulf of Mexico

Petrobras

Ensco DS-6

Drillship (1), (2)

2012

Dynamically Positioned

10,000'/40,000'

Singapore

Delivered/shipyard

Ensco DS-7

Drillship (1), (3)

2013

Dynamically Positioned

10,000'/40,000'

South Korea

Under construction (4)

Ensco 5001

Semisubmersible (1)

1977/1999/2009

Sonat

5,000'/25,000'

Angola

Maersk

Ensco 5006

Semisubmersible (1)

1999

Bingo 8000

6,200'/25,000'

Israel

Noble

Ensco 6001

Semisubmersible (1)

2000/2010

Megathyst

5,700'/25,000'

Brazil

Petrobras

Ensco 6002

Semisubmersible (1)

2001/2009

Megathyst

5,700'/25,000'

Brazil

Petrobras

Ensco 6003

Semisubmersible (1)

2004

Megathyst

5,700'/25,000'

Brazil

Petrobras

Ensco 6004

Semisubmersible (1)

2004

Megathyst

5,700'/25,000'

Brazil

Petrobras

Ensco 7500

Semisubmersible

2000

Dynamically Positioned

8,000'/30,000'

Brazil

Petrobras

Ensco 8500

Semisubmersible

2008

Dynamically Positioned

8,500'/35,000'

Gulf of Mexico

Anadarko/Eni

Ensco 8501

Semisubmersible

2009

Dynamically Positioned

8,500'/35,000'

Gulf of Mexico

Nexen/Noble

Ensco 8502

Semisubmersible

2010

Dynamically Positioned

8,500'/35,000'

Gulf of Mexico

Nexen

Ensco 8503

Semisubmersible

2010

Dynamically Positioned

8,500'/35,000'

Gulf of Mexico

Cobalt

Ensco 8504

Semisubmersible (2)

2011

Dynamically Positioned

8,500'/35,000'

Brunei

TOTAL

Ensco 8505

Semisubmersible (2)

2012

Dynamically Positioned

8,500'/35,000'

Gulf of Mexico

Delivered/en route

Ensco 8506

Semisubmersible

2012

Dynamically Positioned

8,500'/35,000'

Singapore

Under construction/contracted (4)

Midwater

Ensco 5000

Semisubmersible (1)

1973/1995/2008

Neptune Pentagon

2,300'/25,000'

Brazil

Petrobras

Ensco 5002

Semisubmersible (1)

1975/2001

Aker H-3

1,000'/25,000'

Brazil

OGX

Ensco 5003

Semisubmersible (1)

1977/1997

Aker H-3

1,000'/20,000'

Namibia

Available

Ensco 5004

Semisubmersible (1)

1982/2001

F&G Enhanced Pacesetter

1,500'/25,000'

Brazil

OGX

Ensco 5005

Semisubmersible (1)

1982

F&G Enhanced Pacesetter

1,500'/25,000'

Brazil

Petrobras

Ensco 6000

Semisubmersible (1)

1987/1996

Dynamically Positioned

3,400'/12,000'

Brazil

Petrobras

Jackup

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

Petronas Carigali

Ensco 54

Jackup

1982/1997

F&G L-780 MOD II-C

300'/25,000'

UAE/Qatar

ADOC/QPD/Bunduq

Ensco 56

Jackup

1982/1997

F&G L-780 MOD II-C

300'/25,000'

Indonesia

Pertamina

Ensco 58

Jackup (1)

1981/2002

F&G L-780 MOD II

250'/30,000'

Saudi Arabia

Saudi Aramco

Ensco 59

Jackup (1)

1981/2007

F&G L-780 MOD II

300'/20,000'

Gulf of Mexico

Cold Stacked

Ensco 61

Jackup (1)

1983

Levingston Class 111-C

300'/25,000'

Perenco

Cameroon

Ensco 67

Jackup

1976/2005

MLT 84-CE

400'/30,000'

Indonesia

Pertamina

Ensco 68

Jackup

1976/2004

MLT 84-CE

400'/30,000'

Gulf of Mexico

Chevron

Ensco 69

Jackup

1976/1995

MLT 84-Slot

300'/25,000'

Gulf of Mexico

Cold Stacked

Ensco 70

Jackup

1981/1996

Hitachi K1032N

250'/30,000

United Kingdom

Tullow

Ensco 71

Jackup

1982/1995

Hitachi K1032N

225'/25,000'

Denmark

Maersk

Ensco 72

Jackup

1981/1996

Hitachi K1025N

225'/25,000'

Denmark

Maersk

Ensco 75

Jackup

1999

MLT Super 116-C

400'/30,000'

Gulf of Mexico

Apache

Ensco 76

Jackup

2000

MLT Super 116-C

400'/30,000'

Saudi Arabia

Saudi Aramco

Ensco 80

Jackup

1978/1995

MLT 116-CE

225'/30,000'

United Kingdom

Wintershall

Ensco 81

Jackup

1979/2003

MLT 116-C

350'/30,000'

Gulf of Mexico

Walter

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 84

Jackup

1981/2005

MLT 82-SD-C

250'/25,000'

Saudi Arabia

Saudi Aramco

Ensco 85

Jackup

1981/1995

MLT 116-C

300'/25,000'

Singapore

Shipyard/transit

Ensco 86

Jackup

1981/2006

MLT 82-SD-C

250'/30,000'

Gulf of Mexico

Apache

Ensco 87

Jackup

1982/2006

MLT 116-C

350'/25,000'

Gulf of Mexico

Apache

Ensco 88

Jackup

1982/2004

MLT 82-SD-C

250'/25,000'

Qatar

Ras Gas

Ensco 89

Jackup

1982/2005

MLT 82-SD-C

250'/25,000'

Mexico

Pemex

Ensco 90

Jackup

1982/2002

MLT 82-SD-C

250'/25,000'

Gulf of Mexico

Energy XXI

Rig Name

Rig Type

Year Built/

Rebuilt

Design

Maximum

Water Depth/

Drilling Depth

Current

Location

Current Customer

Jackup

Ensco 91

Jackup (1)

1980/2001

Hitachi Zosen

270'/20,000'

Saudi Arabia

Saudi Aramco

Ensco 92

Jackup

1982/1996

MLT 116-C

225'/25,000'

United Kingdom

RWE Dea

Ensco 93

Jackup

1982/2008

MLT 82-SD-C

250'/25,000'

Mexico

Pemex

Ensco 94

Jackup

1981/2001

Hitachi 250-C

250'/25,000'

Qatar

Ras Gas

Ensco 96

Jackup

1982/1997

Hitachi 250-C

250'/25,000'

Saudi Arabia

Saudi Aramco

Ensco 97

Jackup

1980/1997

MLT 82 SD-C

250'/25,000'

Saudi Arabia

Saudi Aramco

Ensco 98

Jackup

1977/2003

MLT 82 SD-C

250'/25,000'

Mexico

Pemex

Ensco 99

Jackup

1985/2005

MLT 82 SD-C

250'/30,000'

Gulf of Mexico

Energy XXI

Ensco 100

Jackup

1987/2009

MLT 150-88-C

350'/30,000

United Kingdom

E.On

Ensco 101

Jackup

2000

KELFS MOD V-A

400'/30,000'

United Kingdom

Maersk

Ensco 102

Jackup

2002

KELFS MOD V-A

400'/30,000'

United Kingdom

ConocoPhillips

Ensco 104

Jackup

2002

KELFS MOD V-B

400'/30,000'

Australia

Apache

Ensco 105

Jackup

2002

KELFS MOD V-B

400'/30,000'

Malaysia

Talisman

Ensco 106

Jackup

2005

KELFS MOD V-B

400'/30,000'

Malaysia

Newfield

Ensco 107

Jackup

2006

KELFS MOD V-B

400'/30,000'

Vietnam

Premier Oil

Ensco 108

Jackup

2007

KELFS MOD V-B

400'/30,000'

Brunei

TOTAL

Ensco 109

Jackup

2008

KELFS MOD V-Super B

350'/35,000'

Australia

PTTEP

Ensco 120

Jackup

2013

KFELS Super A

400'/40,000'

Singapore

Under construction/contracted (4)

Ensco 121

Jackup (3)

2013

KFELS Super A

400'/40,000'

Singapore

Under construction (4)

Ensco 122

Jackup (3)

2014

KFELS Super A

400'/40,000'

Singapore

Under construction (4)

Pride Hawaii

Jackup (1)

1975/1997

Levingston

300'/21,000'

Bahrain

Cold Stacked

Pride Pennsylvania

Jackup (1)

1973/1998

MLT

300'/20,000'

Bahrain

Cold Stacked

Pride Wisconsin

Jackup (1)

1976/2002

MLT-Slot

300'/20,000'

Gulf of Mexico

Cold Stacked

Other

Kizomba

Managed Rig

2004

Managed Rig

5,000'/25,000'

Angola

ExxonMobil

Thunderhorse

Managed Rig

2004

Managed Rig

6,000'/25,000'

Gulf of Mexico

Mad Dog

Managed Rig

2004

Managed Rig

4,500'/25,000'

Gulf of Mexico

Ensco I

Barge

1999

Barge

--'/18,000'

Singapore

Cold Stacked

(1)	In connection with the Merger, we acquired 13 deepwater rigs, one of which currently is under construction, six midwater rigs and seven jackup rigs.

(2)

ENSCO 8504 was delivered and commenced drilling operations in Brunei during the third quarter of 2011. ENSCO 8505 was delivered in January 2012 and is expected to commence drilling operations in the U.S. Gulf of Mexico under a two-year contract during the second quarter of 2012. ENSCO DS-6 was delivered in January 2012, and we expect it will be committed under a long-term drilling contract in the near-term.

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

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

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.

Drillship rigs are maritime vessels that have been outfitted with drilling apparatus. Drillships are self-propelled and can be positioned over a drill site through the use of a computer-controlled propeller or "thruster" (dynamic positioning) system. Our drillships are capable of drilling in water depths of 10,000 feet or less and are suitable for deepwater drilling in remote locations because of their mobility and large load-carrying capacity. Although drillships are most often used for deepwater drilling and exploratory well drilling, drillships can also be used as a platform to carry out well maintenance or completion work such as casing and tubing installation or subsea tree installations.

Semisubmersible rigs are floating offshore drilling units with pontoons and columns that partially submerge to a predetermined depth when sea water is permitted to enter the hull. Semisubmersible rigs can be held in a fixed location over the ocean floor either by being anchored to the sea bottom with mooring chains (moored semisubmersible rig) or dynamically positioned by computer-controlled propellers or "thrusters" (dynamically positioned semisubmersible rig) similar to that used by our drillships. Moored semisubmersible rigs are most commonly used for midwater drilling in water depths of 4,499 feet or less. However, ENSCO 5001 and ENSCO 5006, which are moored semisubmersible rigs, are capable of deepwater drilling in water depths greater than 5,000 feet. ENSCO 7500, which is capable of drilling in water depths up to 8,000 feet, is a dynamically positioned rig that also can be adapted for moored operations. The rig uses a riser system to manage the drilling fluid and well control equipment located on the ocean floor. Dynamically positioned semisubmersible rigs generally are outfitted for drilling in deeper water depths and are well suited for deepwater development and exploratory well drilling.

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

Over the life of a typical rig, many of the major systems are replaced due to normal wear and tear or technological advancements in drilling equipment. All of our rigs are in good condition. As of February 15, 2012, we owned all of the rigs in our fleet with the exception of three managed deepwater rigs for which we perform rig management services.

We lease our executive offices in London, England and own offices and other facilities in Louisiana, France and Scotland. In addition to our executive offices, we currently lease office space in Texas, Abu Dhabi, Angola, Australia, Brazil, Brunei, Denmark, Dubai, Indonesia, Israel, Korea, Malaysia, Mexico, Qatar, Saudi Arabia, Singapore, Switzerland, Tunisia, Vietnam and several additional international locations.

Item 3. Legal Proceedings

Demand Letter, Derivative Cases and Shareholder Class Actions

In June 2009, Pride received a demand letter from counsel representing Kyle Arnold. The letter states that Mr. Arnold was one of Pride’s shareholders and that he believes certain of Pride’s then-current and former officers and directors violated their fiduciary duties related to the issues described below under "—Pride FCPA Investigation." The letter requested that Pride’s board of directors take appropriate action against the individuals in question. In September 2009, Pride’s board of directors formed a special committee, which retained independent counsel and commenced an evaluation of the issues raised by the letter in an effort to determine a course of action.

Beginning in April 2010, two purported Pride shareholders (Edward Ferguson and Lawrence Dixon) filed separate derivative actions in the state courts of Harris County, Texas against all of Pride’s then-current directors and against Pride, as nominal defendant. These cases have been consolidated and allege in the consolidated amended petition that the individual defendants breached their fiduciary duties to Pride related to the issues described below under "—Pride FCPA Investigation." Among other remedies, the lawsuit seeks damages in an unspecified amount and equitable relief against the individual defendants, along with an award of attorney fees and other costs and expenses to the plaintiff.

In December 2010, the special committee completed its evaluation of the issues surrounding Pride's FCPA investigation and again reviewed its conclusion on January 28, 2011 in connection with the amended petition described above. The committee concluded that it was not in the interest of Pride or its shareholders to pursue litigation related to the matter. On February 14, 2011, Pride received the report of the special committee dated December 8, 2010, as well as committee minutes reflecting the conclusions reached in the meeting of January 28, 2011.

Following the announcement of the Merger, a number of putative shareholder class action complaints or petitions were filed against various combinations of Pride, Pride’s directors, Ensco and certain of our subsidiaries in the Delaware Court of Chancery, the U.S. District Court for the Southern District of Texas, and in the state courts of Harris County, Texas. These lawsuits challenged the proposed Merger and generally alleged, among other matters, that the individual members of the Pride board of directors breached their fiduciary duties by approving the proposed Merger, failing to take steps to maximize value to Pride’s stockholders and failing to disclose material information concerning the proposed Merger in the registration statement on Form S-4; that Pride, Ensco and certain of our subsidiaries aided and abetted such breaches of fiduciary duties; and that the Merger Agreement improperly favored Ensco and unduly restricted Pride’s ability to negotiate with other bidders. These lawsuits generally sought, among other remedies, compensatory damages, declaratory and injunctive relief concerning the alleged fiduciary breaches, and injunctive relief prohibiting the defendants from consummating the Merger. In addition, the plaintiffs in the derivative lawsuit discussed above, amended their petition to add similar Merger-related claims and also contended that the proposed Merger was motivated by a desire to extinguish alleged liability related to the derivative action. These claims have been consolidated with the other Merger-related lawsuits in the state courts of Harris County, Texas.

On May 19, 2011, Ensco and the other named defendants signed a memorandum of understanding with the plaintiffs in the consolidated litigation before the Delaware Court of Chancery to settle the previously disclosed shareholder class action lawsuits filed in the Delaware Court of Chancery and any claims asserted in the U.S. District Court for the Southern District of Texas and the state court of Harris County, Texas relating to the Merger (collectively, the "Settled Claims").

On August 29, 2011, the parties to the memorandum of understanding entered into a stipulation of settlement, which provides for, among other matters, the release of the Settled Claims following notice by mailing, certification of a non-opt-out class for settlement purposes, a settlement hearing and final approval of the settlement. Under the stipulation of settlement, Pride or its successor agreed not to oppose any application by attorneys for the class for fees and expenses not exceeding $1.1 million. The stipulation of settlement was approved by the Delaware Court of Chancery on November 23, 2011.

The plaintiffs in all but one of the remaining cases have filed motions to dismiss with prejudice, which currently are pending. Our motion to dismiss in the remaining matter also currently is pending; however, at this time, we are unable to predict the outcome of these matters or estimate the extent to which we may be exposed to any resulting liability. Although the outcome cannot be predicted, we do not expect these matters to have a material adverse effect on our financial position, operating results or cash flows.

Ensco FCPA Investigation

In connection with an independent investigation of potential FCPA violations arising out of business activities in Nigeria, we voluntarily disclosed our investigation to, and cooperated with, the DOJ and the SEC Division of Enforcement. In May 2010, the SEC Division of Enforcement advised us that it did not intend to recommend any enforcement action in connection with the investigation. In May 2011, we received notification from the DOJ that it had determined not to pursue any enforcement action against us with respect to the investigation. Therefore, this matter is now closed before both U.S. agencies.

Pride FCPA Investigation

In 2010, Pride and its subsidiaries resolved with the DOJ and the SEC its previously disclosed investigations into potential violations of the FCPA. In connection with the settlements, Pride paid a total of $56.2 million in penalties, disgorgement and interest.

The settlement with the DOJ included a DPA between Pride and the DOJ and a guilty plea by Pride Forasol, S.A.S., one of Pride’s subsidiaries, to FCPA-related charges. Under the DPA, the DOJ agreed to defer the prosecution of certain FCPA-related charges and agreed not to bring any further criminal or civil charges against Pride or any of its subsidiaries related to either any of the conduct set forth in the statement of facts attached to the DPA or any other information disclosed to the DOJ prior to the execution of the DPA. Pride agreed, among other matters, to continue to cooperate with the DOJ, to continue to review and maintain its anti-bribery compliance program and to submit to the DOJ three annual written reports regarding its progress and experience in maintaining and, as appropriate, enhancing its compliance policies and procedures. In connection with our acquisition of Pride, we agreed to assume the obligations set forth in the DPA. If we comply with the terms of the DPA, the deferred charges against Pride will be dismissed with prejudice. If, during the term of the DPA, the DOJ determines that we have committed a felony under federal law, provided deliberately false information or otherwise breached the DPA, we could be subject to prosecution and penalties for any criminal violation of which the DOJ has knowledge, including the deferred charges.

In connection with the plea agreement, Pride Forasol S.A.S. was sentenced to pay a criminal fine of $32.6 million and to serve a three-year term of organizational probation. The SEC investigation was resolved in November 2010. Without admitting or denying the allegations in a civil complaint filed by the SEC, Pride consented to the entry of a final judgment ordering disgorgement plus pre-judgment interest totaling $23.6 million and a permanent injunction against future violations of the FCPA.

Pride has received preliminary inquiries from governmental authorities of certain of the countries referenced in its settlements with the DOJ and SEC. We could face additional fines, sanctions and other penalties from authorities in these and other relevant jurisdictions, including prohibition of our participating in or curtailment of business operations in those jurisdictions and the seizure of our drilling rigs or other assets. At this early stage of such inquiries, we are unable to determine what, if any, legal liability may result. Our customers in those jurisdictions could seek to impose penalties or take other actions adverse to our interests. We could also face other third-party claims by directors, officers, employees, affiliates, advisors, attorneys, agents, shareholders, debt holders, or other interest holders or constituents of our company. For additional information regarding a shareholder demand letter and derivative cases with respect to these matters, please see the discussion above under "—Demand Letter, Derivative Cases and Shareholder Class Actions." In addition, disclosure of the subject matter of the investigations and settlements could adversely affect our reputation and our ability to obtain new business or retain existing business from our current customers and potential customers, to attract and retain employees and to access the capital markets.

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

Asbestos Litigation

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. 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.

We intend to vigorously defend against these claims and have filed responsive pleadings preserving all defenses and challenges to jurisdiction and venue. However, discovery is still ongoing and, therefore, available information regarding the nature of all pending claims is limited. At present, we cannot reasonably determine how many of the claimants may have valid claims under the Jones Act or estimate a range of potential liability exposure, if any.

In addition to the pending cases in Mississippi, we have 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.

U.S. Gulf of Mexico Drilling Moratorium and Permitting Delays

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 and other federal defendants seeking a ruling that the federal defendants’ actions following the Macondo well incident in April 2010 violated the Administrative Procedure Act and the Outer Continental Shelf Lands Act. As amended, the complaint challenged, among other matters, the federal defendants’ imposition of several deepwater drilling moratoria in the U.S. Gulf of Mexico and the federal defendants’ unreasonable delays in processing six Ensco-related applications for permits to drill in the U.S. Gulf of Mexico following the formal lifting of the moratoria.

Following a summary judgment ruling on the unreasonable delay claims in Ensco’s (and the co-plaintiff ATP Oil & Gas Corporation’s) favor, Ensco and the federal defendants entered into a settlement agreement on June 8, 2011, pursuant to which the federal defendants would act on the six unapproved Ensco-related permit applications within 30 days of any submission or resubmission of the applications and Ensco would dismiss its remaining claims. On June 16, 2011, the court approved the settlement agreement, entered a consent decree incorporating its terms, and dismissed Ensco’s remaining claims. The intervenor-defendants (several environmental groups) have filed an appeal seeking to vacate the district court’s summary judgment decision and declaratory relief in connection with Ensco’s and ATP’s claims of unreasonable delay in processing permit applications. The appeal is pending but does not challenge Ensco’s settlement with the government. The federal defendants did not file an appeal.

Environmental Matters

We are currently subject to pending notices of assessment issued from 2008 to 2011 pursuant to which governmental authorities in Brazil are seeking fines in an aggregate amount of approximately $2.0 million for the release of drilling fluid from drilling rigs operating offshore Brazil. We are contesting these notices and intend to defend ourselves vigorously. Although we do not expect the outcome of these assessments to have a material adverse effect on our financial position, operating results or cash flows, there can be no assurance as to the ultimate outcome of these assessments. A $2.0 million liability related to these matters was recorded as of December 31, 2011.

We currently are subject to a pending administrative proceeding initiated in July 2009 by a governmental authority of Spain pursuant to which such governmental authority is seeking payment in an aggregate amount of approximately $4.0 million for an alleged environmental spill originating from the ENSCO 5006 while it was operating offshore Spain. We expect to be indemnified for any payments resulting from this incident by our customer under the terms of the drilling contract. Our customer has posted guarantees with the Spanish government to cover potential penalties. In addition, a criminal investigation of the incident was initiated in July 2010 by a prosecutor in Tarragona, Spain, and the administrative proceedings have been suspended pending the outcome of this investigation. We do not know at this time what, if any, involvement we may have in this investigation.

We intend to defend ourselves vigorously in the administrative proceeding and any criminal investigation. At this time, we are unable to predict the outcome of these matters or estimate the extent to which we may be exposed to any resulting liability. Although we do not expect the outcome of the proceedings to have a material adverse effect on our financial position, operating results or cash flows, there can be no assurance as to the ultimate outcome of the proceedings.

Seahawk Drilling, Inc. Bankruptcy

In August 2009, Pride completed the spin-off of Seahawk Drilling, Inc., which held the assets and liabilities that were associated with Pride’s mat-supported jackup rig business. In February 2011, Seahawk and several of its affiliates filed for protection under Chapter 11 of the Bankruptcy Code. In the bankruptcy proceedings, Pride filed claims totaling approximately $85.0 million, including approximately $50.0 million in connection with the credit support agreement discussed below. The Seahawk debtors sold substantially all of their assets to Hercules Offshore, Inc. and its affiliate SD Drilling LLC, which paid base aggregate consideration consisting of approximately $25.0 million in cash and 22.3 million shares of Hercules common stock. On August 12, 2011, the Official Committee of Equity Security Holders (the "Equity Committee"), acting on behalf of the Seahawk debtors, filed a lawsuit against Pride and certain of Pride’s affiliates asserting (i) claims under the insolvency laws against the Pride defendants to challenge transfers made in connection with the spin-off of Seahawk and obligations Seahawk incurred with respect thereto, (ii) objections to the allowance of Pride’s proofs of claim against Seahawk and (iii) contractual counter-claims against Pride that the Equity Committee asserted would partially offset amounts Seahawk owed Pride. On September 28, 2011, the bankruptcy court confirmed the Seahawk debtors’ chapter 11 plan of reorganization and the claims against Pride were transferred to the trustee for the Seahawk liquidating trust (the “Trustee”). On the effective date of the plan, Seahawk used a portion of the Hercules common stock to pay off a post-bankruptcy debtor-in-possession loan and the remaining balance of approximately 17.1 million shares were reserved among all unpaid creditors, including Pride.

On December 11, 2011, Pride and the Trustee, together with the Seahawk Debtors and their affiliates, entered into a preliminary settlement agreement, which was filed with the court on December 12, 2011. On December 22, 2011 the court approved the settlement agreement and authorized an initial distribution of Hercules common stock to the creditors, including Pride. The material terms of the settlement agreement were as follows: (i) Pride's claims were allowed in full; (ii) Pride’s claim in connection with the credit support discussed below was subordinated to the payment of allowed claims of other Seahawk creditors; (iii) the lawsuit against the Pride defendants was dismissed with prejudice and all claims against the Pride defendants and related persons were released; and (iv) Pride has the right to continue to pursue recovery efforts in Mexico regarding the credit support discussed below. In the initial distribution, Pride received approximately 10.3 million shares of Hercules common stock, which have been sold for approximately $45.0 million. At the time of the initial distribution, the Trustee established reserves of shares to pay disputed claims of Seahawk creditors in an aggregate amount of approximately $10.0 million. Under the settlement agreement, Pride is entitled to receive a portion of the excess shares that may become available from those disputed claim reserves, of which approximately 540,000 shares have been received during 2012 and sold for approximately $2.4 million. See Note 3 and Note 13 to our consolidated financial statements for additional information on these matters.

Seahawk Tax-Related Credit Support

In August 2009, Pride completed the spin-off of Seahawk Drilling, Inc. ("Seahawk"), which held the assets and liabilities that were associated with Pride's mat-supported jackup rig business. In 2006, 2007 and 2009, Seahawk received tax assessments from the Mexican government related to their operations. Pursuant to local statutory requirements, Seahawk provided suitable collateral to contest these assessments. Pursuant to a tax support agreement between Pride and Seahawk, Pride agreed that in certain circumstances, at Seahawk’s request, it would guarantee or indemnify the issuer of such collateral. Also pursuant to the agreement, Seahawk would indemnify Pride for the amount of any such guarantee. On September 15, 2010, Seahawk requested that Pride provide credit support to a bank for four letters of credit issued for the appeals of four of these tax assessments. The amount of the request totaled approximately $50.0 million. On October 28, 2010, Pride provided credit support in satisfaction of this request.

In November 2011, the Mexican tax authority drew on the letters of credit, thereby triggering Pride’s reimbursement obligation to the letter of credit issuer. We believe the tax authority’s draw on the letters of credit was illegal. We made the reimbursement payment to the letter of credit issuer totaling approximately $43.7 million and, as stated above, Pride's claim for reimbursement from Seahawk was allowed in full under the settlement with the Trustee; however, the Seahawk bankruptcy estate did not have sufficient funds to pay the reimbursement claim in full. As part of the Seahawk bankruptcy settlement, we have the right, but not the obligation, to direct the management of the underlying court cases in respect of the aforementioned tax assessments in Mexico, as well as all other recovery efforts, in order to obtain recompense for its reimbursement of the letter of credit issuer. Further, we are entitled to all recovery from such efforts. We intend to vigorously pursue recovery of these funds; however, there can be no assurances that all or any portion of these funds will be recovered. See Note 13 to our consolidated financial statements for additional information on these matters.

Other Matters

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

Item 4. Mine Safety Disclosures

Not applicable.

PART II

Item 5.

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

Market Information

The following table provides the high and low sales price of our American depositary shares ("ADSs" or "shares"), each representing one Class A ordinary share, par value U.S. $0.10 per share, for each period indicated during the last two fiscal years:

	First Quarter	Second Quarter	Third Quarter	Fourth Quarter	Year

2011 High	$59.61	$60.31	$54.12	$55.29	$60.31
2011 Low	$49.70	$50.00	$39.51	$37.39	$37.39

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

Our ADSs are traded on the NYSE with the ticker symbol "ESV." We had 1,066 holders of record of our ADSs on February 1, 2012.

Dividends

We began paying a $.025 per share quarterly cash dividend during the third quarter of 1997 and continued to pay this quarterly dividend through March 31, 2010. During the second quarter of 2010, our Board of Directors declared a regular quarterly cash dividend of $.35 per share, and we have continued to pay this quarterly cash dividend through December 31, 2011. Cash dividends totaling $1.40 and $1.075 per share were paid during 2011 and 2010, 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 2011/2012 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 2011/2012. 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 chargeable gains arising from a disposal of their ADSs. The rate of U.K. capital gains tax on chargeable gains in the tax year 2011/2012 is 18% for basic rate taxpayers and 28% for higher and additional rate taxpayers.

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 chargeable 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 chargeable 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 chargeable gains arising from a disposal of its ADSs.

The full rate of U.K. corporation tax on chargeable gains is 26% in the financial year 2011 and 25% in the financial year 2012, 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 chargeable 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 chargeable gain accruing to a corporate ADS holder, the chargeable 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 Uncertificated 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, 2011.

			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	1,051	$41.29	--	$562,000,000
November 1 - November 30	2,036	$46.38	--	$562,000,000
December 1 - December 31	14,978	$48.81	--	$562,000,000
Total	18,065	$48.10	--

During the quarter ended December 31, 2011, 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 $1.5 billion 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, 2011 and 2010. Although $562.4 million remained available for repurchase as of December 31, 2011, 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, 2006 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.*

Graphic Comp Year Cumulative Total Return


	12/06	12/07	12/08	12/09	12/10	12/11

Ensco plc	100.00	119.31	56.94	80.34	110.16	99.41
S&P 500	100.00	105.49	66.46	84.05	96.71	98.75
Dow Jones US Oil Equipment & Services	100.00	144.95	59.00	97.43	124.07	108.65

____________________________________

* $100 invested on December 31, 2006 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,
	2011(1)		2010		2009		2008		2007
	(in millions, except per share amounts)
Consolidated Statement of Income Data
Revenues	$2,842.7		$1,696.8		$1,888.9		$2,242.6		$1,899.3
Operating expenses
Contract drilling (exclusive of depreciation)	1,470.9		768.1		709.0		736.3		613.4
Depreciation	418.9		216.3		189.5		172.6		165.5
General and administrative	158.6		86.1		64.0		53.8		59.5
Operating income	794.3		626.3		926.4		1,279.9		1,060.9
Other income (expense), net	(57.7	)	18.2		8.8		(4.2	)	37.8
Provision for income taxes	131.0		96.0		180.0		222.4		235.1
Income from continuing operations	605.6		548.5		755.2		1,053.3		863.6
Income from discontinued operations, net(2)	--		37.4		29.3		103.4		135.3
Net income	605.6		585.9		784.5		1,156.7		998.9
Net income attributable to noncontrolling interests	(5.2	)	(6.4	)	(5.1	)	(5.9	)	(6.9	)
Net income attributable to Ensco	$ 600.4		$ 579.5		$ 779.4		$1,150.8		$ 992.0
Earnings per share – basic
Continuing operations	$ 3.09		$ 3.80		$ 5.28		$ 7.32		$ 5.80
Discontinued operations	--		.26		.20		.72		.91
	$ 3.09		$ 4.06		$ 5.48		$ 8.04		$ 6.71
Earnings per share - diluted
Continuing operations	$ 3.08		$ 3.80		$ 5.28		$ 7.31		$ 5.78
Discontinued operations	--		.26		.20		.71		.91
	$ 3.08		$ 4.06		$ 5.48		$ 8.02		$ 6.69
Net income attributable to Ensco shares
Basic	$ 593.5		$ 572.1		$ 769.7		$1,138.2		$ 984.7
Diluted	$ 593.5		$ 572.1		$ 769.7		$1,138.2		$ 984.7
Weighted-average shares outstanding
Basic	192.2		141.0		140.4		141.6		146.7
Diluted	192.6		141.0		140.5		141.9		147.2
Cash dividends per share	$ 1.40		$ 1.075		$ .10		$ .10		$ .10

Consolidated Balance Sheet and Cash Flow Statement Data
Working capital	$ 321.3	$1,087.7	$1,167.9	$ 973.0	$ 625.8
Total assets	17,871.2	7,051.5	6,747.2	5,830.1	4,968.8
Long-term debt, net of current portion	4,877.6	240.1	257.2	274.3	291.4
Ensco shareholders' equity	10,879.3	5,959.5	5,499.2	4,676.9	3,752.0
Cash flow from continuing operations	732.3	816.7	1,185.6	1,014.7	1,094.3

(1)	Includes the results of Pride International, Inc., from the Merger Date.
(2)	See Note 12 to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" for information on discontinued operations.

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

INTRODUCTION

Our Business

Our Industry

Operating results in the offshore contract drilling industry are cyclical and directly related to the demand for drilling rigs and the available supply of drilling rigs. While the cost of moving a rig and the availability of rig-moving vessels may cause the balance of supply and demand to vary somewhat between regions, significant variations between regions generally do not tend to persist long-term due to rig mobility.

Drilling Rig Demand

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

	•	demand for oil and natural gas,
	•	regional and global economic conditions and changes therein,
	•	political, social and legislative environments in major oil-producing countries,
	•	production and inventory levels and related activities of the Organization of Petroleum Exporting Countries ("OPEC") and other oil and natural gas producers,
	•	technological advancements that impact the methods or cost of oil and natural gas exploration and development,
	•	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 during 2008 and 2009 led to an abrupt reduction in global demand for shallow-water drilling and a relatively modest decline in global demand for deepwater and midwater drilling during 2009. During 2010, demand remained weak in most regions for shallow-water drilling while demand for deepwater and midwater drilling came under additional pressure as a result of delays in operators’ ability to secure permits in the U.S. Gulf of Mexico due to the Macondo well incident and related regulatory developments and other actions imposed by the U.S. Department of the Interior. During 2011, tender activity increased as demand for shallow-water drilling improved, which helped to stabilize jackup rig utilization and day rates, while demand for midwater drilling remained under pressure. Furthermore, permit issuances in the U.S. Gulf of Mexico related to deepwater programs improved, in addition to an upward movement in global demand for deepwater drilling.

Since factors that affect offshore exploration and development spending are beyond our control and, because rig demand can change quickly, it is difficult for us to predict future industry conditions, demand trends or future operating results. Periods of low rig demand often result in excess rig supply, which generally results in reductions in utilization levels and day rates; periods of high rig demand often result in a shortage of rigs, which generally results in increased utilization levels and day rates.

Drilling Rig Supply

During recent periods, various industry participants ordered the construction of over 270 new drillships, semisubmersible rigs and jackup rigs, 120 of which were delivered during the last three years.

Worldwide rig supply in the deepwater segment continues to increase as a result of newbuild construction programs. It has been reported that over 70 newbuild drillships and semisubmersible rigs capable of drilling in water depths of 4,500 feet or greater currently are under construction, over 15 of which are scheduled for delivery during 2012. Approximately half of all newbuild deepwater rigs scheduled for delivery are contracted. We expect newbuild deepwater rigs will be absorbed into the market without a significant effect on utilization and day rates.

Worldwide rig supply in the midwater segment is not expected to increase significantly in the near-term. It has been reported that six newbuild semisubmersible rigs capable of drilling in water depths of 4,499 feet or less are under construction, two of which are scheduled for delivery during 2012. Half of all newbuild midwater rigs scheduled for delivery are contracted. Due to competition with higher specification drilling rigs and the potential oversupply of midwater rigs in certain regions, we expect utilization and day rates to remain under pressure in the near-term.

Worldwide rig supply in the jackup segment continues to increase as a result of newbuild construction programs. It has been reported that over 75 newbuild jackup rigs are under construction, 25 of which are scheduled for delivery during 2012. The majority of all newbuild jackup rigs scheduled for delivery are not contracted. Although the supply of available jackup rigs is expected to further increase from newbuild deliveries, given the aforementioned improvements in demand and utilization, day rates generally are expected to trend upward in the near-term in most regions.

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

Acquisition of Pride International, Inc.

On May 31, 2011 (the "Merger Date"), Ensco plc completed a merger transaction (the "Merger") with Pride International, Inc., a Delaware corporation ("Pride"), ENSCO International Incorporated, a Delaware corporation and an indirect, wholly-owned subsidiary and predecessor of Ensco plc ("Ensco Delaware"), and ENSCO Ventures LLC, a Delaware limited liability company and an indirect, wholly-owned subsidiary of Ensco plc ("Merger Sub"). Pursuant to the merger agreement and subject to the conditions set forth therein, Merger Sub merged with and into Pride, with Pride as the surviving entity and an indirect, wholly-owned subsidiary of Ensco plc. The total consideration delivered in the Merger was $7.4 billion, consisting of $2.8 billion of cash, 85.8 million Ensco ADSs with an aggregate value of $4.6 billion based on the closing price of Ensco ADSs of $53.32 on the Merger Date and the estimated fair value of $35.4 million of vested Pride employee stock options assumed by Ensco.

Drilling Rig Construction and Delivery

We continue to maintain our long-established strategy of high-grading our jackup rig fleet by investing in newer equipment while expanding the size and quality of our deepwater drilling rig fleet. During the three-year period ended December 31, 2011, we invested $1.6 billion in the construction of new drilling rigs.

In February 2011, we entered into agreements with Keppel FELS Limited ("KFELS") to construct two ultra-high specification harsh environment jackup rigs (ENSCO 120 and ENSCO 121). We also entered into an agreement with KFELS in October 2011 to construct a third jackup rig of the same design (ENSCO 122). These rigs are scheduled for delivery during the first and second half of 2013 and the second half of 2014, respectively. ENSCO 120 is committed under a long-term drilling contract with Nexen in the North Sea, while the other two jackup rigs under construction are uncontracted.

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 8501 was delivered and commenced drilling operations under a long-term contract with Nexen and Noble Energy in the U.S. Gulf of Mexico during 2009. ENSCO 8502 was delivered and commenced drilling operations under a long-term contract with Nexen in the U.S. Gulf of Mexico during 2010. ENSCO 8503 was delivered in 2010 and commenced drilling operations in French Guiana under a short-term sublet agreement during the first quarter of 2011. ENSCO 8503 is expected to commence drilling operations under a long-term contract with Cobalt in the U.S. Gulf of Mexico during the first quarter of 2012. ENSCO 8504 was delivered and commenced drilling operations under a long-term contract with TOTAL in Brunei during the third quarter of 2011. ENSCO 8505 was delivered in January 2012 and is expected to commence drilling operations under a long-term contract with Anadarko, Apache and Noble Energy in the U.S. Gulf of Mexico during the second quarter of 2012. We also have remaining one ENSCO 8500 Series® ultra-deepwater semisubmersible rig under construction (ENSCO 8506), which is committed under a long-term drilling contract with Anadarko in the U.S. Gulf of Mexico and scheduled for delivery in the second half of 2012.

In connection with the Merger, we acquired seven drillships, two of which were under construction. These newbuild drillships are based on a Samsung Heavy Industries proprietary hull design capable of drilling in water depths of up to 10,000 feet of water. ENSCO DS-6 was delivered in January 2012, and we expect it will be committed under a long-term drilling contract in the near-term. We also have remaining one uncontracted ultra-deepwater drillship (DS-7) under construction with a scheduled delivery date in the second half of 2013.

We historically have relied on our cash flow from continuing operations to meet liquidity needs and fund the majority of our cash requirements. We have maintained a strong financial position through the disciplined and conservative use of debt, which has provided us the ability to achieve future growth potential through acquisitions and newbuild construction. A substantial portion of our cash flow has been and will continue to be invested in the expansion and enhancement of our fleet of drilling rigs in general and our newbuild construction in particular. We believe our strong balance sheet, over $9.6 billion of contract backlog, $1.9 billion of available revolving credit facilities and our $1.0 billion commercial paper program will enable us to meet the capital expenditure obligations associated with our newbuild rig construction contracts and sustain an adequate level of liquidity during 2012 and beyond.

Divestitures

Our business strategy has been to focus on deepwater, midwater and premium jackup rig assets and operations, and de-emphasize other assets and operations considered to be non-core or that do not meet our standards for financial performance. Consistent with this strategy, we sold four jackup rigs during 2010 and one jackup rig during 2011 for an aggregate $208.8 million in proceeds.

Segment Highlights

Deepwater

Operating results in our Deepwater segment significantly improved during 2011, primarily due to the addition of five drillships and six semisubmersible rigs as a result of the Merger, and the addition of ENSCO 8503 and ENSCO 8504 to our Deepwater fleet. During 2011, ENSCO 8504 commenced drilling operations for TOTAL in Brunei at a day rate of approximately $424,000. ENSCO 8505 was contracted to Anadarko, Apache and Noble Energy in the U.S. Gulf of Mexico during 2011 at a day rate of approximately $475,000. ENSCO DS-3 and ENSCO DS-4 commenced drilling operations for BP and ENSCO DS-5 commenced drilling operations for Petrobras during 2011 at day rates ranging from $430,000 to $540,000. ENSCO 7500 recently completed an enhancement project in a shipyard in Singapore and mobilized to Brazil where the rig commenced drilling operations in December 2011 with Petrobras at a day rate of approximately $320,000.

ENSCO DS-3 recently mobilized from the U.S. Gulf of Mexico to Angola and commenced drilling operations in January 2012 on a sublet to Petrobras under its original drilling contract with BP. ENSCO 8506 was contracted to Anadarko in January 2012 in the U.S. Gulf of Mexico at a day rate of approximately $530,000. We view the aforementioned drilling contracts in the U.S. Gulf of Mexico as another positive sign that customers expect the pace of permitting in the region will continue to improve.

ENSCO 8503 drilled a major discovery on its initial well for Tullow in French Guiana during 2011. The discovery by Tullow is significant as it suggests the geological trend from the equatorial margin of West Africa may extend to the Americas. We expect this will lead to future demand for deepwater drilling in French Guiana as our customers move to assess and develop this new geological trend. Brunei is another new geological region for deepwater drilling, and we expect operators will require more rig time to fully assess the value of this region as well.

Midwater

In connection with the Merger, we acquired six semisubmersible rigs with water depth drilling capabilities ranging from 1,000 feet to 3,400 feet. Five of these rigs currently are operating in Brazil and one is operating in West Africa. During 2011, utilization primarily was impacted by ENSCO 5003 and ENSCO 6000, which incurred idle time for repairs and a shipyard project during the period, respectively.

Jackup

During 2011, we contracted KFELS to construct three ultra-high specification harsh environment jackup rigs (ENSCO 120, ENSCO 121 and ENSCO 122). ENSCO 120 recently was committed under a long-term contract with Nexen at a day rate of approximately $230,000. These rigs feature improved equipment and capabilities with high-temperature, high-pressure equipment, a proprietary Ensco high-capacity design cantilever envelope, 2.5 million pound quad derrick, automated hands-free offline pipe handling systems, ultra-high capacity jacking and fixation systems, 150-person quarters and strict noise and ergonomic standards. We expect these rigs will offer customers value through increased drilling efficiencies for demanding large multi-well platform programs, ultra-deep gas programs and ultra-long reach wells up to 40,000 feet total drilling depth in offshore oil and natural gas regions throughout the world, and the North Sea in particular.

BUSINESS ENVIRONMENT

Deepwater

During 2009, lower oil and natural gas prices resulted in a modest decline in demand for deepwater drilling with utilization and day rates generally remaining stable due to the long-term nature of deepwater projects. Demand for drilling rigs in the deepwater segment remained stable during 2010 but came under pressure as a result of delays in operators’ ability to secure permits in the U.S. Gulf of Mexico due to regulatory developments and other actions imposed by the U.S. Department of the Interior. During 2011, several drilling permits were issued in the U.S. Gulf of Mexico related to deepwater programs that had been interrupted by the response to the Macondo well incident as offshore drilling contractors continued to work with operators and government regulators to address new regulatory requirements and secure drilling permits. The time required for issuance of deepwater drilling permits in the U.S. Gulf of Mexico continues to improve. Demand for deepwater drilling in the region is expected to increase in the near-term as additional permits are issued.

We also are encouraged by an increase in tender activity that has resulted from strengthening demand for work in 2012 and beyond for deepwater drilling in various other regions. Demand has remained strong in Brazil due to recent tenders issued by Petrobras, the national oil company of Brazil. In West Africa, demand for deepwater drilling has improved as illustrated by recent contract awards and inquiries from operators, which are expected to provide opportunities for a number of deepwater rigs. Increased tender activity worldwide, coupled with the increase in oil prices over the past year, are expected to have a positive impact on future rig demand in the deepwater segment. Furthermore, we expect future demand growth for deepwater drilling in French Guiana and Brunei as operators move to assess these relatively new geological regions.

We continue to believe in the long-term positive prospects for deepwater drilling based on the expected growth in oil consumption from developing nations, limited growth in oil supplies and high depletion rates of mature oil fields, as well as geologic successes, improving access to promising offshore areas and new, more efficient technologies. Due to the tendency for deepwater drilling programs to be more insulated from short-term commodity price fluctuations, we expect that the deepwater segment will outperform the midwater and jackup segments over the long-term. We expect rig utilization and day rates in the deepwater segment will be driven by growing worldwide demand for oil and natural gas as global populations expand and economic growth accelerates, along with an increased focus by operators on deepwater offshore prospects. However, the Macondo well incident and associated new regulatory, legislative or permitting requirements in the U.S. Gulf of Mexico may continue to affect utilization and day rates in that region in the near-term.

Midwater

Demand for drilling rigs in the midwater segment came under pressure during 2009 and 2010 as a result of lower oil and natural gas prices, coupled with uncertainty surrounding the Macondo well incident in the U.S. Gulf of Mexico and the resulting regulatory developments and other actions imposed by the U.S. Department of the Interior. However, the number of midwater rigs located in the U.S. Gulf of Mexico has declined significantly over the last several years, primarily due to the risk of mooring system failures during hurricane season, marginal geologic prospects and more attractive opportunities in other regions, such as Brazil and West Africa. This resulted in an increase in the number of midwater rigs that have relocated to other locations.

Although incremental tender activity was seen in Brazil and West Africa during 2011, demand for midwater drilling rigs remained under pressure. Demand for midwater rigs during most of 2011 softened as a result of increased competition with the more capable deepwater rigs that were forced to bid reduced day rates on work programs in relatively shallow-water depths in an attempt to remain active. A recent decline in availability for midwater rigs and a corresponding increase in utilization may indicate strengthening demand for midwater drilling in 2012. An increase in demand for deepwater drilling may provide upward pressure on utilization and day rates for the midwater segment in the near to intermediate term.

Jackup

During 2009, demand for shallow-water drilling was significantly impacted by lower oil and natural gas prices. Demand for drilling rigs in the jackup segment was limited during 2010, resulting in continued softness in day rates for standard duty jackup rigs. However, we are encouraged by recent improvements in tender activity due to an increase in both standard duty and heavy duty jackup rig demand for work in 2012 and beyond across various regions. In addition, the increase in oil prices over the past year is expected to have a positive effect on future jackup rig demand.

Demand for jackup rigs in the Asia Pacific rim, including Vietnam, Malaysia, Indonesia and Australia, strengthened in 2011 as tender activity increased across the region, with a number of operators locking in longer term contracts with both standard duty and heavy duty rigs.

Tender activity in the Middle East increased during 2011 primarily as a result of increased requirements from Saudi Aramco, the national oil company of Saudi Arabia. We expect this trend to continue into 2012, primarily driven by the increase in oil prices over the past year, the potential impact of supply interruptions due to civil unrest in the Middle East and North Africa and a modest improvement in the stability of the global economy.

Demand for jackup rigs in the North Sea improved in 2011 with new inquires for work beginning in 2012 for both standard duty and heavy duty rigs. Although more drilling rigs may enter the North Sea, the market is projected to remain in balance through 2012 with the potential for upward pressure on day rates.

Demand for jackup rigs in the U.S. Gulf of Mexico improved during 2011. Upward pressure on utilization and day rates may occur if additional rigs depart from the region in 2012. Tender activity increased during 2011 in waters offshore Mexico for work beginning in 2012 as Petróleos Mexicanos, the national oil company of Mexico, continues to increase capital spending on offshore drilling.

RESULTS OF OPERATIONS

The following table summarizes our consolidated results of operations for each of the years in the three-year period ended December 31, 2011 and includes the results of Pride from the Merger Date (in millions):

	2011			2010			2009

Revenues		$2,842.7			$1,696.8			$1,888.9
Operating expenses
Contract drilling (exclusive of depreciation)		1,470.9			768.1			709.0
Depreciation		418.9			216.3			189.5
General and administrative		158.6			86.1			64.0
Operating income		794.3			626.3			926.4
Other income (expense), net		(57.7	)		18.2			8.8
Provision for income taxes		131.0			96.0			180.0
Income from continuing operations		605.6			548.5			755.2
Income from discontinued operations, net		--			37.4			29.3
Net income		605.6			585.9			784.5
Net income attributable to noncontrolling interests		(5.2	)		(6.4	)		(5.1	)
Net income attributable to Ensco		$ 600.4			$ 579.5			$ 779.4

During 2011, excluding $1.1 billion of revenues and $223.1 million of operating income attributable to the impact of the Merger, revenues increased by $69.6 million, or 4%, and operating income decreased by $55.1 million, or 9%, as compared to the prior year. The increase in revenues primarily was due to ENSCO 8502, ENSCO 8503 and ENSCO 8504 which were added to our Deepwater segment and commenced drilling operations during the third quarter of 2010 and the first and third quarters of 2011, respectively, partially offset by idle time on ENSCO 7500 as the rig recently completed an enhancement project in a shipyard in Singapore and mobilized to Brazil where the rig commenced drilling operations during the fourth quarter of 2011. The decline in operating income primarily was due to a decrease in average day rates for our Jackup segment, idle time on ENSCO 7500 as previously noted and general and administrative expense incurred by Ensco to effect the Merger.

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 for our Jackup segment in the Europe, Mediterranean and Asia Pacific Rim markets coupled with a decline in average day rates for our Jackup segment in the North America market, partially offset by a significant increase in revenues and operating income generated by our Deepwater segment.

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 future 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 continued to result in a decline in demand for contract drilling services during 2010 and, to a lesser extent, in 2011.

Certain of our drilling rigs 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 in September 2010. 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 Notices to Lessees 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. Additionally, regulatory or customer requirements relating to blowout prevention equipment certification, inspection and testing may adversely impact our revenues.

Rig Locations, Utilization and Average Day Rates

The following table summarizes our offshore drilling rigs by reportable segment and rigs under construction as of December 31, 2011, 2010 and 2009:

	2011(1)	2010	2009

Deepwater(2)	17	5	3
Midwater	6	--	--
Jackup(3)	46	40	39
Under construction(2)(4)	7	3	5
Total(5)	76	48	47

(1)		In connection with the Merger, we acquired 13 deepwater rigs, two of which were under construction, six midwater rigs and seven jackup rigs.
(2)		ENSCO 8504 was delivered and commenced drilling operations in Brunei during the third quarter of 2011. ENSCO 8502 was delivered and commenced drilling operations in the U.S. Gulf of Mexico during 2010. ENSCO 8503 was delivered during 2010 and commenced drilling operations in French Guiana under a short-term sublet agreement during the first quarter of 2011. ENSCO 8503 commenced drilling operations in the U.S. Gulf of Mexico under a long-term contract during the first quarter of 2012.
(3)		In June 2011, we sold ENSCO 95. In July 2010, we acquired ENSCO 109, an ultra-high specification jackup rig.
(4)		In February 2011, we entered into agreements with KFELS to construct two ultra-high specification harsh environment jackup rigs (ENSCO 120 and ENSCO 121). We also entered into an agreement with KFELS in October 2011 to construct a third jackup rig of the same design (ENSCO 122). These rigs are scheduled for delivery during the first and second half of 2013 and the second half of 2014, respectively. ENSCO 120 is committed under a long-term contract in the North Sea, while the other two jackup rigs under construction are uncontracted.
(5)		The total number of rigs for each period excludes rigs reclassified as discontinued operations.

The following table summarizes our rig utilization and average day rates from continuing operations by reportable segment for each of the years in the three-year period ended December 31, 2011 and includes the impact of Pride from the Merger Date:

	2011	2010	2009

Rig utilization(1)
Deepwater	78%	81%	85%
Midwater	85%	N/A	N/A
Jackup(3)	77%	77%	74%
Total	77%	77%	75%
Average day rates(2)
Deepwater	$366,844	$375,098	$425,190
Midwater	234,546	N/A	N/A
Jackup(3)	98,087	106,007	151,636
Total	$159,851	$128,784	$163,568

(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, lump sum revenues and revenues attributable to amortization of drilling contract intangibles (as discussed in Note 2 to our consolidated financial statements), by the aggregate number of contract days, adjusted to exclude contract days associated with certain mobilizations, demobilizations, shipyard contracts and standby contracts.
(3)		ENSCO 69 has been excluded from rig utilization and average day rates for our Jackup operating segment during the period the rig was controlled and operated by Petrosucre, a subsidiary of Petróleos de Venezuela S.A., the national oil company of Venezuela (January 2009 - August 2010).

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

Operating Income

In connection with the Merger, we evaluated our core assets and operations, which consisted of seven drillships, 20 semisubmersible rigs and 48 jackup rigs, including rigs under construction, and organized them into three segments based on water depth operating capabilities. Accordingly, we determined our business to consist of three reportable segments: (1) Deepwater, which consists of our rigs capable of drilling in water depths of 4,500 feet or greater, (2) Midwater, which consists of our semisubmersible rigs capable of drilling in water depths of 4,499 feet or less and (3) Jackup, which consists of our jackup rigs capable of drilling in water depths up to 400 feet. Each of our three reportable segments provides one service, contract drilling. We also manage the drilling operations for two deepwater rigs and own one barge rig, which are included in "Other."

Segment information for each of the years in the three-year period ended December 31, 2011 is presented below and includes the results of Pride from the Merger Date (in millions). General and administrative expense and depreciation expense incurred by our corporate office are not allocated to our operating segments for purposes of measuring segment operating income and were included in "Reconciling Items." Prior year information has been reclassified to conform to the current year presentation.

Year Ended December 31, 2011


					Operating
					Segments	Reconciling	Consolidated
	Deepwater	Midwater	Jackup	Other	Total	Items	Total

Revenues	$1,284.7	$273.8	$1,231.8	$ 52.4	$2,842.7	$ --	$2,842.7
Operating expenses Contract drilling (exclusive of depreciation)	636.1	166.2	623.9	44.7	1,470.9	--	1,470.9
Depreciation	201.7	37.1	173.5	2.1	414.4	4.5	418.9
General and administrative	--	--	--	--	--	158.6	158.6
Operating income (loss)	$ 446.9	$ 70.5	$ 434.4	$ 5.6	$ 957.4	$(163.1)	$ 794.3

Year Ended December 31, 2010


					Operating
					Segments	Reconciling	Consolidated
	Deepwater	Midwater	Jackup	Other	Total	Items	Total

Revenues	$ 475.2	$ --	$1,221.6	$ --	$1,696.8	$ --	$1,696.8
Operating expenses Contract drilling (exclusive of depreciation)	176.1	--	578.2	13.8	768.1	--	768.1
Depreciation	44.8	--	167.8	2.4	215.0	1.3	216.3
General and administrative	--	--	--	--	--	86.1	86.1
Operating income (loss)	$ 254.3	$ --	$ 475.6	$(16.2)	$ 713.7	$ (87.4)	$ 626.3

Year Ended December 31, 2009


					Operating
					Segments	Reconciling	Consolidated
	Deepwater	Midwater	Jackup	Other	Total	Items	Total

Revenues	$ 254.1	$ --	$1,634.8	$ --	$1,888.9	$ --	$1,888.9
Operating expenses Contract drilling (exclusive of depreciation)	108.1	--	599.0	1.9	709.0	--	709.0
Depreciation	22.2	--	162.9	3.1	188.2	1.3	189.5
General and administrative	--	--	--	--	--	64.0	64.0
Operating income (loss)	$ 123.8	$ --	$ 872.9	$ (5.0)	$ 991.7	$ (65.3)	$ 926.4

Deepwater

During 2011, excluding $700.2 million of revenues and $411.6 million of contract drilling expense attributable to the impact of the Merger, Deepwater revenues and contract drilling expense increased by $109.3 million, or 23%, and $48.4 million, or 27%, respectively, as compared to the prior year. The increase in revenues and contract drilling expense primarily was due to the commencement of ENSCO 8502, ENSCO 8503 and ENSCO 8504 drilling operations as previously noted, partially offset by idle time on ENSCO 7500 as the rig recently completed an enhancement project in a shipyard in Singapore and mobilized to Brazil where the rig commenced drilling operations in December 2011. Depreciation expense increased by $35.4 million, or 79%, excluding $121.5 million of expense attributable to the impact of the Merger. The increase in depreciation expense primarily was due to the aforementioned addition of ENSCO 8502, ENSCO 8503 and ENSCO 8504 to our Deepwater segment.

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 segment 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 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 aforementioned addition of ENSCO 8500, ENSCO 8501 and ENSCO 8502 to our Deepwater segment.

Midwater

During 2011, revenues of $273.8 million were attributable to our Midwater fleet acquired in connection with the Merger, which is comprised of five semisubmersible rigs currently operating in Brazil and one semisubmersible rig operating in West Africa. Utilization and average day rates of our Midwater fleet were 85% and $235,000, respectively, during 2011. Utilization primarily was impacted by ENSCO 5003 and ENSCO 6000, which incurred idle time for repairs and a shipyard project during the year, respectively.

Jackup

During 2011, excluding $49.8 million of revenues attributable to the impact of the Merger, Jackup revenues declined by $39.6 million, or 3%, as compared to the prior year. The decline in revenues primarily was due to a 6% decline in average day rates, excluding the impact of the Merger, resulting from lower levels of spending by oil and gas companies coupled with excess rig availability. The decline in average day rates primarily was attributable to the Asia Pacific Rim, Middle East and Africa markets. Contract drilling expense increased by $14.5 million, or 3%, excluding $31.2 million of expense attributable to the impact of the Merger. The increase in contract drilling expense primarily was due to increased personnel costs and repair and maintenance expense, partially offset by gains associated with the disposal of assets and a cash settlement of our insurance claim made under the package policy for ENSCO 69. Depreciation expense was comparable to the prior year period, excluding $6.6 million of expense attributable to the impact of the Merger.

During 2010, Jackup revenues declined by $413.2 million, or 25%, as compared to the prior year. The decline in revenues primarily was due to a 30% decline in average day rates due to lower levels of spending by oil and gas companies across all regions, partially offset by an increase in utilization to 77% from 74% during the prior year. The increase in utilization primarily resulted from the reduced supply of available jackup rigs in the U.S. Gulf of Mexico, including the mobilization of four of our jackup rigs to Mexico during 2009, and lower market day rates in the region. Contract drilling expense declined by $20.8 million, or 3%, as compared to the prior year, primarily due to a $17.3 million loss recorded on the disposal of ENSCO 69 during 2009 and a decline in repair and maintenance expense and personnel costs during 2010. This decline was partially offset by an $11.9 million reduction of our allowance for doubtful accounts during 2009 which was recorded during 2008 and related to ENSCO 69 drilling operations. Depreciation expense increased by 3% as compared to the prior year, primarily due to the addition of ENSCO 109 to our Jackup segment and depreciation on minor upgrades and improvements during 2010.

Other

During 2011, other revenues and contract drilling expense primarily were attributable to our managed drilling rig operations acquired in connection with the Merger. Other contract drilling expense incurred during 2010 primarily was related to a $12.2 million loss on the impairment of ENSCO I, our only barge rig.

Reconciling Items

During 2011, excluding general and administrative expense of $35.5 million attributable to the impact of the Merger, general and administrative expense increased by $37.0 million, or 43%, as compared to the prior year due to increased advisory, legal, accounting, valuation and other professional or consulting fees incurred by Ensco to effect the Merger, in addition to professional fees and personnel expense incurred by Ensco as a result of related ongoing integration efforts.

During 2010, general and administrative expense increased by $22.1 million, or 35%, as compared to the prior year. This increase primarily was 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.

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, 2011 and includes the results of Pride from the Merger Date (in millions):

	2011			2010			2009

Interest income		$ 17.2			$ .7			$ 2.2
Interest expense, net:
Interest expense		(176.1	)		(21.3	)		(20.9	)
Capitalized interest		80.2			21.3			20.9
		(95.9	)		--			--
Other, net		21.0			17.5			6.6
		$(57.7	)		$ 18.2			$ 8.8

During 2011, interest income increased as compared to the prior year due to interest earned on certain long-term receivables for reimbursement of mobilization and capital upgrade costs. Interest expense increased during 2011 as compared to the prior year primarily due to an increase in outstanding debt resulting from our public offering in March 2011 of $2.5 billion aggregate principal amount of senior notes, in addition to $1.9 billion aggregate principal amount of debt assumed in connection with the Merger. Interest expense of $80.2 million was capitalized in connection with our newbuild construction during 2011. All interest expense incurred during 2010 and 2009 was capitalized in connection with our newbuild construction. Information on our senior notes and debt assumed in connection with the Merger is discussed in Note 5 to our consolidated financial statements.

Our functional currency is the U.S. dollar, and a portion of the revenues earned and expenses incurred by certain 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. Net foreign currency exchange gains of $16.9 million, $3.5 million and $2.6 million were included in other, net, on our consolidated statements of income for the years ended December 31, 2011, 2010 and 2009, respectively.

During 2011, a net gain of $4.8 million associated with the sale of our auction rate securities was included in other, net, on our consolidated statement of income for the year ended December 31, 2011. The fair value measurement of our auction rate securities is discussed in Note 3 to our consolidated financial statements.

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, on our consolidated statement of income for the year ended December 31, 2010.

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 others, the transfer of ownership of several of our drilling rigs among our subsidiaries.

Income tax expense was $131.0 million, $96.0 million and $180.0 million and our consolidated effective income tax rate was 17.8%, 14.9% and 19.2% during the years ended December 31, 2011, 2010 and 2009, respectively. Our consolidated effective income tax rate for 2011 includes the impact of various discrete tax items, the majority of which is attributable to a gain on disposal of assets in a jurisdiction with a high tax rate and the recognition of a liability for unrecognized tax benefits associated with a tax position taken in a prior year. Excluding the impact of the aforementioned discrete items, our consolidated effective income tax rate for the year ended December 31, 2011 was 16.0%. The increase in our 2011 consolidated effective income tax rate, excluding discrete tax items, to 16.0% from 14.9% in the prior year was due to unrecognized benefits related to net operating losses and foreign tax credits of certain subsidiaries acquired during 2011, partially offset by the aforementioned transfer of drilling rig ownership in connection with the reorganization of our worldwide operations and other changes in taxing jurisdictions in which our drilling rigs are operated and/or owned that resulted in an increase in the relative components of our earnings generated in tax jurisdictions with lower tax rates.

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.

LIQUIDITY AND CAPITAL RESOURCES

Although our business is cyclical, we historically have relied on our cash flow from continuing operations to meet liquidity needs and fund the majority of our cash requirements. We have maintained a strong financial position through the disciplined and conservative use of debt, which has provided us the ability to achieve future growth potential through acquisitions and newbuild rig construction. A substantial portion of our cash flow has been and will continue to be invested in the expansion and enhancement of our fleet of drilling rigs in general and our newbuild construction in particular.

On May 31, 2011, we completed the Merger, which was financed through a combination of existing cash and cash equivalents, including proceeds from our public offering in March 2011 of $1.0 billion aggregate principal amount of 3.25% senior notes due 2016, $1.5 billion aggregate principal amount of 4.70% senior notes due 2021 and borrowings under our commercial paper program. Total consideration paid to Pride shareholders was $2.8 billion of cash and the delivery of 85.8 million Ensco ADSs. Furthermore, we assumed $1.9 billion aggregate principal amount of long-term debt in conjunction with the Merger. Given the number of our rigs under construction, the amount of debt issued to finance a portion of the Merger and the amount of debt assumed in the Merger, it is contemplated that our cash flows primarily will be dedicated to finance newbuild construction through 2014 and to service our long-term debt.

During 2011 and 2010, our cash flows from operations were negatively influenced by the Macondo well incident and associated new regulatory, legislative or permitting requirements, which may continue into 2012. However, based on our strong balance sheet current contractual backlog of over $9.6 billion, we believe our future operations and obligations associated with our newbuild construction primarily will be funded from future operating cash flow and borrowings under our commercial paper program and/or credit facilities.

During the three-year period ended December 31, 2011, our primary source of cash was an aggregate $2.7 billion generated from operating activities of continuing operations, $2.5 billion in proceeds from the issuance of our senior notes, $167.5 million of proceeds from the sale of five jackup rigs and $125.0 million in net proceeds from our commercial paper program. Our primary uses of cash during the same period included $2.8 billion paid for the cash consideration of the Merger; $2.5 billion for the construction, enhancement and other improvement of our drilling rigs, including $1.6 billion invested in our newbuild construction; $460.2 million for the payment of dividends; $247.7 million for reduction of long-term borrowings and $186.0 million for the acquisition of ENSCO 109.

Detailed explanations of our liquidity and capital resources for each of the years in the three-year period ended December 31, 2011 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, 2011 were as follows (in millions):

	2011	2010	2009

Cash flows from operating activities of continuing operations	$732.3	$816.7	$1,185.6

Capital expenditures on continuing operations:
New rig construction	$394.0	$567.5	$ 623.4
Rig acquisition	--	184.2	--
Rig enhancements	186.7	36.3	153.0
Minor upgrades and improvements	160.9	87.3	80.8
	$741.6	$875.3	$ 857.2

During 2011, cash flows from continuing operations declined by $84.4 million, or 10%, as compared to the prior year. The decrease primarily resulted from a $932.0 million increase in cash payments related to contract drilling expenses, a $75.0 million increase in cash payments for interest and a $142.0 million increase in cash payments related to general and administrative costs, which was primarily attributable to the Merger. The aforementioned items partially were offset by a $991.0 million increase in cash receipts from contract drilling services, a $48.0 million decline in tax payments and a $33.0 million increase in cash receipts from the sale of our auction rate securities.

During 2010, cash flows from continuing operations declined by $368.9 million, or 31%, as compared to the prior year. The decrease primarily resulted 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.

We continue to maintain our long-established strategy of high-grading our jackup rig fleet by investing in newer equipment while expanding the size and quality of our deepwater drilling rig fleet. During the three-year period ended December 31, 2011, we invested $1.6 billion in the construction of new drilling rigs and an additional $376.0 million upgrading the capability and extending the useful lives of our existing fleet.

In February 2011, we entered into agreements with KFELS to construct two ultra-high specification harsh environment jackup rigs (ENSCO 120 and ENSCO 121) for an estimated total construction cost of approximately $230.0 million per rig. We also entered into an agreement with KFELS in October 2011 to construct a third jackup rig of the same design (ENSCO 122) for an estimated total construction cost of approximately $260.0 million. These rigs are scheduled for delivery during the first and second half of 2013 and the second half of 2014, respectively. ENSCO 120 is committed under a long-term drilling contract in the North Sea, while the other two jackup rigs under construction are uncontracted.

We previously contracted KFELS to construct seven ultra-deepwater semisubmersible rigs (the "ENSCO 8500 Series®" rigs) based on our proprietary design. ENSCO 8501 was delivered and commenced drilling operations under a long-term contract in the U.S. Gulf of Mexico during 2009. ENSCO 8502 was delivered and commenced drilling operations under a long-term contract in the U.S. Gulf of Mexico during 2010. ENSCO 8503 was delivered in 2010 and commenced drilling operations in French Guiana under a short-term sublet agreement during the first quarter of 2011. ENSCO 8503 is expected to commence drilling operations in the U.S. Gulf of Mexico under a long-term contract during the first quarter of 2012. ENSCO 8504 was delivered and commenced drilling operations under a long-term contract in Brunei during the third quarter of 2011. ENSCO 8505 was delivered in January 2012 and is expected to commence drilling operations under a long-term contract in the U.S. Gulf of Mexico during the second quarter of 2012. We also have remaining one ENSCO 8500 Series® ultra-deepwater semisubmersible rig under construction (ENSCO 8506), which is committed under a long-term contract in the U.S. Gulf of Mexico and scheduled for delivery in the second half of 2012.

In connection with the Merger, we acquired seven drillships, two of which were under construction. ENSCO DS-6 was delivered in January 2012 and we expect it will be committed under a long-term drilling contract in the near-term. We also have remaining one uncontracted ultra-deepwater drillship (DS-7) under construction with a scheduled delivery date in the second half of 2013. ENSCO DS-3, ENSCO DS-4 and ENSCO DS-5 commenced drilling operations under long-term contracts in June, May and July 2011, respectively.

Based on our current projections, we expect capital expenditures during 2012 to include approximately $1.2 billion for newbuild construction, approximately $380.0 million for rig enhancement projects and approximately $250.0 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 total debt, total capital and total debt to total capital ratios as of December 31, 2011, 2010 and 2009 are summarized below (in millions, except percentages):

	2011	2010	2009

Total debt	$ 5,050.1	$ 257.3	$ 274.4
Total capital*	15,929.4	6,216.8	5,773.6
Total debt to total capital	31.7%	4.2%	4.8%

Total capital includes total debt plus Ensco shareholders' equity.

Senior Notes

On March 17, 2011, we issued $1.0 billion aggregate principal amount of unsecured 3.25% senior notes due 2016 at a discount of $7.6 million and $1.5 billion aggregate principal amount of unsecured 4.70% senior notes due 2021 at a discount of $29.6 million (collectively the "Notes") in a public offering. Interest on the Notes is payable semiannually in March and September of each year. The Notes were issued pursuant to an indenture between us and Deutsche Bank Trust Company Americas, as trustee (the "Trustee"), dated March 17, 2011 (the "Indenture"), and a supplemental indenture between us and the Trustee, dated March 17, 2011 (the "Supplemental Indenture"). The proceeds from the sale of the Notes were used to fund a portion of the cash consideration payable in connection with the Merger.

We may also redeem each series of the Notes, in whole or in part, at any time, at a price equal to 100% of their principal amount, plus accrued and unpaid interest and a "make-whole" premium. The Notes, the Indenture and the Supplemental Indenture also contain customary events of default, including failure to pay principal or interest on the Notes when due, among others. The Supplemental Indenture contains certain restrictions, including, among others, restrictions on our ability and the ability of our subsidiaries to create or incur secured indebtedness, enter into certain sale/leaseback transactions and enter into certain merger or consolidation transactions.

Acquired Debt

In connection with the Merger, we assumed Pride’s outstanding debt comprised of $900.0 million aggregate principal amount of 6.875% senior notes due 2020, $500.0 million of 8.500% senior notes due 2019, $300.0 million of 7.875% senior notes due 2040 (collectively the "Pride Notes") and $151.5 million of Maritime Administration ("MARAD") bonds due 2016. Under a supplemental indenture dated May 31, 2011 to the original indenture dated July 1, 2004, Ensco plc fully and unconditionally guaranteed performance of all obligations of Pride with respect to the Pride Notes. The guarantee of the Pride Notes was made to allow us greater operating flexibility and provides for, among others, modifications of certain reporting requirements and the ability to transfer assets among Ensco subsidiaries. See Note 16 to our consolidated financial statements for additional information on the guarantee of the Pride Notes. In addition, we assumed debt outstanding with respect to Pride’s senior unsecured revolving credit facility totaling $181.0 million which was repaid in full and the facility terminated upon completion of the Merger.

We may also redeem each series of the Pride Notes, in whole or in part, at any time, at a price equal to 100% of their principal amount, plus accrued and unpaid interest and a "make-whole" premium. The Pride Notes also contain customary events of default, including failure to pay principal or interest on the Pride Notes when due, among others. The Pride Notes contain certain restrictions, including, among others, restrictions on our ability and the ability of our subsidiaries to create or incur secured indebtedness, enter into certain sale/leaseback transactions and enter into certain merger or consolidation transactions.

Revolving Credit

On May 12, 2011, we entered into an amended and restated agreement (the "Five-Year Credit Facility") with a syndicate of banks that provided for a $700.0 million unsecured revolving credit facility for general corporate purposes. On May 31, 2011, upon the consummation of the Merger, and pursuant to the terms of the Five-Year Credit Facility, the commitment under the Five-Year Credit Facility increased from $700.0 million to $1.45 billion. In addition, certain of Ensco’s subsidiaries became borrowers and/or guarantors of the Five-Year Credit Facility. The Five-Year Credit Facility has a five-year term, expiring in May 2016, and replaces our $700.0 million four-year credit agreement which was scheduled to mature in May 2014. Advances under the Five-Year Credit Facility bear interest at LIBOR plus an applicable margin rate (currently 1.5% per annum), depending on our credit rating. We are required to pay a quarterly undrawn facility fee (currently 0.20% per annum) on the total $1.45 billion commitment, which is also based on our credit rating. We also are required to maintain a total debt to total capitalization ratio less than or equal to 50% under the Five-Year Credit Facility. We have the right, subject to lender consent, to increase the commitments under the Five-Year Credit Facility to an aggregate amount of up to $1.7 billion. We had no amounts outstanding under the Five-Year Credit Facility or our prior credit agreement as of December 31, 2011 and December 31, 2010, respectively.

On May 12, 2011, we entered into a 364-Day Credit Agreement (the "364-Day Credit Facility") with a syndicate of banks. The 364-Day Credit Facility provided for a $450.0 million unsecured revolving credit facility to be used for general corporate purposes, which would not be available for borrowing until certain conditions at the closing of the Merger were satisfied. On May 31, 2011, upon the consummation of the Merger, the full commitment of $450.0 million under the 364-Day Credit Facility became available for Ensco to use for general corporate purposes. In addition, certain of Ensco’s subsidiaries became borrowers and/or guarantors of the 364-Day Credit Facility. The 364-Day Credit Facility has a one-year term, expiring in May 2012, or the date of the termination of the lender commitments as set forth in the 364-Day Credit Facility. Upon our election prior to maturity, amounts outstanding under the 364-Day Credit Facility may be converted into a term loan with a maturity date of May 11, 2013 after payment of a fee equal to 1% of the amounts converted. Advances under the 364-Day Credit Facility bear interest at LIBOR plus an applicable margin rate (currently 1.50% per annum) depending on our credit rating. We are required to pay a quarterly undrawn facility fee (currently 0.10% per annum) on the total $450.0 million commitment, which is also based on our credit rating. We also are required to maintain a total debt to total capitalization ratio less than or equal to 50% under the 364-Day Credit Facility. We have the right, subject to lender consent, to increase the commitments under the 364-Day Credit Facility to an aggregate amount of up to $550.0 million. We had no amounts outstanding under the 364-Day Credit Facility as of December 31, 2011.

Commercial Paper

On April 26, 2011, we entered into a commercial paper program with four commercial paper dealers pursuant to which we may issue, on a private placement basis, unsecured commercial paper notes up to a maximum aggregate amount outstanding at any time of $700.0 million. On May 31, 2011, following the consummation of the Merger, Ensco increased the maximum aggregate amount of the commercial paper program to $1.0 billion. Under the commercial paper program, we may issue commercial paper from time to time, and the proceeds of such financings will be used for capital expenditures and other general corporate purposes. The commercial paper will bear interest at rates that will vary based on market conditions and the ratings assigned by credit rating agencies at the time of issuance. The weighted-average interest rate on our commercial paper borrowings was 0.40% during 2011. The maturities of the commercial paper will vary, but may not exceed 364 days from the date of issuance. The commercial paper is not redeemable or subject to voluntary prepayment by us prior to maturity. We had $125.0 million outstanding under our commercial paper program as of December 31, 2011.

Other Financing

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 committed to provide a $2.8 billion unsecured bridge term loan facility (the "Bridge Term Facility") to fund a portion of the cash consideration in the Merger. Upon receipt of the proceeds from the issuance of the Notes, we determined that we had adequate cash resources to fund the cash component of the consideration payable in connection with the Merger and accordingly, the Bridge Term Facility was terminated in March 2011.

We filed an immediately effective Form S-3 Registration Statement with the Securities and Exchange Commission ("SEC") on January 13, 2012, which provides us the ability to issue debt securities, equity securities, guarantees and/or units of securities in one or more offerings from time to time. The registration statement, as amended, expires in January 2015.

In addition to the MARAD bonds assumed in connection with the Merger, we had an aggregate $91.2 million outstanding as of December 31, 2011 under two separate MARAD bond issues that require semiannual principal and interest payments and are due in 2015 and 2020, respectively. We also make semiannual interest payments on $150.0 million of 7.20% debentures due in 2027.

The Board of Directors of our U.S. subsidiary and predecessor, Ensco Delaware, previously authorized the repurchase of up to $1.5 billion of our ADSs. 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 three-year period ended December 31, 2011. Although $562.4 million remained available for repurchase as of December 31, 2011, 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, future operating cash flows, funds borrowed under our commercial paper program and, if necessary, funds borrowed under our credit facilities or other future financing arrangements. The actual timing of our new rig construction payments may vary based on the completion of various construction milestones, which are beyond our control. The following table summarizes our significant contractual obligations, inclusive of the significant contractual obligations assumed as a result of the Merger, as of December 31, 2011 and the periods in which such obligations are due (in millions):

	Payments due by period
		2013	2015
		and	and	After
	2012	2014	2016	2016	Total

New rig construction agreements	$ 920.5	$ 894.7	$ --	$ --	$1,815.2
Principal payments on long-term debt(1)	47.5	94.9	1,067.1	3,368.0	4,577.5
Interest payments on long-term debt	252.2	497.5	472.2	1,358.7	2,580.6
Operating leases	15.8	18.8	16.2	17.7	68.5
Total contractual obligations(2)(3)	$1,236.0	$1,505.9	$1,555.5	$4,744.4	$9,041.8

(1)	Contractual obligations do not include $125.0 million of borrowings outstanding under our commercial paper program as of December 31, 2011, which was classified as short-term debt on our consolidated balance sheet.

(2)	Contractual obligations do not include $76.7 million of unrecognized tax benefits, inclusive of interest and penalties, included on our consolidated balance sheet as of December 31, 2011. We are unable to specify with certainty 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, 2011, we had derivatives outstanding to exchange an aggregate $337.3 million U.S. dollars for various foreign currencies. As of December 31, 2011, our consolidated balance sheet included a net derivative liability of $7.1 million. All of our outstanding derivatives mature during the next 17 months.

Liquidity

Our liquidity position as of December 31, 2011, 2010 and 2009 is summarized below (in millions, except ratios):

	2011	2010	2009

Cash and cash equivalents	$430.7	$1,050.7	$1,141.4
Working capital	321.3	1,087.7	1,167.9
Current ratio	1.2	4.1	3.4

Upon completion of the Merger, we increased our indebtedness, which included Pride’s debt obligations outstanding on the Merger Date. In addition, various commitments and contractual obligations in connection with Pride’s normal course of business remained outstanding after the Merger, including obligations associated with Pride’s newbuild program.

We expect to fund our short-term liquidity needs, including contractual obligations and anticipated capital expenditures, as well as any dividends, stock repurchases or working capital requirements, from our operating cash flow and funds borrowed under our commercial paper program and/or 364-Day Credit Facility. We expect to fund our long-term liquidity needs, including contractual obligations, anticipated capital expenditures and dividends, from our operating cash flow and, if necessary, funds borrowed under our Five-Year Credit Facility or other future financing arrangements. We may decide to access debt and/or equity markets to raise additional capital or increase liquidity as necessary.

Effects of Climate Change and Climate Change Regulation

Greenhouse gas emissions have increasingly become the subject of international, national, regional, state and local attention. Cap and trade initiatives to limit greenhouse gas emissions have been introduced in the European Union. Similarly, numerous bills related to climate change have been introduced in the U.S. Congress, which could adversely impact 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

We use derivatives to reduce our exposure to 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 and expenses are denominated in U.S. dollars; however, a portion of the revenues earned and expenses incurred by certain 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 may employ an interest rate risk management strategy that utilizes derivative instruments to mitigate 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 on future expected contract drilling expenses denominated in various foreign currencies. 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 mitigate 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, 2011, we had derivatives outstanding to exchange an aggregate $337.3 million for various foreign currencies. 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, 2011 would approximate $19.3 million. 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 17 months. See Note 6 to our consolidated financial statements for additional information on our derivative instruments.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

The preparation of financial statements and related disclosures in conformity with accounting principles generally accepted in the United States of America 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, 2011, the carrying value of our property and equipment totaled $12.4 billion, which represented 70% 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 18 deepwater rigs, exclusive of three rigs under construction, represented 61% of the gross cost and 70% of the net carrying amount of our depreciable property and equipment as of December 31, 2011. Our deepwater rigs are depreciated over useful lives ranging from 15 to 35 years. Our fleet of six midwater rigs represented 7% of the gross cost and 8% of the net carrying amount of our depreciable property and equipment as of December 31, 2011. Our midwater rigs are depreciated over useful lives ranging from 15 to 30 years. Our fleet of 46 jackup rigs, exclusive of three rigs under construction, represented 29% of the gross cost and 20% of the net carrying amount of our depreciable property and equipment as of December 31, 2011. Our jackup rigs are depreciated over useful lives ranging from 10 to 30 years. 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, 2011 for various assumed changes in the useful lives of our drilling rigs effective January 1, 2011:

Increase (decrease) in useful lives of our drilling rigs		Estimated increase (decrease) in depreciation expense that would have been recognized (in millions)

10%		$(44.6)
20%		(75.7)
(10%)		15.5
(20%)		55.6

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 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. 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 generally may be moved from markets with excess supply, if economically feasible. Our drilling rigs are suited for, and accessible to, broad and numerous markets throughout the world.

For property and equipment used in our operations, recoverability generally is 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 may 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. When testing goodwill for impairment, we perform a qualitative assessment to determine whether it is more-likely-than-not that the fair value of a reporting unit is less than its carrying amount. Our three reportable segments represent our reporting units. If we determine it is more-likely-than-not that the fair value of a reporting unit exceeds its carrying value after qualitatively assessing the totality of facts and circumstances, its goodwill is considered not impaired.

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 a quantitative assessment whereby we estimate the fair value of each reporting unit. 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, 2011, 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, 2011, our consolidated balance sheet included a $316.4 million net deferred income tax liability, a $45.5 million liability for income taxes currently payable and a $76.7 million liability for unrecognized tax benefits, inclusive of interest and penalties.

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.

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 Internal Revenue Service and/or Her Majesty's Revenue and Customs may disagree with our interpretation of tax laws, treaties, or regulations with respect to our redomestication to the U.K in December 2009.
	•	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 generally are subject to complex tax regulations and frequently are 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 May 2011, the FASB issued the Accounting Standard Update 2011-04, "Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs" ("Update 2011-04") which is effective for public entities during interim and annual periods beginning after December 15, 2011. The amendments in Update 2011-04 are to be applied prospectively and early application by public entities is not permitted. Update 2011-04 provides amendments to Topic 820, "Fair Value Measurement" which apply to all reporting entities that are required or permitted to measure or disclose the fair value of an asset, a liability, or an instrument classified in a reporting entity’s shareholders’ equity in the financial statements. The amendments included in this update are intended to clarify the application of existing fair value measurement requirements. We will adopt Update 2011-04 upon its effective date of January 1, 2012. We do not expect the adoption of Update 2011-04 to have a material effect on our consolidated financial statements.

In June 2011, the FASB issued the Accounting Standard Update 2011-05, "Presentation of Comprehensive Income" ("Update 2011-05") which is effective for public entities for fiscal years, and interim periods within those years, beginning after December 15, 2011. Update 2011-05 provides amendments to Topic 220, "Comprehensive Income," to be applied retrospectively. Early adoption is permitted, because compliance with the amendments is already permitted. The amendments do not require any transition disclosures. Update 2011-05 requires that all non-owner changes in stockholders’ equity be presented either in a single continuous statement of comprehensive income or in two separate but consecutive statements. In the two-statement approach, the first statement should present total net income and its components followed consecutively by a second statement that should present total other comprehensive income, the components of other comprehensive income and the total of comprehensive income. In December 2011, the FASB issued Accounting Standards Update 2011-12, “Comprehensive Income (Topic 220): Deferral of the Effective Date for Amendments to the Presentation of Reclassification Items Out of Accumulated Comprehensive Income in Accounting Standards Update 2011-05,” or Update 2011-12. Update 2011-12 maintained the presentation requirements for comprehensive income under Update 2011-05 while deferring the requirement to present certain reclassification adjustments into and out of accumulated other comprehensive income on a gross basis. Update 2011-05 and Update 20011-12 are both effective for public entities during interim and annual periods beginning after December 15, 2011 and should be applied retrospectively to all periods reported after the effective date. We will adopt Update 2011-05 and Update 2011-12 upon its effective date of January 1, 2012. We do not expect the adoption of Update 2011-05 and Update 2011-12 to have a material effect on our consolidated financial statements.

In September 2011, the FASB issued the Accounting Standard Update 2011-08, "Testing Goodwill for Impairment" ("Update 2011-08") which is effective for public entities during interim and annual periods beginning after December 15, 2011. The amendments in Update 2011-08 are to be applied prospectively and early adoption is permitted, including for annual and interim goodwill impairment tests performed as of a date before September 15, 2011. Update 2011-08 provides amendments to Topic 350, "Intangibles - Goodwill and Other" which apply to all reporting entities that disclose goodwill in the financial statements. We early adopted Update 2011-08 as of December 31, 2011. The adoption of Update 2011-08 did not have any effect on our consolidated financial statements.

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.

On May 31, 2011, we completed a merger transaction with Pride International, Inc., as discussed in the Explanatory Note to this annual report. We excluded Pride from our assessment of the effectiveness of our internal control over financial reporting as of December 31, 2011. Total revenues subject to Pride’s internal control over financial reporting represented 39% of our consolidated revenues during the year ended December 31, 2011. Total assets subject to Pride’s internal control over financial reporting represented 46% of our consolidated total assets as of December 31, 2011.

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, 2011 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, has 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, 2012

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, 2011 and 2010, and the related consolidated statements of income and cash flows for each of the years in the three-year period ended December 31, 2011. 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, 2011 and 2010, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2011, 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, 2011, 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, 2012, expressed an unqualified opinion on the effectiveness of the Company's internal control over financial reporting. This report contains an explanatory paragraph stating that the Company acquired Pride International Inc. (Pride) during 2011 and management excluded from its assessment of the effectiveness of Ensco plc’s internal control over financial reporting as of December 31, 2011, Pride’s internal control over financial reporting associated with total assets of $8.2 billion and total revenues of $1.1 billion included in the consolidated financial statements of Ensco plc and subsidiaries as of and for the year ended December 31, 2011. Our audit of internal control over financial reporting of Ensco plc also excluded an evaluation of the internal control over financial reporting of Pride.

/s/ KPMG LLP

Houston, Texas

February 24, 2012

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Shareholders

Ensco plc:

We have audited Ensco plc and subsidiaries’ (Ensco or Company) internal control over financial reporting as of December 31, 2011, 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, 2011, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

Ensco acquired Pride International Inc. (Pride) during 2011, and management excluded from its assessment of the effectiveness of Ensco’s internal control over financial reporting as of December 31, 2011, Pride’s internal control over financial reporting associated with total assets of $8.2 billion and total revenues of $1.1 billion included in the consolidated financial statements of Ensco as of and for the year ended December 31, 2011. Our audit of internal control over financial reporting of Ensco also excluded an evaluation of the internal control over financial reporting of Pride.

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, 2011 and 2010, and the related consolidated statements of income and cash flows for each of the years in the three-year period ended December 31, 2011, and our report dated February 24, 2012 expressed an unqualified opinion on those consolidated financial statements.

/s/ KPMG LLP

Houston, Texas

February 24, 2012

ENSCO PLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

(in millions, except per share amounts)

	Year Ended December 31,
	2011			2010		2009

OPERATING REVENUES		$2,842.7		$1,696.8		$1,888.9

OPERATING EXPENSES
Contract drilling (exclusive of depreciation)		1,470.9		768.1		709.0
Depreciation		418.9		216.3		189.5
General and administrative		158.6		86.1		64.0
		2,048.4		1,070.5		962.5
OPERATING INCOME		794.3		626.3		926.4

OTHER INCOME (EXPENSE)
Interest income		17.2		.7		2.2
Interest expense, net		(95.9	)	--		--
Other, net		21.0		17.5		6.6
		(57.7	)	18.2		8.8

INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES		736.6		644.5		935.2

PROVISION FOR INCOME TAXES
Current income tax expense		150.6		81.7		159.5
Deferred income tax (benefit) expense		(19.6	)	14.3		20.5
		131.0		96.0		180.0

INCOME FROM CONTINUING OPERATIONS		605.6		548.5		755.2

DISCONTINUED OPERATIONS, NET		--		37.4		29.3

NET INCOME		605.6		585.9		784.5

NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS		(5.2	)	(6.4	)	(5.1	)

NET INCOME ATTRIBUTABLE TO ENSCO		$ 600.4		$ 579.5		$ 779.4

EARNINGS PER SHARE - BASIC
Continuing operations		$ 3.09		$ 3.80		$ 5.28
Discontinued operations		--		.26		.20
		$ 3.09		$ 4.06		$ 5.48
EARNINGS PER SHARE - DILUTED
Continuing operations		$ 3.08		$ 3.80		$ 5.28
Discontinued operations		--		.26		.20
		$ 3.08		$ 4.06		$ 5.48
NET INCOME ATTRIBUTABLE TO ENSCO SHARES
Basic		$ 593.5		$ 572.1		$ 769.7
Diluted		$ 593.5		$ 572.1		$ 769.7
WEIGHTED-AVERAGE SHARES OUTSTANDING
Basic		192.2		141.0		140.4
Diluted		192.6		141.0		140.5

CASH DIVIDENDS PER SHARE		$ 1.40		$ 1.075		$ .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	2011		2010
CURRENT ASSETS
Cash and cash equivalents	$ 430.7		$1,050.7
Accounts receivable, net	838.3		214.6
Other	375.7		171.4
Total current assets	1,644.7		1,436.7

PROPERTY AND EQUIPMENT, AT COST	14,485.7		6,744.6
Less accumulated depreciation	2,061.5		1,694.7
Property and equipment, net	12,424.2		5,049.9

GOODWILL	3,288.8		336.2

OTHER ASSETS, NET	513.5		228.7
	$17,871.2		$7,051.5

LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable - trade	$ 643.5		$ 163.5
Accrued liabilities and other	507.4		168.3
Short-term debt	125.0		--
Current maturities of long-term debt	47.5		17.2
Total current liabilities	1,323.4		349.0

LONG-TERM DEBT	4,877.6		240.1

DEFERRED INCOME TAXES	339.5		358.0

OTHER LIABILITIES	446.2		139.4

COMMITMENTS AND CONTINGENCIES

ENSCO SHAREHOLDERS' EQUITY
Class A ordinary shares, U.S. $.10 par value, 450.0 million shares authorized, 235.8 million and 150.0 million shares issued as of December 31, 2011 and 2010	23.6		15.0
Class B ordinary shares, £1 par value, 50,000 shares authorized and issued as of December 31, 2011 and 2010	.1		.1
Additional paid-in capital	5,253.0		637.1
Retained earnings	5,613.1		5,305.0
Accumulated other comprehensive income	8.6		11.1
Treasury shares, at cost, 4.9 million shares and 7.1 million shares	(19.1	)	(8.8	)
Total Ensco shareholders' equity	10,879.3		5,959.5

NONCONTROLLING INTERESTS	5.2		5.5
Total equity	10,884.5		5,965.0
	$17,871.2		$7,051.5

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,
	2011			2010		2009
OPERATING ACTIVITIES
Net income		$ 605.6		$ 585.9		$ 784.5
Adjustments to reconcile net income to net cash provided
by operating activities of continuing operations:
Depreciation expense		418.9		216.3		189.5
Share-based compensation expense		47.7		44.5		35.5
Amortization of intangibles and other, net		(42.4	)	31.4		31.0
Deferred income tax (benefit) expense		(19.6	)	14.3		20.5
Loss on asset impairment		--		12.2		17.3
Discontinued operations, net		--		(37.4	)	(29.3	)
Other		(13.5	)	6.6		7.5
Changes in operating assets and liabilities:
(Increase) decrease in accounts receivable		(247.6	)	110.9		167.4
Increase in other assets		(14.5	)	(10.6	)	(67.6	)
(Decrease) increase in liabilities		(2.3	)	(157.4	)	29.3
Net cash provided by operating activities of continuing operations		732.3		816.7		1,185.6
INVESTING ACTIVITIES
Acquisition of Pride International Inc., net of cash acquired		(2,656.0	)	--		--
Additions to property and equipment		(741.6	)	(875.3	)	(857.2	)
Proceeds from disposal of discontinued operations		--		158.1		14.3
Proceeds from disposition of assets		46.5		1.5		2.6
Other		(4.5	)	--		--
Net cash used in investing activities		(3,355.6	)	(715.7	)	(840.3	)
FINANCING ACTIVITIES
Proceeds from issuance of senior notes		2,462.8		--		--
Cash dividends paid		(292.3	)	(153.7	)	(14.2	)
Reduction of long-term borrowings		(213.3	)	(17.2	)	(17.2	)
Commercial paper borrowings, net		125.0		--		--
Equity financing costs		(70.5	)	--		--
Proceeds from exercise of share options		39.9		1.4		9.6
Debt financing costs		(31.8	)	(6.2	)	--
Other		(15.7	)	(16.9	)	(12.4	)
Net cash provided by (used in) financing activities		2,004.1		(192.6	)	(34.2	)

Effect of exchange rate changes on cash and cash equivalents		(.8	)	(.5	)	.5
Net cash provided by operating activities of discontinued operations		--		1.4		40.2

(DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS		(620.0	)	(90.7	)	351.8

CASH AND CASH EQUIVALENTS, BEGINNING OF YEAR		1,050.7		1,141.4		789.6

CASH AND CASH EQUIVALENTS, END OF YEAR		$ 430.7		$1,050.7		$1,141.4

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

Acquisition of Pride International, Inc.

On May 31, 2011 (the "Merger Date"), Ensco plc completed a merger transaction (the "Merger") with Pride International, Inc., a Delaware corporation ("Pride"), ENSCO International Incorporated, a Delaware corporation and an indirect, wholly-owned subsidiary and predecessor of Ensco plc ("Ensco Delaware"), and ENSCO Ventures LLC, a Delaware limited liability company and an indirect, wholly-owned subsidiary of Ensco plc ("Merger Sub"). Pursuant to the merger agreement and subject to the conditions set forth therein, Merger Sub merged with and into Pride, with Pride as the surviving entity and an indirect, wholly-owned subsidiary of Ensco plc. The total consideration delivered in the Merger was $7.4 billion, consisting of $2.8 billion of cash, 85.8 million Ensco ADSs with an aggregate value of $4.6 billion based on the closing price of Ensco ADSs of $53.32 on the Merger Date and the estimated fair value of $35.4 million of vested Pride employee stock options assumed by Ensco. The results of Pride were included in our consolidated financial statements from the Merger Date.

In connection with the Merger, we acquired seven drillships, including rigs under construction, 12 semisubmersible rigs and seven jackup rigs. As a result, we evaluated our then-current core assets and operations, and organized them into three segments based on water depth operating capabilities. Accordingly, we now consider our business to consist of three reportable segments: (1) Deepwater, which consists of our drillships and semisubmersible rigs capable of drilling in water depths of 4,500 feet or greater, (2) Midwater, which consists of our semisubmersible rigs capable of drilling in water depths of 4,499 feet or less and (3) Jackup, which consists of our jackup rigs capable of drilling in water depths up to 400 feet. Each of our three reportable segments provides one service, contract drilling. We also manage the drilling operations for two deepwater rigs and own one barge rig, which are included in "Other."

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.

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.

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 our results of operations and financial position. The accompanying consolidated financial statements do not constitute statutory accounts required by the U.K. Companies Act 2006, which for year ended December 31, 2011 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 on 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 and Translation

Our functional currency is the U.S. dollar. As is customary in the oil and gas industry, a majority of our revenues and expenses are denominated in U.S. dollars; however, a portion of the revenues earned and expenses incurred by certain 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. Most transaction gains and losses, including certain gains and losses on our derivative instruments, are included in other, net, in our consolidated statement of income. Certain gains and losses from the translation of foreign currency balances of our non-U.S. dollar functional currency subsidiaries are included in accumulated other comprehensive income on our consolidated balance sheet. We incurred net foreign currency exchange gains of $16.9 million, $3.5 million and $2.6 million for the years ended December 31, 2011, 2010 and 2009, 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 a straight-line basis, 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 35 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 generally is 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 a $12.2 million impairment charge on ENSCO I during 2010. 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

On May 31, 2011, we completed the acquisition of Pride resulting in the recognition of a preliminary amount of $2.95 billion in goodwill, including measurement period adjustments. See "Note 2 - Acquisition of Pride International, Inc." for additional information on the Merger. In connection with the Merger, we evaluated our then-current core assets and operations, which consisted of drillships, semisubmersible rigs and jackup rigs and organized them into three segments based on water depth operating capabilities. Accordingly, we now consider our business to consist of three reportable segments: (1) Deepwater, (2) Midwater and (3) Jackup. Our three reportable segments represent our reporting units. The carrying amount of goodwill as of December 31, 2011 is detailed below by reporting unit (in millions):

Deepwater					$2,623.5
Midwater					472.7
Jackup					192.6
Total					$3,288.8

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. When testing goodwill for impairment, we perform a qualitative assessment to determine whether it is more-likely-than-not that the fair value of a reporting unit is less than its carrying amount.

If we conclude that the fair value of one or more of our reporting units has more-likely-than-not declined below its carrying amount after qualitatively assessing the totality of facts and circumstances, we perform a quantitative assessment whereby we estimate the fair value of each reporting unit. 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, 2011. 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 a goodwill impairment. 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 $82.1 million and $51.0 million as of December 31, 2011 and 2010, respectively. Deferred mobilization revenue was included in accrued liabilities and other, and other liabilities on our consolidated balance sheets and totaled $104.3 million and $82.8 million as of December 31, 2011 and 2010, 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 $37.9 million and $27.4 million as of December 31, 2011 and 2010, 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 $9.1 million and $7.0 million as of December 31, 2011 and 2010, 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 6 - 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 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 ("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, 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, 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, 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 sheet depending on maturity date. Derivatives with liability fair values are reported in accrued liabilities and other, or other liabilities on our consolidated balance sheet 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.

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 or derecognized.

We do not provide deferred taxes on the undistributed earnings of Ensco Delaware or Ensco United Incorporated, an indirect wholly-owned subsidiary of Ensco and immediate parent company of Pride, 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 or Ensco United Incorporated's non-U.S. subsidiaries because our policy and intention is to reinvest such earnings indefinitely. See "Note 11 - Income Taxes" for additional information on our deferred taxes, unrecognized tax benefits, intercompany rig sales and reinvestments of certain undistributed earnings.

Share-Based Compensation

We sponsor share-based compensation plans that provide equity compensation to our employees, officers and non-employee 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 10 - 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 represent inputs that are observable for similar assets or liabilities, either directly or indirectly, other than quoted prices included within Level 1. See "Note 3 - 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, 2011 (in millions):

	2011		2010		2009

Net income attributable to Ensco	$600.4		$579.5		$779.4
Net income allocated to non-vested share awards	(6.9	)	(7.4	)	(9.7	)
Net income attributable to Ensco shares	$593.5		$572.1		$769.7

The following table is a reconciliation of the weighted-average shares used in our basic and diluted earnings per share computations for each of the years in the three-year period ended December 31, 2011 (in millions):

	2011	2010	2009

Weighted-average shares - basic	192.2	141.0	140.4
Potentially dilutive share options	.4	.0	.1
Weighted-average shares - diluted	192.6	141.0	140.5

Antidilutive share options totaling 400,000 for the year ended December 31, 2011 and 1.1 million for each of the years ended December 31, 2010 and 2009 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. Certain third parties hold a noncontrolling ownership interest in certain of our non-U.S. subsidiaries.

Income from continuing operations attributable to Ensco for each of the years in the three-year period ended December 31, 2011 was as follows (in millions):

	2011	2010	2009

Income from continuing operations	$605.6	$548.5	$755.2
Income from continuing operations attributable to noncontrolling interests	(5.2)	(6.2)	(4.2)
Income from continuing operations attributable to Ensco	$600.4	$542.3	$751.0

Income from discontinued operations attributable to Ensco for each of the years in the three-year period ended December 31, 2011 was as follows:

	2011	2010	2009

Income from discontinued operations	$ --	$37.4	$29.3
Income from discontinued operations attributable to noncontrolling interests	--	(.2)	(.9)
Income from discontinued operations attributable to Ensco	$ --	$37.2	$28.4

2. ACQUISITION OF PRIDE INTERNATIONAL, INC.

On May 31, 2011, Ensco plc completed a merger transaction with Pride, Ensco Delaware and Merger Sub. Pursuant to the Merger Agreement, among Ensco plc, Pride, Ensco Delaware and Merger Sub, and subject to the conditions set forth therein, Merger Sub merged with and into Pride, with Pride as the surviving entity and an indirect, wholly-owned subsidiary of Ensco plc.

The Merger expands our deepwater fleet with drillship assets, increases our presence in the floater markets as well as various major offshore drilling markets and establishes Ensco with the world's second largest competitive offshore drilling rig fleet. Revenues and net income of Pride from the Merger Date included in our consolidated statements of income were $1.1 billion and $121.0 million, respectively, for the year ended December 31, 2011.

Consideration

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 were cancelled as a result of the Merger) and those shares held by certain U.K. residents if determined by Ensco) were converted into the right to receive $15.60 in cash and 0.4778 Ensco ADSs. Under certain circumstances, U.K. residents received all cash consideration as a result of compliance with legal requirements. The total consideration delivered in the Merger was $7.4 billion, consisting of $2.8 billion of cash, 85.8 million Ensco ADSs with an aggregate value of $4.6 billion based on the closing price of Ensco ADSs of $53.32 on the Merger Date and the estimated fair value of $35.4 million of vested Pride employee stock options assumed by Ensco.

The following table summarizes the components of the merger consideration (dollars in millions, except per share amounts):

Share consideration paid:
179.7 million outstanding shares of Pride common stock converted to 85.8 million Ensco ADSs using the exchange ratio of 0.4778 and valued at $53.32 per share		$4,577.5

Cash and other consideration paid:
179.7 million outstanding shares of Pride common stock at $15.60 per share		2,803.0
Estimated fair value of 2.5 million vested Pride employee stock options assumed by Ensco		35.4
Merger consideration		$7,415.9

Assets Acquired and Liabilities Assumed

The transaction has been accounted for using the acquisition method of accounting which requires that assets acquired and liabilities assumed be recorded at their estimated fair values as of the Merger Date. The excess of the consideration transferred over the estimated fair values of the net assets acquired was recorded as goodwill. We have not finalized the determination of the fair values of the assets acquired and liabilities assumed and, therefore, the fair value estimates set forth below are subject to adjustment during a measurement period not to exceed one year subsequent to the acquisition date as permitted under GAAP. The estimated fair values of certain assets and liabilities, including inventory, taxes and contingencies require judgments and assumptions that increase the likelihood that adjustments may be made to these estimates during the measurement period. The provisional amounts and respective measurement period adjustments recorded for assets acquired and liabilities assumed were based on preliminary estimates of their fair values as of the Merger Date and were as follows:

	Amounts Recognized as of Merger Date	Measurement Period Adjustments(1)	Estimated Fair Value
Assets:
Cash and cash equivalents	$ 147.0	$ --	$ 147.0
Accounts receivable(2)	371.3	24.7	396.0
Other current assets	150.9	4.3	155.2
Property and equipment	6,758.8	(7.2)	6,751.6
Other assets	343.7	--	343.7
Liabilities:
Accounts payable and accrued liabilities and other	539.8	44.6	584.4
Debt	2,436.0	--	2,436.0
Deferred income tax liabilities	19.0	(18.3)	.7
Other liabilities	319.8	(10.7)	309.1
Net assets acquired	4,457.1	6.2	4,463.3
Less merger consideration	7,415.9	--	7,415.9
Goodwill	$2,958.8	$ (6.2)	$2,952.6

(1)

The measurement period adjustments reflect changes in the estimated fair values of certain assets and liabilities, including contingencies and income taxes. The measurement period adjustments were recorded to reflect new information obtained about facts and circumstances existing as of the Merger Date and did not result from intervening events subsequent to the Merger Date. These adjustments did not have a material impact on our previously reported interim results of operations or financial position subsequent to the Merger Date and, therefore, we have not retrospectively adjusted our respective interim condensed consolidated financial statements.

(2)

Gross contractual amounts receivable totaled $453.2 million as of the Merger Date.

Property and Equipment

Property and equipment acquired in connection with the Merger consisted primarily of drilling rigs and related equipment, including seven drillships (two of which were under construction), 12 semisubmersible rigs and seven jackup rigs. We recorded step-up adjustments in the aggregate of $278.3 million to record the estimated fair value of Pride’s drilling rigs and related equipment, which were primarily based on an income approach valuation model. We estimated remaining useful lives for Pride’s drilling rigs, which ranged from 10 to 35 years based on original estimated useful lives of 30 to 35 years.

Goodwill

Goodwill recognized as a result of the Merger was calculated as the excess of the consideration transferred over the net assets acquired and represents the future economic benefits arising from other intangible assets acquired that could not be individually identified and separately recognized. Goodwill specifically includes the expected synergies and other benefits that we believe will result from combining the operations of Pride with the operations of Ensco and other intangible assets that do not qualify for separate recognition, such as assembled workforce in place at the Merger Date. Goodwill is not expected to be tax deductible.

Goodwill recognized as a result of the Merger preliminarily was allocated to our reporting units as follows (in millions):

Deepwater					$2,479.9
Midwater					472.7
Jackup					--
Total					$2,952.6

Other Intangible Assets and Liabilities

We recorded intangible assets and liabilities in the aggregate of $209.0 million and $278.0 million, respectively, representing the estimated fair values of Pride's firm drilling contracts in place at the Merger Date with favorable or unfavorable contract terms as compared to then-current market day rates for comparable drilling rigs. The various factors considered in the determination of these fair values were (1) the contracted day rate for each contract, (2) the remaining term of each contract, (3) the rig class and (4) the market conditions for each respective rig class at the Merger Date. The intangible assets and liabilities were calculated based on the present value of the difference in cash inflows over the remaining contract term as compared to a hypothetical contract with the same remaining term at an estimated then-current market day rate using a risk-adjusted discount rate and an estimated effective income tax rate. After amortizing income of $55.4 million to operating revenues during the year ended December 31, 2011, the remaining balances were $172.6 million of intangible assets included in other current assets and other assets, net, and $186.2 million of intangible liabilities included in accrued liabilities and other and other liabilities on our consolidated balance sheet as of December 31, 2011. These balances will be amortized to operating revenues over the respective remaining drilling contract terms on a straight-line basis. Amortization income (expense) for these intangible assets and liabilities is estimated to be $17.1 million for 2012, $7.9 million for 2013, ($4.3) million for 2014, ($6.7) million for 2015, ($800,000) for 2016 and $400,000 thereafter.

We recorded an intangible liability of $36.0 million for the estimated fair value of an unfavorable drillship construction contract which was determined by comparing the firm obligations for the remaining construction of the ENSCO DS-6 as of May 31, 2011 to then-current market rates for the construction of a similar design drilling rig. The unfavorable construction contract liability was calculated based on the present value of the difference in cash outflows for the remaining contractual payments as compared to a hypothetical contract with the same remaining contractual payments at then-current market rates using a risk-adjusted discount rate and estimated effective income tax rate. This liability will be amortized over the estimated useful life of ENSCO DS-6 as a reduction of depreciation expense beginning on the date the rig is placed into service.

Debt

We assumed Pride's outstanding debt comprised of $900.0 million aggregate principal amount of 6.875% senior notes due 2020, $500.0 million aggregate principal amount of 8.500% senior notes due 2019, $300.0 million aggregate principal amount of 7.875% senior notes due 2040 (collectively the "Pride Notes") and $151.5 million aggregate principal amount of Maritime Administration ("MARAD") bonds due 2016. Under a supplemental indenture, Ensco plc has fully and unconditionally guaranteed the performance of all obligations of Pride with respect to the Pride Notes. See "Note 16 - Guarantee of Registered Securities" for additional information on the guarantee of the Pride Notes. A step-up adjustment of $406.2 million was recorded to adjust the Pride Notes and the MARAD bonds to their aggregate estimated fair value. The adjustment was based on quoted market prices for Pride’s publicly traded debt and an income approach valuation model for Pride’s non-publicly traded debt. This step-up will be amortized over the remaining lives of the respective debt instruments as a reduction of interest expense. In addition, we assumed debt outstanding with respect to Pride's senior unsecured revolving credit facility totaling $181.0 million, which was repaid in full and the facility terminated upon completion of the Merger.

Merger-Related Costs

Merger-related transaction costs consisted of various advisory, legal, accounting, valuation and other professional or consulting fees totaling $23.8 million for the year ended December 31, 2011 and were expensed as incurred and included in general and administrative expense on our consolidated statement of income. Debt issuance costs of $27.2 million associated with our senior notes issued in March 2011 and bridge term facility issued in February 2011 were deferred and are amortized to interest expense over the lives of the respective debt arrangements. The costs of $70.5 million associated with the Ensco ADSs issued to effect the Merger were recorded as a reduction to additional paid-in capital.

Deferred Taxes

The acquisition of a business through the purchase of its common stock generally is treated as a "nontaxable" transaction. The acquisition of Pride was executed through the acquisition of its outstanding common stock and, therefore, the historical tax bases of the acquired assets and assumed liabilities, net operating losses and other tax attributes of Pride were assumed as of the Merger Date. However, adjustments were recorded to recognize deferred tax assets and liabilities for the tax effects of differences between acquisition date fair values and tax bases of assets acquired and liabilities assumed. As of the Merger Date, a decrease of $31.1 million to Pride’s net deferred tax liability was recognized.

Deferred tax assets and liabilities recognized in connection with the Merger were measured at rates enacted as of the Merger Date. Tax rate changes, or any deferred tax adjustments for new tax legislation, following the Merger Date will be reflected in our operating results in the period in which the change in tax laws or rate is enacted.

Contingencies

In connection with the Merger, we recognized contingent liabilities resulting from certain lawsuits, claims or proceedings existing as of the Merger Date. These matters existed as of the Merger Date as Pride was involved from time to time as party to governmental or other 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. See "Note 13 – Commitments and Contingencies" for additional information on contingencies.

Pro Forma Impact of the Merger

The following unaudited supplemental pro forma results present consolidated information as if the Merger had been completed on January 1, 2010. The pro forma results include, among others, (i) the amortization associated with the acquired intangible assets and liabilities, (ii) interest expense associated with debt used to fund a portion of the Merger and (iii) the impact of certain fair value adjustments such as additional depreciation expense for adjustments to property and equipment and reduction to interest expense for adjustments to debt. The pro forma results do not include any potential synergies, non-recurring charges which result directly from the Merger, cost savings or other expected benefits of the Merger. Accordingly, the pro forma results should not be considered indicative of the results that would have occurred if the Merger and related borrowings had occurred on January 1, 2010, nor are they indicative of future results.

(In millions, except per share amounts)	Year Ended
	December 31,
	2011*	2010

Revenues	$3,503.9	$3,223.2
Net income	604.8	805.9
Earnings per share - basic	2.61	3.50
Earnings per share - diluted	2.60	3.49

*	Supplemental pro forma earnings were adjusted to exclude an aggregate $157.6 million of merger-related costs incurred by Ensco and Pride during 2011.

3. 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, 2011 and 2010 (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, 2011
Hercules Offshore, Inc. common stock		$32.2		$ --		$ --		$32.2
Supplemental executive retirement plan assets		25.6		--		--		25.6
Total financial assets		$57.8		$ --		$ --		$57.8
Derivatives, net		$ --		$ 7.1		$ --		$ 7.1
Total financial liabilities		$ --		$ 7.1		$ --		$ 7.1

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

Hercules Offshore, Inc. Common Stock

In December 2011, we received 10.3 million shares of Hercules Offshore, Inc. ("HERO") common stock in connection with the resolution of certain litigation in respect of the previously reported Seahawk Drilling, Inc. bankruptcy claims. Subsequently, we sold 3.0 million shares for $13.4 million of net proceeds in December 2011 and sold the remaining 7.3 million shares for $31.4 million of net proceeds in January 2012. In connection with the bankruptcy, we received an additional 540,000 shares of HERO during 2012, which we sold for $2.4 million. For additional information regarding Seahawk's bankruptcy, see "Seahawk Drilling, Inc. Bankruptcy" in Part I, Item 3. Legal Proceedings of this annual report on Form 10-K.

Our investments in HERO common stock were measured at fair value on a recurring basis using Level 1 inputs and were included in other current assets on our consolidated balance sheet as of December 31, 2011. The fair value measurement of HERO common stock was based on quoted market prices of identical assets. Net unrealized losses of $400,000 were included in other, net, in our consolidated statement of income for the year ended December 31, 2011. We designated our investments in HERO common stock as trading securities as it was our intent to sell them in the near-term. Proceeds from sales of HERO common stock and realized losses recorded during the year ended December 31, 2011 were as follows (in millions):

		2011

Proceeds from sales of HERO common stock		$13.4
Realized losses		.2

Auction Rate Securities

As of December 31, 2010, we held long-term debt instruments with variable interest rates that periodically reset through an auction process ("auction rate securities") totaling $50.1 million (par value) and were included in other assets, net, on our consolidated balance sheet. During the quarter ended March 31, 2011, $42.0 million (par value) of our auction rate securities were repurchased at par and $8.1 million (par value) were sold at 90% of par. Our auction rate securities were measured at fair value on a recurring basis using significant Level 3 inputs as of December 31, 2010. 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, 2011 (in millions):

	2011		2010		2009

Beginning Balance	$44.5		$60.5		$64.2
Sales	(49.3	)	(16.7	)	(5.5	)
Realized losses*	(.1	)	--		--
Unrealized gains*	4.9		.7		1.8
Ending balance	$ --		$44.5		$60.5

*	Realized losses and unrealized gains were included in other, net, in our consolidated statements of income.

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, 2011 and 2010. The fair value measurements of assets held in the SERP were 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, 2011 and 2010. See "Note 6 - 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 measurements of our derivatives were based on market prices that generally are 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, 2011 and 2010 were as follows (in millions):

	December 31,		December 31,
	2011		2010
		Estimated		Estimated
	Carrying	Fair	Carrying	Fair
	Value	Value	Value	Value

4.70% Senior notes due 2021	$1,472.2	$1,565.8	$ --	$ --
6.875% Senior notes due 2020	1,055.8	1,042.7	--	--
3.25% Senior notes due 2016	993.5	1,016.5	--	--
8.50% Senior notes due 2019	631.7	615.3	--	--
7.875% Senior notes due 2040	385.0	381.9	--	--
7.20% Debentures due 2027	149.0	167.2	148.9	165.0
4.33% MARAD bonds, including current maturities, due 2016	146.7	156.4	--	--
6.36% MARAD bonds, including current maturities, due 2015	50.7	64.0	63.4	71.9
4.65% MARAD bonds, including current maturities, due 2020	40.5	49.6	45.0	50.6
Total	$4,925.1	$5,059.4	$257.3	$287.5

The estimated fair values of our senior notes and debentures were determined using quoted market prices. The estimated fair values of our MARAD bonds were determined using an income approach valuation model. The estimated fair values of our cash and cash equivalents, receivables, trade payables and other liabilities approximated their carrying values as of December 31, 2011 and December 31, 2010.

4. PROPERTY AND EQUIPMENT

Property and equipment as of December 31, 2011 and 2010 consisted of the following (in millions):

	2011	2010

Drilling rigs and equipment	$12,672.6	$5,175.2
Other	92.7	50.4
Work in progress	1,720.4	1,519.0
	$14,485.7	$6,744.6

Drilling rigs and equipment increased $7.5 billion during 2011 primarily due to the Merger. The estimated fair values recorded for Pride's drilling rigs and equipment as of the Merger Date totaled $5.5 billion, which included five drillships, 12 semisubmersible rigs and seven jackup rigs.

Work in progress increased $201.4 million during 2011 primarily related to the Merger, mostly offset by ENSCO 8503 and ENSCO 8504, which were placed into service during 2011. The estimated fair value recorded for Pride’s work in progress as of the Merger Date was $1.3 billion. Work in progress as of December 31, 2011 primarily consisted of $803.4 million related to the construction of ENSCO 8505 and ENSCO 8506 ultra-deepwater semisubmersible rigs, $487.8 million related to the construction of ENSCO DS-6 and ENSCO DS-7 ultra-deepwater drillships, which were acquired in connection with the Merger, $142.7 million related to the construction of three ultra-high specification harsh environment jackup rigs and costs associated with various modification and enhancement projects.

Work in progress as of December 31, 2010 primarily consisted of $1.4 billion related to the construction of our ENSCO 8500 Series® ultra-deepwater semisubmersible rigs and costs associated with various modification and enhancement projects.

5. DEBT

The carrying value of long-term debt as of December 31, 2011 and 2010 consisted of the following (in millions):

	2011			2010

4.70% Senior notes due 2021		$1,472.2		$ --
6.875% Senior notes due 2020		1,055.8		--
3.25% Senior notes due 2016		993.5		--
8.50% Senior notes due 2019		631.7		--
7.875% Senior notes due 2040		385.0		--
7.20% Debentures due 2027		149.0		148.9
4.33% MARAD bonds due 2016		146.7		--
6.36% MARAD bonds due 2015		50.7		63.4
4.65% MARAD bonds due 2020		40.5		45.0
Commercial paper		125.0		--
Total debt		5,050.1		257.3
Less current maturities		(172.5	)	(17.2	)
Total long-term debt		$4,877.6		$240.1

Acquired Debt

In connection with the Merger, we assumed Pride’s outstanding debt comprised of $900.0 million aggregate principal amount of 6.875% senior notes due 2020, $500.0 million aggregate principal amount of 8.500% senior notes due 2019, $300.0 million aggregate principal amount of 7.875% senior notes due 2040 and $151.5 million aggregate principal amount of MARAD bonds due 2016. Under a supplemental indenture, Ensco plc has fully and unconditionally guaranteed the performance of all obligations of Pride with respect to the Pride Notes. See "Note 16 - Guarantee of Registered Securities" for additional information on the guarantee of the Pride Notes. In addition, we assumed debt outstanding with respect to Pride’s senior unsecured revolving credit facility totaling $181.0 million, which was repaid in full and the facility terminated upon completion of the Merger.

Senior Notes

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 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.

Five-Year Credit Facility

364-Day Credit Facility

Commercial Paper

On April 26, 2011, we entered into a commercial paper program with four commercial paper dealers pursuant to which we may issue, on a private placement basis, unsecured commercial paper notes up to a maximum aggregate amount outstanding at any time of $700.0 million. On May 31, 2011, following the consummation of the Merger, Ensco increased the maximum aggregate amount of the commercial paper program to $1.0 billion. Under the commercial paper program, we may issue commercial paper from time to time, and the proceeds of such financings will be used for capital expenditures and other general corporate purposes. The commercial paper will bear interest at rates that will vary based on market conditions and the ratings assigned by credit rating agencies at the time of issuance. The weighted-average interest rate on our commercial paper borrowings was 0.40% during 2011. The maturities of the commercial paper will vary, but may not exceed 364 days from the date of issue. The commercial paper is not redeemable or subject to voluntary prepayment by us prior to maturity. We had $125.0 million outstanding under our commercial paper program as of December 31, 2011, which was classified as short-term debt on our consolidated balance sheet.

Bridge Term Facility

Maturities

The aggregate maturities of our debt, excluding net unamortized premiums of $347.4 million, as of December 31, 2011 were as follows (in millions):

2012					$ 172.5
2013					47.5
2014					47.5
2015					47.5
2016					1,019.7
Thereafter					3,368.0
Total					$4,702.7

Interest expense totaled $95.9 million for the year ended December 31, 2011 which was net of amounts capitalized of $80.2 million in connection with our newbuild rig construction. All interest expense incurred during the years ended December 31, 2010 and 2009 of $21.3 million and $20.9 million, respectively, was capitalized in connection with our newbuild rig construction.

6. 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, 2011 and 2010, we may employ an interest rate risk management strategy that utilizes derivatives to mitigate or eliminate unanticipated fluctuations in earnings and cash flows arising from changes in, and volatility of, interest rates. We mitigate 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 3 - Fair Value Measurements" for additional information on the fair value measurement of our derivatives.

As of December 31, 2011 and 2010, our consolidated balance sheets included a net foreign currency derivative liability of $7.1 million and a net foreign currency derivative asset of $16.4 million, respectively. All of our derivatives mature during the next 17 months. Derivatives recorded at fair value in our consolidated balance sheets as of December 31, 2011 and 2010 consisted of the following (in millions):

	Derivative Assets		Derivative Liabilities
	2011	2010	2011	2010
Derivatives Designated as Hedging Instruments
Foreign currency forward contracts - current(1)	$ .2	$16.8	$7.1	$ .6
Foreign currency forward contracts - non-current(2)	.1	.1	.1	.1
	.3	16.9	7.2	.7
Derivatives not Designated as Hedging Instruments
Foreign currency forward contracts - current(1)	--	.2	.2	--
	--	.2	.2	--
Total	$ .3	$17.1	$7.4	$ .7

(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 cash flow hedges to hedge forecasted foreign currency denominated transactions, primarily to reduce our exposure to foreign currency exchange rate risk associated with contract drilling expenses denominated in various currencies. As of December 31, 2011, we had cash flow hedges outstanding to exchange an aggregate $293.9 million for various foreign currencies, including $122.7 million for British pounds, $114.3 million for Singapore dollars, $27.6 million for Australian dollars, $24.2 million for Euros and $5.1 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, 2011 were as follows (in millions):

	Gain (Loss) Recognized in Other Comprehensive Income ("OCI") on Derivatives (Effective Portion)			Gain (Loss) Reclassified from AOCI into Income (Effective Portion)				Gain (Loss) Recognized in Income on Derivatives (Ineffective Portion and Amount Excluded from Effectiveness Testing)(1)
	2011	2010	2009		2011	2010	2009		2011	2010	2009

Interest rate lock contracts(2)	$ --	$ --	$ --		$ (.5)	$(.6)	$ (.7)		$ --	$ --	$ --
Foreign currency forward contracts(3)	.1	7.6	13.5		6.0	2.3	(8.0)		.3	.3	(2.9)
Total	$ .1	$7.6	$13.5		$5.5	$1.7	$(8.7)		$ .3	$ .3	$(2.9)

(1)		Gains and losses recognized in income for ineffectiveness and amounts excluded from effectiveness testing were included in other, net, in our consolidated statements of income.
(2)		Gains and losses on derivatives reclassified from AOCI into income (effective portion) were included in interest expense 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, 2011, we had derivatives not designated as hedging instruments outstanding to exchange an aggregate $43.4 million for various foreign currencies, including $12.7 million for Swiss francs, $11.6 million for Australian dollars and $19.1 million for other currencies.

Net gains of $500,000, $2.9 million and $4.6 million associated with our derivatives not designated as hedging instruments were included in other, net, in our consolidated statements of income for the years ended December 31, 2011, 2010 and 2009, respectively.

As of December 31, 2011, the estimated amount of net losses associated with derivatives, net of tax, that will be reclassified to earnings during the next twelve months was as follows (in millions):

Net unrealized losses to be reclassified to contract drilling expense		$2.7
Net realized losses to be reclassified to interest expense		.3
Net losses to be reclassified to earnings		$3.0

7. GOODWILL

	Deepwater	Midwater	Jackup	Total

Balance as of December 31, 2010	$ 143.6	$ --	$192.6	$ 336.2
Acquisition of Pride, including measurement period adjustments	2,479.9	472.7	--	2,952.6
Balance as of December 31, 2011	$2,623.5	$472.7	$192.6	$3,288.8

8. SHAREHOLDERS' EQUITY

Activity in our various shareholders' equity accounts for each of the years in the three-year period ended December 31, 2011 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, 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
Net income	--	--	--	600.4		--	--	5.2
Cash dividends paid	--	--	--	(292.3)		--	--	--
Distributions to noncontrolling interests	--	--	--	--		--	--	(5.5)
Shares issued under share-based compensation
plans, net	--	--	39.7	--		--	.2	--
Shares issued in connection with the Merger	85.8	8.6	4,568.9	--		--	--	--
Fair value of share options assumed in connection with the Merger	--	--	35.4	--		--	--	--
Equity issuance costs	--	--	(70.5)	--		--	--	--
Tax benefit from share-based
compensation	--	--	.5	--		--	--	--
Repurchase of shares	--	--	--	--		--	(10.5)	--
Share-based compensation cost	--	--	41.9	--		--	--	--
Net other comprehensive loss	--	--	--	--		(2.5)	--	--
BALANCE, December 31, 2011	235.9	$ 23.7	$5,253.0	$5,613.1		$ 8.6	$ (19.1)	$ 5.2

100

The Board of Directors of Ensco Delaware previously authorized the repurchase of up to $1.5 billion 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, 2011 and 2010. Although $562.4 million remained available for repurchase as of December 31, 2011, 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.

9. COMPREHENSIVE INCOME

Accumulated other comprehensive income as of December 31, 2011 and 2010 primarily 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, 2011 were as follows (in millions):

	2011			2010		2009

Net income		$605.6		$585.9		$784.5
Other comprehensive income (loss):
Net change in fair value of derivatives		.1		7.6		13.5
Reclassification of gains and losses on derivative instruments from other comprehensive (income) loss into net income		(5.5	)	(1.7	)	8.7
Other		2.9		--		--
Net other comprehensive (loss) income		(2.5	)	5.9		22.2
Comprehensive income		603.1		591.8		806.7
Comprehensive income attributable to noncontrolling interests		(5.2	)	(6.4	)	(5.1	)
Comprehensive income attributable to Ensco		$597.9		$585.4		$801.6

101

10. 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, 2011, there were 1.6 million shares available for issuance of non-vested share awards under the LTIP. Non-vested share awards may be satisfied by delivery of share units, 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, 2011 (in millions):

	2011		2010		2009

Contract drilling	$17.0		$17.2		$16.8
General and administrative	21.5		13.9		11.4
Non-vested share award related compensation expense
included in operating expenses	38.5		31.1		28.2
Tax benefit	(6.9	)	(6.3	)	(7.0	)
Total non-vested share award related compensation
expense included in net income	$31.6		$24.8		$21.2

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, 2011:

	2011	2010	2009

Weighted-average grant-date fair value of
non-vested share awards granted (per share)	$52.50	$35.81	$40.91
Total fair value of non-vested share awards
vested during the period (in millions)	$41.0	$22.1	$18.6

102

The following table summarizes non-vested share award activity for the year ended December 31, 2011 (shares in thousands):

			Weighted-
			Average
			Grant-Date
	Shares		Fair Value

Non-vested as of December 31, 2010	1,791		$47.75
Granted	1,384		52.50
Vested	(678	)	50.50
Forfeited	(121	)	48.07
Non-vested as of December 31, 2011	2,376		$49.69

As of December 31, 2011, there was $92.4 million of total unrecognized compensation cost related to non-vested share awards, which is expected to be recognized over a weighted-average period of 3.1 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, 2011, options to purchase 2.3 million shares were outstanding under the LTIP and 3.3 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, 2011 (in millions):

	2011	2010	2009

Contract drilling	$ --	$ .7	$ 1.7
General and administrative	2.5	2.8	3.7
Option related compensation expense included in operating expenses	2.5	3.5	5.4
Tax benefit	(.5)	(.6)	(1.6)
Total option related compensation expense included in net income	$2.0	$ 2.9	$ 3.8

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The fair value of each option is estimated on the date of grant using the Black-Scholes option valuation model. The following weighted-average assumptions were utilized in the Black-Scholes model for each of the years in the three-year period ended December 31, 2011:

	2011		2010		2009

Risk-free interest rate	1.4	%	1.8	%	1.8	%
Expected term (in years)	3.7		4.0		3.9
Expected volatility	50.2	%	53.1	%	53.3	%
Dividend yield	2.6	%	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, 2011 (shares and intrinsic value in thousands, term in years):

			Weighted-		Weighted-
			Average		Average
			Exercise		Contractual		Intrinsic
	Shares		Price		Term		Value

Outstanding as of December 31, 2010	1,321		$47	.52
Options assumed in the Merger	1,926		35	.40
Granted	129		54	.92
Exercised	(1,083	)	36	.91
Forfeited	--			--
Expired	(4	)	50	.17
Outstanding as of December 31, 2011	2,289		$42	.78	4	.2	$15,602
Exercisable as of December 31, 2011	2,032		$42	.49	4	.0	$14,168

The following table summarizes the value of options granted and exercised during each of the years in the three-year period ended December 31, 2011:

	2011	2010	2009

Weighted-average grant-date fair value of
options granted (per share)	$19.05	$11.05	$17.17
Intrinsic value of options exercised during
the year (in millions)	$17.2	$ .4	$ 3.6

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The following table summarizes information about options outstanding as of December 31, 2011 (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

$18.87 - $34.45	556	4.6 years	$27.29	458	$25.76
35.12 - 41.29	448	5.6 years	39.31	411	39.13
42.25 - 50.09	560	4.5 years	44.72	560	44.72
50.28 - 60.74	725	2.7 years	55.33	603	55.42
	2,289	4.2 years	$42.78	2,032		$42.49

As of December 31, 2011, there was $2.7 million of total unrecognized compensation cost related to options, which is expected to be recognized over a weighted-average period of 1.7 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, 2011. 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 2011, 2010 and 2009 totaled $3.1 million, $4.3 million and $12.1 million, respectively. The aggregate fair value of performance awards vested during 2011 and 2010 totaled $5.6 million and $2.4 million, respectively, all of which was paid in cash.

During the years ended December 31, 2011, 2010 and 2009, we recognized $6.7 million, $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. As of December 31, 2011, there was $7.6 million of total unrecognized compensation cost related to unvested performance awards, which is expected to be recognized over a weighted-average period of 1.8 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 $11.6 million, $5.0 million and $4.1 million for the years ended December 31, 2011, 2010 and 2009, 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 $18.1 million, $16.2 million and $14.2 million for the years ended December 31, 2011, 2010 and 2009, 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.

11. 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 26.5% during 2011 and 28% during 2010 and for eight days of 2009. Our consolidated effective income tax rate information for the year ended December 31, 2009 has been presented from the perspective of an enterprise domiciled in the U.S.

We generated $(30.5) million, $90.5 million and $292.2 million of (loss) income from continuing operations before income taxes in the U.S. and $767.1 million, $554.0 million and $643.0 million of income from continuing operations before income taxes in non-U.S. countries for the years ended December 31, 2011, 2010 and 2009, 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, 2011 (in millions):

	2011		2010		2009

Current income tax expense:
U.S.	$ 51.8		$ 9.8		$ 71.9
Non-U.S.	98.8		71.9		87.6
	150.6		81.7		159.5

Deferred income tax expense (benefit):
U.S.	(14.9	)	15.2		20.5
Non-U.S.	(4.7	)	(.9	)	--
	(19.6	)	14.3		20.5

Total income tax expense	$131.0		$96.0		$180.0

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The following table summarizes significant components of deferred income tax assets (liabilities) as of December 31, 2011 and 2010 (in millions):

	2011		2010
Deferred tax assets:
Net operating loss carryforwards	$ 193.1		$ 9.9
Premium on long-term debt	135.7		--
Foreign tax credits	92.6		--
Employee benefits, including share-based compensation	33.1		23.3
Deferred revenue	32.0		28.9
Other	30.1		9.8
Total deferred tax assets	516.6		71.9
Valuation allowance	(239.5	)	(11.0	)
Net deferred tax assets	277.1		60.9
Deferred tax liabilities:
Property and equipment	(493.6	)	(335.6	)
Deferred costs	(35.9	)	(24.5	)
Intercompany transfers of property	(38.8	)	(35.2	)
Other	(25.2	)	(14.3	)
Total deferred tax liabilities	(593.5	)	(409.6	)
Net deferred tax liability	$(316.4	)	$(348.7	)

Net current deferred tax asset	$ 1.4		$ 9.3
Net noncurrent deferred tax liability	(317.8	)	(358.0	)
Net deferred tax liability	$(316.4	)	$(348.7	)

The realization of substantially all of our deferred tax assets is dependent on generating sufficient taxable income during future periods in various jurisdictions in which we operate. Realization of certain of our deferred tax assets is not assured. We recognize a valuation allowance for deferred tax assets when it is more-likely-than-not that the benefit from the deferred tax asset will not be realized. The amount of deferred tax assets considered realizable could increase or decrease in the near-term if estimates of future taxable income change.

As of December 31, 2011, we had deferred tax assets of $193.1 million related to $854.9 million of net operating loss (“NOL”) carryforwards and $92.6 million of U.S. foreign tax credits (“FTC”), which can be used to reduce our income taxes payable in future years. NOL carryforwards, which were generated in various jurisdictions worldwide, include $212.0 million of NOLs that do not expire and $642.9 million that will expire, if not utilized, beginning in 2012 through 2031. The FTC expire between 2017 and 2021. Due to the uncertainty of realization, we have a $235.6 million valuation allowance on NOL carryforwards and FTC, primarily relating to countries where we no longer operate or do not expect to generate future taxable income.

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Our consolidated effective income tax rate for 2011 includes the impact of various discrete tax items, the majority of which is attributable to a gain on disposal of assets in a jurisdiction with a high tax rate and the recognition of a liability for unrecognized tax benefits associated with a tax position taken in a prior year. Excluding the impact of the aforementioned discrete items, our consolidated effective income tax rate for the year ended December 31, 2011 was 16.0%. The increase in our 2011 consolidated effective income tax rate, excluding discrete tax items, to 16.0% from 14.9% in the prior year was due to unrecognized benefits related to net operating losses and foreign tax credits of certain subsidiaries acquired in 2011, partially offset by the aforementioned transfer of drilling rig ownership in connection with the reorganization of our worldwide operations and other changes in taxing jurisdictions in which our drilling rigs are operated and/or owned that resulted in an increase in the relative components of our earnings generated in tax jurisdictions with lower tax rates.

Our consolidated effective income tax rate on continuing operations for each of the years in the three-year period ended December 31, 2011, differs from the U.K. or U.S. statutory income tax rates as follows:

	2011		2010		2009

Statutory income tax rate	26.5	%	28.0	%	35.0	%
Non-U.K./U.S. taxes	(17.9	)	(18.9	)	(17.7	)
Amortization of deferred charges associated with intercompany rig sales	1.3		2.7		1.8
Redomestication related income taxes	.0		.0		.9
Valuation allowance	6.7		1.7		.1
Net expense (benefit) in connection with resolutions
of tax issues and adjustments relating to prior years	.8		(.5	)	(.9	)
Other	.4		1.9		.0
Effective income tax rate	17.8	%	14.9	%	19.2	%

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, 2011, we had $54.0 million of unrecognized tax benefits, of which $31.2 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, 2011 and 2010 is as follows (in millions):

	2011		2010

Balance, beginning of year	$13.7		$17.6
Unrecognized tax benefits assumed in the Merger	35.2		--
Increases in unrecognized tax benefits as a result of tax positions taken during the current year	1.9		1.0
Increases in unrecognized tax benefits as a result of tax positions taken during prior years	6.1		--
Decreases in unrecognized tax benefits as a result of tax positions taken during prior years	--		(.2	)
Settlements with taxing authorities	--		--
Lapse of applicable statutes of limitations	(2.0	)	(1.3	)
Impact of foreign currency exchange rates	(.9	)	(3.4	)
Balance, end of year	$54.0		$13.7

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Accrued interest and penalties totaled $22.7 million and $12.0 million as of December 31, 2011 and 2010, respectively, and were included in other liabilities on our consolidated balance sheets. We recognized a net benefit of $400,000 and net expense of $1.5 million and $3.3 million associated with interest and penalties during the years ended December 31, 2011, 2010 and 2009, 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 major tax jurisdictions in which we operated. Ensco Delaware participates in the U.S. Internal Revenue Service’s Compliance Assurance Process (“IRS CAP”) which, among others, provides for the resolution of tax issues in a timely manner and generally eliminates the need for lengthy post-filing examinations. Our 2010 U.S federal tax return remains subject to examination under the IRS CAP.

During 2011, statutes of limitations applicable to certain of our tax positions lapsed resulting in a $2.0 million decline in unrecognized tax benefits and a $4.2 million net income tax benefit, inclusive of interest and penalties.

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.

Statutes of limitations applicable to certain of our tax positions will lapse during 2012. Therefore, it is reasonably possible that our unrecognized tax benefits will decline during the next twelve months by $30.3 million, inclusive of $6.9 million of accrued interest and penalties, of which $11.3 million would impact our consolidated effective income tax rate if recognized.

Intercompany Transfer of Drilling Rigs

Subsequent to the Merger, we transferred ownership of several acquired drilling rigs among our subsidiaries in June 2011. Following our redomestication to the U.K. in December 2009, we reorganized our worldwide operations, which included, among others, the transfer of ownership of several of our drilling rigs among our subsidiaries during 2010 and 2009. The drilling rigs transferred during 2010 were either transferred among subsidiaries that are not subject to income tax or transferred among subsidiaries that were resident in the same tax jurisdiction and included in a consolidated tax return. Accordingly, the selling subsidiaries incurred no income tax liability or benefit on gains and losses, nor were there any reversing temporary differences, in connection with the transfer of drilling rigs during 2010.

The income tax liability associated with gains on the intercompany transfers of drilling rigs totaled $10.3 million and $30.8 million in 2011 and 2009, respectively. 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 35 years for the rigs transferred in 2011 and 29 to 30 years for the rigs transferred in 2009. Similarly, the tax effects of $29.6 million and $45.6 million of reversing temporary differences of the selling subsidiaries in 2011 and 2009, respectively, also were deferred and are being amortized on the same basis and over the same periods as described above.

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As of December 31, 2011 and 2010, the unamortized balance associated with deferred charges for income taxes incurred in connection with intercompany transfers of drilling rigs totaled $68.8 million and $74.6 million, respectively, and was included in other assets, net, on our consolidated balance sheets. Current income tax expense for the years ended December 31, 2011, 2010 and 2009 included $16.1 million, $23.5 million and $22.8 million, respectively, of amortization of income taxes incurred in connection with intercompany transfers of drilling rigs.

As of December 31, 2011 and 2010, the deferred tax liability associated with temporary differences of transferred drilling rigs totaled $38.8 million and $35.2 million, respectively, and was included in deferred income taxes on our consolidated balance sheet. Deferred income tax expense for the years ended December 31, 2011, 2010 and 2009 included benefits of $6.6 million, $6.4 million and $5.8 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 or Ensco United Incorporated, an indirect wholly-owned subsidiary of Ensco and immediate parent company of Pride, 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 or Ensco United Incorporated'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/or other financial resources available to meet their operational and capital investment requirements and otherwise allow us to continue to maintain our policy of reinvesting the undistributed earnings of these companies indefinitely.

As of December 31, 2011, the aggregate undistributed earnings of Ensco Delaware, Ensco United Incorporated and their non-U.S. subsidiaries totaled $3.8 billion 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 these undistributed earnings was not practicable to estimate as of December 31, 2011.

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12. DISCONTINUED OPERATIONS

During 2010, we sold jackup rigs ENSCO 50, ENSCO 51, ENSCO 57 and ENSCO 60 for an aggregate $167.5 million, of which deposits of $9.4 million were received in December 2009. We recognized an aggregate pre-tax gain of $57.5 million in connection with the disposals, 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 rigs’ aggregate net book value, inventory and other assets on the date of sale totaled $110.0 million. The rigs' operating results were reclassified to discontinued operations in our consolidated statements of income for the years ended December 31, 2010 and 2009 and previously were included within our Jackup segment results.

The following table summarizes income from discontinued operations for the years ended December 31, 2010 and 2009 (in millions):

	2010			2009

Revenues		$12.5			$83.0
Operating expenses		17.1			54.2
Operating (loss) income before income taxes		(4.6	)		28.8
Income tax benefit		(3.4	)		(.5	)
Gain on disposal of discontinued operations, net		38.6			--
Income from discontinued operations		$37.4			$29.3

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

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13. COMMITMENTS AND CONTINGENCIES

Leases

We are obligated under leases for certain of our offices and equipment. Rental expense relating to operating leases was $31.5 million, $15.9 million and $14.2 million during the years ended December 31, 2011, 2010 and 2009, respectively. Future minimum rental payments under our noncancellable operating lease obligations are as follows: $15.8 million during 2012; $11.1 million during 2013; $7.7 million during 2014; $7.7 million during 2015, $8.5 million during 2016 and $17.7 million thereafter.

Capital Commitments

The following table summarizes the aggregate contractual commitments related to our two ENSCO 8500 Series® rigs, our two ultra-deepwater drillships and our three ultra-high specification harsh environment jackup rigs under construction as of December 31, 2011 (in millions):

2012					$ 920.5
2013					698.7
2014					196.0
Total					$1,815.2

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.

Demand Letter, Derivative Cases and Shareholder Class Actions

In June 2009, Pride received a demand letter from a purported shareholder that alleged certain of Pride’s then-current and former officers and directors violated their fiduciary duties in regards to certain matters involving Pride’s previously disclosed Foreign Corrupt Practices Act ("FCPA") investigation. The letter requested that Pride’s board of directors take appropriate action against the individuals in question. In September 2009, Pride’s board of directors formed a special committee, which retained independent legal counsel and commenced an evaluation of the issues raised by the letter in an effort to determine a course of action.

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In April 2010, two purported shareholders of Pride filed separate derivative actions against all of Pride’s then-current directors and against Pride, as nominal defendant. The lawsuits were consolidated and alleged that the individual defendants breached their fiduciary duties in regards to certain matters involving Pride’s previously disclosed FCPA investigation. Among other remedies, the lawsuit seeks damages in an unspecified amount and equitable relief against the individual defendants, along with an award of attorney fees and other costs and expenses to the plaintiff. After the conclusion of Pride's investigation, the plaintiffs filed a consolidated amended petition in January 2011, raising allegations substantially similar to those made in the prior lawsuits.

In December 2010, the special committee completed its evaluation of the issues surrounding Pride's FCPA investigation and again reviewed its conclusion in January 2011 in connection with the amended petition described above. The committee concluded that it was not in the interest of Pride or its shareholders to pursue litigation related to the matter.

Following the announcement of the Merger, a number of putative shareholder class action complaints or petitions were filed against various combinations of Pride, Pride’s directors, Ensco and certain of our subsidiaries. These lawsuits challenged the proposed Merger and generally alleged, among other matters, that the individual members of the Pride board of directors breached their fiduciary duties by approving the proposed Merger, failing to take steps to maximize value to Pride’s shareholders and failing to disclose material information concerning the proposed Merger in the registration statement on Form S-4; that Pride, Ensco and certain of our subsidiaries aided and abetted such breaches of fiduciary duties; and that the Merger Agreement improperly favored Ensco and unduly restricted Pride’s ability to negotiate with other bidders. These lawsuits generally sought, among other remedies, compensatory damages, declaratory and injunctive relief concerning the alleged fiduciary breaches, and injunctive relief prohibiting the defendants from consummating the Merger. In addition, the plaintiffs in the derivative class action lawsuits related to Pride’s previously disclosed FCPA investigation amended their petition to add claims related to the Merger.

In May 2011, Ensco and the other named defendants signed a memorandum of understanding with the plaintiffs to settle the previously disclosed shareholder class action lawsuits filed related to the Merger (collectively, the “Settled Claims”).

In August 2011, the parties to the memorandum of understanding entered into a stipulation of settlement, which provides for, among other matters, the release of the Settled Claims following notice by mailing, certification of a non-opt-out class for settlement purposes, a settlement hearing and final approval of the settlement. Under the stipulation of settlement, Pride or its successor agreed not to oppose any application by attorneys for the class for fees and expenses not exceeding $1.1 million. The stipulation of settlement was approved in November 2011.

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Seahawk

In August 2009, Pride completed the spin-off of Seahawk Drilling, Inc. ("Seahawk"), which held the assets and liabilities that were associated with Pride's mat-supported jackup rig business.

In 2006, 2007 and 2009, Seahawk received tax assessments from the Mexican government related to their operations. Pursuant to local statutory requirements, Seahawk provided suitable collateral to contest these assessments. Pursuant to a tax support agreement between Pride and Seahawk, Pride agreed that in certain circumstances, at Seahawk’s request, it would guarantee or indemnify the issuer of such collateral. Also pursuant to the agreement, Seahawk would indemnify Pride for the amount of any such guarantee. In September 2010, Seahawk requested that Pride provide credit support to a bank for four letters of credit issued for these tax assessments. The amount of the request totaled approximately $50.0 million. In October 2010, Pride provided credit support in satisfaction of this request.

In November 2011, the Mexican tax authority drew the letters of credit, thereby triggering Pride’s reimbursement obligation to the bank. We believe the tax authority’s draw on the letters of credit was illegal. We made the required cash payment to the bank totaling $43.7 million. Pride’s claim for reimbursement from Seahawk was allowed in full under the bankruptcy settlement with the Trustee; however, the Seahawk bankruptcy estate did not have sufficient funds to pay the reimbursement claim in full.

The draw by Hacienda was a direct consequence of the contractual obligation created by the credit support originally provided by Pride previous to the Merger, and the cash payment made by us to the bank was the performance of that contractual obligation. The aforementioned events revealed new information about facts and circumstances in existence as of the Merger Date that, if known at the Merger Date, would have led to a different estimate of the assumed liability related to the credit support. Therefore, the impact of the aforementioned payment, along with the applicable portions of our partial recovery of $45.0 million in Hercules Offshore, Inc. common stock from the Seahawk bankruptcy estate in December 2011, was recorded as an increase to goodwill of $24.9 million. This adjustment included a $49.6 million retrospective increase in the assumed liability related to the credit support and a $24.7 million retrospective increase in the acquired receivable from Seahawk as of the Merger Date.

As part of the Seahawk bankruptcy settlement, we have the right, but not the obligation, to direct the management of the underlying court cases in respect of the aforementioned tax assessments in Mexico, as well as all other recovery efforts, in order to obtain recompense for its reimbursement of the bank. Further, we are entitled to all recovery from such efforts. We intend to vigorously pursue recovery of these funds; however, there can be no assurances that all or any portion of these funds will be recovered. For additional information regarding Seahawk's bankruptcy proceedings and related settlements, see "Seahawk Drilling, Inc. Bankruptcy" in Part I, Item 3. Legal Proceedings of this annual report on Form 10-K.

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ENSCO 74 Loss

In September 2008, ENSCO 74 was lost as a result of Hurricane Ike in the U.S. Gulf of Mexico. Portions of its legs remained underwater adjacent to the customer's platform, and 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 in March 2009. During 2010, wreck removal operations on the sunken rig hull of ENSCO 74 were completed.

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 removal costs to range from $16.0 million to $30.0 million. We expect the cost of removal of the legs to be fully covered by our insurance.

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. 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 $16.0 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 under our insurance policy was recorded as of December 31, 2011 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.

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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 two subsea pipelines have presented claims in the exoneration/limitation proceedings. The matter is scheduled for trial in March 2012.

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

Although we do not expect final disposition of the claims associated with the ENSCO 74 loss to have a material adverse effect upon our financial position, operating results or cash flows, there can be no assurances as to the ultimate outcome.

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 and seeking a declaration that removal of wreckage and debris is covered under our liability insurance, monetary damages, attorneys' fees and other remedies. The court heard several pretrial motions on May 25, 2011 and on July 31, 2011 issued an order compelling the matter to be submitted to arbitration.

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 in 2006.

116

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. 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.

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.

Environmental Matters

117

Other Matters

14. SEGMENT INFORMATION

In connection with the Merger, we evaluated our then-current core assets and operations, which consisted of seven drillships, 20 semisubmersible rigs and 48 jackup rigs, including rigs under construction, and organized them into three segments based on water depth operating capabilities. Accordingly, we now consider our business to consist of three reportable segments: (1) Deepwater, which consists of our drillships and semisubmersible rigs capable of drilling in water depths of 4,500 feet or greater, (2) Midwater, which consists of our semisubmersible rigs capable of drilling in water depths of 4,499 feet or less and (3) Jackup, which consists of our jackup rigs capable of drilling in water depths up to 400 feet. Each of our three reportable segments provides one service, contract drilling. We also manage the drilling operations for two deepwater rigs and own one barge rig, which are included in "Other."

Segment information for each of the years in the three-year period ended December 31, 2011 is presented below (in millions). General and administrative expense and depreciation expense incurred by our corporate office are not allocated to our operating segments for purposes of measuring segment operating income and were included in "Reconciling Items." We measure segment assets as property and equipment. Prior year information has been reclassified to conform to the current year presentation.

Year Ended December 31, 2011


					Operating
					Segments	Reconciling	Consolidated
	Deepwater	Midwater	Jackup	Other	Total	Items	Total

Revenues	$1,284.7	$273.8	$1,231.8	$ 52.4	$ 2,842.7	$ --	$ 2,842.7
Operating expenses Contract drilling (exclusive of depreciation)	636.1	166.2	623.9	44.7	1,470.9	--	1,470.9
Depreciation	201.7	37.1	173.5	2.1	414.4	4.5	418.9
General and administrative	--	--	--	--	--	158.6	158.6
Operating income (loss)	$ 446.9	$ 70.5	$ 434.4	$ 5.6	$ 957.4	$(163.1)	$ 794.3
Property and equipment, net	$9,006.7	$896.1	$2,456.5	$ 41.8	$12,401.1	$ 23.1	$12,424.2
Capital expenditures	401.1	20.1	271.5	48.9	741.6	--	741.6

118

Year Ended December 31, 2010


						Operating
						Segments	Reconciling	Consolidated
	Deepwater	Midwater	Jackup	Other		Total	Items	Total

Revenues	$ 475.2	$ --	$1,221.6	$ --		$1,696.8	$ --	$1,696.8
Operating expenses Contract drilling (exclusive of depreciation)	176.1	--	578.2	13.8		768.1	--	768.1
Depreciation	44.8	--	167.8	2.4		215.0	1.3	216.3
General and administrative	--	--	--	--		--	86.1	86.1
Operating income (loss)	$ 254.3	$ --	$ 475.6	$(16.2	)	$ 713.7	$ (87.4)	$ 626.3
Property and equipment, net	$2,866.4	$ --	$2,165.2	$ 14.4		$5,046.0	$ 3.9	$5,049.9
Capital expenditures	632.5	--	238.7	--		871.2	4.1	875.3

Year Ended December 31, 2009


						Operating
						Segments	Reconciling	Consolidated
	Deepwater	Midwater	Jackup	Other		Total	Items	Total

Revenues	$ 254.1	$ --	$1,634.8	$ --		$1,888.9	$ --	$1,888.9
Operating expenses Contract drilling (exclusive of depreciation)	108.1	--	599.0	1.9		709.0	--	709.0
Depreciation	22.2	--	162.9	3.1		188.2	1.3	189.5
General and administrative	--	--	--	--		--	64.0	64.0
Operating income (loss)	$ 123.8	$ --	$ 872.9	$ (5.0	)	$ 991.7	$ (65.3)	$ 926.4
Property and equipment, net	$2,243.3	$ --	$2,200.8	$ 28.8		$4,472.9	$ 4.4	$4,477.3
Capital expenditures	644.4	--	209.8	.3		854.5	2.7	857.2

Information about Geographic Areas

As of December 31, 2011, our Deepwater operating segment consisted of five drillships, 10 dynamically positioned semisubmersible rigs and two moored semisubmersible rigs deployed in various locations throughout Asia Pacific, Europe and Mediterranean, Brazil, Middle East and Africa and North and South America. Additionally, our Deepwater operating segment consisted of two ultra-deepwater drillships under construction in South Korea and two dynamically positioned semisubmersible rigs under construction in Singapore. Our Midwater operating segment consisted of one dynamically positioned semisubmersible rig and five moored semisubmersible rigs deployed in Brazil and West Africa. Our Jackup operating segment consisted of 49 jackup rigs, of which 46 are deployed in various locations throughout Asia Pacific, Europe and Mediterranean, Middle East and Africa and North and South America, and three currently are under construction in Singapore as part of our ongoing strategy to continually expand and high-grade our fleet. We also own one barge rig, which is included in "Other."

As of December 31, 2011, the geographic distribution of our drilling rigs by operating segment was as follows:

	Deepwater	Midwater	Jackup	Other	Total	*

North & South America (excluding Brazil)	5	--	15	--	20
Brazil	6	5	--	--	11
Europe & Mediterranean	1	--	8	--	9
Middle East & Africa	4	1	12	--	17
Asia & Pacific Rim	1	--	11	1	13
Asia & Pacific Rim (under construction)	4	--	3	--	7
Total	21	6	49	1	77

*	We have two deepwater drilling management contracts not included in the table above.

119

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. 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 Notices to Lessees 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, 2011, revenues provided by our drilling operations in the U.S. Gulf of Mexico totaled $753.8 million, or 27% of our consolidated revenues. Of this amount, 54% 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.

For purposes of our geographic disclosure, 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
	2011	2010	2009	2011	2010	2009

United States	$ 753.8	$ 421.3	$ 263.0	$ 3,450.6	$1,993.3	$1,806.7
Brazil	583.1	--	--	3,104.1	--	--
Angola	250.7	--	--	1,347.9	--	--
Australia	61.2	225.3	188.7	350.6	194.9	175.0
United Kingdom	240.4	219.0	353.2	398.9	429.2	457.4
Mexico	148.3	179.8	159.5	206.3	259.3	229.3
Singapore	--	--	--	1,082.3	1,235.6	720.1
Other countries	805.2	651.4	924.5	2,483.5	937.6	1,088.8
Total	$2,842.7	$1,696.8	$1,888.9	$12,424.2	$5,049.9	$4,477.3

15. SUPPLEMENTAL FINANCIAL INFORMATION

Consolidated Balance Sheet Information

Accounts receivable, net, as of December 31, 2011 and 2010 consisted of the following (in millions):

	2011		2010

Trade	$803.5		$209.9
Other	48.4		7.8
	851.9		217.7
Allowance for doubtful accounts	(13.6	)	(3.1	)
	$838.3		$214.6

Other current assets as of December 31, 2011 and 2010 consisted of the following (in millions):

	2011	2010

Inventory	$188.9	$ 56.4
Prepaid taxes	59.5	47.4
Deferred mobilization costs	43.8	19.7
Marketable securities	32.2	--
Prepaid expenses	22.3	12.9
Deferred tax assets	4.4	9.5
Other	24.6	25.5
	$375.7	$171.4

120

Other assets, net, as of December 31, 2011 and 2010 consisted of the following (in millions):

	2011		2010

Intangible assets	$197.3		$ --
Unbilled reimbursable receivables	119.4		20.0
Prepaid taxes on intercompany transfers of property	68.8		74.6
Deferred mobilization costs	38.4		31.3
Supplemental executive retirement plan assets	25.6		23.0
Wreckage and debris removal receivables	19.8		26.8
Deferred tax assets	18.0		--
Auction rate securities	--		44.5
Other	26.2		8.5
	$513.5	$228.7

Accrued liabilities and other as of December 31, 2011 and 2010 consisted of the following (in millions):

	2011	2010

Personnel costs	$153.1	$ 58.0
Deferred revenue	111.3	48.1
Taxes	74.0	22.4
Accrued interest	69.4	2.1
Intangible liabilities	43.4	5.1
Wreckage and debris removal	16.0	21.0
Other	40.2	11.6
	$507.4	$168.3

Other liabilities as of December 31, 2011 and 2010 consisted of the following (in millions):

	2011	2010

Intangible liabilities	$177.8	$ --
Deferred revenue	124.4	68.0
Unrecognized tax benefits (inclusive of interest and penalties)	76.7	25.7
Supplemental executive retirement plan liabilities	30.1	26.0
Other	37.2	19.7
	$446.2	$139.4

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, 2011 was as follows (in millions):

	2011	2010	2009

Repair and maintenance expense	$267.9	$120.0	$120.6

121

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, 2011 was as follows (in millions):

	2011	2010	2009

Interest, net of amounts capitalized	$ 28.6	$ --	$ --
Income taxes	123.9	171.6	152.9

Capitalized interest totaled $80.2 million, $21.3 million and $20.9 million during the years ended December 31, 2011, 2010 and 2009, respectively. Capital expenditure accruals totaling $305.8 million, $39.7 million and $83.8 million for the years ended December 31, 2011, 2010 and 2009, respectively, were excluded from investing activities in our consolidated statements of cash flows. Amortization of intangibles and other, net, included amortization of intangible assets and liabilities related to the estimated fair values of Pride's firm drilling contracts in place at the Merger Date, deferred charges for income taxes incurred on intercompany transfers of drilling rigs and certain other deferred costs.

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 mitigate 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 mitigate our credit risk relating to cash and investments by focusing on diversification and quality of instruments. Cash balances are maintained in major, well-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. We mitigate 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, 2011, one customer provided a total of $458.2 million, or 16%, of consolidated revenues which were attributable to our Deepwater and Midwater segments. During the year ended December 31, 2010, two customers provided a total of $421.4 million, or 25%, of consolidated revenues which were attributable to our Deepwater and Jackup segments. During the year ended December 31, 2009, one customer provided $249.6 million, or 13%, of consolidated revenues which were attributable to our Jackup segment.

16. GUARANTEE OF REGISTERED SECURITIES

In connection with the Merger, on May 31, 2011, Ensco plc and Pride entered into a supplemental indenture to the indenture dated as of July 1, 2004 between Pride and the Bank of New York Mellon, as indenture trustee, providing for, among other matters, the full and unconditional guarantee by Ensco plc of Pride’s 8.50% senior notes due 2019, 6.875% senior notes due 2020 and 7.875% senior notes due 2040, which had an aggregate outstanding principal balance as of December 31, 2011 of $1.7 billion. The Ensco plc guarantee provides for the unconditional and irrevocable guarantee of the prompt payment, when due, of any amount owed to the holders of the Pride Notes.

Ensco plc is also a full and unconditional guarantor of the 7.20% Debentures due 2027 issued by Ensco Delaware in November 1997, which had an aggregate outstanding principal balance of $150.0 million as of December 31, 2011.

All guarantees are unsecured obligations of Ensco plc ranking equal in right of payment with all of its existing and future unsecured and unsubordinated indebtedness.

122

The following tables present the condensed consolidating statements of income for each of the years in the three-year period ended December 31, 2011; the condensed consolidating balance sheets as of December 31, 2011 and 2010; and the condensed consolidating statements of cash flows for each of the years in the three-year period ended December 31, 2011, in accordance with Rule 3-10 of Regulation S-X. The condensed consolidating financial statements for the year ended December 31, 2011 include the results of Pride from the Merger Date.

ENSCO PLC AND SUBSIDIARIES CONDENSED CONSOLIDATING STATEMENTS OF INCOME Year Ended December 31, 2011 (in millions)

	Ensco plc		ENSCO International Inc.		Pride International Inc.		Other Non-guarantor Subsidiaries of Ensco		Consolidating Adjustments		Total

OPERATING REVENUES	$ --		$ 70.0		$ --		$2,914.5		$ (141.8	)	$2,842.7

OPERATING EXPENSES
Contract drilling (exclusive of depreciation)	46.9		70.0		--		1,495.8		(141.8	)	1,470.9
Depreciation	.4		1.8		--		416.7		--		418.9
General and administrative	52.2		--		--		106.4		--		158.6

OPERATING (LOSS) INCOME	(99.5	)	(1.8	)	--		895.6		--		794.3

OTHER INCOME (EXPENSE), NET	32.1		.4		(22.7	)	(67.5	)	--		(57.7	)

INCOME BEFORE INCOME TAXES	(67.4	)	(1.4	)	(22.7	)	828.1		--		736.6

INCOME TAX PROVISION	--		49.6		1.5		79.9		--		131.0

EQUITY EARNINGS IN AFFILIATES,
NET OF TAX	667.8		271.5		143.9		--		(1,083.2	)	--

NET INCOME	600.4		220.5		119.7		748.2		(1,083.2	)	605.6

NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS	--		--		--		(5.2	)	--		(5.2	)

NET INCOME ATTRIBUTABLE TO ENSCO	$600.4		$220.5		$119.7		$ 743.0		$(1,083.2	)	$ 600.4

123

ENSCO PLC AND SUBSIDIARIES CONDENSED CONSOLIDATING STATEMENTS OF INCOME Year Ended December 31, 2010 (in millions)

	Ensco plc		ENSCO International Inc.		Other Non-guarantor Subsidiaries of Ensco		Consolidating Adjustments		Total

OPERATING REVENUES	$ --		$ 53.4		$1,748.5		$ (105.1	)	$1,696.8

OPERATING EXPENSES
Contract drilling (exclusive of depreciation)	29.0		53.4		790.8		(105.1	)	768.1
Depreciation	.2		1.0		215.1		--		216.3
General and administrative	55.1		--		31.0		--		86.1

OPERATING (LOSS) INCOME	(84.3	)	(1.0	)	711.6		--		626.3

OTHER INCOME (EXPENSE), NET	55.6		3.8		(41.2	)	--		18.2

(LOSS) INCOME FROM CONTINUING
OPERATIONS BEFORE INCOME TAXES	(28.7	)	2.8		670.4		--		644.5

INCOME TAX PROVISION	1.3		44.6		50.1		--		96.0

DISCONTINUED OPERATIONS, NET	--		(15.5	)	52.9		--		37.4

EQUITY EARNINGS IN AFFILIATES, NET OF TAX	609.5		137.7		--		(747.2	)	--

NET INCOME	579.5		80.4		673.2		(747.2	)	585.9

NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS	--		--		(6.4	)	--		(6.4	)

NET INCOME ATTRIBUTABLE TO ENSCO	$579.5		$ 80.4		$ 666.8		$(747.2	)	$ 579.5

124

ENSCO PLC AND SUBSIDIARIES CONDENSED CONSOLIDATING STATEMENTS OF INCOME Year Ended December 31, 2009 (in millions)

	Ensco plc		ENSCO International Inc.		Other Non-guarantor Subsidiaries of Ensco		Consolidating Adjustments		Total

OPERATING REVENUES	$ --		$ 12.5		$1,888.9		$ (12.5	)	$1,888.9

OPERATING EXPENSES
Contract drilling (exclusive of depreciation)	--		12.5		709.0		(12.5	)	709.0
Depreciation	--		1.3		188.2		--		189.5
General and administrative	8.7		--		55.3		--		64.0

OPERATING (LOSS) INCOME	(8.7	)	(1.3	)	936.4		--		926.4

OTHER INCOME (EXPENSE), NET	.2		3.2		5.4		--		8.8

INCOME FROM CONTINUING
OPERATIONS BEFORE INCOME TAXES	(8.5	)	1.9		941.8		--		935.2

INCOME TAX PROVISION	(.7	)	104.2		76.5		--		180.0

DISCONTINUED OPERATIONS, NET	--		2.9		26.4		--		29.3

EQUITY EARNINGS IN AFFILIATES, NET OF TAX	25.8		895.2		--		(921.0	)	--

NET INCOME	18.0		795.8		891.7		(921.0	)	784.5

NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS	--		--		(5.1	)	--		(5.1	)

NET INCOME ATTRIBUTABLE TO ENSCO	$18.0		$795.8		$ 886.6		$(921.0	)	$ 779.4

125

ENSCO PLC AND SUBSIDIARIES CONDENSED CONSOLIDATING BALANCE SHEETS December 31, 2011 (in millions)

	Ensco plc	ENSCO International Inc.	Pride International Inc.	Other Non-guarantor Subsidiaries of Ensco	Consolidating Adjustments		Total

ASSETS
CURRENT ASSETS
Cash and cash equivalents	$ 236.6	$ --	$ 22.6	$ 171.5	$ --		$ 430.7
Accounts receivable	--	.3	--	838.0	--		838.3
Accounts receivable from affiliates	1,268.4	89.8	278.2	1,194.5	(2,830.9	)	--
Other	2.8	35.2	46.2	291.5	--		375.7
Total current assets	1,507.8	125.3	347.0	2,495.5	(2,830.9	)	1,644.7

PROPERTY AND EQUIPMENT, AT COST	1.8	30.6	--	14,453.3	--		14,485.7
Less accumulated depreciation	.7	23.8	--	2,037.0	--		2,061.5
Property and equipment, net	1.1	6.8	--	12,416.3	--		12,424.2

GOODWILL	--	--	--	3,288.8	--		3,288.8

DUE FROM AFFILIATES	2,002.3	2,486.9	313.5	3,638.7	(8,441.4	)	--

INVESTMENTS IN AFFILIATES	12,041.9	2,966.0	4,802.6	--	(19,810.5	)	--

OTHER ASSETS, NET	13.9	83.4	9.8	406.4	--		513.5
	$15,567.0	$5,668.4	$5,472.9	$22,245.7	$(31,082.8	)	$17,871.2

LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable and accrued liabilities	$ 30.4	$ 20.0	$ 27.4	$ 1,073.1	$ --		$ 1,150.9
Accounts payable to affiliates	575.1	606.6	85.2	1,564.0	(2,830.9	)	--
Short-term debt	125.0	--	--	--	--		125.0
Current maturities of long-term debt	--	--	--	47.5	--		47.5
Total current liabilities	730.5	626.6	112.6	2,684.6	(2,830.9	)	1,323.4

DUE TO AFFILIATES	2,191.7	1,058.2	401.3	4,790.2	(8,441.4	)	--

LONG-TERM DEBT	2,465.7	149.0	2,072.5	190.4	--		4,877.6

DEFERRED INCOME TAXES	--	326.8	--	12.7	--		339.5

OTHER LIABILITIES	--	5.2	20.5	420.5	--		446.2

ENSCO SHAREHOLDERS' EQUITY	10,179.1	3,502.6	2,866.0	14,142.1	(19,810.5	)	10,879.3

NONCONTROLLING INTERESTS	--	--	--	5.2	--		5.2
Total equity	10,179.1	3,502.6	2,866.0	14,147.3	(19,810.5	)	10,884.5
	$15,567.0	$5,668.4	$5,472.9	$22,245.7	$(31,082.8	)	$17,871.2

126

ENSCO PLC AND SUBSIDIARIES CONDENSED CONSOLIDATING BALANCE SHEETS December 31, 2010 (in millions)

	Ensco plc	ENSCO International Inc.	Other Non-guarantor Subsidiaries of Ensco	Consolidating Adjustments		Total

ASSETS
CURRENT ASSETS
Cash and cash equivalents	$ 3.4	$ 19.1	$1,028.2	$ --		$1,050.7
Accounts receivable	--	1.8	212.8	--		214.6
Accounts receivable from affiliates	28.5	144.2	93.5	(266.2	)	--
Other	0.5	35.2	135.7	--		171.4
Total current assets	32.4	200.3	1,470.2	(266.2	)	1,436.7

PROPERTY AND EQUIPMENT, AT COST	1.8	24.5	6,718.3	--		6,744.6
Less accumulated depreciation	0.3	22.0	1,672.4	--		1,694.7
Property and equipment, net	1.5	2.5	5,045.9	--		5,049.9

GOODWILL	--	--	336.2	--		336.2

DUE FROM AFFILIATES	1,200.3	2,788.2	2,929.3	(6,917.8	)	--

INVESTMENTS IN AFFILIATES	5,063.4	2,687.4	--	(7,750.8	)	--

OTHER ASSETS, NET	--	130.7	98.0	--		228.7

	$6,297.6	$5,809.1	$9,879.6	$(14,934.8	)	$7,051.5

LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable and accrued liabilities	$ 2.4	$ 12.3	$ 317.1	$ --		$ 331.8
Accounts payable to affiliates	33.4	90.1	142.7	(266.2	)	--
Current maturities of long-term debt	--	--	17.2	--		17.2
Total current liabilities	35.8	102.4	477.0	(266.2	)	349.0

DUE TO AFFILIATES	922.6	2,006.7	3,988.5	(6,917.8	)	--

LONG-TERM DEBT	--	148.9	91.2	--		240.1

DEFERRED INCOME TAXES	--	346.0	12.0	--		358.0

OTHER LIABILITIES	--	5.1	134.3	--		139.4

ENSCO SHAREHOLDERS' EQUITY	5,339.2	3,200.0	5,171.1	(7,750.8	)	5,959.5

NONCONTROLLING INTERESTS	--	--	5.5	--		5.5
Total equity	5,339.2	3,200.0	5,176.6	(7,750.8	)	5,965.0
	$6,297.6	$5,809.1	$9,879.6	$(14,934.8	)	$7,051.5

127

ENSCO PLC AND SUBSIDIARIES CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS Year Ended December 31, 2011 (in millions)

	Ensco plc		ENSCO International Inc.		Pride International Inc.		Other Non-guarantor Subsidiaries of Ensco		Consolidating Adjustments	Total

OPERATING ACTIVITIES
Net cash (used in) provided by operating activities of continuing operations	$ 2.0		$ (13.7	)	$ (59.9	)	$ 803.9		$ --	$ 732.3

INVESTING ACTIVITIES
Acquisition of Pride International, Inc., net of cash acquired	--		--		92.9		(2,748.9	)	--	(2,656.0	)
Additions to property and equipment	--		(6.1	)	--		(735.5	)	--	(741.6	)
Proceeds from disposition of assets	--		--		--		46.5		--	46.5
Other	--		--		--		(4.5	)	--	(4.5	)
Net cash (used in) provided by investing activities	--		(6.1	)	92.9		(3,442.4	)	--	(3,355.6	)

FINANCING ACTIVITIES
Proceeds from issuance of senior notes	2,462.8		--		--		--		--	2,462.8
Cash dividends paid	(292.3	)	--		--		--		--	(292.3	)
Reduction of long-term borrowings	--		--		(181.0	)	(32.3	)	--	(213.3	)
Commercial paper borrowings, net	125.0		--		--		--		--	125.0
Equity financing costs	(70.5	)	--		--		--		--	(70.5	)
Proceeds from exercise of share options	--		39.9		--		--		--	39.9
Debt financing costs	(27.1	)	(4.7	)	--		--		--	(31.8	)
Advances (to) from affiliates	(1,966.7	)	(34.5	)	170.6		1,830.6		--	--
Other	--		--		--		(15.7	)	--	(15.7	)
Net cash provided by (used in) financing activities	231.2		.7		(10.4	)	1,782.6		--	2,004.1

Effect of exchange rate changes on cash and cash equivalents	--		--		--		(.8	)	--	(.8	)
Net cash provided by operating activities of discontinued operations	--		--		--		--		--	--
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	233.2		(19.1	)	22.6		(856.7	)	--	(620.0	)

CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD	3.4		19.1		--		1,028.2		--	1,050.7

CASH AND CASH EQUIVALENTS, END OF PERIOD	$ 236.6		$ --		$ 22.6		$ 171.5		$ --	$ 430.7

128

ENSCO PLC AND SUBSIDIARIES CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS Year Ended December 31, 2010 (in millions)

	Ensco plc		ENSCO International Inc.		Other Non-guarantor Subsidiaries of Ensco		Consolidating Adjustments	Total

OPERATING ACTIVITIES
Net cash (used in) provided by operating activities of continuing operations	$ (6.8	)	$ (55.1	)	$ 878.6		$ --	$ 816.7

INVESTING ACTIVITIES
Additions to property and equipment	(1.8	)	--		(873.5	)	--	(875.3	)
Proceeds from disposal of discontinued operations	--		--		158.1		--	158.1
Proceeds from disposition of assets	--		--		1.5		--	1.5
Net cash used in investing activities	(1.8	)	--		(713.9	)	--	(715.7	)

FINANCING ACTIVITIES
Cash dividends paid	(153.7	)	--		--		--	(153.7	)
Reduction of long-term borrowings	--		--		(17.2	)	--	(17.2	)
Proceeds from exercise of share options	--		1.4		--		--	1.4
Debt financing costs	--		(6.2	)	--		--	(6.2	)
Advances (to) from affiliates	140.9		(183.3	)	42.4		--	--
Other	--		--		(16.9	)	--	(16.9	)
Net cash (used in) provided by financing activities	(12.8	)	(188.1	)	8.3		--	(192.6	)

Effect of exchange rate changes on cash and cash equivalents	--		--		(.5	)	--	(.5	)
Net cash (used in) provided by operating activities of discontinued operations	--		(15.5	)	16.9		--	1.4
NET (DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS	(21.4	)	(258.7	)	189.4		--	(90.7	)

CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD	24.8		277.8		838.8		--	1,141.4

CASH AND CASH EQUIVALENTS, END OF PERIOD	$ 3.4		$ 19.1		$1,028.2		$ --	$1,050.7

129

ENSCO PLC AND SUBSIDIARIES CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS Year Ended December 31, 2009 (in millions)

	Ensco plc		ENSCO International Inc.		Other Non-guarantor Subsidiaries of Ensco		Consolidating Adjustments	Total

OPERATING ACTIVITIES
Net cash (used in) provided by operating activities of continuing operations	$(4.5	)	$(44.7	)	$1,234.8		$ --	$1,185.6

INVESTING ACTIVITIES
Additions to property and equipment	--		(1.5	)	(855.7	)	--	(857.2	)
Proceeds from disposal of discontinued operations	--		--		14.3		--	14.3
Proceeds from disposition of assets	--		--		2.6		--	2.6
Net cash used in investing activities	--		(1.5	)	(838.8	)	--	(840.3	)

FINANCING ACTIVITIES
Cash dividends paid	--		(14.2	)	--		--	(14.2	)
Reduction of long-term borrowings	--		--		(17.2	)	--	(17.2	)
Proceeds from exercise of share options	--		9.6		--		--	9.6
Advances (to) from affiliates	29.3		54.7		(84.0	)	--	--
Other	--		(6.5	)	(5.9	)	--	(12.4	)
Net cash provided by (used in) financing activities	29.3		43.6		(107.1	)	--	(34.2	)

Effect of exchange rate changes on cash and cash equivalents	--		--		.5		--	.5
Net cash provided by operating activities of discontinued operations	--		2.9		37.3		--	40.2

NET INCREASE IN CASH AND CASH EQUIVALENTS	24.8		.3		326.7		--	351.8

CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD	--		277.5		512.1		--	789.6

CASH AND CASH EQUIVALENTS, END OF PERIOD	$24.8		$277.8		$ 838.8		$ --	$1,141.4

130

17. UNAUDITED QUARTERLY FINANCIAL DATA

The following table summarizes our unaudited quarterly consolidated income statement data for the years ended December 31, 2011 and 2010 (in millions, except per share amounts):

2011	First Quarter		Second Quarter		Third Quarter		Fourth Quarter		Year

Operating revenues	$361.5		$564.2		$915.6		$1,001.4		$2,842.7
Operating expenses
Contract drilling (exclusive of depreciation)	191.6		286.3		477.5		515.5		1,470.9
Depreciation	59.5		83.5		135.8		140.1		418.9
General and administrative	30.1		47.4		40.8		40.3		158.6
Operating income	80.3		147.0		261.5		305.5		794.3
Other income (expense), net	2.2		(18.1	)	(13.5	)	(28.3	)	(57.7	)
Income before income taxes	82.5		128.9		248.0		277.2		736.6
Provision for income taxes	17.0		25.3		41.9		46.8		131.0
Net income	65.5		103.6		206.1		230.4		605.6
Net income attributable to noncontrolling interests	(.9	)	(1.7	)	(1.6	)	(1.0	)	(5.2	)
Net income attributable to Ensco	$ 64.6		$101.9		$204.5		$ 229.4		$ 600.4

Earnings per share – basic
Continuing operations	$ .45		$ .59		$ .89		$ .99		$ 3.09
Discontinued operations	--		--		--		--		--
	$ .45		$ .59		$ .89		$ .99		$ 3.09

Earnings per share – diluted
Continuing operations	$ .45		$ .59		$ .88		$ .99		$ 3.08
Discontinued operations	--		--		--		--		--
	$ .45		$ .59		$ .88		$ .99		$ 3.08

131

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

132

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, 2011, 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.

133

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, 2011 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 713-430-4607.

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.

134

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, 2011:

					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		1,370,642		$48.59		3,258,546
Equity compensation plans not approved by security holders(2)		98		23.12		--
Equity compensation plans not approved by security holders(3)		917,953		34.11		--
Total		2,288,693		$42.78		3,258,546

(1)		Under the LTIP, 3.3 million shares remained available for future issuances of equity awards as of December 31, 2011. Of the 3.3 million shares authorized for future issuances, 3.3 million are authorized for future option issuances, 1.6 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, 2011, 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.
(3)		In connection with the Merger, we assumed Pride’s option plan and the outstanding options thereunder. As of December 31, 2011, options to purchase 918,000 shares at a weighted-average exercise price of $34.11 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.

135

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

136

Exhibit

Number

Exhibit

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 filed on November 9, 2009, File No. 333-162975).

2.2

Agreement and Plan of Merger by and among Ensco plc, Pride International, Inc., ENSCO International Incorporated, and ENSCO Ventures LLC, dated as of 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).

2.3

Amendment No. 1 to Agreement and Plan of Merger by and among Ensco plc, Pride International, Inc., ENSCO International Incorporated and ENSCO Ventures LLC, dated as of March 1, 2011 (incorporated by reference to Exhibit 2.2 to the Registrants Registration Statement on Form S-4 filed on March 3, 2011, File No. 333-172587).

2.4

Amendment No. 2 to Agreement and Plan of Merger by and among Ensco plc, Pride International, Inc., ENSCO International Incorporated and ENSCO Ventures LLC, dated as of May 23, 2011 (incorporated by reference to Exhibit 2.1 to the Registrant’s Current Report on Form 8-K filed with the SEC on May 24, 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 filed on November 9, 2009, File No. 333-162975).

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 as of 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 as of 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 as of 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).

137

Exhibit

Number

Exhibit

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).

4.7

Indenture, dated as of July 1, 2004 between Pride International, Inc. and The Bank of New York Mellon, as trustee, including the form of notes issued pursuant thereto (successor to JPMorgan Chase Bank) (incorporated by reference to Exhibit 4.1 to Pride International, Inc.’s Registration Statement on Form S-4 filed on August 10, 2004, File No. 333-118104).

4.8

Second Supplemental Indenture, dated as of June 2, 2009 between Pride International, Inc. and The Bank of New York Mellon, as trustee, including the form of notes issued pursuant thereto (incorporated by reference to Exhibit 4.1 to Pride International, Inc.’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2009, File No. 1-13289).

4.9

Third Supplemental Indenture, dated as of August 6, 2010 between Pride International, Inc. and The Bank of New York Mellon, as trustee, including the form of notes issued pursuant thereto (incorporated by reference to Exhibit 4.3 to Pride International, Inc.’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2010, File No. 1-13289).

4.10

Fourth Supplemental Indenture, dated as of May 31, 2011, among Ensco plc, Pride International, Inc. and The Bank of New York Mellon, as trustee (incorporated by reference to Exhibit 4.4 to the Registrant's Current Report on Form 8-K filed on May 31, 2011, File No. 1-8097).

4.11

Form of Guarantee by Ensco plc (incorporated by reference to Exhibit 4.4 to the Registrant’s Current Report on Form 8-K filed on May 31, 2011, File No. 1-8097).

4.12

Indenture dated as of March 17, 2011 by and between Ensco plc and Deutsche Bank Trust Company Americas, as trustee (incorporated by reference to Exhibit 4.22 to Post-Effective Amendment No. 2 to the Registrant’s Registration Statement on Form S-3 filed on March 17, 2011, File No. 333-156705).

4.13

First Supplemental Indenture dated as of March 17, 2011 by and between Ensco plc and Deutsche Bank Trust Company Americas, as trustee (incorporated by reference to Exhibit 4.23 to Post-Effective Amendment No. 2 to the Registrant’s Registration Statement on Form S-3 filed on March 17, 2011, File No. 333-156705).

4.14

Form of Global Note for 3.250% Senior Notes due 2016 (incorporated by reference to Exhibit A of Exhibit 4.23 to Post-Effective Amendment No. 2 to the Registrant’s Registration Statement on Form S-3 filed on March 17, 2011, File No. 333-156705).

4.15

Form of Global Note for 4.700% Senior Notes due 2021 (incorporated by reference to Exhibit B of Exhibit 4.23 to Post-Effective Amendment No. 2 to the Registrant’s Registration Statement on Form S-3 filed on March 17, 2011, File No. 333-156705).

4.16

Form of Deed of Release of Shareholders (incorporated by reference to Annex A to the Registrant’s Proxy Statement on Schedule 14A filed on April 5, 2011, File No. 1-8097).

138

Exhibit

Number

Exhibit

10.1

Third Amended and Restated Credit Agreement, dated as of May 12, 2011, among Ensco plc, ENSCO International Incorporated, ENSCO Universal Limited, and ENSCO Offshore International Company, as Borrowers, Ensco plc, ENSCO Global Limited, ENSCO United Incorporated and ENSCO International Incorporated, as Guarantors, the Banks named therein, as Banks, Citibank, N.A., as Administrative Agent, Deutsche Bank Securities, Inc., as Syndication Agent, and Citibank, N.A., Deutsche Bank AG New York Branch, Wells Fargo Bank, National Association and DnB NOR Bank ASA, each as an Issuing Bank (incorporated by reference to Exhibit 10.1 to the Registrant's Current Report on Form 8-K filed on May 18, 2011, File No. 1-8097).

10.2

Third Amended and Restated Guaranty, dated as of May 12, 2011, made by Ensco plc, ENSCO Global Limited, ENSCO United Incorporated and ENSCO International Incorporated, as Guarantors, in favor of Citibank, N.A., as Administrative Agent under the Third Amended and Restated Credit Agreement (incorporated by reference to Exhibit 10.2 to the Registrant's Current Report on Form 8-K filed on May 18, 2011, File No. 1-8097).

10.3

364-Day Credit Agreement, dated as of May 12, 2011, among Ensco plc, ENSCO International Incorporated, ENSCO Universal Limited, and ENSCO Offshore International Company, as Borrowers, Ensco plc, ENSCO Global Limited, ENSCO United Incorporated and ENSCO International Incorporated, as Guarantors, the Banks named therein, as Banks, Citibank, N.A., as Administrative Agent, Deutsche Bank Securities, Inc. as Syndication Agent, and Citigroup Global Markets Inc. and Deutsche Bank Securities Inc. as Joint Lead Arrangers and Joint Book Managers (incorporated by reference to Exhibit 10.3 to the Registrant's Current Report on Form 8-K filed on May 18, 2011, File No. 1-8097).

10.4

364-Day Guaranty, dated as of May 12, 2011, made by Ensco plc, ENSCO Global Limited, ENSCO United Incorporated and ENSCO International Incorporated, as Guarantors, in favor of Citibank, N.A., as Administrative Agent under the 364-Day Credit Agreement (incorporated by reference to Exhibit 10.4 to the Registrant's Current Report on Form 8-K filed on May 18, 2011, File No. 1-8097).

+10.5

Pride International, Inc. 1993 Directors’ Stock Option Plan (incorporated by reference to Exhibit 10(j) to Pride’s Annual Report on Form 10-K for the year ended December 31, 1992, File No. 0-16963).

+10.6

First Amendment to Pride International, Inc. 1993 Directors’ Stock Option Plan (incorporated by reference to Exhibit 4.7 to Pride’s Registration Statement on Form S-8, File No. 333-35093).

+10.7

Second Amendment to Pride International, Inc. 1993 Directors’ Stock Option Plan (incorporated by reference to Exhibit 10.10 to Pride’s Annual Report on Form 10-K for the year ended December 31, 1997, File No. 1-13289).

+10.8

Third Amendment to Pride International, Inc. 1993 Directors’ Stock Option Plan (incorporated by reference to Exhibit 10.11 of Pride’s Annual Report on Form 10-K for the year ended December 31, 1998, File No. 1-13289).

139

Exhibit

Number

Exhibit

+10.9

Fourth Amendment to Pride International, Inc. 1993 Directors’ Stock Option Plan (incorporated by reference to Exhibit 10.12 to Pride’s Annual Report on Form 10-K for the year ended December 31, 2002, File No. 1-13289).

+10.10

Fifth Amendment to Pride International, Inc. 1993 Directors’ Stock Option Plan (incorporated by reference to Exhibit 10.13 to Pride’s Annual Report on Form 10-K for the year ended December 31, 2002, File No. 1-13289).

+10.11

Sixth Amendment to Pride International, Inc. 1993 Directors’ Stock Option Plan (incorporated by reference to Exhibit 10.5 to Pride’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2005, File No. 1-13289)

+10.12

Seventh Amendment to Pride International, Inc. 1993 Directors’ Stock Option Plan, effective as of May 31, 2011 (incorporated by reference to Exhibit 4.38 to the Registrant’s Registration Statement on Form S-8 filed on May 31, 2011, File No. 333-174611).

+10.13

Pride International, Inc. 1998 Long-Term Incentive Plan, as amended and restated (incorporated by reference to Exhibit 10.21 to Pride’s Annual Report on Form 10-K for the year ended December 31, 2004, File No. 1-13289).

+10.14

Amendment to Pride International, Inc. 1998 Long-Term Incentive Plan, as amended and restated, effective as of May 31, 2011 (incorporated by reference to Exhibit 4.37 to the Registrant’s Registration Statement on Form S-8 filed on May 31, 2011, File No. 333-174611).

+10.15

Pride International, Inc. 2004 Directors’ Stock Incentive Plan, as amended and restated, (incorporated by reference to Appendix B to Pride’s Proxy Statement on Schedule 14A for the 2008 Annual Meeting of Stockholders, File No. 1-13289).

+10.16

First Amendment to 2004 Directors’ Stock Incentive Plan, as amended and restated, (incorporated by reference to Exhibit 10.2 to Pride’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2008, File No. 1-13289).

+10.17

Amendment to Pride International, Inc. 2004 Directors’ Stock Incentive Plan, as amended and restated, effective as of May 31, 2011 (incorporated by reference to Exhibit 4.36 to the Registrant’s Registration Statement on Form S-8 filed on May 31, 2011, File No. 333-174611).

+10.18

Pride International, Inc. 2007 Long-Term Incentive Plan, as amended and restated, (incorporated by reference to Appendix A to Pride’s Proxy Statement on Schedule 14A for the 2010 Annual Meeting of Stockholders, File No. 1-13289).

140

Exhibit

Number

Exhibit

+10.19

First Amendment to Pride International, Inc. 2007 Long-Term Incentive Plan, as amended and restated, (incorporated by reference to Exhibit 10.1 to Pride’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2010, File No. 1-13289).

+10.20

Amendment to Pride International, Inc. 2007 Long-Term Incentive Plan, as amended and restated, effective as of May 31, 2011 (incorporated by reference to Exhibit 4.35 to the Registrant’s Registration Statement on Form S-8 filed on May 31, 2011, File No. 333-174611)

+10.21

Deed of Assumption by Ensco plc relating to equity incentive plans of Pride International, Inc., dated as of May 26, 2011 (incorporated by reference to Exhibit 4.34 to the Registrant’s Registration Statement on Form S-8 filed on May 31, 2011, File No. 333-174611)

+10.22

Form of Deed of Release of Directors (incorporated by reference to Annex B to the Registrant’s Proxy Statement on Schedule 14A filed on April 5, 2011, File No. 1-8097).

+10.23

Form of Deed of Indemnity for directors and executive officers of Ensco plc (incorporated by reference to Exhibit 10.27 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2011, File No. 1-8097).

+10.24

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, File No. 333-58625).

+10.25

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).

+10.26

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).

+10.27

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).

141

Exhibit

Number

Exhibit

+10.28

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).

+10.29

Amendment to the ENSCO International Incorporated 1998 Incentive Plan, executed on August 23, 2011 (incorporated by reference to Exhibit 10.1 to the Registrant's Quarterly Report on Form 10-Q for the quarter ended September 30, 2011, File No. 1-8097).

+10.30

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, File No. 333-97757).

+10.31

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, File No. 333-97757).

+10.32

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, File No. 333-97757).

+10.33

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).

+10.34

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).

+10.35

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).

+10.36

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).

142

Exhibit

Number

Exhibit

+10.37

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).

+10.38

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).

+10.39

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).

+10.40

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).

+10.41

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).

+10.42

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).

+10.43

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).

+10.44

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).

+10.45

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).

143

Exhibit

Number

Exhibit

+10.46

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).

+10.47

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).

+10.48

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).

+10.49

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).

+10.50

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).

+10.51

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).

+10.52

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).

+10.53

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, File No. 1-8097).

+10.54

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).

+10.55

ENSCO International Incorporated Savings Plan, as revised and restated effective January 1, 2002, incorporating Amendments Nos. 1 - 17 dated November 18, 2010 (incorporated by reference to Exhibit 10.33 to the Registrant's Annual Report on Form 10-K for the year ended December 31, 2011, File No. 1-8097).

144

Exhibit

Number

Exhibit

+10.56

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).

+10.57

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).

+10.58

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).

+10.59

Deed of Amendment No. 3 to the Ensco Multinational Savings Plan, dated as of November 4, 2010 (incorporated by reference to Exhibit 10.37 to the Registrant's Annual Report on Form 10-K for the year ended December 31, 2011, File No. 1-8097).

+10.60

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).

+10.61

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).

+10.62

Second Amendment to the 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 10.2 to the Registrant's Quarterly Report on Form 10-Q for the period ending September 30, 2011, File No. 1-8097).

+10.63

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).

+10.64

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).

145

Exhibit

Number

Exhibit

+10.65

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).

+10.66

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).

+10.67

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).

+10.68

2010 Performance Criteria for Named Executive Officers under the ENSCO 2005 Cash Incentive Plan (incorporated by reference to “Compensation Discussion and Analysis – Components of Compensation for 2010 – Cash Bonus” in the Registrant's Definitive Proxy Statement filed on April 5, 2011, File No. 1-8097).

+10.69

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).

+10.70

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).

+10.71

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).

+10.72

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).

+10.73

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).

+10.74

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).

+10.75

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).

146

Exhibit

Number

Exhibit

+10.76

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).

+10.77

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).

+10.78

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).

+10.79

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).

+10.80

Summary of 2011 Compensation of Non-Employee Directors, (incorporated by reference to “Executive Compensation – Compensation of Non-Employee Directors” in the Registrant's Definitive Proxy Statement filed on April 5, 2011, File No. 1-8097).

+10.81

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).

*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.

**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.

147

Exhibit

Number

Exhibit

*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.

148

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, 2012.

		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, 2012

/s/ DAVID A. B. BROWN	Director	February 24, 2012
David A. B. Brown

/s/ J. RODERICK CLARK J. Roderick Clark	Director	February 24, 2012

/s/ C. CHRISTOPHER GAUT C. Christopher Gaut	Director	February 24, 2012

/s/ GERALD W. HADDOCK Gerald W. Haddock	Director	February 24, 2012

/s/ FRANCIS S. KALMAN	Director	February 24, 2012
Francis S. Kalman

/s/ THOMAS L. KELLY II Thomas L. Kelly II	Director	February 24, 2012

/s/ KEITH O. RATTIE Keith O. Rattie	Director	February 24, 2012

/s/ RITA M. RODRIGUEZ Rita M. Rodriguez	Director	February 24, 2012

/s/ PAUL E. ROWSEY, III Paul E. Rowsey, III	Director	February 24, 2012

/s/ JAMES W. SWENT III James W. Swent III	Senior Vice President and Chief Financial Officer (principal financial officer)	February 24, 2012

/s/ MICHAEL B. HOWE Michael B. Howe	Vice President - Finance (Corporate)	February 24, 2012

/s/ DOUGLAS J. MANKO Douglas J. Manko	Controller (principal accounting officer)	February 24, 2012

149

INDEX TO EXHIBITS

Exhibit

Number

Exhibit

2.1

2.2

2.3

2.4

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

4.2

4.3

4.4

4.5

150

Exhibit

Number

Exhibit

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).

4.7

4.8

4.9

4.10

4.11

Form of Guarantee by Ensco plc (incorporated by reference to Exhibit 4.4 to the Registrant’s Current Report on Form 8-K filed on May 31, 2011, File No. 1-8097).

4.12

4.13

4.14

4.15

4.16

Form of Deed of Release of Shareholders (incorporated by reference to Annex A to the Registrant’s Proxy Statement on Schedule 14A filed on April 5, 2011, File No. 1-8097).

151

Exhibit

Number

Exhibit

10.1

10.2

10.3

10.4

+10.5

+10.6

First Amendment to Pride International, Inc. 1993 Directors’ Stock Option Plan (incorporated by reference to Exhibit 4.7 to Pride’s Registration Statement on Form S-8, File No. 333-35093).

+10.7

+10.8

152

Exhibit

Number

Exhibit

+10.9

+10.10

+10.11

+10.12

+10.13

+10.14

+10.15

+10.16

+10.17

+10.18

153

Exhibit

Number

Exhibit

+10.19

+10.20

+10.21

+10.22

Form of Deed of Release of Directors (incorporated by reference to Annex B to the Registrant’s Proxy Statement on Schedule 14A filed on April 5, 2011, File No. 1-8097).

+10.23

+10.24

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, File No. 333-58625).

+10.25

+10.26

+10.27

154

Exhibit

Number

Exhibit

+10.28

+10.29

+10.30

+10.31

+10.32

+10.33

+10.34

+10.35

+10.36

155

Exhibit

Number

Exhibit

+10.37

+10.38

+10.39

+10.40

+10.41

+10.42

+10.43

+10.44

+10.45

156

Exhibit

Number

Exhibit

+10.46

+10.47

+10.48

+10.49

+10.50

+10.51

+10.52

+10.53

+10.54

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).

+10.55

157

Exhibit

Number

Exhibit

+10.56

+10.57

+10.58

+10.59

+10.60

+10.61

+10.62

+10.63

+10.64

158

Exhibit

Number

Exhibit

+10.65

+10.66

+10.67

+10.68

+10.69

+10.70

+10.71

+10.72

+10.73

+10.74

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).

+10.75

159

Exhibit

Number

Exhibit

+10.76

+10.77

+10.78

+10.79

+10.80

+10.81

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).

*21.1

Subsidiaries of the Registrant.

*23.1

Consent of Independent Registered Public Accounting Firm.

*31.1

*31.2

**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.

160

Exhibit

Number

Exhibit

*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.

161