Edgar Filing: Ensco plc

form10q3rdqtr2010.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2010

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

SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission File Number 1-8097

Ensco plc

(Exact name of registrant as specified in its charter)

England and Wales (State or other jurisdiction of incorporation or organization) 6 Chesterfield Gardens London, England (Address of principal executive offices)		98-0635229 (I.R.S. Employer Identification No.) W1J 5BQ (Zip Code)
Registrant's telephone number, including area code: 44 (0) 20 7659 4660

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ý No o

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

Large accelerated filer ý

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

Accelerated filer o

Smaller reporting company o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No ý

As of October 20, 2010, there were 142,957,550 American depositary shares of the registrant issued and outstanding, each representing one Class A ordinary share.

ENSCO PLC

INDEX TO FORM 10-Q

FOR THE QUARTER ENDED SEPTEMBER 30, 2010

PART I	FINANCIAL INFORMATION
	ITEM 1.	FINANCIAL STATEMENTS	5
		Report of Independent Registered Public Accounting Firm	5
		Condensed Consolidated Statements of Income Three Months Ended September 30, 2010 and 2009	6
		Condensed Consolidated Statements of Income Nine Months Ended September 30, 2010 and 2009	7
		Condensed Consolidated Balance Sheets September 30, 2010 and December 31, 2009	8
		Condensed Consolidated Statements of Cash Flows Nine Months Ended September 30, 2010 and 2009	9
		Notes to Condensed Consolidated Financial Statements	10
	ITEM 2.	MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	29
	ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	48
	ITEM 4.	CONTROLS AND PROCEDURES	48
PART II	OTHER INFORMATION
	ITEM 1.	LEGAL PROCEEDINGS	49
	ITEM 1A.	RISK FACTORS	55
	ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	58
	ITEM 6.	EXHIBITS	59
	SIGNATURES		60

FORWARD-LOOKING STATEMENTS

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

Forward-looking statements include words or phrases such as "anticipate," "believe," "estimate," "expect," "intend," "plan," "project," "could," "may," "might," "should," "will" and words and phrases of similar import. The forward-looking statements include, but are not limited to, statements about our intention to explore alternatives to keep our rigs operating, high-grading the rig fleet by investing in new equipment and divesting selected assets, potential utilization of ENSCO 69 and contemplated sale of ENSCO 60. The forward-looking statements also include statements regarding future operations, market conditions, cash generation, the impact of the BP Macondo well incident in the U.S. Gulf of Mexico, contributions from our ultra-deepwater semisubmersible rig fleet expansion program, expense management, industry trends or conditions and the overall business environment; statements regarding future levels of, or trends in, utilization, day rates, revenues, operating expenses, contract term, contract backlog, capital expenditures, insurance, financing and funding; statements regarding future rig construction (including construction in progress and completion thereof), enhancement, upgrade or repair and timing thereof; statements regarding future delivery, mobilization, contract commencement, relocation or other movement of rigs and timing thereof; statements regarding future availability or suitability of rigs and the timing thereof; and statements regarding the likely outcome of litigation, legal proceedings, investigations or insurance or other claims and the timing thereof.

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

	•	changes in U.S. or non-U.S. laws, including tax laws, that could effectively reduce or eliminate the benefits we expect to achieve from the December 2009 reorganization of the Company's corporate structure (the "redomestication") or regulatory or legislative activity that would impact U.S. Gulf of Mexico operations, potentially resulting in a force majeure situation,
	•	an inability to realize expected benefits from the redomestication,
	•	the impact of the BP Macondo well incident in the U.S. Gulf of Mexico upon future deepwater and other offshore drilling operations in general, and as respects current and future actual or de facto drilling permit and operations delays, moratoria or suspensions, new and future regulatory, legislative or permitting requirements (including requirements related to equipment and operations), future lease sales and other governmental activities that may impact deepwater and other offshore operations in the U.S. Gulf of Mexico in general, and our existing drilling contracts for ENSCO 8500, ENSCO 8501, ENSCO 8502, ENSCO 8503 and our U.S. Gulf of Mexico jackup rigs in particular,

	•	resolution of the pending contractual dispute with a customer regarding the ENSCO 8502 drilling contract,
	•	industry conditions and competition, including changes in rig supply and demand or new technology,
	•	risks associated with the global economy and its impact on capital markets and liquidity,

	•	prices of oil and natural gas and their impact upon future levels of drilling activity and expenditures,
	•	worldwide expenditures for oil and natural gas drilling,

	•	further declines in drilling activity, which may cause us to idle or stack additional rigs,
	•	excess rig availability or supply resulting from delivery of newbuild drilling rigs,
	•	concentration of our rig fleet in premium jackups,
	•	concentration of our active ultra-deepwater semisubmersible drilling rigs in the U.S. Gulf of Mexico,
	•	cyclical nature of the industry,
	•	risks associated with offshore rig operations or rig relocations,
	•	inability to collect receivables,
	•	availability of transport vessels to relocate rigs,
	•	the ultimate resolution of the ENSCO 69 pending litigation and related package policy political risk insurance recovery,
	•	changes in the timing of revenue recognition resulting from the deferral of certain revenues for mobilization of our drilling rigs, time waiting on weather or time in shipyards, which are recognized over the contract term upon commencement of drilling operations,

	•	operational risks, including excessive unplanned downtime due to rig or equipment failure, damage or repair in general and hazards created by severe storms and hurricanes in particular,
	•	changes in the dates our rigs will enter a shipyard, be delivered, return to service or enter service,
	•	risks inherent to shipyard rig construction, repair or enhancement, including risks associated with concentration of our remaining three ENSCO 8500 Series® rig construction contracts in a single shipyard in Singapore, unexpected delays in equipment delivery and engineering or design issues following shipyard delivery,
	•	changes in the dates new contracts actually commence,
	•	renegotiation, nullification, cancellation or breach of contracts or letters of intent with customers or other parties, including failure to negotiate definitive contracts following announcements or receipt of letters of intent and failure to consummate the contemplated sale of ENSCO 60,

•

environmental or other liabilities, risks or losses, whether related to hurricane damage, losses or liabilities (including wreckage or debris removal) in the Gulf of Mexico or otherwise, that may arise in the future which are not covered by insurance or indemnity in whole or in part,

	•	limited availability or high cost of insurance coverage for certain perils such as hurricanes in the Gulf of Mexico or associated removal of wreckage or debris,
	•	self-imposed or regulatory limitations on drilling locations in the Gulf of Mexico during hurricane season,

	•	impact of current and future government laws and regulation affecting the oil and gas industry in general and our operations in particular, including taxation, as well as repeal or modification of same,
	•	our ability to attract and retain skilled personnel,
	•	governmental action and political and economic uncertainties, which may result in expropriation, nationalization, confiscation or deprivation of our assets or create a force majeure situation,
	•	terrorism or military action impacting our operations, assets or financial performance,
	•	outcome of litigation, legal proceedings, investigations or insurance or other claims,
	•	adverse changes in foreign currency exchange rates, including their impact on the fair value measurement of our derivative instruments,
	•	potential long-lived asset or goodwill impairments,
	•	potential reduction in fair value of our auction rate securities and the ultimate resolution of our pending arbitration proceedings.

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

In addition to the numerous factors described above and in "Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations" in Part I and "Item 1A. Risk Factors" in Part II of this report, you should carefully read and consider "Item 1A. Risk Factors" in Part I and "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" in Part II of our Annual Report on Form 10-K for the year ended December 31, 2009, as updated in the Current Reports on Form 8-K dated June 8, 2010 and August 13, 2010.

PART I - FINANCIAL INFORMATION

Item 1. Financial Statements

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Shareholders

Ensco plc:

We have reviewed the condensed consolidated balance sheet of Ensco plc and subsidiaries as of September 30, 2010, the related condensed consolidated statements of income for the three-month and nine-month periods ended September 30, 2010 and 2009, and the related condensed consolidated statements of cash flows for the nine-month periods ended September 30, 2010 and 2009. These condensed consolidated financial statements are the responsibility of the Company's management.

We conducted our review in accordance with the standards of the Public Company Accounting Oversight Board (United States). A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board (United States), the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.

Based on our review, we are not aware of any material modifications that should be made to the condensed consolidated financial statements referred to above for them to be in conformity with U.S. generally accepted accounting principles.

We have previously audited, in accordance with standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet of Ensco plc and subsidiaries as of December 31, 2009, and the related consolidated statements of income and cash flows for the year then ended (not presented herein); and in our report dated February 25, 2010 except for the updated disclosures and reclassification of ENSCO 50, ENSCO 51 and ENSCO 57 operating results from continuing to discontinued operations for all periods presented, as described in Note 11, as to which the date is June 8, 2010 for ENSCO 50 and ENSCO 51 and August 13, 2010 for ENSCO 57, we expressed an unqualified opinion on these consolidated financial statements. In our opinion, the information set forth in the accompanying condensed consolidated balance sheet as of December 31, 2009, is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

/s/ KPMG LLP

Dallas, Texas

October 21, 2010

ENSCO PLC AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(In millions, except per share amounts)

(Unaudited)

	Three Months Ended September 30,
	2010			2009

OPERATING REVENUES		$428.3			$408.9

OPERATING EXPENSES
Contract drilling (exclusive of depreciation)		194.1			175.4
Depreciation		55.6			48.9
General and administrative		20.6			13.6
		270.3			237.9

OPERATING INCOME		158.0			171.0

OTHER INCOME, NET		2.7			3.6

INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES		160.7			174.6

PROVISION FOR INCOME TAXES
Current income tax expense		25.6			18.1
Deferred income tax expense		1.1			11.5
		26.7			29.6

INCOME FROM CONTINUING OPERATIONS		134.0			145.0

(LOSS) INCOME FROM DISCONTINUED OPERATIONS, NET		(1.9	)		5.8

NET INCOME		132.1			150.8

NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS		(1.6	)		(1.1	)

NET INCOME ATTRIBUTABLE TO ENSCO		$130.5			$149.7

EARNINGS (LOSS) PER SHARE - BASIC
Continuing operations		$ .92			$ 1.01
Discontinued operations		(.01	)		.04
		$ .91			$ 1.05
EARNINGS (LOSS) PER SHARE - DILUTED
Continuing operations		$ .92			$ 1.01
Discontinued operations		(.01	)		.04
		$ .91			$ 1.05

NET INCOME ATTRIBUTABLE TO ENSCO SHARES
Basic		$128.7			$147.8
Diluted		$128.7			$147.8
WEIGHTED-AVERAGE SHARES OUTSTANDING
Basic		141.1			140.7
Diluted		141.2			140.7

CASH DIVIDENDS PER SHARE		$ .35			$ .025

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

ENSCO PLC AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(In millions, except per share amounts)

(Unaudited)

	Nine Months Ended September 30,
	2010			2009

OPERATING REVENUES		$1,288.3			$1,391.1

OPERATING EXPENSES
Contract drilling (exclusive of depreciation)		582.5			533.2
Depreciation		159.2			137.9
General and administrative		63.2			41.6
		804.9			712.7

OPERATING INCOME		483.4			678.4

OTHER INCOME, NET		18.6			6.2

INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES		502.0			684.6

PROVISION FOR INCOME TAXES
Current income tax expense		77.5			100.6
Deferred income tax expense		6.6			29.1
		84.1			129.7

INCOME FROM CONTINUING OPERATIONS		417.9			554.9

DISCONTINUED OPERATIONS
(Loss) income from discontinued operations, net		(1.2	)		19.4
Gain on disposal of discontinued operations, net		34.9			--
		33.7			19.4

NET INCOME		451.6			574.3

NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS		(5.0	)		(3.6	)

NET INCOME ATTRIBUTABLE TO ENSCO		$ 446.6			$ 570.7

EARNINGS PER SHARE - BASIC
Continuing operations		$ 2.89			$ 3.89
Discontinued operations		.24			.13
		$ 3.13			$ 4.02

EARNINGS PER SHARE - DILUTED
Continuing operations		$ 2.89			$ 3.88
Discontinued operations		.24			.13
		$ 3.13			$ 4.01

NET INCOME ATTRIBUTABLE TO ENSCO SHARES
Basic		$ 440.9			$ 563.7
Diluted		$ 440.9			$ 563.7
WEIGHTED-AVERAGE SHARES OUTSTANDING
Basic		140.9			140.3
Diluted		141.0			140.4

CASH DIVIDENDS PER SHARE		$ .725			$ .075

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

ENSCO PLC AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(In millions, except share and par value amounts)

	September 30, 2010			December 31, 2009
	(Unaudited)
ASSETS

CURRENT ASSETS
Cash and cash equivalents		$ 905.2		$1,141.4
Accounts receivable, net		414.9		324.6
Other		205.8		186.8
Total current assets		1,525.9		1,652.8

PROPERTY AND EQUIPMENT, AT COST		6,625.6		6,151.2
Less accumulated depreciation		1,639.5		1,673.9
Property and equipment, net		4,986.1		4,477.3

GOODWILL		336.2		336.2

LONG-TERM INVESTMENTS		45.0		60.5

OTHER ASSETS, NET		216.9		220.4
		$7,110.1		$6,747.2

LIABILITIES AND SHAREHOLDERS' EQUITY

CURRENT LIABILITIES
Accounts payable - trade		$ 182.2		$ 159.1
Accrued liabilities and other		278.5		308.6
Current maturities of long-term debt		17.2		17.2
Total current liabilities		477.9		484.9

LONG-TERM DEBT		248.6		257.2

DEFERRED INCOME TAXES		376.1		377.3

OTHER LIABILITIES		134.5		120.7

COMMITMENTS AND CONTINGENCIES

ENSCO SHAREHOLDERS' EQUITY
Class A ordinary shares, U.S. $.10 par value, 450.0 million shares authorized, 150.0 million shares issued		15.0		15.0
Class B ordinary shares, £1 par value, 50,000 shares authorized
and issued		.1		.1
Additional paid-in capital		627.4		602.6
Retained earnings		5,222.2		4,879.2
Accumulated other comprehensive income		9.6		5.2
Treasury shares, at cost, 7.1 million and 7.5 million shares		(8.7	)	(2.9	)
Total Ensco shareholders' equity		5,865.6		5,499.2

NONCONTROLLING INTERESTS		7.4		7.9
Total equity		5,873.0		5,507.1
		$7,110.1		$6,747.2

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

ENSCO PLC AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In millions)

(Unaudited)

	Nine Months Ended September 30,
	2010		2009

OPERATING ACTIVITIES
Net income	$ 451.6		$ 574.3
Adjustments to reconcile net income to net cash provided by operating
activities of continuing operations:
Depreciation expense	159.2		137.9
Share-based compensation expense	33.5		25.1
Amortization expense	24.9		23.1
Loss on asset impairment	12.2		17.3
Deferred income tax expense	6.6		29.1
Loss (income) from discontinued operations, net	1.2		(19.4	)
Gain on disposal of discontinued operations, net	(34.9	)	--
Other	5.6		10.1
Changes in operating assets and liabilities:
(Increase) decrease in accounts receivable	(66.1	)	149.7
Decrease in trading securities	16.5		3.6
Increase in other assets	(41.9	)	(76.0	)
(Decrease) increase in liabilities	(47.0	)	23.0
Net cash provided by operating activities of continuing operations	521.4		897.8

INVESTING ACTIVITIES
Additions to property and equipment	(737.5	)	(681.1	)
Proceeds from disposal of discontinued operations	132.4		4.9
Proceeds from disposition of assets	1.1		1.8
Net cash used in investing activities	(604.0	)	(674.4	)

FINANCING ACTIVITIES
Cash dividends paid	(103.6	)	(10.7	)
Reduction of long-term borrowings	(8.6	)	(8.6	)
Financing costs	(6.2	)	--
Repurchase of shares	(5.8	)	(6.3	)
Other	(7.2	)	3.9
Net cash used in financing activities	(131.4	)	(21.7	)

Effect of exchange rate changes on cash and cash equivalents	(.5	)	.3
Net cash (used in) provided by operating activities of discontinued operations	(21.7	)	25.6

(DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS	(236.2	)	227.6

CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD	1,141.4		789.6

CASH AND CASH EQUIVALENTS, END OF PERIOD	$ 905.2		$1,017.2

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

ENSCO PLC AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 1 - Unaudited Condensed Consolidated Financial Statements

We prepared the accompanying condensed consolidated financial statements of Ensco plc and subsidiaries (the "Company", "Ensco", "we" or "us") in accordance with accounting principles generally accepted in the United States of America ("GAAP"), pursuant to the rules and regulations of the Securities and Exchange Commission (the "SEC") included in the instructions to Form 10-Q and Article 10 of Regulation S-X. The financial information included in this report is unaudited but, in our opinion, includes all adjustments (consisting of normal recurring adjustments) that are necessary for a fair presentation of our financial position, results of operations and cash flows for the interim periods presented. The December 31, 2009 condensed consolidated balance sheet data were derived from our 2009 audited consolidated financial statements, but do not include all disclosures required by GAAP. Certain previously reported amounts have been reclassified to conform to the current year presentation. The preparation of our condensed consolidated financial statements 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.

The financial data for the three-month and nine-month periods ended September 30, 2010 and 2009 included herein have been subjected to a limited review by KPMG LLP, our independent registered public accounting firm. The accompanying independent registered public accounting firm's review report is not a report within the meaning of Sections 7 and 11 of the Securities Act of 1933, and the independent registered public accounting firm's liability under Section 11 does not extend to it.

Results of operations for the three-month and nine-month periods ended September 30, 2010 are not necessarily indicative of the results of operations that will be realized for the year ending December 31, 2010. It is recommended that these condensed consolidated financial statements be read in conjunction with our audited consolidated financial statements and notes thereto for the year ended December 31, 2009 included in our Annual Report on Form 10-K filed with the SEC on February 25, 2010, as updated in the Current Reports on Form 8-K dated June 8, 2010 and August 13, 2010.

Note 2 - Noncontrolling Interests

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

The following table is a reconciliation of income from continuing operations attributable to Ensco for the three-month and nine-month periods ended September 30, 2010 and 2009 (in millions):

	Three Months Ended September 30,			Nine Months Ended September 30,
	2010	2009		2010		2009

Income from continuing operations	$134.0	$145.0		$417.9		$554.9
Income from continuing operations attributable to noncontrolling interests	(1.6)	(.9	)	(4.8	)	(3.0	)
Income from continuing operations attributable to Ensco	$132.4	$144.1		$413.1		$551.9

The following table is a reconciliation of (loss) income from discontinued operations attributable to Ensco for the three-month and nine-month periods ended September 30, 2010 and 2009 (in millions):

	Three Months Ended September 30,		Nine Months Ended September 30,
	2010	2009	2010		2009

(Loss) income from discontinued operations	$(1.9)	$5.8	$33.7		$19.4
Income from discontinued operations attributable to noncontrolling interests	--	(.2)	(.2	)	(.6)
(Loss) income from discontinued operations attributable to Ensco	$(1.9)	$5.6	$33.5		$18.8

Note 3 - 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 the three-month and nine-month periods ended September 30, 2010 and 2009 (in millions):

	Three Months				Nine Months
	Ended September 30,				Ended September 30,
	2010		2009		2010		2009

Net income attributable to Ensco	$130.5		$149.7		$446.6		$570.7
Net income allocated to non-vested share awards	(1.8	)	(1.9	)	(5.7	)	(7.0	)
Net income attributable to Ensco shares	$128.7		$147.8		$440.9		$563.7

The following table is a reconciliation of the weighted-average shares used in our basic and diluted EPS computations for the three-month and nine-month periods ended September 30, 2010 and 2009 (in millions):

	Three Months		Nine Months
	Ended September 30,		Ended September 30,
	2010	2009	2010	2009

Weighted-average shares - basic	141.1	140.7	140.9	140.3
Potentially dilutive share options	.1	.0	.1	.1
Weighted-average shares - diluted	141.2	140.7	141.0	140.4

Antidilutive share options totaling 1.1 million were excluded from the computation of diluted EPS during the three-month periods ended September 30, 2010 and 2009, respectively. Antidilutive share options totaling 1.1 million and 1.3 million were excluded from the computation of diluted EPS during the nine-month periods ended September 30, 2010 and 2009, respectively.

Note 4 - Derivative Instruments

Our functional currency is the U.S. dollar. As is customary in the oil and gas industry, a majority of our revenues are denominated in U.S. dollars, however, a portion of the revenues earned and expenses incurred by some of our subsidiaries are denominated in currencies other than the U.S. dollar ("foreign currencies"). These transactions are remeasured in U.S. dollars based on a combination of both current and historical exchange rates. We use foreign currency forward contracts ("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 September 30, 2010 and December 31, 2009, we occasionally employ an interest rate risk management strategy that utilizes derivatives to minimize or eliminate unanticipated fluctuations in earnings and cash flows arising from changes in, and volatility of, interest rates. We minimize our credit risk relating to the counterparties of our derivatives by transacting with multiple, high-quality financial institutions, thereby limiting exposure to individual counterparties, and by monitoring the financial condition of our counterparties. We do not enter into derivatives for trading or other speculative purposes.

All derivatives were recorded on our condensed 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. As of September 30, 2010 and December 31, 2009, our condensed consolidated balance sheets included net foreign currency derivative assets of $14.8 million and $13.2 million, respectively. All of our derivatives mature during the next 12 months. See "Note 8 - Fair Value Measurements" for additional information on the fair value measurement of our derivatives.

Derivatives recorded at fair value in our condensed consolidated balance sheets as of September 30, 2010 and December 31, 2009 consisted of the following (in millions):

	Derivative Assets		Derivative Liabilities
	September 30, 2010	December 31, 2009	September 30, 2010	December 31, 2009
Derivatives Designated as Hedging Instruments
Foreign currency forward contracts – current(1)	$14.9	$10.2	$.4	$1.1
Foreign currency forward contracts – non-current(2)	--	3.8	--	--
	14.9	14.0	.4	1.1
Derivatives Not Designated as Hedging Instruments
Foreign currency forward contracts – current(1)	.4	.3	.1	.0
	.4	.3	.1	.0
Total	$15.3	$14.3	$.5	$1.1

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

We utilize derivatives designated as hedging instruments to hedge forecasted foreign currency denominated transactions ("cash flow hedges"), primarily to reduce our exposure to foreign currency exchange rate risk associated with the portion of our remaining ENSCO 8500 Series® construction obligations denominated in Singapore dollars and contract drilling expenses denominated in various other currencies. As of September 30, 2010, we had cash flow hedges outstanding to exchange an aggregate $187.4 million for various foreign currencies, including $121.0 million for Singapore dollars, $41.6 million for British pounds, $15.0 million for Australian dollars and $9.8 million for other currencies.

Gains and losses on derivatives designated as cash flow hedges included in our condensed consolidated statements of income for the three-month and nine-month periods ended September 30, 2010 and 2009 were as follows (in millions):

Three Months Ended September 30, 2010 and 2009
Derivatives Designated as Cash Flow Hedges	Gain Recognized in Other Comprehensive Income ("OCI") (Effective Portion)		(Loss) Gain Reclassified from Accumulated Other Comprehensive Income ("AOCI") into Income (Effective Portion)		Gain (Loss) Recognized in Income on Derivatives (Ineffective Portion and Amount Excluded from Effectiveness Testing)(1)
	2010	2009	2010	2009	2010	2009

Interest rate lock contracts(2)	$ --	$ --	$(.2)	$(.2)	$--	$ --
Foreign currency forward contracts(3)	8.7	7.8	--	.8	.1	(.6)
Total	$8.7	$7.8	$(.2)	$ .6	$.1	$(.6)

Nine Months Ended September 30, 2010 and 2009
Derivatives Designated as Cash Flow Hedges	Gain Recognized in OCI (Effective Portion)		(Loss) Gain Reclassified from AOCI into Income (Effective Portion)		Loss Recognized in Income on Derivatives (Ineffective Portion and Amount Excluded from Effectiveness Testing)(1)
	2010	2009	2010	2009	2010	2009

Interest rate lock contracts(2)	$ --	$ --	$(.5)	$ (.5)	$ --	$ --
Foreign currency forward contracts(3)	5.7	6.6	1.8	(14.0)	(.1)	(3.0)
Total	$5.7	$6.6	$1.3	$(14.5)	$(.1)	$(3.0)

(1)		Gains and losses recognized in income for ineffectiveness and amounts excluded from effectiveness testing were included in other income, net, in our condensed consolidated statements of income.
(2)		Losses on derivatives reclassified from AOCI into income (effective portion) were included in other income, net, in our condensed 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 condensed 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 September 30, 2010, we had derivatives not designated as hedging instruments outstanding to exchange an aggregate $47.0 million for various foreign currencies, including $21.3 million for Australian dollars, $12.7 million for Singapore dollars, $7.9 million for British pounds and $5.1 million for other currencies.

Net gains of $3.6 million and $1.6 million associated with our derivatives not designated as hedging instruments were included in other income, net, in our condensed consolidated statements of income for the three-month periods ended September 30, 2010 and 2009, respectively. Net gains of $2.5 million and $3.8 million associated with our derivatives not designated as hedging instruments were included in other income, net, in our condensed consolidated statements of income for the nine-month periods ended September 30, 2010 and 2009, respectively.

As of September 30, 2010, the estimated amount of net gains associated with derivatives, net of tax, that will be reclassified to earnings during the next twelve months was as follows (in millions):

Net unrealized gains to be reclassified to contract drilling expense	$1.6
Net realized losses to be reclassified to other income, net	(.3	)
Net gains to be reclassified to earnings	$1.3

Note 5 - Accrued Liabilities and Other

Accrued liabilities and other as of September 30, 2010 and December 31, 2009 consisted of the following (in millions):

	2010	2009

Deferred revenue	$119.6	$ 89.0
Personnel costs	51.8	48.6
Taxes	51.3	97.3
Wreckage and debris removal	26.8	50.3
Other	29.0	23.4
	$278.5	$308.6

Note 6 - Long-Term Debt

On May 28, 2010, we entered into an amended and restated agreement (the "2010 Credit Facility") with a syndicate of banks that provides for a $700.0 million unsecured revolving credit facility for general corporate purposes. The 2010 Credit Facility has a four-year term, expiring in May 2014, and replaces our $350.0 million five-year credit agreement which was scheduled to mature in June 2010. Advances under the 2010 Credit Facility generally bear interest at LIBOR plus an applicable margin rate (currently 2.0% per annum), depending on our credit rating. We are required to pay an annual undrawn facility fee (currently .25% per annum) on the total $700.0 million commitment, which is also based on our credit rating. We also are required to maintain a debt to total capitalization ratio less than or equal to 50% under the 2010 Credit Facility. We have the right, subject to lender consent, to increase the commitments under the 2010 Credit Facility up to $850.0 million. We had no amounts outstanding under the 2010 Credit Facility or the prior credit agreement as of September 30, 2010 and December 31, 2009, respectively.

Note 7 - Comprehensive Income

Accumulated other comprehensive income as of September 30, 2010 and December 31, 2009 was comprised of gains and losses on derivative instruments, net of tax. The components of comprehensive income, net of tax, for the three-month and nine-month periods ended September 30, 2010 and 2009 were as follows (in millions):

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2010		2009		2010		2009

Net income	$132.1		$150.8		$451.6		$574.3
Other comprehensive income:
Net change in fair value of derivatives	8.7		7.8		5.7		6.6
Reclassification of gains and losses on derivative
instruments from other comprehensive loss (income)
into net income	.2		(.6	)	(1.3	)	14.5
Net other comprehensive income	8.9		7.2		4.4		21.1
Comprehensive income	141.0		158.0		456.0		595.4
Comprehensive income attributable to noncontrolling interests	(1.6	)	(1.1	)	(5.0	)	(3.6	)
Comprehensive income attributable to Ensco	$139.4		$156.9		$451.0		$591.8

Note 8 - Fair Value Measurements

The following fair value hierarchy table categorizes information regarding our financial assets and liabilities measured at fair value on a recurring basis as of September 30, 2010 and December 31, 2009 (in millions):

	Quoted Prices		Significant
	in Active		Other		Significant
	Markets for		Observable		Unobservable
	Identical Assets		Inputs		Inputs
	(Level 1)		(Level 2)		(Level 3)		Total
As of September 30, 2010
Auction rate securities		$ --		$ --		$45.0		$45.0
Supplemental executive retirement plan assets		21.1		--		--		21.1
Derivatives, net		--		14.8		--		14.8
Total financial assets		$21.1		$14.8		$45.0		$80.9
As of December 31, 2009
Auction rate securities		$ --		$ --		$60.5		$60.5
Supplemental executive retirement plan assets		18.7		--		--		18.7
Derivatives, net		--		13.2		--		13.2
Total financial assets		$18.7		$13.2		$60.5		$92.4

Auction Rate Securities

As of September 30, 2010 and December 31, 2009, we held long-term debt instruments with variable interest rates that periodically reset through an auction process ("auction rate securities") totaling $50.3 million and $66.8 million (par value), respectively. These auction rate securities were classified as long-term investments on our condensed consolidated balance sheets. Our auction rate securities were originally acquired in January 2008 and have maturity dates ranging from 2025 to 2047. Our auction rate securities were measured at fair value on a recurring basis using significant Level 3 inputs as of September 30, 2010 and December 31, 2009. The following table summarizes the fair value measurements of our auction rate securities using significant Level 3 inputs, and changes therein, for the three-month and nine-month periods ended September 30, 2010 and 2009 (in millions):

	Three Months Ended			Nine Months Ended
	September 30,			September 30,
	2010	2009		2010	2009

Beginning balance	$45.2	$61.6		$60.5	$64.2
Sales	(.6)	(1.0	)	(16.5)	(3.6)
Unrealized gains*	.4	.3		1.0	.3
Transfers in and/or out of Level 3	--	--		--	--
Ending balance	$45.0	$60.9		$45.0	$60.9

*	Unrealized gains are included in other, net, in the condensed consolidated statements of income.

Before utilizing Level 3 inputs in our fair value measurements, we considered whether observable inputs were available. As a result of continued auction failures, quoted prices for our auction rate securities did not exist as of September 30, 2010. Accordingly, we concluded that Level 1 inputs were not available. Brokerage statements received from the three broker/dealers that held our auction rate securities included their estimated market value as of September 30, 2010. All three broker/dealers valued our auction rate securities at par. Due to the lack of transparency into the methodologies used to determine the estimated market values, we have concluded that estimated market values provided on our brokerage statements do not constitute valid inputs, and we do not utilize them in measuring the fair value of our auction rate securities.

We used an income approach valuation model to estimate the price that would be received in exchange for our auction rate securities in an orderly transaction between market participants ("exit price") as of September 30, 2010. The exit price was derived as the weighted-average present value of expected cash flows over various periods of illiquidity, using a risk-adjusted discount rate based on the credit risk and liquidity risk of our auction rate securities. While our valuation model was based on both Level 2 (credit quality and interest rates) and Level 3 inputs, we determined that Level 3 inputs were significant to the overall fair value measurement of our auction rate securities, particularly the estimates of risk-adjusted discount rates and ranges of expected periods of illiquidity. We have the ability to maintain our investment in these securities until they are redeemed, repurchased or sold in a market that facilitates orderly transactions.

Supplemental Executive Retirement Plans

Our Ensco supplemental executive retirement plans (the "SERP") are non-qualified plans that provide for eligible employees to defer a portion of their compensation for use after retirement. Assets held in the SERP were marketable securities measured at fair value on a recurring basis using Level 1 inputs and were included in other assets, net, on our condensed consolidated balance sheets as of September 30, 2010 and December 31, 2009. The fair value measurement of assets held in the SERP was based on quoted market prices.

Derivatives

Our derivatives were measured at fair value on a recurring basis using Level 2 inputs as of September 30, 2010 and December 31, 2009. See "Note 4 - Derivative Instruments" for additional information on our derivatives, including a description of our foreign currency hedging activities and related methodologies used to manage foreign currency exchange rate risk. The fair value measurement of our derivatives was based on market prices that are generally observable for similar assets or liabilities at commonly quoted intervals.

Other Financial Instruments

The carrying values and estimated fair values of our debt instruments as of September 30, 2010 and December 31, 2009 were as follows (in millions):

	September 30,		December 31,
	2010		2009
		Estimated		Estimated
	Carrying	Fair	Carrying	Fair
	Value	Value	Value	Value

7.20% Debentures	$148.9	$157.8	$148.9	$155.9
6.36% Bonds, including current maturities	69.7	79.3	76.0	85.8
4.65% Bonds, including current maturities	47.2	54.4	49.5	53.8

The estimated fair value of our 7.20% Debentures was determined using quoted market prices. The estimated fair values of our 6.36% Bonds and 4.65% Bonds were determined using an income approach valuation model. The estimated fair value of our cash and cash equivalents, receivables, trade payables and other liabilities approximated their carrying values as of September 30, 2010 and December 31, 2009.

ENSCO I Impairment

In June 2010, we recorded a $12.2 million loss from the impairment of ENSCO I, the only barge rig in our fleet, which is currently cold-stacked in Singapore and is included in our Asia Pacific operating segment. The loss on impairment was included in contract drilling expense in our condensed consolidated statement of income for the nine-month period ended September 30, 2010. The impairment resulted from the adjustment of the rig’s carrying value to its estimated fair value based on a change in our expectation that it is more-likely-than-not that the rig will be disposed of significantly before the end of its estimated useful life. ENSCO I was not classified as held-for-sale as of September 30, 2010, as a sale was not deemed probable of occurring within the next twelve months.

We utilized an income approach valuation model to estimate the price that would be received in exchange for the rig in an orderly transaction between market participants as of June 30, 2010. The resulting exit price was derived as the present value of expected cash flows from the use and eventual disposition of the rig, using a risk-adjusted discount rate. Level 3 inputs were significant to the overall fair value measurement of ENSCO I, due to the limited availability of observable market data for similar assets.

Note 9 - Discontinued Operations

ENSCO 60

In September 2010, we executed a Memorandum of Agreement (the “MOA”) to sell ENSCO 60 for $26.0 million. The MOA requires the sale to close in the near-term and the buyer to pay us a non-refundable deposit of $2.6 million. The deposit was received in September 2010 and included in accrued liabilities and other on our condensed consolidated balance sheet as of September 30, 2010.

Based on the facts and circumstances as of September 30, 2010 and our conclusion that it was probable the sale of the rig would occur within one year, we classified ENSCO 60 as held-for-sale. The rig’s net book value and inventory were included in other current assets on our condensed consolidated balance sheet and totaled $20.1 million as of September 30, 2010. ENSCO 60 operating results were reclassified to discontinued operations in our condensed consolidated statements of income for the three-month and nine-month periods ended September 30, 2010 and 2009 and previously were included within our North and South America operating segment.

Rig Sales

In April 2010, we sold jackup rig ENSCO 57 for $47.1 million, of which a deposit of $4.7 million was received in December 2009. We recognized a pre-tax gain of $17.9 million in connection with the disposal of ENSCO 57, which was included in gain on disposal of discontinued operations, net, in our condensed consolidated statement of income for the nine-month period ended September 30, 2010. The rig’s net book value and inventory and other assets on the date of sale totaled $29.2 million. ENSCO 57 operating results were reclassified to discontinued operations in our condensed consolidated statements of income for the three-month period ended September 30, 2009 and the nine-month periods ended September 30, 2010 and 2009 and previously were included within our Asia Pacific operating segment.

In March 2010, we sold jackup rigs ENSCO 50 and ENSCO 51 for an aggregate $94.7 million, of which a deposit of $4.7 million was received in December 2009. We recognized an aggregate pre-tax gain of $33.9 million in connection with the disposals of ENSCO 50 and ENSCO 51, which was included in gain on disposal of discontinued operations, net, in our condensed consolidated statement of income for the nine-month period ended September 30, 2010. The two rigs' aggregate net book value and inventory and other assets on the date of sale totaled $60.8 million. ENSCO 50 and ENSCO 51 operating results were reclassified to discontinued operations in our condensed consolidated statements of income for the three-month period ended September 30, 2009 and the nine-month periods ended September 30, 2010 and 2009 and previously were included within our Asia Pacific operating segment.

ENSCO 69

From May 2007 to June 2009, ENSCO 69 was contracted to Petrosucre, a subsidiary of Petróleos de Venezuela S.A., the national oil company of Venezuela. In January 2009, we suspended drilling operations on ENSCO 69 after Petrosucre failed to satisfy its contractual obligations and meet commitments relative to the payment of past due invoices. Petrosucre then took over complete control of ENSCO 69 drilling operations utilizing Petrosucre employees and a portion of the Venezuelan rig crews we had utilized. In June 2009, we terminated our contract with Petrosucre and removed all remaining Ensco employees from the rig.

Due to Petrosucre's failure to satisfy its contractual obligations and meet payment commitments, and in consideration of the Venezuelan government's nationalization of certain assets owned by other international oil and gas companies and oilfield service companies, we concluded it was remote that ENSCO 69 would be returned to us by Petrosucre and operated again by Ensco. Therefore, we recorded the disposal of ENSCO 69 during the second quarter of 2009 and reclassified its operating results to discontinued operations.

In November 2009, we executed an agreement with Petrosucre to mitigate our losses and resolve issues relative to outstanding amounts owed by Petrosucre for drilling operations performed by Ensco through the date of termination of the drilling contract in June 2009 (the "agreement"). The agreement also required Petrosucre to compensate us for its use of the rig, and we recognized $9.3 million and $21.7 million of pre-tax income for the three-month and nine-month periods ended September 30, 2010 associated with collections under the agreement. Although the agreement obligates Petrosucre to make additional payments for its use of the rig through August 2010, the associated income was not recognized in our condensed consolidated statements of income, as collectability was not reasonably assured.

On August 24, 2010, possession of ENSCO 69 was returned to Ensco. Due to the return of ENSCO 69 from Petrosucre and our ability to significantly influence the future operations of the rig and to incur significant future cash flows related to those operations until the pending insurance claim is resolved and possibly thereafter, ENSCO 69 operating results were reclassified to continuing operations for the three-month and nine-month periods ended September 30, 2010 and 2009.

There can be no assurances relative to the recovery of outstanding contract entitlements, insurance recovery and related pending litigation or the imposition of customs duties in relation to the rig's recent presence in Venezuela. See "Note 10 - Contingencies" for additional information on insurance and legal remedies related to ENSCO 69.

The following table summarizes our (loss) income from discontinued operations for the three-month and nine-month periods ended September 30, 2010 and 2009 (in millions):

	Three Months Ended September 30,				Nine Months Ended September 30,
	2010		2009		2010		2009

Revenues	$ --		$16.5		$12.5		$60.0
Operating expenses	2.2		11.5		16.2		40.6
Operating (loss) income before income taxes	(2.2	)	5.0		(3.7	)	19.4
Income tax benefit	(.3	)	(.8	)	(2.5	)	--
Gain on disposal of discontinued operations, net	--		--		34.9		--
(Loss) income from discontinued operations	$(1.9	)	$ 5.8		$33.7		$19.4

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

Note 10 - Contingencies

FCPA Internal Investigation

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

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

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

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

Our internal investigation has essentially been concluded. Discussions were held with the authorities to review the results of the investigation and discuss associated matters during 2009 and the first half of 2010. On May 24, 2010, we received notification from the SEC Division of Enforcement advising that it does not intend to recommend any enforcement action. We expect to receive a determination by the United States Department of Justice in the near-term.

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

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

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

ENSCO 74 Loss

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

In March 2009, the sunken rig hull of ENSCO 74 was located approximately 95 miles from the original drilling location when it was struck by an oil tanker. Following discovery of the sunken rig hull, we removed the accessible hydrocarbons onboard and began planning for removal of the wreckage. As an interim measure, the wreckage was appropriately marked, and the U.S. Coast Guard issued a Notice to Mariners. In October 2010, wreck removal operations on the sunken rig hull of ENSCO 74 were substantially 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. We estimate the leg removal costs to range from $16.0 million to $30.0 million and the costs of the hull and related debris removal to range from $36.0 million to $55.0 million. We expect the cost of removal of the legs and the hull and related debris to be fully covered by our insurance without any additional retention.

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

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 removal costs, and a corresponding receivable for recovery of those costs was recorded as of September 30, 2010. A $10.8 million liability, representing the low end of the range of estimated remaining hull and related debris removal costs, and a corresponding receivable for recovery of those costs was recorded as of September 30, 2010. As of September 30, 2010, $25.2 million of wreckage and debris removal costs had been incurred and paid by Ensco, primarily related to removal of the hull. The remaining estimated aggregate $26.8 million liability for leg and hull and related debris removal costs and corresponding receivable for recovery of those costs were included in accrued liabilities and other and other assets, net, on our September 30, 2010 condensed consolidated balance sheet. Additionally, a $23.4 million receivable for recovery of costs incurred and paid by Ensco related to removal of the hull was included in accounts receivable, net, on our September 30, 2010 condensed consolidated balance sheet.

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

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

We filed a petition for exoneration or limitation of liability under U.S. admiralty and maritime law in September 2009. The petition seeks exoneration from or limitation of liability for any and all injury, loss or damage caused, occasioned or occurred in relation to the ENSCO 74 loss in September 2008. The owner of the tanker that struck the hull of ENSCO 74 and the owners of four subsea pipelines have presented claims in the exoneration/limitation proceedings. The matter is scheduled for trial in September 2011.

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

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

ENSCO 69

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

In September 2009, legal counsel acting for the package policy underwriters denied coverage under the package policy and reserved rights. In March 2010, underwriters commenced litigation in the U.K. for purposes of enforcing mediation under the disputes clause of our package policy and precluding us from pursuing litigation in the United States. On that date, we commenced litigation to recover on our political risk package policy claim. Our lawsuit seeks recovery under the policy for the loss of ENSCO 69 and includes claims for wrongful denial of coverage, breach of contract, breach of the Texas insurance code, failure to timely respond to the claim and bad faith. Our lawsuit seeks actual damages in the amount of $55.0 million (insured value of $65.0 million less a $10.0 million deductible), punitive damages and attorneys' fees. On July 27, 2010, we agreed with underwriters to submit the matter to arbitration.

We were unable to conclude that collection of insurance proceeds associated with ENSCO 69 was probable as of September 30, 2010. Accordingly, no ENSCO 69 related insurance receivables were recorded on our condensed consolidated balance sheet as of September 30, 2010. See "Note 9 - Discontinued Operations" for additional information on ENSCO 69.

ENSCO 29 Wreck Removal

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

Our liability insurance underwriters have issued letters reserving rights and effectively denying coverage by questioning the applicability of coverage for the potential ENSCO 29 wreckage and debris removal costs. During 2007, we commenced litigation against certain underwriters alleging breach of contract, wrongful denial, bad faith and other claims which seek a declaration that removal of wreckage and debris is covered under our liability insurance, monetary damages, attorneys' fees and other remedies. The matter is scheduled for trial in April 2011.

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

Asbestos Litigation

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

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

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

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

In addition to the pending cases in Mississippi, we have two other asbestos or lung injury claims pending against us in litigation in other jurisdictions. Although we do not expect the final disposition of the Mississippi and other asbestos or lung injury lawsuits to have a material adverse effect upon our financial position, operating results or cash flows, there can be no assurances as to the ultimate outcome of the lawsuits.

Working Time Directive

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

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

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

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

Other Matters

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

Note 11 - Segment Information

Our business consists of four operating segments: (1) Deepwater, (2) Asia Pacific, (3) Europe and Africa and (4) North and South America. Each of our four operating segments provides one service, contract drilling. Segment information for the three-month and nine-month periods ended September 30, 2010 and 2009 is presented below (in millions). General and administrative expense is not allocated to our operating segments for purposes of measuring segment operating income and is included in "Reconciling Items." Assets not allocated to our operating segments consisted primarily of cash and cash equivalents and goodwill and also are included in "Reconciling Items."

Three Months Ended September 30, 2010
	Deepwater	Asia Pacific	Europe and Africa	North and South America	Operating Segments Total	Reconciling Items	Consolidated Total

Revenues	$ 110.5	$ 131.6	$ 91.5	$ 94.7	$ 428.3	$ --	$ 428.3
Operating expenses Contract drilling (exclusive of depreciation)	48.0	54.2	50.5	41.4	194.1	--	194.1
Depreciation	11.7	19.6	12.2	11.8	55.3	.3	55.6
General and administrative	--	--	--	--	--	20.6	20.6
Operating income (loss)	$ 50.8	$ 57.8	$ 28.8	$ 41.5	$ 178.9	$ (20.9)	$ 158.0
Total assets	$3,255.6	$1,388.5	$873.9	$846.3	$6,364.3	$745.8	$7,110.1

Three Months Ended September 30, 2009
	Deepwater	Asia Pacific	Europe and Africa	North and South America	Operating Segments Total	Reconciling Items	Consolidated Total

Revenues	$ 62.5	$ 145.1	$104.4	$ 96.9	$ 408.9	$ --	$ 408.9
Operating expenses Contract drilling (exclusive of depreciation)	34.7	54.8	46.5	39.4	175.4	--	175.4
Depreciation	6.5	18.9	11.1	12.1	48.6	.3	48.9
General and administrative	--	--	--	--	--	13.6	13.6
Operating income (loss)	$ 21.3	$ 71.4	$ 46.8	$ 45.4	$ 184.9	$ (13.9)	$ 171.0
Total assets	$2,225.6	$1,277.5	$785.5	$821.9	$5,110.5	$1,344.7	$6,455.2

Nine Months Ended September 30, 2010
	Deepwater	Asia Pacific	Europe and Africa	North and South America	Operating Segments Total	Reconciling Items	Consolidated Total

Revenues	$ 361.8	$ 384.9	$252.6	$289.0	$1,288.3	$ --	$1,288.3
Operating expenses Contract drilling (exclusive of depreciation)	139.5	171.8	148.6	122.6	582.5	--	582.5
Depreciation	31.2	56.1	35.9	35.1	158.3	.9	159.2
General and administrative	--	--	--	--	--	63.2	63.2
Operating income (loss)	$ 191.1	$ 157.0	$ 68.1	$131.3	$ 547.5	$ (64.1)	$ 483.4
Total assets	$3,255.6	$1,388.5	$873.9	$846.3	$6,364.3	$745.8	$7,110.1

Nine Months Ended September 30, 2009
	Deepwater	Asia Pacific	Europe and Africa	North and South America	Operating Segments Total	Reconciling Items	Consolidated Total

Revenues	$ 130.2	$ 488.1	$476.8	$296.0	$1,391.1	$ --	$1,391.1
Operating expenses Contract drilling (exclusive of depreciation)	63.2	166.4	152.6	151.0	533.2	--	533.2
Depreciation	12.5	55.9	33.0	35.6	137.0	.9	137.9
General and administrative	--	--	--	--	--	41.6	41.6
Operating income (loss)	$ 54.5	$ 265.8	$291.2	$109.4	$ 720.9	$ (42.5)	$ 678.4
Total assets	$2,225.6	$1,277.5	$785.5	$821.9	$5,110.5	$1,344.7	$6,455.2

Information about Geographic Areas

As of September 30, 2010, our Deepwater operating segment consisted of three ultra-deepwater semisubmersible rigs located in the U.S. Gulf of Mexico, two ultra-deepwater semisubmersible rigs located in Singapore and three ultra-deepwater semisubmersible rigs under construction in Singapore. Our Asia Pacific operating segment consisted of 17 jackup rigs and one barge rig deployed in various locations throughout Asia, the Middle East and Australia. Our Europe and Africa operating segment consisted of eight jackup rigs deployed in various territorial waters of the North Sea and two jackup rigs located offshore Tunisia. Our North and South America operating segment consisted of seven jackup rigs located in the U.S. Gulf of Mexico, five jackup rigs located offshore Mexico and one jackup rig located in Trinidad.

Certain of our drilling rigs currently in the U.S. Gulf of Mexico have been and 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. The moratorium/suspension, related Notices to Lessees (“NTLs”) and other actions have been and are being challenged in litigation by Ensco and others. The operations of certain of our rigs in the U.S. Gulf of Mexico are or may be delayed due to regulatory requirements and delays in our customers securing drilling permits. Current or future NTLs or other directives and regulations may impact our customers' ability to obtain drilling permits and commence or continue deepwater or shallow-water operations in the U.S. Gulf of Mexico. During the three-month and nine-month periods ended September 30, 2010, revenues provided by our drilling operations in the U.S. Gulf of Mexico totaled $105.1 million and $293.5 million, or 25% and 23%, of our consolidated revenues, respectively. Of these amounts, 60% and 63% were provided by our deepwater drilling operations in the U.S. Gulf of Mexico for the three-month and nine-month periods ended September 30, 2010, respectively. 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.

Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations

BUSINESS ENVIRONMENT

In May 2010, the U.S. Department of the Interior implemented a six-month moratorium/suspension on certain drilling activities in water depths greater than 500 feet in the U.S. Gulf of Mexico. The U.S. Department of the Interior subsequently issued NTLs implementing additional safety and certification requirements applicable to drilling activities in the U.S. Gulf of Mexico, imposed additional requirements with respect to development and production activities in the U.S. Gulf of Mexico and has delayed the approval of applications to drill in both deepwater and shallow-water areas. On July 12, 2010, the U.S. Department of the Interior issued a revised moratorium/suspension on drilling in the U.S. Gulf of Mexico, which was lifted on October 12, 2010 after the adoption on September 30, 2010 of new regulations relating to the design of wells and testing of the integrity of wellbores, the use of drilling fluids, the functionality and testing of well control equipment, including blowout preventers, and other safety regulations. It is uncertain as to the impact these new regulations may have upon our operations and our customers' ability to obtain new drilling permits.

As a condition to lifting of the moratorium/suspension, the Bureau of Ocean Energy Management, Regulation and Enforcement (the “BOEM”) was directed to require that each operator demonstrate that it has in place written and enforceable commitments that ensure that containment resources are available promptly in the event of a blowout and that the Chief Executive Officer of each operator certify to the BOEM that the operator has complied with applicable regulations. Before deepwater drilling is resumed, the BOEM intends to conduct inspections of each deepwater drilling operation for compliance with regulations, including but not limited to the testing of blowout preventers. It is unclear when these requirements will be satisfied, due in part to the limited staffing of the BOEM.

A significant number of U.S. Gulf of Mexico deepwater projects have been delayed as a result of the recently lifted moratorium/suspension and related regulatory developments. Certain well operations were permitted to continue under the moratorium/suspension, such as workovers and completions with operators and contractors reacting to these circumstances on a case-by-case basis. Although demand for global deepwater drilling has remained stable during 2010, there is significant uncertainty as to the near-term and long-term impact the BP Macondo well incident and associated new regulatory, legislative or permitting requirements may have on deepwater drilling in the U.S. Gulf of Mexico, in addition to the potential impact on the global deepwater market.

Semisubmersible rig supply also continues to increase as a result of newbuild construction programs. It has been reported that 28 newbuild semisubmersible rigs are currently under construction, of which 10 are scheduled for delivery during the remainder of 2010 and 11 are scheduled for delivery during 2011. The majority of semisubmersible rigs scheduled for delivery during the remainder of 2010 and 2011 are contracted. Based on the current level of uncertainty regarding deepwater drilling in the U.S. Gulf of Mexico, we are unable to predict whether newbuild semisubmersible rigs will be absorbed into the global market without a significant effect on utilization and day rates.

Depressed oil and natural gas prices and the deterioration of the global economy led to an abrupt reduction in demand for jackup rigs during 2009. Although oil prices have stabilized, incremental drilling activity during the first nine months of 2010 has remained limited resulting in continued softness in day rates for standard duty jackup rigs. We are encouraged by improving tender activity as modest increases in jackup rig demand are seen for work in 2011 across various regions. However, it is uncertain as to the impact the BP Macondo well incident and associated new regulatory, legislative or permitting requirements may have on jackup rig demand in general, and in the U.S. Gulf of Mexico in particular.

Jackup rig supply continues to increase as a result of newbuild construction programs which were initiated prior to the 2008 decline in oil and natural gas prices. It has been reported that 36 newbuild jackup rigs are currently under construction, of which 10 are scheduled for delivery during the remainder of 2010 and 19 are scheduled for delivery during 2011. The majority of jackup rigs scheduled for delivery during the remainder of 2010 and 2011 are not contracted. It is unlikely that the market in general or any geographic region in particular will be able to fully absorb newbuild jackup rig deliveries in the near-term, especially in consideration of the existing oversupply of jackup rigs.

For additional information concerning the potential impact the aforementioned events and circumstances may have on our business, our industry and global supply, see "Item 1A. Risk Factors" in Part I and "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" in Part II of our Annual Report on Form 10-K for the year ended December 31, 2009, as updated in the Current Reports on Form 8-K dated June 8, 2010 and August 13, 2010 and in this report.

Deepwater

During 2009, depressed oil and natural gas prices and the deterioration of the global economy resulted in a modest decline in demand for ultra-deepwater semisubmersible rigs, however, global utilization and day rates generally were stable. Although utilization and day rates remained stable during the first half of 2010, the majority of ultra-deepwater semisubmersible rigs in the U.S. Gulf of Mexico currently are on standby, idle or undergoing shipyard work as a result of the recently lifted moratorium/suspension and related regulatory developments. A large scale departure of these rigs from the U.S. Gulf of Mexico has not yet occurred as contractors have hesitated to abandon the remaining deepwater reservoir potential in the region, while continuing to monitor developments regarding permitting delays. A limited number of rigs have mobilized from the U.S. Gulf of Mexico to other regions, and we expect utilization and day rates to come under pressure if additional deepwater contracts in the U.S. Gulf of Mexico are terminated and/or those rigs are marketed in or relocated to other regions. Future ultra-deepwater semisubmersible rig utilization and day rates will depend in large part on projected oil and natural gas prices, the global economy and the potential long-term impact the BP Macondo well incident and associated new regulatory, legislative or permitting requirements may have on the U.S. Gulf of Mexico and global deepwater markets.

ENSCO 8502 was delivered in January 2010, and we have notified its customer that the contract term for drilling operations in the U.S. Gulf of Mexico commenced as of August 13, 2010. Prior to submission of notice that the term commenced, the customer stated that it is not obligated to accept the rig, pursuant to the terms of the contract, in the current circumstances. Thereafter, the customer asserted that the contract term has not commenced, that its use of the rig has been prevented by force majeure and that it is not obligated to accept the rig under current circumstances. We believe the rig complies with all contractual requirements and that the contract term has commenced pursuant to the contract. Accordingly, we disagree with the customer’s position and continue to discuss a potential compromise agreement while reviewing available remedies to resolve the dispute.

ENSCO 8503 was delivered in September 2010 and is currently mobilizing to the U.S. Gulf of Mexico from Singapore. ENSCO 8503 is expected to commence drilling operations in the U.S. Gulf of Mexico under a two-year contract during the first quarter of 2011. We also have three uncontracted ENSCO 8500 Series® rigs under construction with scheduled delivery dates during the second half of 2011 and the first and second half of 2012. Our ENSCO 7500 ultra-deepwater semisubmersible rig currently is without a contract and undergoing an enhancement project in a shipyard in Singapore.

Asia Pacific

During 2009, Asia Pacific jackup rig utilization and day rates were significantly impacted by depressed oil and natural gas prices and the deterioration of the global economy. The Asia Pacific jackup market began to stabilize during the first nine months of 2010 with incremental demand seen as multiple tenders were recently issued for work beginning in late 2010 and beyond. In consideration of an expected increase in the supply of available jackup rigs from newbuild deliveries and expiring drilling contracts, we anticipate that Asia Pacific jackup rig utilization and day rates will remain under pressure in the near-term.

In conjunction with our long-established strategy of high-grading our jackup rig fleet by investing in newer equipment, we sold three jackup rigs located in the Asia Pacific region during the first six months of 2010. In July 2010, we acquired a KFELS Super B Class design jackup rig constructed in 2008. The rig was renamed ENSCO 109 and is currently operating in Australia.

Europe and Africa

Our Europe and Africa offshore drilling operations are mainly conducted in Northern Europe. Depressed oil and natural gas prices and the deterioration of the global economy resulted in several cancelled tenders and unexercised contract extension options during the latter portion of 2009. Tender activity during the first nine months of 2010 was limited with a recent increase seen in inquiries for work beginning in 2011 resulting from incremental demand in the region. However, with limited tender activity for work beginning in late 2010 and additional jackup rigs projected to complete their current contracts later this year, we anticipate this market will experience excess rig availability, and utilization and day rates will remain under pressure in the near-term.

North and South America

A significant portion of our North and South America offshore drilling operations are conducted in Mexico, where demand for rigs increased in recent years as Petróleos Mexicanos ("PEMEX"), the national oil company of Mexico, accelerated drilling activities in an attempt to offset continued depletion of its major oil and natural gas fields. During 2009 and the first nine months of 2010, demand for jackup rigs in Mexico remained high despite global economic conditions. We expect tender activity to increase in the near-term for work beginning in late 2010 and early 2011 in response to contracts expiring later this year, however, we expect future day rates in Mexico to face pressure as jackup rig contracts in the region expire and drilling contractors with idle rigs in the Gulf of Mexico and other geographic regions pursue the available contract opportunities.

We also conduct a portion of our North and South America jackup rig operations in the U.S. Gulf of Mexico. The U.S. Gulf of Mexico jackup rig market remained extremely weak during 2009, with drilling activity reaching historic lows as a result of depressed oil and natural gas prices and the deterioration of the global economy. During early 2010, tender activity in the U.S. Gulf of Mexico improved as operators capitalized on cost-effective terms offered by drilling contractors. Due to the potential for delays from hurricane season, certain operators’ inability to timely obtain drilling permits and the uncertainty regarding the impact the BP Macondo well incident and associated new regulatory, legislative or permitting requirements may have on jackup rig drilling operations in the region, we anticipate that U.S. Gulf of Mexico jackup rig utilization and day rates will remain under pressure in the near-term.

RESULTS OF OPERATIONS

The following table summarizes our condensed consolidated results of operations for the three-month and nine-month periods ended September 30, 2010 and 2009 (in millions):

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2010		2009		2010		2009

Revenues	$428.3		$408.9		$1,288.3		$1,391.1
Operating expenses
Contract drilling (exclusive of depreciation)	194.1		175.4		582.5		533.2
Depreciation	55.6		48.9		159.2		137.9
General and administrative	20.6		13.6		63.2		41.6
Operating income	158.0		171.0		483.4		678.4
Other income, net	2.7		3.6		18.6		6.2
Provision for income taxes	26.7		29.6		84.1		129.7
Income from continuing operations	134.0		145.0		417.9		554.9
(Loss) income from discontinued operations, net	(1.9	)	5.8		33.7		19.4
Net income	132.1		150.8		451.6		574.3
Net income attributable to noncontrolling interests	(1.6	)	(1.1	)	(5.0	)	(3.6	)
Net income attributable to Ensco	$130.5		$149.7		$ 446.6		$ 570.7

For the quarter ended September 30, 2010, revenues increased by $19.4 million, or 5%, and operating income declined by $13.0 million, or 8%, as compared to the prior year quarter. The increase in revenues was primarily due to a significant increase in revenues generated by our ultra-deepwater semisubmersible rig fleet, partially offset by a decline in average day rates of our Asia Pacific and Europe and Africa jackup rig fleets. The decline in operating income was primarily due to the aforementioned decline in average day rates, partially offset by a significant increase in operating income generated by our ultra-deepwater semisubmersible rig fleet.

For the nine-month period ended September 30, 2010, revenues declined by $102.8 million, or 7%, and operating income declined by $195.0 million, or 29%, as compared to the prior year period. These declines were primarily due to a decline in utilization and average day rates of our Europe and Africa jackup rig fleets coupled with a decline in average day rates of our Asia Pacific jackup rig fleet, partially offset by a significant increase in revenues and operating income generated by our ultra-deepwater semisubmersible rig fleet.

A significant number of our drilling contracts are of a long-term nature. Accordingly, a decline in demand for contract drilling services typically affects our operating results and cash flows gradually over many quarters as long-term contracts expire. The significant decline in oil and natural gas prices during the latter half of 2008 and the deterioration of the global economy resulted in a dramatic decline in demand for contract drilling services during 2009, which will continue to negatively impact our operating results during 2010. While we have substantial contract backlog for 2010, it is unlikely that revenue and operating income levels achieved during 2009 will be sustained during 2010.

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. The moratorium/suspension, related NTLs and other actions have been and are being challenged in litigation by Ensco and others. The operations of certain of our rigs in the U.S. Gulf of Mexico are or may be delayed due to regulatory requirements and delays in our customers securing drilling permits. Current or future NTLs or other directives and regulations may impact our customers' ability to obtain drilling permits and commence or continue deepwater or shallow-water operations in the U.S. Gulf of Mexico.

We notified the customer of ENSCO 8502 that the contract term commenced as of August 13, 2010. Prior to submission of notice that the term commenced, the customer stated that it is not obligated to accept the rig, pursuant to the terms of the contract, in the current circumstances. Thereafter, the customer asserted that the contract term has not commenced, that its use of the rig has been prevented by force majeure and that it is not obligated to accept the rig under current circumstances. Ensco believes the rig complies with all contractual requirements and that the contract term has commenced pursuant to the contract. Accordingly, we disagree with the customer’s position and continue to discuss a potential compromise agreement while reviewing available remedies to resolve the dispute.

As previously noted, we have asserted that the contract term for ENSCO 8502 has commenced on August 13, 2010, however, we deferred the recognition of revenue totaling $27.2 million during the quarter ended September 30, 2010 as collectability was not reasonably assured due to the contractual dispute by the customer. The full impact of the BP Macondo well incident, resulting regulatory developments and potential new regulatory, legislative or permitting requirements has not yet been determined but could have a further material adverse effect upon our operating results.

Rig Locations, Utilization and Average Day Rates

We manage our business through four operating segments. Our jackup rigs are mobile and occasionally move between operating segments in response to market conditions and contract opportunities. The following table summarizes our offshore drilling rigs by segment and rigs under construction as of September 30, 2010 and 2009:

	September 30,	September 30,
	2010	2009

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

(1)		ENSCO 8503 was delivered in September 2010 and is currently mobilizing to the U.S. Gulf of Mexico from Singapore. ENSCO 8503 is expected to commence drilling operations in the U.S. Gulf of Mexico under a two-year contract during the first quarter of 2011. ENSCO 8502 was delivered in January 2010. As discussed above, we have notified our customer that the contract term for drilling operations in the U.S. Gulf of Mexico commenced as of August 13, 2010.
(2)		On July 7, 2010, we acquired a KFELS Super B Class design jackup rig. The rig was renamed ENSCO 109 and is currently operating offshore Australia.
(3)		The total number of rigs for each period excludes rigs reclassified as discontinued operations.

The following table summarizes our rig utilization and average day rates from continuing operations by operating segment for the three-month and nine-month periods ended September 30, 2010 and 2009:

	Three Months Ended		Nine Months Ended
	September 30,		September 30,
	2010	2009	2010	2009
Rig Utilization(1)
Deepwater	75%	64%	88%	82%
Asia Pacific(3)	74%	67%	73%	72%
Europe and Africa	76%	63%	69%	83%
North and South America(4)	88%	62%	92%	69%
Total	79%	64%	78%	74%

Average Day Rates(2)
Deepwater	$387,777	$387,407	$401,055	$436,340
Asia Pacific(3)	112,993	139,881	115,414	148,359
Europe and Africa	126,160	175,861	130,728	208,259
North and South America(4)	81,689	132,985	84,222	123,641
Total	$127,545	$158,947	$132,444	$167,113

(1)		Rig utilization is derived by dividing the number of days under contract by the number of days in the period. Days under contract equals the total number of days that rigs have earned a day rate, including days associated with compensated downtime and mobilizations. For newly constructed or acquired rigs, the number of days in the period begins upon commencement of drilling operations for rigs with a contract or when the rig becomes available for drilling operations for rigs without a contract.
(2)		Average day rates are derived by dividing contract drilling revenues, adjusted to exclude certain types of non-recurring reimbursable revenues and lump sum revenues, by the aggregate number of contract days, adjusted to exclude contract days associated with certain mobilizations, demobilizations, shipyard contracts and standby contracts.
(3)		ENSCO I, the only barge rig in our fleet, is currently cold-stacked in Singapore and has been excluded from rig utilization and average day rates for our Asia Pacific operating segment.
(4)		ENSCO 69 has been excluded from rig utilization and average day rates for our North and South America operating segment during the period the rig was controlled and operated by Petrosucre, a subsidiary of Petróleos de Venezuela S.A., the national oil company of Venezuela (January 2009 - August 2010). See Note 9 to our condensed consolidated financial statements for additional information on ENSCO 69.

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

Operating Income

Three Months Ended September 30, 2010

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

Revenues	$110.5	$131.6	$91.5	$94.7	$428.3	$ --	$428.3
Operating expenses Contract drilling (exclusive of depreciation)	48.0	54.2	50.5	41.4	194.1	--	194.1
Depreciation	11.7	19.6	12.2	11.8	55.3	.3	55.6
General and administrative	--	--	--	--	--	20.6	20.6
Operating income (loss)	$ 50.8	$ 57.8	$28.8	$41.5	$178.9	$(20.9)	$158.0

Three Months Ended September 30, 2009

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

Revenues	$62.5	$145.1	$104.4	$96.9	$408.9	$ --	$408.9
Operating expenses Contract drilling (exclusive of depreciation)	34.7	54.8	46.5	39.4	175.4	--	175.4
Depreciation	6.5	18.9	11.1	12.1	48.6	.3	48.9
General and administrative	--	--	--	--	--	13.6	13.6
Operating income (loss)	$21.3	$ 71.4	$ 46.8	$45.4	$184.9	$(13.9)	$171.0

Nine Months Ended September 30, 2010

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

Revenues	$361.8	$384.9	$252.6	$289.0	$1,288.3	$ --	$1,288.3
Operating expenses Contract drilling (exclusive of depreciation)	139.5	171.8	148.6	122.6	582.5	--	582.5
Depreciation	31.2	56.1	35.9	35.1	158.3	.9	159.2
General and administrative	--	--	--	--	--	63.2	63.2
Operating income (loss)	$191.1	$157.0	$ 68.1	$131.3	$ 547.5	$(64.1)	$ 483.4

Nine Months Ended September 30, 2009

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

Revenues	$130.2	$488.1	$476.8	$296.0	$1,391.1	$ --	$1,391.1
Operating expenses Contract drilling (exclusive of depreciation)	63.2	166.4	152.6	151.0	533.2	--	533.2
Depreciation	12.5	55.9	33.0	35.6	137.0	.9	137.9
General and administrative	--	--	--	--	--	41.6	41.6
Operating income (loss)	$ 54.5	$265.8	$291.2	$109.4	$ 720.9	$(42.5)	$ 678.4

Deepwater

Deepwater revenues for the quarter ended September 30, 2010 increased by $48.0 million, or 77%, as compared to the prior year quarter. The increase in revenues was primarily due to revenues earned by ENSCO 8501 which commenced drilling operations under a long-term contract during the fourth quarter of 2009. As previously noted, we have asserted that the contract term for ENSCO 8502 has commenced on August 13, 2010, however, we deferred the recognition of revenue totaling $27.2 million as collectability was not reasonably assured due to the contractual dispute by the customer involving various issues, including whether use of the rig has been prevented by force majeure and whether the customer is obligated to accept the rig under current circumstances. Contract drilling expense increased by $13.3 million, or 38%, due to the commencement of ENSCO 8501 drilling operations as previously noted, in addition to costs incurred by ENSCO 8502 as it remained on standby waiting for customer acceptance prior to commencement of drilling operations. Depreciation expense increased by $5.2 million, or 80%, due to the addition of ENSCO 8501 and ENSCO 8502 to our Deepwater fleet in the fourth quarter of 2009 and third quarter of 2010, respectively.

Deepwater revenues for the nine-month period ended September 30, 2010 increased by $231.6 million as compared to the prior year period. The increase in revenues was due to revenues earned by ENSCO 8500 and ENSCO 8501 which commenced drilling operations under long-term contracts during the second and fourth quarters of 2009, respectively, and due to the deferral of ENSCO 7500 revenues during the first quarter of 2009 as the rig mobilized from the Gulf of Mexico to Australia. As previously noted, we deferred the recognition of revenue for ENSCO 8502 totaling $27.2 million as collectability was not reasonably assured due to the contractual dispute by the customer. Contract drilling expense increased by $76.3 million due to the commencement of ENSCO 8500 and ENSCO 8501 drilling operations as previously noted, the deferral of certain costs during the first quarter of 2009 associated with the ENSCO 7500 mobilization to Australia and costs incurred by ENSCO 8502 as it remained on standby waiting for customer acceptance prior to commencement of drilling operations. Depreciation expense increased by $18.7 million due to the addition of ENSCO 8500, ENSCO 8501 and ENSCO 8502 to our Deepwater fleet in the second and fourth quarters of 2009 and third quarter of 2010, respectively.

Asia Pacific

Asia Pacific revenues for the quarter ended September 30, 2010 declined by $13.5 million, or 9%, as compared to the prior year quarter. The decline in revenues was primarily due to a 19% decline in average day rates, partially offset by an increase in utilization to 74% from 67% in the prior year quarter. The increase in utilization resulted from lower market day rates in the region coupled with a recent modest increase in jackup rig demand. Contract drilling expense was comparable to the prior year quarter. Depreciation expense increased by 4% due to the addition of ENSCO 109 to our Asia Pacific fleet.

Asia Pacific revenues for the nine-month period ended September 30, 2010 declined by $103.2 million, or 21%, as compared to the prior year period. The decline in revenues was primarily due to a 22% decline in average day rates as compared to the prior year period, due to lower levels of spending by oil and gas companies in response to the current economic environment. Contract drilling expense increased by $5.4 million, or 3%, as compared to the prior year period, primarily due to a $12.2 million loss on impairment of ENSCO I, our only barge rig, partially offset by a decline in repair and maintenance and payroll expense. Depreciation expense was comparable to the prior year period.

Europe and Africa

Europe and Africa revenues for the quarter ended September 30, 2010 declined by $12.9 million, or 12%, as compared to the prior year quarter. The decline in revenues was primarily due to a 28% decline in average day rates, partially offset by an increase in utilization to 76% from 63% in the prior year quarter. The increase in utilization resulted from lower market day rates in the region coupled with a recent modest increase in jackup rig demand. Contract drilling expense increased by $4.0 million, or 9%, as compared to the prior year quarter, due to the impact of increased utilization. Depreciation expense increased by 10% due to the ENSCO 100 capital enhancement project completed during the fourth quarter of 2009 and depreciation on minor upgrades and improvements to our Europe and Africa fleet completed during the fourth quarter of 2009 and the first nine months of 2010.

Europe and Africa revenues for the nine-month period ended September 30, 2010 declined by $224.2 million, or 47%, as compared to the prior year period. The decline in revenues was primarily due to a decline in utilization to 69% from 83% and a 37% decline in average day rates as compared to the prior year period, due to lower levels of spending by oil and gas companies in response to the current economic environment. Contract drilling expense declined by $4.0 million, or 3%, as compared to the prior year period, primarily due to a decline in payroll and reimbursable expense. Depreciation expense increased by 9% due to the ENSCO 100 capital enhancement project completed during the fourth quarter of 2009 and depreciation on minor upgrades and improvements to our Europe and Africa fleet completed during the fourth quarter of 2009 and the first nine months of 2010.

North and South America

North and South America revenues for the quarter ended September 30, 2010 declined by $2.2 million, or 2%, as compared to the prior year quarter. The decline in revenues was primarily due to a 39% decline in average day rates, partially offset by an increase in utilization to 88% from 62% in the prior year quarter. The increase in utilization resulted primarily from the reduced supply of available jackup rigs in the 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 increased by $2.0 million, or 5%, as compared to the prior year quarter, due to increased payroll and repair and maintenance expense. Depreciation expense was comparable to the prior year quarter.

North and South America revenues for the nine-month period ended September 30, 2010 declined by $7.0 million, or 2%, as compared to the prior year period. The decline in revenues was primarily due to a 32% decline in average day rates, partially offset by an increase in utilization to 92% from 69% in the comparable prior year period. The increase in utilization resulted from the reduced supply of available jackup rigs in the 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 $28.4 million, or 19%, as compared to the prior year period, due to a $17.3 million loss recorded on the disposal of ENSCO 69 during the second quarter of 2009 coupled with a decline in bad debt expense. Depreciation expense was comparable to the prior year period.

Other

General and administrative expense for the quarter ended September 30, 2010 increased by $7.0 million, or 51%, as compared to the prior year quarter. This increase was primarily due to increased share-based compensation expense and costs related to operating our new London headquarters.

General and administrative expense for the nine-month period ended September 30, 2010 increased by $21.6 million, or 52%, as compared to the prior year period. This increase was primarily due to increased share-based compensation expense, professional fees incurred in connection with various reorganization efforts undertaken as a result of our redomestication to the U.K. in December 2009 and costs related to operating our new London headquarters.

Other Income, Net

The following summarizes other income, net, for the three-month and nine-month periods ended September 30, 2010 and 2009 (in millions):

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2010		2009		2010		2009

Interest income	$ .2		$ .8		$ .5		$ 1.9
Interest expense, net:
Interest expense	(5.5	)	(5.2	)	(15.9	)	(15.8	)
Capitalized interest	5.5		5.2		15.9		15.8
	--		--		--		--
Other, net	2.5		2.8		18.1		4.3
	$ 2.7		$ 3.6		$ 18.6		$ 6.2

Interest income for the three-month and nine-month periods ended September 30, 2010 declined as compared to the respective prior year periods due to lower average interest rates, partially offset by an increase in amounts invested. Interest expense for the three-month and nine-month periods ended September 30, 2010 was comparable with the respective prior year periods.

In June 2010, we recognized a gain of $11.4 million, net of related expenses, for a break-up fee resulting from our unsuccessful tender offer for Scorpion Offshore Ltd. The net gain was included in other, net, for the nine-month period ended September 30, 2010.

Our functional currency is the U.S. dollar, and a portion of the revenues earned and expenses incurred by some of our subsidiaries are denominated in currencies other than the U.S. dollar ("foreign currencies"). These transactions are remeasured in U.S. dollars based on a combination of both current and historical exchange rates. Net foreign currency exchange gains of $500,000 and $4.5 million were included in other, net, for the three-month and nine-month periods ended September 30, 2010, respectively. Net foreign currency exchange gains of $1.8 million and $2.3 million were included in other, net, for the three-month and nine-month periods ended September 30, 2009, respectively.

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 rig among our subsidiaries. As a result of the frequent changes in taxing jurisdictions in which our drilling rigs are operated and/or owned, our consolidated effective income tax rate may vary substantially from one reporting period to another, depending on the relative components of our earnings generated in tax jurisdictions with higher tax rates or lower tax rates.

Subsequent to our redomestication to the U.K. in December 2009, we reorganized our worldwide operations, which included, among other things, the transfer of ownership of several of our drilling rigs among our subsidiaries.

Income tax expense was $26.7 million and $29.6 million for the quarters ended September 30, 2010 and 2009, respectively. The $2.9 million decline in income tax expense as compared to the prior year quarter was primarily due to reduced profitability and a decline in our consolidated effective income tax rate to 16.6% from 17.0% in the prior year quarter. The decline in our 2010 consolidated effective income tax rate as compared to the prior year quarter 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.

Income tax expense was $84.1 million and $129.7 million for the nine-month period ended September 30, 2010 and 2009, respectively. The $45.6 million decline in income tax expense as compared to the prior year period was primarily due to reduced profitability and a decline in our consolidated effective income tax rate to 16.8% from 18.9% in the comparable prior year period. The decline in our 2010 consolidated effective income tax rate as compared to the prior year period 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.

Discontinued Operations

ENSCO 60

Rig Sales

In recent years, we have focused on the expansion of our ultra-deepwater semisubmersible rig fleet and high-grading our premium jackup fleet. Accordingly, we sold jackup rig ENSCO 57 in April 2010 for $47.1 million, of which a deposit of $4.7 million was received in December 2009. We recognized a pre-tax gain of $17.9 million in connection with the disposal of ENSCO 57, which was included in gain on disposal of discontinued operations, net, in our condensed consolidated statement of income for the nine-month period ended September 30, 2010. The rig’s net book value and inventory and other assets on the date of sale totaled $29.2 million. ENSCO 57 operating results were reclassified to discontinued operations in our condensed consolidated statements of income for the three-month period ended September 30, 2009 and the nine-month periods ended September 30, 2010 and 2009 and previously were included within our Asia Pacific operating segment.

ENSCO 69

From May 2007 to June 2009, ENSCO 69 was contracted to Petrosucre. In January 2009, we suspended drilling operations on ENSCO 69 after Petrosucre failed to satisfy its contractual obligations and meet commitments relative to the payment of past due invoices. Petrosucre then took over complete control of ENSCO 69 drilling operations utilizing Petrosucre employees and a portion of the Venezuelan rig crews we had utilized. In June 2009, we terminated our contract with Petrosucre and removed all remaining Ensco employees from the rig.

There can be no assurances relative to the recovery of outstanding contract entitlements, insurance recovery and related pending litigation or the imposition of customs duties in relation to the rig's recent presence in Venezuela. See Note 10 to our condensed consolidated financial statements for additional information on insurance and legal remedies related to ENSCO 69.

The following table summarizes our (loss) income from discontinued operations for the three-month and nine-month periods ended September 30, 2010 and 2009 (in millions):

	Three Months				Nine Months
	Ended September 30,				Ended September 30,
	2010		2009		2010		2009

Revenues	$ --		$16.5		$12.5		$60.0
Operating expenses	2.2		11.5		16.2		40.6
Operating (loss) income before income taxes	(2.2	)	5.0		(3.7	)	19.4
Income tax benefit	(.3	)	(.8	)	(2.5	)	--
Gain on disposal of discontinued operations, net	--		--		34.9		--
(Loss) income from discontinued operations	$(1.9	)	$ 5.8		$33.7		$19.4

Fair Value Measurements

Auction Rate Securities

Our auction rate securities were measured at fair value as of September 30, 2010 and December 31, 2009 using significant Level 3 inputs. As a result of continued auction failures, quoted prices for our auction rate securities did not exist as of September 30, 2010 and, accordingly, we concluded that Level 1 inputs were not available. We used an income approach valuation model to estimate the price that would be received in exchange for our auction rate securities in an orderly transaction between market participants ("exit price") as of September 30, 2010. The exit price was derived as the weighted-average present value of expected cash flows over various periods of illiquidity, using a risk-adjusted discount rate that was based on the credit risk and liquidity risk of our auction rate securities.

While our valuation model was based on both Level 2 (credit quality and interest rates) and Level 3 inputs, we determined that Level 3 inputs were significant to the overall fair value measurement, particularly the estimates of risk-adjusted discount rates and ranges of expected periods of illiquidity. We reviewed these inputs to our valuation model, evaluated the results and performed sensitivity analysis on key assumptions. Based on our review, we concluded that the fair value measurement of our auction rate securities as of September 30, 2010 was appropriate.

Based on the results of our fair value measurements, we recognized net unrealized gains of $400,000 and $1.0 million during the three-month and nine-month periods ended September 30, 2010, included in other income, net, in our condensed consolidated statements of income. The carrying values of our auction rate securities, classified as long-term investments on our condensed consolidated balance sheets, were $45.0 million and $60.5 million as of September 30, 2010 and December 31, 2009, respectively. We anticipate realizing the $50.3 million (par value) of our auction rate securities on the basis that we intend to hold them until they are redeemed, repurchased or sold in a market that facilitates orderly transactions.

Auction rate securities measured at fair value using significant Level 3 inputs constituted 56% of our assets measured at fair value on a recurring basis and less than 1% of our total assets as of September 30, 2010. See Note 8 to our condensed consolidated financial statements for additional information on our fair value measurements.

ENSCO I Impairment

The estimated fair value of ENSCO I using significant Level 3 inputs constituted less than 1% of our total assets as of September 30, 2010. See Note 8 to our condensed consolidated financial statements for additional information on our fair value measurements.

LIQUIDITY AND CAPITAL RESOURCES

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

It is likely that the impact from the BP Macondo well incident and associated new regulatory, legislative or permitting requirements could result in a decline in our cash flow from operations during the remainder of 2010 and beyond. However, based on $905.2 million of cash and cash equivalents on hand as of September 30, 2010 and our current contractual backlog, we believe our future operations and remaining obligations associated with the construction of our ENSCO 8500 Series® rigs will be funded from existing cash and cash equivalents and future operating cash flow.

During the nine-month period ended September 30, 2010, our primary source of cash was $521.4 million generated from operating activities of continuing operations and $132.4 million of proceeds from the sale of three jackup rigs. Our primary uses of cash for the same period included $553.1 million for the construction, enhancement and other improvement of our drilling rigs, including $478.3 invested in the construction of our ENSCO 8500 Series® rigs, $186.0 million for the acquisition of a KFELS Super B Class design jackup rig and accompanying inventory and $103.6 million for the payment of dividends.

During the nine-month period ended September 30, 2009, our primary source of cash was $897.8 million generated from operating activities of continuing operations. Our primary use of cash for the same period included $681.1 million for the construction, enhancement and other improvement of our drilling rigs, including $486.5 million invested in the construction of our ENSCO 8500 Series® rigs.

Cash Flow and Capital Expenditures

Our cash flow from operating activities of continuing operations and capital expenditures on continuing operations for the nine-month periods ended September 30, 2010 and 2009 were as follows (in millions):

	Nine Months Ended
	September 30,
	2010	2009

Cash flow from operating activities of continuing operations	$521.4	$897.8
Capital expenditures on continuing operations
New rig construction	$478.3	$486.5
Rig acquisition	184.4	--
Minor upgrades and improvements	65.6	64.7
Rig enhancements	9.2	129.9
	$737.5	$681.1

Cash flow from operating activities of continuing operations decreased by $376.4 million, or 42%, for the nine-month period ended September 30, 2010 as compared to the prior year period. The decline resulted primarily from a $327.3 million decline in cash receipts from contract drilling services, a $16.0 million increase in tax payments and a $7.5 million increase in cash payments related to contract drilling expenses.

In conjunction with our long-established strategy of high-grading our fleet by investing in newer equipment, we acquired a KFELS Super B Class design jackup rig and accompanying inventory in July 2010 with available cash for $186.0 million. The rig, which was constructed in 2008, has been renamed ENSCO 109, and we assumed its drilling contract offshore Australia that extends through May 2011.

Based on our current projections, we expect capital expenditures during 2010 to include approximately $610.0 million for construction of our ENSCO 8500® Series rigs, approximately $186.0 million for the acquisition of ENSCO 109, approximately $40.0 million for rig enhancement projects and approximately $100.00 million for minor upgrades and improvements. Depending on market conditions and opportunities, we may make additional capital expenditures to upgrade rigs and construct or acquire additional rigs.

Financing and Capital Resources

Our long-term debt, total capital and long-term debt to total capital ratios as of September 30, 2010 and December 31, 2009 are summarized below (in millions, except percentages):

	September 30,		December 31,
	2010		2009

Long-term debt	$ 248.6		$ 257.2
Total capital*	6,114.2		5,756.4
Long-term debt to total capital	4.1	%	4.5	%

*Total capital consists of long-term debt and Ensco shareholders' equity.

We filed a Form S-3 Registration Statement with the Securities and Exchange Commission (the "SEC") in January 2009, which provides us the ability to issue debt and/or equity securities in one or more offerings. The registration statement was immediately effective and expires in January 2012.

As of September 30, 2010, we had an aggregate $116.9 million outstanding under two separate bond issues guaranteed by the United States of America, acting by and through the United States Department of Transportation, Maritime Administration, that require semiannual principal and interest payments. We also make semiannual interest payments on $150.0 million of 7.20% debentures due in 2027.

The Board of Directors of our U.S. subsidiary and predecessor, ENSCO International Incorporated, previously authorized the repurchase of up to $1,500.0 million of our American depositary shares ("ADSs" or "shares"), 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. No shares were repurchased under the share repurchase programs during the nine-month period ended September 30, 2010. Although $562.4 million remained available for repurchase as of September 30, 2010, we will not repurchase any shares under our share repurchase program without further consultation with and approval by the Board of Directors of Ensco plc.

Liquidity

Our liquidity position as of September 30, 2010 and December 31, 2009 is summarized in the table below (in millions, except ratios):

	September 30,	December 31,
	2010	2009

Cash and cash equivalents	$ 905.2	$1,141.4
Working capital	$1,048.0	$1,167.9
Current ratio	3.2	3.4

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 cash and cash equivalents and operating cash flow. We expect to fund our long-term liquidity needs, including contractual obligations, anticipated capital expenditures and dividends, from our cash and cash equivalents, investments, operating cash flow and, if necessary, funds borrowed under our credit facility or other future financing arrangements.

Based on our $905.2 million of cash and cash equivalents as of September 30, 2010 and our current contractual backlog, we believe our remaining $728.8 million of contractual obligations associated with the construction of our ENSCO 8500 Series® rigs will be funded from existing cash and cash equivalents and future operating cash flow. We may decide to access debt markets to raise additional capital or increase liquidity as necessary.

Effects of Climate Change and Climate Change Regulation

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

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

MARKET RISK

Derivatives

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

We utilize derivatives to hedge forecasted foreign currency denominated transactions, primarily to reduce our exposure to foreign currency exchange rate risk associated with the portion of our remaining ENSCO 8500 Series® construction obligations denominated in Singapore dollars and contract drilling expenses denominated in various other currencies. As of September 30, 2010, $189.4 million of the aggregate remaining contractual obligations associated with our ENSCO 8500 Series® construction projects was denominated in Singapore dollars, of which $133.6 million was hedged through derivatives.

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

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

As of September 30, 2010, we had derivatives outstanding to exchange an aggregate $234.4 million for various foreign currencies, including $133.7 million for Singapore dollars. If we were to incur a hypothetical 10% adverse change in foreign currency exchange rates, net unrealized losses associated with our foreign currency denominated assets and liabilities and related derivatives as of September 30, 2010 would approximate $19.1 million, including $12.5 million related to our Singapore dollar exposures. All of our derivatives mature during the next 12 months. See Note 4 to our condensed consolidated financial statements for additional information on our derivative instruments.

Auction Rate Securities

We have generated a substantial cash balance, portions of which are invested in securities that meet our requirements for quality and return. Investment of our cash exposes us to market risk. We held $50.3 million (par value) of auction rate securities with a carrying value of $45.0 million as of September 30, 2010. We intend to hold these securities until they can be redeemed by issuers, repurchased by brokerage firms or sold in a market that facilitates orderly transactions. Due to significant uncertainties related to the auction rate securities market, we will be exposed to the risk of changes in the fair value of these securities in future periods.

To measure the fair value of our auction rate securities as of September 30, 2010, we used an income approach valuation model to estimate the price that would be received in exchange for our auction rate securities in an orderly transaction between market participants. The resulting exit price was derived as the weighted-average present value of expected cash flows over various periods of illiquidity, using a risk-adjusted discount rate based on the credit risk and liquidity risk of our auction rate securities. If we were to incur a hypothetical 10% adverse change in the risk-adjusted discount rate and a 10% adverse change in the periods of illiquidity, the additional net unrealized losses on our auction rate securities as of September 30, 2010 would approximate $1.4 million. See Note 8 to our condensed consolidated financial statements for additional information on our auction rate securities.

CRITICAL ACCOUNTING POLICIES

The preparation of our consolidated 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 the Consolidated Financial Statements for the year ended December 31, 2009 included in our Annual Report on Form 10-K filed with the SEC on February 25, 2010, as updated in the Current Reports on Form 8-K dated June 8, 2010 and August 13, 2010. 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 September 30, 2010, the carrying value of our property and equipment totaled $4,986.1 million, 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 carrying values of assets and operating results.

For additional information on the useful lives of our drilling rigs, including an analysis of the impact of various changes in useful life assumptions, see "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Critical Accounting Policies and Estimates" in Part II of our Annual Report on Form 10-K for the year ended December 31, 2009, as updated in the Current Reports on Form 8-K dated June 8, 2010 and August 13, 2010.

Impairment of Long-Lived Assets and Goodwill

We evaluate the carrying value of our property and equipment, primarily our drilling rigs, when events or changes in circumstances indicate that the carrying value of such rigs may not be recoverable. Generally, extended periods of idle time and/or inability to contract rigs at economical rates are an indication that a rig may be impaired. However, the offshore drilling industry has historically been highly cyclical, and it is not unusual for rigs to be unutilized or underutilized for significant periods of time and subsequently resume full or near full utilization when business cycles change. Likewise, during periods of supply and demand imbalance, rigs are frequently contracted at or near cash break-even rates for extended periods of time until day rates increase when demand comes back into balance with supply. Impairment situations may arise with respect to specific individual rigs, groups of rigs, such as a specific type of drilling rig, or rigs in a certain geographic location. Our rigs are mobile and may generally be moved from markets with excess supply, if economically feasible. Our ultra-deepwater semisubmersible rigs and jackup 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 future utilization, day rates, expense levels and capital requirements for each of our drilling rigs, as well as cash flows generated upon disposition. 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 of our drilling rigs may not be recoverable, we will conclude that a triggering event has occurred and perform a recoverability test. If, at the time of the recoverability test, management's judgments and assumptions regarding future industry conditions and operations have diminished, it is reasonably possible that we would conclude that one or more of our drilling rigs are impaired.

We test goodwill for impairment on an annual basis, or when events or changes in circumstances indicate that a potential impairment exists. The goodwill impairment test requires us to identify reporting units and estimate each unit's fair value as of the testing date. Our four operating segments represent our reporting units. In most instances, our calculation of the fair value of our reporting units is based on estimates of future discounted cash flows to be generated by our drilling rigs, which reflect management's judgments and assumptions regarding the appropriate risk-adjusted discount rate, as well as future industry conditions and operations, including future utilization, day rates, expense levels, capital requirements and terminal values 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 goodwill impairment test.

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

If the global economy deteriorates and/or our expectations relative to future offshore drilling industry conditions decline, we may conclude that the fair value of one or more of our reporting units has more-likely-than-not declined below its carrying amount and perform an interim period goodwill impairment test. If, at the time of the goodwill impairment test, management's judgments and assumptions regarding future industry conditions and operations have diminished, or if the market value of our shares has substantially declined, we may 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 future 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 and expected future 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 September 30, 2010, our condensed consolidated balance sheet included a $347.2 million net deferred income tax liability, a $36.9 million liability for income taxes currently payable and a $13.8 million liability for unrecognized tax benefits.

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

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

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

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

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

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

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Information required under Item 3 has been incorporated into "Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations - Market Risk."

Item 4. Controls and Procedures

Based on their evaluation as of the end of the period covered by this Quarterly Report on Form 10-Q, 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 and Exchange Act of 1934 (the "Exchange Act"), are effective.

During the fiscal quarter ended September 30, 2010, there were no changes in our internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II - OTHER INFORMATION

Item 1. Legal Proceedings

FCPA Internal Investigation

Our internal investigation has essentially been concluded. Discussions were held with the authorities to review the results of the investigation and discuss associated matters during 2009 and the first half of 2010. On May 24, 2010, we received notification from the SEC Division of Enforcement advising that it does not intend to recommend any enforcement actions. We expect to receive a determination by the United States Department of Justice in the near-term.

ENSCO 74 Loss

In March 2009, the sunken rig hull of ENSCO 74 was located approximately 95 miles from the original drilling location when it was struck by the oil tanker SKS Satilla. Following discovery of the sunken rig hull, we removed the accessible hydrocarbons onboard the rig and began planning for removal of the wreckage. As an interim measure, the wreckage was appropriately marked, and the U.S. Coast Guard issued a Notice to Mariners. In October 2010, wreck removal operations on the sunken rig hull of ENSCO 74 were substantially completed.

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

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

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

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

We filed a petition for exoneration or limitation of liability under U.S. admiralty and maritime law in the U.S. District Court for the Southern District of Texas on September 2, 2009. The petition seeks exoneration from or limitation of liability for any and all injury, loss or damage caused, occasioned or occurred in relation to the ENSCO 74 loss in September 2008. The exoneration/limitation proceedings currently include the tanker claim and the four pipeline claims described above, which effectively supersedes their prior civil litigation filings. The matter is scheduled for trial in September 2011.

ENSCO 69

By letter dated September 30, 2009, legal counsel acting for the package policy underwriters denied coverage under the package policy and reserved rights. On March 15, 2010, underwriters commenced litigation in the U.K. High Court of Justice, Commercial Court, for purposes of enforcing mediation under the disputes clause of our package policy and precluding us from pursuing litigation in the United States. On that date, we commenced litigation styled ENSCO International Incorporated vs. Certain Underwriters at Lloyds, et al, in the District Court, Dallas County, Texas to recover on our political risk package policy claim. Our lawsuit seeks recovery under the policy for the loss of ENSCO 69 and includes claims for wrongful denial of coverage, breach of contract, breach of the Texas insurance code, failure to timely respond to the claim and bad faith. Our lawsuit seeks actual damages in the amount of $55.0 million (insured value of $65.0 million less a $10.0 million deductible), punitive damages and attorneys' fees.

On April 26, 2010, we obtained a temporary injunction from the Texas Court that effectively prohibits the insurance underwriters from pursuing litigation they filed in the U.K. On July 27, 2010, we agreed with underwriters to submit the matter to arbitration, which will be held in Houston, Texas. The U.K. litigation has been dismissed and the Dallas District Court litigation has been stayed. Until these proceedings are concluded, there can be no assurances as to the ultimate outcome. See Note 9 to our condensed consolidated financial statements for additional information on ENSCO 69.

ENSCO 29 Wreck Removal

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

Our liability insurance underwriters have issued letters reserving rights and effectively denying coverage by questioning the applicability of coverage for the potential ENSCO 29 wreckage and debris removal costs. During 2007, we commenced litigation in the Texas District Court of Dallas County against certain underwriters at Lloyd's of London and other insurance companies, Bryan Johnson and BC Johnson Associates, LLC (collectively "the Underwriters") alleging breach of contract, wrongful denial, bad faith and other claims which seek a declaration that removal of wreckage and debris is covered under our liability insurance, monetary damages, attorneys' fees and other remedies. The matter is scheduled for trial in April 2011.

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.

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

Other Matters

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

The lawsuit continues to seek a more well-defined regulatory process for instituting new safety measures and operational and permitting requirements for U.S. Gulf of Mexico shallow-water and deepwater offshore drilling so as to comply with the U.S. Administrative Procedures Act and the Outer Continental Shelf Lands Act. On September 29, 2010, a partial summary judgment motion was heard in the U.S. District Court for the Eastern District of Louisiana seeking a ruling that certain regulatory action known as NTL-5 and the second moratorium/suspension were invalid due to the government's failure to follow prescribed procedures. The judge ordered supplemental briefing from the parties which was submitted on October 12, 2010. A ruling was expected shortly after the briefs were submitted, but the purported early termination of the deepwater drilling moratorium/suspension order impacted the proceedings as the defendants filed a motion to dismiss a portion of our summary judgment motion which we opposed. On October 19, 2010, the court issued an order granting our summary judgment motion in respect of NTL-5 and ruled that NTL-5 was improperly issued. A decision is expected in early November 2010 in respect of our motion for summary judgment challenging the validity of the second moratorium/suspension. There can be no assurances as to the ultimate outcome of these proceedings.

During 2009, we filed arbitration claims with the Financial Industry Regulatory Authority ("FINRA") alleging fraud, conflict of interest and breach of contract against Citigroup Global Markets, Inc. and Merrill Lynch, Pierce, Fenner & Smith, Inc. and breach of contract against Jefferies & Company, Inc. and Oppenheimer & Co., Inc. in connection with the sale of certain auction rate securities to us in the aggregate principal amount of $50.3 million. These proceedings are in the discovery pre-arbitration stages and there can be no assurances as to the ultimate outcome.

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

Item 1A. Risk Factors

There are numerous factors that affect our business and results of operations, many of which are beyond our control. In addition to information set forth in this Quarterly Report, you should carefully read and consider "Item 1A. Risk Factors" in Part I and "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" in Part II of our Annual Report on Form 10-K for the year ended December 31, 2009, as updated in the Current Reports on Form 8-K dated June 8, 2010 and August 13, 2010, which contains descriptions of significant factors that might cause the actual results of operations in future periods to differ materially from those currently anticipated or expected. Except as set forth below, there have been no material changes from the risk factors previously disclosed in our Annual Report on Form 10-K for the year ended December 31, 2009.

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

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

At this time, we cannot predict the impact of the BP Macondo well incident and resulting changes in the regulation of offshore oil and gas exploration and development activity on our operations or contracts or what actions may be taken by our customers, other industry participants or the U.S. or other governments in response to the incident. Future legislative or regulatory enactments may impose new requirements for well control and blowout prevention equipment that could increase our costs and cause delays in our operations due to unavailability of associated equipment.

Prolonged actual or de facto delays, moratoria or suspensions of drilling activity in the U.S. Gulf of Mexico and associated new regulatory, legislative or permitting requirements in the U.S. or elsewhere could materially adversely affect our financial condition, operating results or cash flows.

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

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

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

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

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

The table below provides a summary of our repurchases of our shares during the quarter ended September 30, 2010:

Issuer Purchases of Equity Securities

Approximate

Total Number

Dollar

of Shares

Value of

Average

Purchased as

Shares that

Total

Price

Part of Publicly

May Yet Be

Number of

Paid

Announced

Purchased

per

Plans or

Under Plans

Period

Purchased

Programs

or Programs

July 1 - July 31

3,021

$41.09

$562,000,000

August 1 - August 31

2,120

43.62

$562,000,000

September 1 - September 30

12,667

44.70

$562,000,000

Total

17,808

$43.96

During the quarter ended September 30, 2010, repurchases of our shares were primarily from employees and non-employee directors in connection with the settlement of income tax withholding obligations arising from the vesting of share awards.

The Board of Directors of our U.S. subsidiary and predecessor, ENSCO International Incorporated, previously authorized the repurchase of up to $1,500.0 million of our shares. In December 2009, the then-Board of Directors of Ensco International Limited, a predecessor of Ensco plc, continued the prior authorization and, subject to shareholder approval, authorized management to repurchase up to $562.4 million of our ADSs from time to time pursuant to share repurchase agreements with two investment banks. The then-sole shareholder of Ensco International Limited approved such share repurchase agreements for a five-year term. No shares were repurchased under the share repurchase programs during the nine-month period ended September 30, 2010. Although $562.4 million remained available for repurchase as of September 30, 2010, we will not repurchase any shares under our share repurchase program without further consultation with and approval by the Board of Directors of Ensco plc.

Item 6. Exhibits

Exhibit No.

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		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).
*10.1		Amendment No. 17 to the ENSCO Savings Plan (As Revised and Restated effective January 1, 1997), dated August 2, 2010.
*15.1		Letter regarding unaudited interim financial information.
*31.1		Certification of the Chief Executive Officer of Registrant Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
*31.2		Certification of the Chief Financial Officer of Registrant Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
**32.1		Certification of the Chief Executive Officer of Registrant Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
**32.2		Certification of the Chief Financial Officer of Registrant Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
**101.INS		XBRL Instance Document
**101.SCH		XBRL Taxonomy Extension Schema
**101.CAL		XBRL Taxonomy Extension Calculation Linkbase
**101.DEF		XBRL Taxonomy Extension Definition Linkbase
**101.LAB		XBRL Taxonomy Extension Label Linkbase
**101.PRE		XBRL Taxonomy Extension Presentation Linkbase

* Filed herewith

**Furnished herewith

SIGNATURES

Pursuant to the requirements 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.

		Ensco plc



Date: October 21, 2010		/s/ JAMES W. SWENT III James W. Swent III Senior Vice President and Chief Financial Officer


		/s/ DAVID A. ARMOUR David A. Armour Vice President - Finance


		/s/ DOUGLAS J. MANKO Douglas J. Manko Controller and Assistant Secretary