UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
     Washington, D.C. 20549     

FORM 10-Q

(Mark One)

OR

Commission File Number 1-8097

ENSCO International Incorporated
(Exact name of registrant as specified in its charter)

Registrant's telephone number, including area code: (214) 397-3000

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 is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of "accelerated filer and large accelerated filer" in Rule 12b-2 of the Exchange Act:
          Large accelerated filer ý         Accelerated filer o            Non-accelerated filer 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

There were 144,869,131 shares of Common Stock, $.10 par value, of the registrant outstanding as of October 24, 2007.

ENSCO INTERNATIONAL INCORPORATED

INDEX TO FORM 10-Q

FOR THE QUARTER ENDED SEPTEMBER 30, 2007

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FORWARD-LOOKING STATEMENTS

       This report contains forward-looking statements that are subject to a number of risks and uncertainties and that are based on information as of the date of this report. We assume no obligation to update these statements based on developments or information received or discovered 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 impact. The forward-looking statements include statements regarding:

       The 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 those described under "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, 2006, as updated in this report.

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PART I - FINANCIAL INFORMATION

Item 1.  Financial Statements

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders
ENSCO International Incorporated:

We have reviewed the accompanying condensed consolidated balance sheet of ENSCO International Incorporated and subsidiaries as of September 30, 2007, the related condensed consolidated statements of income for the three-month and nine-month periods ended September 30, 2007 and 2006, and the related condensed consolidated statements of cash flows for the nine-month periods ended September 30, 2007 and 2006. These condensed consolidated financial statements are the responsibility of the Company's management.

We conducted our reviews 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 reviews, 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 International Incorporated and subsidiaries as of December 31, 2006, and the related consolidated statements of income and cash flows for the year then ended (not presented herein); and in our report dated February 22, 2007, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying condensed consolidated balance sheet as of December 31, 2006, 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 25, 2007

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ENSCO INTERNATIONAL INCORPORATED AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(In millions, except per share amounts)
(Unaudited)

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

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ENSCO INTERNATIONAL INCORPORATED AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(In millions, except per share amounts)
(Unaudited)

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

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ENSCO INTERNATIONAL INCORPORATED AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(In millions, except par value amounts)

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

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ENSCO INTERNATIONAL INCORPORATED AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(In millions)
(Unaudited)

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

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ENSCO INTERNATIONAL INCORPORATED 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 International Incorporated and subsidiaries in accordance with U.S. generally accepted accounting principles, 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, 2006 consolidated balance sheet data were derived from audited financial statements, but do not include all disclosures required by U.S. generally accepted accounting principles. Certain previously reported amounts have been reclassified to conform to the current-year presentation. The preparation of the condensed consolidated financial statements requires our management to make certain estimates and assumptions that affect the reported amounts of assets and liabilities, the related revenues and expenses, and disclosure of gain and loss contingencies at 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, 2007 and 2006 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 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, 2007 are not necessarily indicative of the results of operations that will be realized for the year ending December 31, 2007. It is recommended that these financial statements be read in conjunction with our consolidated financial statements and notes thereto for the year ended December 31, 2006 included in our Annual Report on Form 10-K filed with the SEC.

Note 2 - Earnings Per Share

       For the three-month and nine-month periods ended September 30, 2007 and 2006, there were no adjustments to net income for purposes of calculating basic and diluted earnings per share. The following is a reconciliation of the weighted average common shares used in the basic and diluted earnings per share computations (in millions):

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       Options to purchase 511,000 shares and 1.1 million shares of common stock in the three-month periods ended September 30, 2007 and 2006, respectively, were not included in the computation of diluted earnings per share because the exercise price of the options exceeded the average market price of the common stock for the respective periods. Options to purchase 519,000 shares and 684,000 shares of common stock in the nine-month periods ended September 30, 2007 and 2006, respectively, were not included in the computation of diluted earnings per share because the exercise price of the options exceeded the average market price of the common stock for the respective periods.

Note 3 - Stockholders' Equity

       In March 2006, our Board of Directors authorized the repurchase of up to $500.0 million of our outstanding common stock. In August 2007, following completion of the authorized repurchase of $500.0 million of common stock, our Board of Directors authorized the repurchase of an additional $500.0 million of our outstanding common stock. Aggregate repurchases of common stock during the three-month and nine-month periods ended September 30, 2007 totaled 2.5 million shares at a cost of $145.1 million (an average cost of $57.74 per share) and 7.5 million shares at a cost of $417.5 million (an average cost of $55.61 per share), respectively.

       At September 30, 2007 and December 31, 2006, the outstanding shares of our common stock, net of treasury shares, were 145.6 million and 151.8 million, respectively.

Note 4 - Comprehensive Income

       The components of our comprehensive income are as follows (in millions):

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       Accumulated other comprehensive loss at September 30, 2007 and December 31, 2006, is comprised of net unrealized losses on derivative instruments, net of tax. The estimated amount of unrealized gains and losses on derivative instruments, net of tax at September 30, 2007, that will be reclassified to earnings during the next twelve months is as follows (in millions):

Note 5 - Income Taxes

       We conduct operations, earn income and are subject to tax in the U.S. and numerous international countries. In many of the international jurisdictions where we operate, tax laws relating to the offshore drilling industry are not well developed and change frequently. Furthermore, in most of the tax jurisdictions where we operate, we enter into transactions with affiliates or employ other tax planning strategies that generally are subject to complex tax regulations. As a result of the foregoing, the tax liabilities and benefits we recognize in our financial statements may differ from the tax positions taken, or expected to be taken, in our tax returns.

       On January 1, 2007, we adopted the recognition and disclosure provisions of FASB Interpretation No. 48, "Accounting for Uncertainty in Income Taxes - an interpretation of FASB Statement No. 109" ("FIN 48"). Under FIN 48, tax positions are evaluated for recognition using a more-likely-than-not threshold, and those tax positions requiring recognition are measured as the largest amount of tax benefit that is greater than 50 percent likely of being realized upon ultimate settlement with a taxing authority that has full knowledge of all relevant information. As a result of adopting FIN 48, we reported a $5.8 million increase to our January 1, 2007, balance of retained earnings. On January 1, 2007, we had $19.3 million of unrecognized tax benefits, of which $16.0 million would impact our effective tax rate if recognized.

       Interest and penalties relating to income taxes are included in current income tax expense. Accrued interest and penalties at January 1, 2007, were $9.6 million and $6.3 million, respectively.

       Our U.S. tax returns for 2004 and subsequent years remain subject to examination by tax authorities. In our international tax jurisdictions, numerous tax years remain subject to examination by tax authorities, including tax returns for at least 2002 and subsequent years in most of our major international tax jurisdictions.

       During the second quarter of 2007, the taxing authority in an international jurisdiction in which we operate issued a draft interpretation of certain tax laws that is inconsistent with a tax position we have taken and previously recognized approximately $40.6 million of aggregate tax benefits during the current and previous years. We have evaluated the draft interpretation, considering the technical arguments supporting its conclusion, the circumstances of its issuance, its consistency with existing tax code and case law, professional guidance and other available qualitative information, and have concluded that our uncertain tax position in this jurisdiction continues to meet the more-likely-than-not recognition threshold of FIN 48. However, it is reasonably possible that the taxing authority's interpretation will be revised and re-issued, relevant legislation will be enacted or other related events will take place within the next twelve months that cause us to re-evaluate our tax position.

       During the third quarter of 2007, new information became available in one of our international tax jurisdictions that enabled us to conclude an uncertain tax position established in prior years had been effectively settled. As a result, we recognized an aggregate $11.1 million current tax benefit during the three-month period ended September 30, 2007, consisting of $9.0 million for the previously unrecognized tax benefit and $2.1 million of previously accrued penalties and interest.

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Note 6 - Discontinued Operations

       In December 2006, we sold the ENSCO 25 platform rig for $13.7 million and recognized a pre-tax gain of $5.0 million. The operating results of ENSCO 25 have been reclassified as discontinued operations in the condensed consolidated statements of income for the three-month and nine-month periods ended September 30, 2006.

       The ENSCO 29 platform rig sustained substantial damage as a consequence of Hurricane Katrina in the third quarter of 2005. On January 5, 2006, beneficial ownership of ENSCO 29 effectively transferred to our insurance underwriters when the rig was declared a constructive total loss under the terms of our insurance policies. Accordingly, we received the rig's net insured value of $10.0 million and recognized a pre-tax gain of $7.5 million, which consists of the $2.5 million excess of insurance proceeds over the net book value of the rig ($7.5 million) plus $5.0 million for the de-recognition of a loss provision in the amount of an insurance deductible accrued upon hurricane damage in 2005. The gain is included in "Gain on disposal of discontinued operations, net" in the condensed consolidated statement of income for the nine-month period ended September 30, 2006. During the third quarter of 2006, we recognized a $1.2 million provision ($800,000 net of tax) relating to issues involving ENSCO 29 wreckage and debris removal insurance coverage (see "Note 7 - Contingencies"). The operating results of ENSCO 29 and the $1.2 million provision for wreckage and debris removal have been reclassified as discontinued operations in the condensed consolidated statements of income for the three-month and nine-month periods ended September 30, 2006.

       The following is a summary of income from discontinued operations (in millions):
 

       There is no debt or interest expense allocated to our discontinued operations.

Note 7 - Contingencies

       Following disclosures by other offshore oil service companies announcing internal investigations focusing on 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 of our payments to customs brokers primarily relating to the temporary importation of ENSCO 100 (a rig that formerly operated offshore Nigeria), which investigation has been extended to include activities in Saudi Arabia by one of the customs brokers.

       The purpose of our investigation is to determine whether any of the payments made to or by our customs brokers were inappropriate under the U.S. Foreign Corrupt Practices Act ("FCPA"). Our Audit Committee has engaged Miller & Chevalier, a Washington, D.C. law firm with significant experience in investigating and advising upon FCPA matters, to assist the Audit Committee and management in the internal investigation.

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       Following consultation with outside legal counsel, notification to the Audit Committee and KPMG LLP, our independent registered public accounting firm, we voluntarily notified the United States Securities and Exchange Commission and the United States Department of Justice that an internal investigation is underway and that we intend to cooperate fully with both agencies. The internal investigation is in an early stage and we are unable to predict whether either agency will initiate a separate investigation of this matter or what potential corrective measures, sanctions or other remedies, if any, the agencies may seek against us or any of our employees.

       This matter did not have any material effect on or disrupt our recent operations in Nigeria because our only rig in that jurisdiction, ENSCO 100, completed its contract commitment and departed Nigeria during August 2007. At this time, we cannot predict the effect of this matter upon our operations in Saudi Arabia. We are unable to predict the outcome of the investigation or determine whether or the extent to which we may be exposed to any resulting potential liability or significant additional expense.

       A portion of the ENSCO 29 platform drilling rig was lost over the side of a customer's platform during Hurricane Katrina in the third quarter of 2005. Although beneficial ownership of ENSCO 29 was subsequently transferred to our insurance underwriters when the rig was determined to be a constructive total loss, management believes we may be contractually required to remove the ENSCO 29 wreckage and debris from the seabed and currently estimates that 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 coverage for wreckage and debris removal costs in excess of the $3.8 million coverage provided under the property insurance policies.

       Our liability insurance underwriters have issued reservation of rights letters raising issues regarding the applicability of coverage for the potential ENSCO 29 wreckage and debris removal costs. During August 2007, we commenced litigation against the liability underwriters alleging breach of contract, wrongful denial, bad faith and other claims which seek a declaration that the removal of wreckage and debris is covered under our liability insurance, damages, attorneys' fees and other remedies. While we believe it is likely that any ENSCO 29 wreckage and debris removal costs incurred will be fully covered by insurance, a $1.2 million provision, representing the portion of the $5.0 million low range of the estimated removal cost we believe is subject to liability insurance coverage, was recognized during the third quarter of 2006.

       In August 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.

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       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 62 individual plaintiffs. Of these claims, 60 claims or lawsuits are pending in Mississippi state courts and two are pending in the United States District Court as a result of their removal from state court.

       We intend to vigorously defend against these claims and have filed responsive pleadings preserving all defenses and challenges to jurisdiction and venue. However, inasmuch as discovery is in the very early stages and available information regarding the nature of these claims is limited, we cannot reasonably determine if the claimants have valid claims under the Jones Act or estimate a range of potential liability exposure, if any. At present, none of the pending Mississippi asbestos lawsuits against us have been set for trial. Although we do not expect the final disposition of these 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.

       Legislation known as the U.K. Working Time Directive ("WTD") was introduced in August 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). The related issues are subject to pending or potential judicial, administrative and legislative review. We also have received inquiries from the Danish and Dutch authorities regarding applicability of the WTD as adopted by Denmark and The Netherlands to our employees on our rigs operating in the Danish and Dutch sectors of the North Sea. Based on information currently available, we do not expect the resolution of these matters to have a material adverse effect on our financial position, operating results or cash flows.

       In addition to the foregoing, we and our subsidiaries are named defendants in certain other lawsuits incidental to our business and are involved from time to time as parties to governmental proceedings, including matters related to taxation, arising in the ordinary course of business. Although the outcome of lawsuits or other proceedings involving us and our subsidiaries 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, management does not expect these matters will have a material effect on our financial position, operating results or cash flows.

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

BUSINESS ENVIRONMENT

       During the first nine months of 2007, jackup rig demand continued to meet or exceed supply in all major geographical regions except the Gulf of Mexico, where there continued to be an excess supply of available jackup rigs due to a decline in shallow-water drilling activity over recent years. In the current market, major and large independent oil and gas companies continue to divert spending outside of the shallow waters of the Gulf in search of more productive oil and gas fields.

       Demand for ultra-deepwater drilling rigs exceeds the available supply, both internationally and in the Gulf of Mexico. As oil and gas companies continue to increase their investment in deepwater projects, it is anticipated that the global deepwater fleet will remain near full utilization for the next several years.

       Overall, the global supply of available rigs is anticipated to remain tight through the remainder of 2007 as the fundamentals for oil and gas drilling are expected to remain favorable. There are, however, over 110 new jackup and semisubmersible rigs reported to be on order and scheduled for delivery starting in late 2007. For additional information concerning the potential risks and uncertainties these new drilling rigs may have on our business, our industry, global supply, day rates and utilization, see "Item 1A. Risk Factors" and "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" in our Annual Report on Form 10-K for the year ended December 31, 2006.

Asia Pacific

       During 2006, demand for jackup rigs in most of the Asia Pacific region markets exceeded the supply of available rigs. As a result, jackup rig utilization levels remained high and day rates continued to increase. During the first nine months of 2007, demand for drilling rigs remained strong and drilling contractors continued to experience high day rates and utilization. Jackup rig drilling contracts in the Asia Pacific region historically have been for longer durations than those in other geographical regions. Since day rates for such contracts normally are fixed, or fixed subject to adjustment for variations in the contractor's costs, our Asia Pacific operations generally are not subject to the same level of day rate volatility as regions where shorter term contracts are more prevalent.

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Europe/Africa

       Our Europe/Africa offshore drilling operations are mainly conducted in northern Europe (North Sea) where moderate duration jackup rig contracts are prevalent. During 2006, a strong backlog of firm contract commitments and options in northern Europe resulted in little or no availability of jackup rigs. This caused demand to exceed the supply of available rigs, resulting in a substantial increase in day rates from the prior year. During the first three quarters of 2007, jackup rig day rates and utilization levels remained strong and there appears to be very limited rig availability for the remainder of 2007 and into 2008.

North and South America

       Our North and South America offshore drilling operations are mainly conducted in the Gulf of Mexico. The U.S. natural gas market and trends in oil and gas company spending largely determine offshore drilling industry conditions and demand for rigs in this region. Gulf of Mexico jackup rig contracts are normally entered into for relatively short durations and day rates are adjusted to current market rates upon contract renewal.

       During the first five months of 2006, jackup rig day rates in the Gulf of Mexico experienced a fairly rapid increase due to the decreased supply of available rigs in the region resulting from the departure of rigs contracted to work in international waters. However, the impact of the decreased supply of available jackup rigs was more than offset by a decrease in demand that began late in the second quarter of 2006, as oil and gas companies were reluctant to start new projects in view of the upcoming hurricane season. Additionally, a decrease in the price of natural gas, increased insurance costs, and the limited availability of hurricane risk insurance coverage resulting in uninsured exposure, also made this region less attractive to oil and gas companies. As a result, jackup rig day rates began to moderate late in the second quarter of 2006 and remained under pressure during the rest of the year.

       During the first six months of 2007, it appeared that demand for jackup rigs in the Gulf of Mexico stabilized, although average day rates softened during the second quarter as a result of competition for work among drilling contractors particularly related to smaller premium jackup rigs. In the third quarter, oil and gas companies remained cautious during hurricane season and continued to shift their focus to more economically attractive prospects in the deeper waters of the Gulf and elsewhere. As a result, jackup rig demand dropped to its lowest point in the year, thus having an adverse impact on utilization and day rates. Drilling contractors continue to pursue international opportunities and, despite the relocation of several jackup rigs from the region, rig demand decreased at a faster pace than supply. We anticipate that drilling contractors will continue to market their Gulf of Mexico jackup rigs for longer term international contracts which, in turn, will help bring Gulf of Mexico rig supply more into balance with demand.

       Demand for deepwater semisubmersible rigs in the Gulf of Mexico continues to outpace supply resulting in high day rates and utilization for ultra-deepwater rigs. In addition to the ENSCO 7500 deepwater semisubmersible rig currently operating in the Gulf of Mexico, we have four ultra-deepwater semisubmersible rigs under construction with scheduled delivery dates in the second quarter of 2008, the first and fourth quarters of 2009 and the third quarter of 2010. The first three rigs to be delivered have secured long-term contracts in the Gulf of Mexico and we are marketing ENSCO 8503 and fully anticipate that it will be contracted well in advance of delivery. As oil and gas companies continue to increase their investment in deepwater projects, it is anticipated that the ultra-deepwater rigs in the Gulf of Mexico, as well as other geographical regions of the world, will remain near full utilization for the next several years.

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RESULTS OF OPERATIONS

       The following analysis highlights our consolidated operating results (in millions):

       For the three-month period ended September 30, 2007, revenues increased by $65.8 million, or 14%, and operating income increased by $34.6 million, or 12%, from the prior year quarter. The increases were primarily due to improved average day rates of our jackup rigs in the Europe/Africa and Asia Pacific regions, partially offset by a reduction in average day rates and utilization of our Gulf of Mexico jackup rigs.

       For the nine-month period ended September 30, 2007, revenues increased by $271.7 million, or 20%, and operating income increased by $163.2 million, or 22%, from the prior year period. The increases were primarily due to improved average day rates of our jackup rigs in the Europe/Africa and Asia Pacific regions, partially offset by a reduction in average day rates and utilization of our Gulf of Mexico jackup rigs. Detailed explanations of our operating results for the three-month and nine-month periods ended September 30, 2007 and 2006, including discussions of revenues and contract drilling expense based on geographical location and type of rig, are set forth below.

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Revenue and Contract Drilling Expense

       The following is an analysis of our revenues, contract drilling expense, rig utilization and average day rates from continuing operations (in millions, except utilization and day rates):

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       The following is a summary of our offshore drilling rigs by location:

   Asia Pacific Jackup Rigs

       Third quarter 2007 revenues for the Asia Pacific jackup rigs increased by $81.2 million, or 55%, as compared to the prior year quarter. The increase in revenues was primarily due to a 45% increase in average day rates and the increased size of the Asia Pacific fleet as ENSCO 84 mobilized to the region in late September 2006 and ENSCO 108 was delivered by a shipyard in the first quarter of 2007. The two additional rigs provided an aggregate $34.7 million of revenue in the current quarter. The increase in average day rates resulted from stronger demand due to higher levels of spending by oil and gas companies coupled with limited rig availability in the region. Contract drilling expense increased by $10.6 million, or 19%, as compared to the prior year quarter due to the increased size of the fleet as well as higher personnel costs and repair and maintenance expense.

       For the nine months ended September 30, 2007, revenues for the Asia Pacific jackup rigs increased by $247.8 million, or 61%, as compared to the prior year period. The increase in revenues was primarily due to a 49% increase in average day rates and the two rigs added to the Asia Pacific fleet, which contributed $75.9 million of revenue in the current year period. The increase in average day rates resulted from stronger demand and limited rig availability as noted above. Contract drilling expense increased by $35.3 million, or 23%, as compared to the prior year period due partially to the increased size of the fleet as well as increased personnel costs, and repair and maintenance expense. The increased costs were partially offset by a $2.7 million estimated loss recognized in the prior year period related to damage sustained by ENSCO 107 while pre-loading on a drilling location offshore Vietnam.

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   Europe/Africa Jackup Rigs

       Third quarter 2007 revenues for the Europe/Africa jackup rigs increased by $39.1 million, or 29%, as compared to the prior year quarter. The increase in revenues was primarily due to the addition of ENSCO 105 to the Europe/Africa jackup fleet in the first quarter of 2007, which provided $22.8 million of revenue in the current quarter, and to a 29% increase in average day rates. The increase was partially offset by a decrease in utilization to 90% in 2007 from 100% in 2006. The improvement in average day rates was attributable to improved demand resulting from increased spending by oil and gas companies. The decrease in utilization primarily was attributable to the mobilization of ENSCO 100 from Nigeria to the North Sea, which commenced in late August of 2007. Contract drilling expense increased by $16.2 million, or 40%, from the prior year quarter due primarily to the relocation of ENSCO 105 to the region, which resulted in an additional $7.4 million of expense in the current quarter, and to increased personnel costs, repair and maintenance expense and costs associated with the departure of ENSCO 100 from Nigeria, all of which were partially offset by a reduction in mobilization expense during the quarter.

       For the nine months ended September 30, 2007, revenues for the Europe/Africa jackup rigs increased by $134.6 million, or 37%, from the prior year period. The increase in revenues was primarily attributable to the addition of ENSCO 105 to the Europe/Africa jackup fleet in the first quarter of 2007, which provided $32.7 million of revenue in the current year period, and to a 33% increase in average day rates. The increase was partially offset by a decrease in utilization to 95% in 2007 from 100% in 2006 due primarily to the mobilization of ENSCO 100 as noted above. The improvement in average day rates was attributable to improved demand resulting from increased spending by oil and gas companies. Contract drilling expense increased by $41.8 million, or 36%, from the prior year period due to the relocation of ENSCO 105, which resulted in an additional $14.0 million of expense during the current year period, and to increased personnel costs, reimbursable expenses, repair and maintenance expense and costs associated with the departure of ENSCO 100 from Nigeria, all of which were partially offset by a reduction in mobilization expense during the period.

   North and South America Jackup Rigs

       Third quarter 2007 revenues for the North and South America jackup rigs decreased by $57.2 million, or 32%, compared to the prior year quarter. The decrease in revenues was partially due to the reduced size of the North and South America jackup fleet as two rigs were relocated from the Gulf of Mexico during the first quarter of 2007 and the third quarter of 2006. The two jackup rigs provided $17.1 million of revenue during the third quarter of 2006. The decrease in revenues also was due to a decrease in utilization to 78% in 2007 from 93% in 2006 and to an 11% decrease in average day rates compared to the prior year quarter. The decrease in utilization and average day rates was primarily attributable to a decrease in demand by oil and gas companies as they have reduced spending on shallow water drilling in this region. The decrease in utilization also resulted from an increase in the amount of time rigs spent in shipyards during the current year quarter as compared to the prior year quarter. Third quarter 2007 contract drilling expense increased by $900,000, or 2%, compared to the prior year quarter. The increase in contract drilling expense resulted from increased personnel costs and repair and maintenance expense partially offset by the reduction in fleet size.

       For the nine months ended September 30, 2007, revenues for the North and South America jackup rigs decreased by $122.5 million, or 24%, compared to the prior year period. The decrease in revenues was partially due to the two relocated rigs as noted above, which provided $55.8 million of revenue in the prior year period. An 8% decrease in average day rates and a decrease in utilization to 82% in 2007 from 90% in 2006 also contributed to the reduction in revenue from the prior year period. The decrease in utilization and average day rates is due to a decrease in demand by oil and gas companies as noted above. For the nine months ended September 30, 2007, contract drilling expense increased by $7.7 million, or 6%, compared to the prior year period. The increase in contract drilling expense was primarily attributable to increased personnel, insurance, and repair and maintenance expense, partially offset by the reduced size of the fleet.

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   North America Semisubmersible Rigs

       Third quarter 2007 revenues for ENSCO 7500 increased by $1.3 million, or 7%, and contract drilling expense increased by $1.2 million or 17%, as compared to the prior year quarter. The increase in revenues was primarily due to a 5% increase in the average day rate resulting from a cost escalation provision in the contract. The increase in contract drilling expense was primarily due to increased personnel costs and repair and maintenance expense.

       For the nine months ended September 30, 2007, revenues for ENSCO 7500 increased $10.9 million, or 25%, and contract drilling expense increased by $1.2 million, or 6%, compared to the prior year period. The increase in revenues was primarily due to a 5% increase in the average day rate as noted above and an increase in utilization to 97% in 2007 from 84% in 2006, as ENSCO 7500 was idle for approximately one month in the prior year period while undergoing minor enhancement and preparatory work for its current contract. The increase in contract drilling expense was primarily due to increased personnel costs and reimbursable expense partially offset by a reduction in repair and maintenance expense.

Depreciation

       Depreciation expense for the three-month period ended September 30, 2007 increased by $2.8 million, or 6%, as compared to the prior year quarter. The increase was primarily attributable to depreciation associated with ENSCO 108, which was placed into service in April 2007, and capital enhancement and upgrade projects completed subsequent to the third quarter of 2006.

       Depreciation expense for the nine-month period ended September 30, 2007 increased by $8.6 million, or 7%, as compared to the corresponding prior year period. The increase was primarily attributable to depreciation associated with ENSCO 108 and ENSCO 107, which were placed into service in April 2007 and March 2006, respectively, and capital enhancement and upgrade projects completed subsequent to the third quarter of 2006.

General and Administrative

       General and administrative expense for the three-month period ended September 30, 2007 increased by $200,000, or 2%, as compared to the prior year quarter. The increase was primarily attributable to a general increase in professional fees and salary expense, partially offset by a decrease in share-based employee compensation expense as compared to the prior year quarter.

       General and administrative expense for the nine-month period ended September 30, 2007 increased by $14.4 million, or 45%, as compared to the prior year period. The increase was primarily attributable to a $10.7 million expense we incurred during the current period in connection with the retirement agreement entered into in February of 2007 with our former CEO and non-executive Chairman of our Board of Directors and to an increase in professional fees, salary expense and share-based employee compensation expense as compared to the prior year period. These increases were partially offset by a one-time discretionary $1.1 million cash contribution made during the first quarter of 2006 to the ENSCO 2005 Supplemental Executive Retirement Plan account of our new Chief Executive Officer to offset pension and other benefits forfeited under his previous employment.

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Other Income (Expense)

       The following is an analysis of other income (expense) (in millions):
 

       Interest income for the three-month and nine-month periods ended September 30, 2007 increased as compared to the corresponding prior year periods primarily due to an increase in cash balances invested. Interest expense decreased during the same periods due primarily to a decrease in outstanding debt. Capitalized interest for the three-month and nine-month periods ended September 30, 2007 increased as compared to the corresponding prior year periods due to an increase in the amount invested in new rig construction projects.

       Foreign currency transaction gains and losses are included in Other, net, on our consolidated statements of income. Net foreign currency transaction gains totaled $2.7 million and $5.4 million for the three-month and nine-month periods ended September 30, 2007. We had net foreign currency transaction gains of $200,000 for the three-month period ended September 30, 2006, and net foreign currency transaction losses of $1.2 million for the nine-month period ended September 30, 2006.

Provision for Income Taxes

       Our effective income tax rates for the three-month periods ended September 30, 2007 and 2006 were 17.8% and 23.2%, respectively. The income tax provision for the three-month period ended September 30, 2007 included an $11.1 million benefit from the recognition of a prior period uncertain tax position. The income tax provision for the three-month period ended September 30, 2006 included a $6.6 million net benefit that resulted primarily from the resolution of various issues in connection with the completion of audits by tax authorities of certain foreign tax returns and release of certain tax liabilities recognized in prior years that were determined to no longer be necessary. Excluding the impact of the aforementioned net benefits, our effective income tax rates for the three-month periods ended September 30, 2007 and 2006 would have been 21.2% and 25.5%, respectively.

       Our effective income tax rates for the nine-month periods ended September 30, 2007 and 2006 were 20.4% and 26.1%, respectively. The income tax provision for the nine-month period ended September 30, 2007 included an $11.1 million benefit from the recognition of a prior period uncertain tax position as noted above. The income tax provision for the nine-month period ended September 30, 2006 included a $2.3 million net benefit that resulted primarily from the resolution of various issues relating to prior periods. Excluding the impact of the aforementioned net benefits, our effective income tax rates for the nine-month periods ended September 30, 2007 and 2006 would have been 21.5% and 26.4%, respectively.

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       The reduction in our effective tax rates was primarily due to an increase in the relative portion of our earnings generated by foreign subsidiaries whose earnings are permanently reinvested and taxed at lower rates.

LIQUIDITY AND CAPITAL RESOURCES

       Although our business is very cyclical, we historically have relied on our cash flow from continuing operations to meet liquidity needs and fund the majority of our cash requirements. Our management believes we have maintained a strong financial position through the disciplined and conservative use of debt. A substantial amount of our cash flow is invested in the expansion and enhancement of our fleet of drilling rigs.

       During the nine month period ended September 30, 2007, our primary sources of cash consisted of $867.3 million generated from continuing operations and $29.8 million from the exercise of stock options. Our primary use of cash consisted of $417.5 million for the repurchase of our common stock and $407.9 million for the acquisition, construction, enhancement and other improvement of drilling rigs and equipment.

       During the nine-month period ended September 30, 2006, our primary sources of cash included $654.4 million generated from continuing operations, $10.0 million from the disposal of discontinued operations and $21.9 million from the exercise of share options. Our primary use of cash for the same period consisted of $405.2 million for the construction, enhancement and other improvement of drilling rigs and $106.7 million for the repurchase of our common stock.

       Detailed explanations of our liquidity and capital resources for the nine-month periods ended September 30, 2007 and 2006, are set forth below.

Cash Flow and Capital Expenditures

       Our cash flow from continuing operations and capital expenditures on continuing operations are as follows (in millions):

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       Our cash flow from continuing operations increased by $212.9 million, or 33%, for the nine-month period ended September 30, 2007 as compared to the prior year period. The increase resulted primarily from a $296.4 million increase in cash receipts from drilling services offset by a $76.1 million increase in cash payments related to contract drilling expenses and a $15.3 million increase in cash payments related to income taxes.

       On June 7, 2007, we entered into an agreement with Keppel FELS Limited ("KFELS") in Singapore to construct ENSCO 8503 for a total project construction cost of approximately $427.0 million, with delivery expected in the third quarter of 2010. ENSCO 8503 is our fourth ultra-deepwater semisubmersible rig in the ENSCO 8500 Series^®. The first three 8500 Series rigs (ENSCO 8500, ENSCO 8501 and ENSCO 8502) are under construction by KFELS with expected deliveries in the second quarter of 2008, first quarter of 2009 and fourth quarter of 2009, respectively. The ENSCO 8500, ENSCO 8501 and ENSCO 8502 are subject to long-term drilling contracts upon completion of their construction.

       On March 30, 2007, we accepted delivery of ENSCO 108, an ultra-high specification jackup rig, and made the final construction installment payment of $23.4 million in April of 2007.

       We currently expect that our capital expenditures in 2007 will include approximately $80.0 million for minor rig upgrades and improvements, $85.0 million for rig enhancement projects and approximately $390.0 million for new rig construction, which includes progress payments on the four ultra-deepwater semisubmersible rigs under construction and the final payment we made on ENSCO 108. Depending on market conditions and opportunities, we may also make capital expenditures to construct or acquire additional rigs.

Contractual Obligations

       On June 7, 2007, we entered into an agreement to construct ENSCO 8503 for a total contractual commitment of approximately $403.4 million. Of this amount, we projected that $86.0 million will be due in 2007, an aggregate $198.9 million will be due in the years 2008 and 2009, and $118.5 million will be due in the year 2010. We expect to fund this commitment from our existing cash and cash equivalents and future operating cash flow.

       The contractual obligations disclosed in Management's Discussion and Analysis of Financial Condition and Results of Operations included in our Form 10-K for the year ended December 31, 2006, did not include unrecognized tax benefits. We adopted the recognition and disclosure provisions of FASB Interpretation No. 48, "Accounting for Uncertainty in Income Taxes - an interpretation of FASB Statement No. 109," on January 1, 2007 and had $19.3 million of unrecognized tax benefits upon adoption. Substantially all of our unrecognized tax benefits relate to uncertain tax positions that are not currently under review by taxing authorities and we therefore are unable to specify the future periods in which we may be obligated to settle such amounts.

Financing and Capital Resources

       Our long-term debt, total capital and long-term debt to total capital ratios are summarized below (in millions, except percentages):

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       In March 2006, our Board of Directors authorized the repurchase of up to $500.0 million of our outstanding common stock. In August 2007, following completion of the authorized repurchase of $500.0 million of common stock, our Board of Directors authorized the repurchase of an additional $500.0 million of our outstanding common stock (the "supplemental authorization"). Aggregate repurchases of common stock during the three-month and nine-month periods ended September 30, 2007 totaled 2.5 million shares at a cost of $145.1 million (an average cost of $57.74 per share) and 7.5 million shares at a cost of $417.5 million (an average cost of $55.61 per share), respectively.

       Since the inception of our stock repurchase programs in March 2006, we have repurchased an aggregate 11.0 million shares at a cost of $577.5 million (an average cost of $52.65 per share). As of September 30, 2007, approximately $422.5 million was available for repurchases of our outstanding common stock under the supplemental authorization.

       We have $150.0 million of outstanding notes that mature in November 2007 and we plan to meet our repayment obligation with funds to be borrowed under our $350.0 million unsecured revolving credit facility (which remains undrawn since inception). Although we maintain substantial cash and cash equivalents, we expect to utilize our unsecured revolving credit facility to repay the notes in order to maintain future financing flexibility, in light of our current capital structure and debt levels. As part of our evaluation, we considered the remaining funding requirements relative to our construction of semisubmersible rigs and our authorized share repurchases, which exceed an aggregate of $1.3 billion, as well as our desire to utilize our existing cash and cash equivalents and future generated cash flows in a tax efficient manner.

Liquidity

       Our liquidity position is summarized in the table below (in millions, except ratios):

        We expect to fund our short-term liquidity needs, including contractual obligations, anticipated capital expenditures and stock repurchases, as well as any working capital requirements, from our cash and cash equivalents and operating cash flow. As noted above, we expect to fund repayment of the $150 million of notes with funds to be borrowed under our unsecured revolving credit facility.

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        We expect to fund our long-term liquidity needs, including contractual obligations and anticipated capital expenditures, from our cash and cash equivalents, operating cash flow and, if necessary, from funds borrowed under our $350.0 million unsecured revolving credit facility, or borrowings under other future financing arrangements.

        We historically have funded the majority of our liquidity from operating cash flow. We anticipate a substantial amount of our cash flow in the near to intermediate-term will continue to be invested in the expansion of our deepwater drilling fleet and used to repurchase our outstanding common stock under the $500.0 million supplemental authorization, of which, approximately $422.5 million was available for repurchases as of September 30, 2007. While future operating cash flow cannot be accurately predicted, based on our contractual backlog and current industry conditions, management believes our long-term liquidity will continue to be funded primarily by operating cash flow.

Backlog Information

        Our contract drilling backlog at October 15, 2007, totaled approximately $3.8 billion, consisting of $2.3 billion related to our jackup rig fleet and $1.5 billion related to our semisubmersible rig fleet. Approximately $453.2 million of the total backlog is expected to be realized during the remainder of 2007. Our contract drilling backlog at February 1, 2007 (the date reported in our Annual Report on Form 10-K for the year ended December 31, 2006), was $3.2 billion. The increase in our backlog was primarily attributable to the ENSCO 8502 drilling contract entered into in September 2007.

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

MARKET RISK

       We have net assets and liabilities denominated in numerous foreign currencies and use various methods to manage our exposure to foreign currency exchange risk. We predominantly structure our 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 derivative instruments, 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 also utilize derivative instruments to hedge forecasted foreign currency denominated transactions. At September 30, 2007, we had contracts outstanding to exchange an aggregate $239.2 million U.S. dollars for various foreign currencies, all of which mature during the next twelve months. If we were to incur a hypothetical 10% adverse change in foreign currency exchange rates, the net unrealized loss associated with our foreign currency denominated assets and liabilities and related foreign currency exchange contracts as of September 30, 2007 would approximate $16.2 million.

       We utilize derivative instruments and undertake foreign currency hedging activities in accordance with our established policies for the management of market risk. We do not enter into derivative instruments for trading or other speculative purposes. We believe that our use of derivative instruments and related hedging activities do not expose us to any material interest rate risk, foreign currency exchange rate risk, commodity price risk, credit risk or any other material market rate or price risk.

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CRITICAL ACCOUNTING POLICIES AND ESTIMATES

       The preparation of our financial statements and related disclosures in conformity with U.S. generally accepted accounting principles requires our management to make estimates, judgments and assumptions that affect the amounts reported in the 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, 2006 included in our Annual Report on Form 10-K filed with the SEC. These policies, along with our underlying assumptions and judgments made in their application, have a significant impact on our consolidated financial statements. We identify our most 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 our management regarding estimates in matters that are inherently uncertain. Our most critical accounting policies are those related to property and equipment, impairment of long-lived assets and goodwill, and income taxes.

    Property and Equipment

       At September 30, 2007, the carrying value of our property and equipment totaled $3.2 billion, which represents 67% of total assets. This carrying value reflects the application of our property and equipment accounting policies, which incorporate our management's estimates, assumptions and judgments 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 judgment and assumptions by our 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 assumptions and judgments used by our management in determining the estimated 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, assumptions and judgments 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 concerning 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 our Annual Report on Form 10-K for the year ended December 31, 2006.

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    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 is 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 demand comes back into balance with supply. Impairment situations may arise with respect to specific individual rigs, groups of rigs, such as a specific type of drilling rig, or rigs in a certain geographic location. Our rigs are mobile and may generally be moved from markets with excess supply, if economically feasible. Our jackup rigs and semisubmersible rigs are suited for, and accessible to, broad and numerous markets throughout the world. However, there are fewer economically feasible markets available to our barge rig.

       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 the fair value of those units as of the testing date. 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 sale. Based on our goodwill impairment analysis performed as of December 31, 2006, there was no impairment of goodwill.

       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, and are based on our management's assumptions and judgments regarding future industry conditions and operations, as well as our management's estimates of future expected utilization, contract rates, expense levels and capital requirements of our drilling rigs. The estimates, assumptions and judgments used by our management in the application of our asset impairment policies reflect both historical experience and an assessment of current operational, industry, economic and political environments. The use of different estimates, assumptions, judgments and expectations regarding future industry conditions and operations would likely result in materially different carrying values of assets and operating results.

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    Income Taxes

       We conduct operations and earn income in numerous international countries and are subject to the laws of tax jurisdictions within those countries, as well as U.S. federal and state tax laws. At September 30, 2007, we had a $343.2 million net deferred income tax liability, a $57.3 million liability for income taxes currently payable and a $12.5 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 in accordance with Statement of Financial Accounting Standards No. 109, "Accounting for Income Taxes" ("SFAS 109"), and are based on our management's assumptions and estimates regarding future operating results and levels of taxable income, as well as our management's judgments regarding the interpretation of the provisions of SFAS 109. Carryforwards and tax credits are assessed for realization as a reduction of future taxable income by using a more-likely-than-not determination. A U.S. deferred tax liability has not been recognized for undistributed earnings of our non-U.S. subsidiaries because it is not practicable to estimate. Should we elect to make a distribution of these earnings, or be deemed to have made a distribution of them through application of various provisions of the Internal Revenue Code, we may be subject to additional U.S. income taxes.

        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 assumptions and judgments regarding the use of tax planning strategies in various taxing jurisdictions. The use of different estimates, assumptions and judgments in connection with accounting for income taxes, especially those involving tax planning strategies, may result in materially different carrying values of income tax assets and liabilities and operating results.

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       We operate in many international 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 frequently finalized through a negotiation process. While we historically have not 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 assets and liabilities to increase, including the following:
 

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NEW ACCOUNTING PRONOUNCEMENTS

       In February 2007, the FASB issued SFAS No. 159, "The Fair Value Option for Financial Assets and Financial Liabilities - Including an amendment of FASB Statement No. 115" ("SFAS 159"). SFAS 159 permits entities to choose to measure certain financial assets and liabilities and other eligible items at fair value, which are not otherwise currently required to be measured at fair value. Under SFAS 159, the decision to measure items at fair value is made at specified election dates on an irrevocable instrument-by-instrument basis. Entities electing the fair value option would be required to recognize changes in fair value in earnings and to expense upfront cost and fees associated with the item for which the fair value option is elected. Entities may elect the fair value option provided for in this standard and adopt SFAS 159 on January 1, 2008. We do not expect this statement to have a material effect on our consolidated financial position, operating results or cash flows.

       In September 2006, the FASB issued SFAS No. 157, "Fair Value Measurements" ("SFAS 157"). SFAS 157 defines fair value, provides a framework for measuring fair value in accordance with U.S. generally accepted accounting principles, and expands the disclosures required for fair value measurements. SFAS 157 applies to other accounting pronouncements that require fair value measurements; it does not require any new fair value measurements. This statement is effective for financial statements issued for fiscal years beginning after November 15, 2007. We do not expect this statement to have a material effect on our consolidated financial position, operating results or cash flows.

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 Exchange Act of 1934 (the "Exchange Act"), are effective.

       During the fiscal quarter ended September 30, 2007, 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.

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PART II - OTHER INFORMATION

Item 1.   Legal Proceedings

       A portion of the ENSCO 29 platform drilling rig was lost over the side of a customer's platform during Hurricane Katrina in the third quarter of 2005. Although beneficial ownership of ENSCO 29 was subsequently transferred to our insurance underwriters when the rig was determined to be a constructive total loss, management believes we may be contractually required to remove the ENSCO 29 wreckage and debris from the seabed and currently estimates that 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 coverage for wreckage and debris removal costs in excess of the $3.8 million coverage provided under the property insurance policies.

       Our liability insurance underwriters have issued reservation of rights letters raising issues regarding the applicability of coverage for the potential ENSCO 29 wreckage and debris removal costs. During August 2007, we commenced litigation against the liability underwriters alleging breach of contract, wrongful denial, bad faith and other claims which seek a declaration that the removal of wreckage and debris is covered under our liability insurance, damages, attorneys' fees and other remedies. While we believe it is likely that any ENSCO 29 wreckage and debris removal costs incurred will be fully covered by insurance, a $1.2 million provision, representing the portion of the $5.0 million low range of the estimated removal cost we believe is subject to liability insurance coverage, was recognized during the third quarter of 2006.

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

       In compliance with the Mississippi Rules of Civil Procedure, the individual claimants in the original multi-party lawsuits whose claims were not dismissed were ordered to file either new or amended single plaintiff complaints naming the specific defendant(s) against whom they intended to pursue claims. As a result, out of more than 600 initial multi-party claims, we have been named as a defendant by 62 individual plaintiffs. Of these claims, 60 claims or lawsuits are pending in Mississippi state courts and two are pending in the United States District Court as a result of their removal from state court.

       We intend to vigorously defend against these claims and have filed responsive pleadings preserving all defenses and challenges to jurisdiction and venue. However, inasmuch as discovery is in the very early stages and available information regarding the nature of these claims is limited, we cannot reasonably determine if the claimants have valid claims under the Jones Act or estimate a range of potential liability exposure, if any. At present, none of the pending Mississippi asbestos lawsuits against us have been set for trial. Although we do not expect the final disposition of these 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.

       In addition to the foregoing, we and our subsidiaries are named defendants in certain other lawsuits incidental to our business and are involved from time to time as parties to governmental proceedings, including matters related to taxation, all arising in the ordinary course of business. Although the outcome of lawsuits or other proceedings involving us and our subsidiaries 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, management does not expect these matters to have a material effect on our financial position, operating results or cash flows.

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Item 1A.   Risk Factors

       There are numerous factors that affect our business and the results of our operations, many of which are beyond our control. In addition to the other 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, 2006, which contain descriptions of significant factors that might cause the actual results of operations in future periods to differ materially from those currently expected or desired. The risks described in our Annual Report on Form 10-K for the year ended December 31, 2006, are not the only risks facing our Company. Additional risks and uncertainties not currently known to us or that we currently deem immaterial also may materially adversely affect our business, financial condition and/or operating results.

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

       Following is a summary of our repurchases of our common stock during the three month period ended September 30, 2007:

       In March 2006, our Board of Directors authorized an initial stock repurchase program for the repurchase of up to $500.0 million of our outstanding common stock. Under this program we repurchased approximately 1.1 million shares of our common stock at a cost of $67.6 million (an average cost of $62.10 per share), during the three-month period ended September 30, 2007. We completed the initial stock repurchase program in August 2007 after purchasing an aggregate 9.5 million shares at an average cost of $52.38 per share.

       In August 2007, our Board of Directors authorized the repurchase of an additional $500.0 million of our outstanding common stock. Under the supplemental authorization we repurchased approximately 1.4 million shares of our common stock at a cost of $77.5 million (an average cost of $54.42 per share), during the three-month period ended September 30, 2007.

       Additionally, we repurchased 3,743 shares at an average cost of $59.38 per share from employees in connection with the settlement of tax withholding obligations arising from the vesting of share awards during the three-month period ended September 30, 2007.

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Item 6.   Exhibits

     Exhibit No.

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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.

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