10-K 1 form10k2007.htm FORM 10-K 2007 10-K

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

2007 FORM 10-K

(Mark One)

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2007

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

DELAWARE
(State or other jurisdiction of
incorporation or organization)

500 North Akard Street
Suite 4300
Dallas, Texas
(Address of principal executive offices)

76-0232579
(I.R.S. Employer
Identification No.)

75201-3331
(Zip Code)

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

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

Title of each class
Common Stock, par value $.10

Name of each exchange on which registered
New York Stock Exchange

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

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

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

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

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

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

Large accelerated filer ý Accelerated filer o

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

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

The aggregate market value of the common stock (based upon the closing price on the New York Stock Exchange on June 29, 2007, of $61.01) of ENSCO International Incorporated held by nonaffiliates of the registrant at that date was approximately $6,978,598,000.

As of February 25, 2008, there were 143,931,358 shares of the registrant's common stock issued and outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Company's Proxy Statement for the 2008 Annual Meeting of Stockholders are incorporated by reference into Part III of this report.

PART I
	ITEM 1.	BUSINESS	3
	ITEM 1A.	RISK FACTORS	10
	ITEM 1B.	UNRESOLVED STAFF COMMENTS	19
	ITEM 2.	PROPERTIES	20
	ITEM 3.	LEGAL PROCEEDINGS	22
	ITEM 4.	SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS	23

PART II
	ITEM 5.	MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES	24
	ITEM 6.	SELECTED FINANCIAL DATA	26
	ITEM 7.	MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	27
	ITEM 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	44
	ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	45
	ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	77
	ITEM 9A.	CONTROLS AND PROCEDURES	77
	ITEM 9B.	OTHER INFORMATION	77

PART III
	ITEM 10.	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE	78
	ITEM 11.	EXECUTIVE COMPENSATION	79
	ITEM 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS	79
	ITEM 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE	80
	ITEM 14.	PRINCIPAL ACCOUNTING FEES AND SERVICES	80

PART IV
	ITEM 15.	EXHIBITS, FINANCIAL STATEMENT SCHEDULES	81

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 import. The forward-looking statements include statements regarding:

	•	future operations, industry trends or conditions and the business environment,
	•	future levels of, or trends in, day rates, utilization, revenues, operating expenses, contract backlog, capital expenditures, insurance, financing and funding,
	•	the likely outcome of legal proceedings, investigations or claims,
	•	future construction (including construction in progress and completion thereof), enhancement, upgrade or repair of rigs,
	•	future mobilization, relocation or other movement of rigs, and
	•	future availability or suitability of rigs.

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" and "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" in this Form 10-K.

PART I

Item 1. Business

General

ENSCO International Incorporated is an international offshore contract drilling company. As of February 15, 2008, our offshore rig fleet included 44 jackup rigs, one ultra-deepwater semisubmersible rig and one barge rig. Additionally, we have four ultra-deepwater semisubmersible rigs under construction.

We are one of the leading providers of offshore contract drilling services to the international oil and gas industry. Our operations are concentrated in the geographic regions of Asia Pacific (which includes Asia, the Middle East, Australia, and New Zealand), Europe/Africa, and North and South America. In this report, the terms "ENSCO," "Company," "we," "us" and "our" mean ENSCO International Incorporated and all of its subsidiaries included in our consolidated financial statements.

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

We have assembled one of the largest and most capable offshore drilling rig fleets in the world. We have grown our fleet through corporate acquisitions, rig acquisitions and new rig construction. We acquired a total of 32 jackup rigs through acquisitions of Penrod Holding Corporation in 1993, Dual Drilling Company in 1996 and Chiles Offshore Inc. in 2002. From 1994 to 1999, we acquired five additional jackup rigs and built seven barge rigs (only one of which remains in our fleet). In 2000, we completed construction of ENSCO 101, a harsh environment jackup rig, and ENSCO 7500, a dynamically positioned ultra-deepwater semisubmersible rig capable of drilling in water depths of up to 8,000 feet.

During 2004 and 2005, we purchased a harsh environment jackup rig, ENSCO 102, and an ultra-high specification jackup rig, ENSCO 106. Although both rigs were constructed through joint ventures with Keppel FELS Limited ("KFELS"), a major international shipyard, we subsequently acquired full ownership of these rigs. In January 2006 and March 2007, we completed construction of ENSCO 107 and ENSCO 108, both of which are ultra-high specification jackup rigs.

We also have contracted KFELS to construct four ultra-deepwater semisubmersible rigs (the "ENSCO 8500 Series®"). In 2005, we entered into the ENSCO 8500 construction agreement with delivery anticipated in the third quarter of 2008. In 2006, we entered into agreements to construct ENSCO 8501 and ENSCO 8502, with deliveries expected during the first and fourth quarters of 2009, respectively. In June 2007, we entered into the ENSCO 8503 construction agreement with delivery anticipated in the third quarter of 2010. The ENSCO 8500 Series® ultra-deepwater semisubmersibles are based on our proprietary design and are enhanced versions of the ENSCO 7500 capable of drilling in up to 8,500 feet of water. The ENSCO 8500, ENSCO 8501 and ENSCO 8502 are subject to long-term drilling contracts of four years, three and one half years and two years, respectively.

Our business strategy has been to focus on jackup rig and ultra-deepwater semisubmersible rig operations and we have de-emphasized other operations and assets considered to be non-core or that do not meet our standards for financial performance. Accordingly, we sold our marine transportation fleet, two platform rigs and two barge rigs in 2003. We sold one jackup rig and two platform rigs to KFELS in 2004 in connection with the execution of the ENSCO 107 construction agreement. We also disposed of five barge rigs and one platform rig in 2005 and our one remaining platform rig in 2006.

We were formed as a Texas corporation in 1975 and were reincorporated in Delaware in 1987. Our principal office is located at 500 North Akard Street, Suite 4300, Dallas, Texas, 75201-3331, and our telephone number is (214) 397-3000. Our website is www.enscous.com.

Contract Drilling Operations

Our operations consist of one reportable segment: contract drilling services. We engage in the drilling of offshore oil and gas wells in domestic and international markets by providing our drilling rigs and crews under contracts with major international, government-owned and independent oil and gas companies.

As of February 15, 2008, we own and operate 44 jackup rigs, one ultra-deepwater semisubmersible rig and one barge rig. Of the 44 jackup rigs, 19 are located in the Asia Pacific region, 10 are located in the Europe/Africa region and 15 are located in the North and South America region. Our ultra-deepwater semisubmersible rig is located in the Gulf of Mexico and our barge rig is located in Indonesia. In addition to our 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 third 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 drilling contracts in the Gulf of Mexico and we are currently marketing ENSCO 8503 and anticipate that it will be contracted in advance of delivery.

Our drilling rigs are used to drill and complete oil and gas wells. Demand for our drilling services is based upon many factors which are beyond our control, including:

	•	market price of oil and gas and the stability thereof,
	•	production levels and related activities of the Organization of Petroleum Exporting Countries ("OPEC") and other oil and gas producers,
	•	global oil supply and demand,
	•	regional natural gas supply and demand,
	•	worldwide expenditures for offshore oil and gas drilling,
	•	long-term effect of worldwide energy conservation measures,
	•	the development and use of alternatives to hydrocarbon-based energy sources, and
	•	worldwide economic activity.

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

	•	contract duration extending over a specific period of time or a period necessary to drill one or more wells,
	•	term extension options in favor of our customer, generally upon advance notice to us at mutually agreed rates,
	•	provisions permitting early termination of the contract (i) if the rig is lost or destroyed or (ii) by the customer if operations are suspended for a specified period of time due to breakdown of major rig equipment, unsatisfactory performance, "force majeure" events beyond our control and the control of the customer, or other specified conditions,
	•	some of our drilling contracts permit early termination of the contract by the customer without cause, generally exercisable upon advance notice to us and in some cases without making an early termination payment to us,
	•	payment of compensation to us (generally in U.S. dollars although some contracts require a part of the compensation to be paid in local currency) on a "day work" basis such that we receive a fixed amount for each day ("day rate") that the drilling unit is operating under contract (lower rates or no compensation generally apply during periods of equipment breakdown and repair or in the event operations are suspended or interrupted by other specified conditions, some of which may be beyond our control),
	•	payment by us of the operating expenses of the drilling unit, including crew labor costs and the cost of incidental rig supplies, and
	•	provisions in many of our contracts allowing us to recover certain labor and other operating cost increases from our customers through day rate adjustment (or otherwise).

Financial information regarding our operating segment and geographic regions is presented in Note 11 to the Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data." Additional financial information regarding our operating segment is presented in "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations."

Backlog Information

Our contract drilling backlog reflects firm commitments, typically represented by signed drilling contracts, and 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.

Our current and historic backlog of business as of February 1, 2008 and 2007 were $3,870.8 million and $3,177.4 million, respectively. Our jackup backlog increased $388.6 million primarily due to increased day rates and contract durations for our international rigs, while our semisubmersible backlog increased by $304.1 million primarily due to the ENSCO 8502 contract entered into in September 2007. The table below provides a detail of our annual backlog by geographic region and rig type as of February 1, 2008 and includes $1,162.3 million of backlog associated with three of our semisubmersible rigs under construction (in millions):

									2012 and
	2008		2009		2010		2011		Beyond		Total

Jackup rigs
Asia Pacific	$ 914	.1	$242	.4	$ 51	.7	$	--	$	--	$1,208	.2
Europe/Africa	631	.2	142	.8	104	.0	95	.5		--	973	.5
North and South America	157	.0	59	.3	27	.8		--		--	244	.1

Total jackup rigs	1,702	.3	444	.5	183	.5	95	.5		--	2,425	.8
Semisubmersible rigs	129	.2	409	.3	407	.1	277	.7	215	.1	1,438	.4
Barge rig	6	.6		--		--		--		--	6	.6

Total	$1,838	.1	$853	.8	$590	.6	$373	.2	$215	.1	$3,870	.8

Major Customers

Competition

The offshore contract drilling industry is highly competitive with numerous industry participants. Drilling contracts are, for the most part, awarded on a competitive bid basis. Price competition is often the primary factor in determining which contractor is awarded a contract, although quality of service, operational and safety performance, equipment suitability and availability, location of equipment, reputation and technical expertise are also factors. We have numerous competitors in the offshore contract drilling industry, several of which are larger and have greater resources than us including a company which resulted from the merger of two of our largest competitors in late 2007.

Governmental Regulation

Our operations are affected by political developments and by local, state, federal and international laws and regulations that relate directly to the oil and gas industry. Accordingly, we will be directly affected by the approval and adoption of laws and regulations curtailing exploration and development drilling for oil and natural gas for economic, environmental, safety or other policy reasons. It is also possible that these laws and regulations could adversely affect our operations in the future by significantly increasing our operating costs.

Environmental Matters

Our operations are subject to local, state, federal and international 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. 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 the occurrence 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, events in recent years have heightened environmental concerns about the oil and gas industry.

The United States Oil Pollution Act of 1990 ("OPA 90"), as amended, and other federal statutes applicable to us and our operations, as well as similar state statutes in Texas, Louisiana and other coastal states, 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, both federal and state, impose a variety of obligations on us related to the prevention of oil spills 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 and a variety of fines, penalties and damages. A failure to comply with these statutes, 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.

From time to time, legislative proposals have been introduced that would materially limit or prohibit offshore drilling in certain areas. To date, no proposals which would materially limit or prohibit offshore drilling in our principal areas of operation have been enacted into law. However, we are adversely affected by moratoria on drilling in certain areas of the Gulf of Mexico. If new laws are enacted or if other environmental related or other governmental action is taken that restrict or prohibit offshore drilling in our principal areas of operation or impose environmental protection requirements that materially increase the cost of offshore drilling, exploration, development or production of oil and gas, we could be materially adversely affected.

International Operations

A majority of our contract drilling operations are conducted in countries outside the U.S. Revenues from international operations as a percentage of our total revenues were 75% and 61% in 2007 and 2006, respectively. Our international operations and our international shipyard rig construction and enhancement projects are subject to political, economic and other uncertainties, such as the risks of:

	•	terrorist acts, war and civil disturbances,
	•	expropriation, nationalization, deprivation or confiscation of our equipment,
	•	expropriation or nationalization of a customer's property or drilling rights,
	•	repudiation or nationalization of contracts,
	•	assaults on property or personnel,
	•	exchange restrictions,
	•	currency fluctuations,
	•	changes in the manner or rate of taxation,
	•	limitations on the ability to repatriate income or capital to the United States,
	•	changing local and international political conditions, and
	•	international and domestic monetary policies.

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

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

Our international operations also face the risk of fluctuating currency values, which can impact our revenues and operating costs. In addition, some of the countries in which we operate have occasionally enacted exchange controls. Historically, these risks have been limited by invoicing and receiving payment in U.S. dollars or freely convertible international currency and, to the extent possible, by limiting acceptance of foreign currency to amounts which approximate our expenditure requirements in such currencies. However, there is no assurance that our contracts will contain such terms in the future. We also use foreign currency purchase options or futures contracts to reduce our exposure to foreign currency risk.

We currently conduct contract drilling operations in certain countries that have experienced substantial fluctuations in the value of their currency compared to the U.S. dollar. Our drilling contracts generally stipulate payment wholly or substantially in U.S. dollars, which reduces the impact currency fluctuations have on our earnings and cash flows. However, there is no assurance that our contracts will contain such payment terms in the future.

A substantial portion of the costs and expenditures incurred by our international operations are settled in the local currencies of the countries in which we operate, exposing us to risks associated with fluctuation in the value of these currencies relative to the U.S. dollar. We use foreign currency purchase options or futures contracts to reduce this exposure, however, the relative weakening in the value of the U.S. dollar in relation to the local currencies in these countries may increase our costs and expenditures.

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

Executive Officers

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

Name	Age	Position

Daniel W. Rabun	53	Chairman, President and Chief Executive Officer

William S. Chadwick, Jr.	60	Executive Vice President - Chief Operating Officer

Jay W. Swent	57	Senior Vice President - Chief Financial Officer

Phillip J. Saile	55	Senior Vice President - Operations

Richard A. LeBlanc	57	Vice President - Investor Relations

H. E. Malone, Jr.	64	Vice President - Finance

Paul Mars	49	President - ENSCO Offshore International Company

Charles A. Mills	58	Vice President - Human Resources and Security

Cary A. Moomjian, Jr.	60	Vice President, General Counsel and Secretary

David A. Armour	50	Controller

Ramon Yi	54	Treasurer

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

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

William S. Chadwick, Jr. joined ENSCO in June 1987 and was elected to his present position of Executive Vice President and Chief Operating Officer effective January 1, 2006. Prior to his current position, Mr. Chadwick served as Senior Vice President - Operations, Senior Vice President, Member - Office of the President and Chief Operating Officer and as Vice President - Administration and Secretary. Mr. Chadwick holds a Bachelor of Science Degree in Economics from the Wharton School of the University of Pennsylvania.

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

Phillip J. Saile joined ENSCO in August 1987 and was elected Senior Vice President - Operations in January 2008. In this position he serves as the Senior Executive having oversight responsibility for the North and South America Business Unit and the Deepwater Business Unit. Prior to assuming his current position, Mr. Saile served as Senior Vice President - Business Development and SHE, President and Chief Operating Officer of ENSCO Offshore International Company, a subsidiary of the company, Senior Vice President, Member - Office of the President and Chief Operating Officer and as Vice President - Operations. Mr. Saile holds a Bachelor of Business Administration Degree from the University of Mississippi.

Richard A. LeBlanc joined ENSCO in July 1989 as Manager of Finance. He assumed responsibilities for the investor relations function in March 1993. Prior to his current position, he was elected Treasurer in May 1995 and Vice President - Corporate Finance, Investor Relations and Treasurer in May 2002. Mr. LeBlanc holds a Bachelor of Science Degree in Finance and a Masters of Business Administration Degree, from Louisiana State University.

H. E. Malone, Jr. joined ENSCO in August 1987 and was elected Vice President - Finance effective May 2004. Prior to his current position, Mr. Malone served as Vice President - Accounting, Tax and Information Systems, Vice President - Finance and Vice President - Controller. Mr. Malone holds Bachelor of Business Administration Degrees from The University of Texas at Austin and Southern Methodist University and a Masters of Business Administration Degree from the University of North Texas.

Paul Mars joined ENSCO in June 1998 and served as Vice President - Engineering from May 2003 until July 2005, when he was elected to his current position as President of ENSCO Offshore International Company, a subsidiary of the company. Mr. Mars previously served as General Manager for the Europe/Africa Business Unit. Prior to joining ENSCO, Mr. Mars served in various capacities as an employee of Smedvig Offshore Limited and Transworld North Sea Drilling Services Limited. Mr. Mars holds a Bachelor of Science Honors Degree in Naval Architecture from the University of Newcastle upon Tyne, England.

Charles A. Mills joined ENSCO in June 2004 as Vice President - Human Resources and Security. He has over 27 years oil and gas industry experience in human resources and managerial positions most recently from 1989 to 2002 with Hunt Oil Company where he was Senior Vice President Human Resources and Corporate Services. Prior to 1989, Mr. Mills held a number of executive and management positions with Tenneco Oil E&P and Shell Oil Company. Mr. Mills holds a Bachelor of Science Degree in Management from the University of West Florida.

Cary A. Moomjian, Jr. joined ENSCO in January 2002 and thereupon was elected Vice President, General Counsel and Secretary. Mr. Moomjian has over thirty years of experience in the oil and gas industry. From 1976 to 2001, Mr. Moomjian served in various management and executive capacities as an employee of Santa Fe International Corporation, including Vice President, General Counsel and Secretary from 1993 to 2001. Mr. Moomjian was admitted to the California Bar in 1972 and to the Texas Bar in 1994. He holds a Bachelor of Arts Degree from Occidental College and a Juris Doctorate Degree from Duke University School of Law.

David A. Armour joined ENSCO in October 1990 as Assistant Controller and was elected Controller effective January 2002. From 1981 to 1990, Mr. Armour served in various capacities as an employee of the public accounting firm Deloitte & Touche LLP, and its predecessor firm, Touche Ross & Co. Mr. Armour holds a Bachelor of Business Administration Degree from The University of Texas at Austin.

Ramon Yi joined ENSCO in August 2004 as Treasurer. Mr. Yi has over thirty years of business experience in a variety of industries, most recently as Corporate Treasurer in the manufacturing and high tech sectors, including Sunrise Medical and Fresenius Medical Care, global manufacturers of durable medical equipment, and Symbios, Inc., a manufacturer of semiconductor chips. He was also Vice President for George E. Warren Corporation and Assistant Treasurer for Northeast Petroleum Corporation, both in the petroleum trading and marketing industry. Mr. Yi holds a Bachelor of Arts Degree from Harvard University in 1975 and a Masters of Business Administration Degree in Finance and Accounting from Boston University.

Officers generally serve for a one-year term or until their successors are elected and qualified to serve. Mr. Malone is a brother-in-law of Carl F. Thorne who served as Chairman of the Board of Directors for all periods prior to May 22, 2007, and as Chief Executive Officer for all periods prior to December 31, 2006.

Employees

We employed approximately 4,100 personnel worldwide as of February 1, 2008, of which 2,800 were full-time employees. The majority of our personnel work on rig crews and are compensated on an hourly basis.

Available Information

Our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and amendments to those reports that we file or furnish to the Securities and Exchange Commission (the "SEC") in accordance with the Securities Exchange Act of 1934, as amended, are available on our website at www.enscous.com and in print without charge by contacting our Investor Relations Department at 214-397-3045, as soon as reasonably practicable after we electronically file the information with, or furnish it to, the SEC.

Item 1A. Risk Factors

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

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

The success of our business largely depends on the level of activity in offshore oil and natural gas exploration, development and production in markets worldwide. Oil and natural gas prices, and market expectations of potential changes in these prices, may significantly affect the level of drilling activity. An actual decline, or the perceived risk of a decline, in oil or natural gas prices could cause oil and gas companies to reduce their overall level of activity or spending, in which case demand for our equipment and services may decrease and revenues may be adversely affected through lower rig utilization and lower average day rates. Worldwide military, political, environmental and economic events also contribute to oil and natural gas price volatility. Numerous other factors may affect oil and natural gas prices and the level of demand for our services, including:

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

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

Financial operating results in the offshore contract drilling industry have historically been very cyclical and primarily are related to the demand for drilling rigs and the available supply of rigs.

Demand for rigs is directly related to the regional and worldwide levels of offshore exploration and development spending by oil and gas companies, which is beyond our control. Offshore exploration and development spending may fluctuate substantially from year to year and from region to region.

The supply of offshore drilling rigs is limited and new rigs require a substantial capital investment and a long period of time to construct. There are over 120 new jackup and semisubmersible rigs reported to be on order for delivery by the end of 2011. Approximately 50 of these rigs are scheduled for delivery in 2008, representing an approximate 10% increase in the total worldwide fleet of jackups and semisubmersible rigs. There are no assurances that the market in general, or a geographic region in particular, will be able to fully absorb the supply of new rigs in future periods. The increase in supply of offshore drilling rigs in 2008 and future periods could result in an oversupply of offshore drilling rigs and could cause a decline in utilization and day rates. Lower utilization and day rates in one or more of the regions in which we operate could adversely affect our revenues, utilization and profitability.

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

Future periods of decreased demand and/or excess rig supply may require us to idle rigs or to enter into lower rate contracts or contracts with less favorable terms. There can be no assurance that the current demand for drilling rigs will not decline in future periods, nor can there be any assurance concerning any adverse effect resulting from such decrease in activity or an increase in rig supply.

RIG CONSTRUCTION, UPGRADE AND ENHANCEMENT PROJECTS ARE SUBJECT TO RISKS INCLUDING DELAYS AND COST OVERRUNS WHICH COULD HAVE A MATERIAL ADVERSE IMPACT ON OUR OPERATING RESULTS. THE RISKS ARE CONCENTRATED BECAUSE OUR FOUR SEMISUBMERSIBLE RIGS CURRENTLY UNDER CONSTRUCTION ARE AT ONE SHIPYARD IN SINGAPORE.

There are over 120 new jackup and semisubmersible rigs reported to be on order for construction with delivery dates through 2011. As a result, shipyards and third party equipment vendors are under significant resource constraints to meet delivery obligations. Such constraints may lead to substantial delivery and commissioning delays of rigs under construction and/or equipment failures and/or quality deficiencies. Furthermore, new drilling rigs may face start-up or other operational complications following completion of construction work, or other unexpected difficulties or equipment failures that could result in significant downtime at reduced or zero day rates or the cancellation or termination of drilling contracts.

We have four ultra-deepwater semisubmersible rigs under construction at a shipyard in Singapore. In addition, we may construct additional rigs and continue to upgrade the capability and extend the service lives of our existing rigs. Rig construction, upgrade, life extension and repair projects are subject to the risks of delay or cost overruns inherent in any large construction project, including the following:

	•	failure of third party equipment to meet quality and/or performance standards,
	•	delays in equipment deliveries or shipyard construction,
	•	shortages of materials or skilled labor,
	•	unforeseen design or engineering problems,
	•	unanticipated actual or purported change orders,
	•	strikes, labor disputes or work stoppages,
	•	financial or operating difficulties of equipment vendors or the shipyard while constructing, upgrading, refurbishing or repairing a rig or rigs,
	•	adverse weather conditions,
	•	unanticipated cost increases,
	•	foreign currency fluctuations impacting overall cost,
	•	inability to obtain any of the requisite permits or approvals,
	•	force majeure, and
	•	additional risks inherent to shipyard projects in an international location.

Our risks are concentrated because our four ultra-deepwater semisubmersible rigs currently under construction are at one shipyard in Singapore. Although based on the existing design of ENSCO 7500, these four rigs have a common risk of unforeseen design or engineering problems. Furthermore, three of the rigs (ENSCO 8500, ENSCO 8501 and ENSCO 8502) are subject to firm, fixed day rate drilling contracts upon completion of construction and significant shipyard project cost overruns or delays could impact the projected financial results or the viability of the contracts and materially and adversely affect our financial condition and operating results. Our fourth ultra-deepwater semisubmersible rig under construction (ENSCO 8503) currently does not have a contractual commitment upon completion. If we are unable to secure a contractual commitment for the rig prior to the completion of construction, it may result in a material adverse affect on our financial condition or operating results. If we are able to secure a drilling contract prior to completion, we will be exposed to the risk of delays that could impact the projected financial results or the viability of the contract and could materially and adversely affect our financial condition and operating results.

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

We require skilled personnel to operate our drilling rigs and to provide technical services and support for our business. Competition for skilled and other labor has intensified as additional rigs are activated or are added to the worldwide fleet. There are over 120 new jackup and semisubmersible rigs reported to be on order for delivery by the end of 2011, approximately 50 of which are scheduled for delivery in 2008. These rigs will require new skilled and other personnel to operate. In periods of high utilization, such as the current period, it is more difficult and costly to recruit and retain qualified employees. Although competition for skilled and other labor has not materially affected us to date, competition for such personnel could increase our future operating expenses, with a resulting reduction in net income, or impact our ability to fully staff and operate our rigs.

We have experienced a tightening in our labor markets largely due to the loss of experienced personnel to our customers, competitors and other businesses involved in oil and gas exploration activities. In response to these market conditions, we have increased compensation and have incurred other costs to retain our workforce, including bonus and retention programs for certain personnel. We also are subject to potential further unionization of our labor force or legislative or regulatory action that may impact working conditions, paid time off, or other conditions of employment. If such labor trends continue, they could further increase our costs or limit our ability to fully staff and operate our rigs.

WE MAY SUFFER LOSSES IF OUR CUSTOMERS TERMINATE OR SEEK TO RENEGOTIATE OUR CONTRACTS OR IF OPERATIONS ARE SUSPENDED OR INTERRUPTED RESULTING IN REDUCTION OR CESSATION OF DAY RATES.

Our drilling contracts often are subject to termination without cause upon specific notice by the customer. Although contracts may require the customer to pay an early termination payment, such payment may not fully compensate for the loss of the contract and some of our contracts permit termination by the customer without an early termination payment. In periods of rapid market downturn, our customers may not honor the terms of existing contracts, may terminate contracts or may seek to renegotiate contract rates and terms to conform with depressed market conditions. Furthermore, contracts customarily specify automatic termination or termination at the option of the customer in the event of a total loss of the drilling rig and often include provisions addressing termination rights or reduction or cessation of day rates if operations are suspended or interrupted for extended periods by reason of excessive downtime for breakdowns or repairs, force majeure or other specified conditions, some of which may be beyond our control. Our operating results may be adversely affected by early termination of contracts, contract renegotiations or cessation of day rates while operations are suspended.

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

We provide our services to major international, government-owned and independent oil and gas companies. The number of customers we serve has decreased in recent years as a result of mergers among oil companies. Although no customer represented more than 10% of revenues in 2007, our five largest customers accounted for approximately 35% of consolidated revenues in the aggregate. Our operating results may be materially adversely affected if any major customer terminates its contracts with us, fails to renew its existing contracts with us, or declines to award new contracts to us.

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

We currently have 11 jackup rigs contracted with national oil companies. The terms of these contracts may expose us to greater risks than we normally assume, such as exposure to greater environmental liability or the risk that the contract may be terminated by our customer without cause on short-term notice, contractually or by governmental action, subject to certain conditions which may not provide us an early termination payment. While we believe that the financial terms of these contracts and our operating safeguards in place mitigate these risks, we can provide no assurance that the increased risk exposure will not have a negative impact on our future operations or that we will not increase the number of rigs contracted to national oil companies with commensurate additional contractual risks.

WE HAVE SIGNIFICANT LEVELS OF SELF-INSURANCE FOR GULF OF MEXICO HURRICANE RELATED WINDSTORM DAMAGE COVERAGE WHICH EXPOSES US TO ADDITIONAL RISK AND CAUSES US TO ALTER OUR OPERATING PROCEDURES DURING HURRICANE SEASON WHICH COULD ADVERSELY AFFECT OUR BUSINESS.

Certain areas in and near the Gulf of Mexico experience hurricanes and other extreme weather conditions on a relatively frequent basis. Some of our drilling rigs in the Gulf Coast Region are located in areas that could cause them to be susceptible to damage and/or total loss by these storms and we have a larger concentration of rigs in the Gulf Coast Region than most of our competitors. Damage caused by high winds and turbulent seas could potentially result in rig loss or damage or could cause termination of drilling contracts on lost or severely damaged rigs or curtailment of operations on damaged drilling rigs with reduced or suspended day rates for significant periods of time until the damage can be repaired. Moreover, even if our drilling rigs are not directly damaged by such storms, we may experience disruptions in our operations due to damage to our customers' platforms and other related facilities in the area. To date, our drilling operations in the Gulf of Mexico have not been materially impacted by hurricanes, although we sustained the total loss of one jackup rig in 2004 and one platform rig in 2005 by reason of hurricane damage. We currently have 13 jackup rigs and one ultra-deepwater semisubmersible rig in the Gulf of Mexico.

Insurance companies incurred substantial losses in the offshore drilling, exploration and production industries as a consequence of hurricanes that occurred in the Gulf of Mexico during 2004 and 2005. Accordingly, insurance companies have substantially reduced the levels of insurance coverage available for losses arising from Gulf of Mexico hurricane related windstorm damage and have dramatically increased the cost of such coverage. Upon renewal of our annual insurance policies effective July 1, 2007, we obtained $127.5 million of annual aggregate coverage for jackup rig hull and machinery losses arising from Gulf of Mexico hurricane related windstorm damage with a $50.0 million per occurrence deductible (these limits do not apply to our ultra-deepwater semisubmersible rig as long as the rig takes action to evade the storm by moving off location according to established procedures). This amount of coverage is significantly less than our historical coverage.

Our limited insurance coverage exposes us to a significant level of risk due to rig damage or loss related to severe weather conditions caused by Gulf of Mexico hurricanes or windstorms and could have a material adverse effect on our financial position, operating results and cash flows. Our current liability insurance policies maintain coverage for Gulf of Mexico hurricane related windstorm exposures, including removal of wreckage and debris, and have self retained interest (generally equivalent to a deductible) of $10.0 million per occurrence.

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

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

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

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

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

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

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

Our contracts generally protect us from certain losses sustained as a result of our negligence. However, losses resulting from contracts that do not contain such protection could have a material adverse affect on our financial position, operating results and cash flows. Losses resulting from our gross negligence or willful misconduct may not be protected contractually by specific provision or by application of law, and our insurance may not provide adequate protection for such losses.

The cost of many of the types of insurance coverage maintained by us has increased significantly during recent years. In addition, insurance market conditions have resulted in retention of additional risk by us, primarily through higher insurance deductibles or self-insured retentions. Very few insurance underwriters offer certain types of insurance coverage we maintain, and there can be no assurance that any particular type of insurance coverage will continue to be available in the future, that we will not accept retention of additional risk through higher insurance deductibles, self-insurance risk retention or otherwise, or that we will be able to purchase our desired level of insurance coverage at commercially feasible rates.

OUR INTERNATIONAL OPERATIONS INVOLVE ADDITIONAL RISKS NOT ASSOCIATED WITH DOMESTIC OPERATIONS.

A significant portion of our contract drilling operations are conducted in countries outside the U.S. Revenues from international operations as a percentage of our total revenues were 75% and 61% in 2007 and 2006, respectively. Our international operations and our international shipyard rig construction and enhancement projects are subject to political, economic and other uncertainties, including:

	•	terrorist acts, war and civil disturbances,
	•	expropriation, nationalization, deprivation or confiscation of our equipment,
	•	expropriation or nationalization of a customer's property or drilling rights,
	•	repudiation or nationalization of contracts,
	•	assaults on property or personnel,
	•	exchange restrictions,
	•	currency fluctuations,
	•	changes in the manner or rate of taxation,
	•	limitations on the ability to repatriate income or capital to the United States,
	•	changing local and international political conditions, and
	•	international and domestic monetary policies.

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

Our operations are subject to local, state, federal and foreign 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. 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 the occurrence 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, there can be no assurance that such laws and regulations or accidents will not expose us to material liability in the future.

Events in recent years have heightened environmental concerns about the oil and gas industry generally. From time to time, legislative proposals have been introduced that would materially limit or prohibit offshore drilling in certain areas. To date, no proposals which would materially limit or prohibit offshore drilling in our principal areas of operation have been enacted into law. If laws are enacted or other governmental action is taken that restrict or prohibit offshore drilling in our principal areas of operation or impose environmental protection requirements that materially increase the cost of offshore drilling, exploration, development or production of oil and gas, we could be materially adversely affected.

LAWS AND GOVERNMENTAL REGULATIONS MAY ADD TO COSTS OR LIMIT OUR DRILLING ACTIVITY.

Our operations are affected by political developments and by local, state, federal and foreign laws and regulations that relate directly to the oil and gas industry. The offshore contract drilling industry is dependent on demand for services from the oil and natural gas exploration industry. Accordingly, we will be directly affected by the approval and adoption of laws and regulations limiting or curtailing exploration and development drilling for oil and natural gas for economic, environmental, safety and other policy reasons. Furthermore, we may be required to make significant capital expenditures or incur substantial additional costs to comply with governmental laws and regulations. It is also possible that laws and regulations could adversely affect our operations by limiting drilling opportunities or significantly increasing our operating costs.

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

The offshore contract drilling industry is generally divided into two broad markets: deepwater and shallow water drilling. These broad markets are generally divided into smaller sub-markets based upon various factors, including type of drilling rig. The primary types of drilling rigs include jackup rigs, semisubmersible rigs, drill ships, platform rigs, barge rigs and submersible rigs. While these market segments are affected by common characteristics, they each have separate market conditions that affect the demand and rates for drilling equipment in that segment. We currently have 44 jackup rigs, one ultra-deepwater semisubmersible rig and one barge rig. Additionally, we have four ultra-deepwater semisubmersible rigs under construction.

Our drilling fleet is heavily concentrated in the premium jackup rig market. If the market for premium jackup rigs should decline relative to the markets for other drilling rig types, our operating results could be more adversely affected relative to our competitors with drilling fleets that are not concentrated in premium jackup rigs.

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

Our future effective tax rates could be adversely affected by changes in tax laws, both domestically and internationally. They could also be adversely affected by lower than anticipated earnings in countries where we have lower statutory rates and higher than anticipated earnings in countries where we have higher statutory rates, by changes in the valuation of our deferred tax assets and liabilities, or by changes in tax treaties, regulations, accounting principles or interpretations thereof in one or more countries in which we operate. In addition, we are subject to the continuous examination of our income tax returns by the Internal Revenue Service and other tax authorities. We regularly assess the likelihood of adverse outcomes resulting from these examinations to determine the adequacy of our provision for taxes. There can be no assurance that such examinations will not have an adverse effect on our operating results and financial condition.

TERRORIST ATTACKS AND MILITARY ACTION COULD RESULT IN A MATERIAL ADVERSE EFFECT ON OUR BUSINESS.

Terrorist acts or acts of war may cause damage to or disruption of our United States or international operations, employees, property and equipment, or customers, suppliers and subcontractors, which could significantly impact our financial position, operating results and cash flows. Terrorist acts create many economic and political uncertainties and the potential for future terrorist acts, the national and international responses to terrorism and other acts of war or hostility, could create many economic and political uncertainties, including an impact upon oil and gas drilling, exploration and development. This could adversely affect our business in ways that cannot readily be determined.

LEGAL PROCEEDINGS COULD AFFECT US ADVERSELY.

We are involved in various litigation, claims, disputes and regulatory proceedings that arise in the ordinary course of business, many of which are uninsured and relate to commercial, employment or regulatory activities. We also are conducting an internal investigation relating to compliance with the U.S. Foreign Corrupt Practices Act which focuses on activities related to our former operations in Nigeria and the associated accounting entries and internal controls.

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

Item 1B. Unresolved Staff Comments

None.

Item 2. Properties

Contract Drilling Fleet

The table below provides certain information about the rigs in our drilling fleet as of February 15, 2008:

JACKUP RIGS

Rig Name	Year Built/ Rebuilt	Rig Make	Maximum Water Depth/ Drilling Depth	Current Location	Current Customer
Asia Pacific
ENSCO 50	1983/1998	F&G L-780 MOD II-C	300'/25,000'	India	British Gas
ENSCO 51	1981/2002	F&G L-780 MOD II-C	300'/25,000'	Thailand	Pearl
ENSCO 52	1983/1997	F&G L-780 MOD II-C	300'/25,000'	Malaysia	Petronas Carigali
ENSCO 53	1982/1998	F&G L-780 MOD II-C	300'/25,000'	India	British Gas
ENSCO 54	1982/1997	F&G L-780 MOD II-C	300'/25,000'	Qatar	Ras Gas
ENSCO 56	1982/1997	F&G L-780 MOD II-C	300'/25,000'	New Zealand	Shell
ENSCO 57	1982/2003	F&G L-780 MOD II-C	300'/25,000'	Malaysia	Petronas Carigali
ENSCO 67	1976/2005	MLT 84-CE	400'/30,000'	Indonesia	ConocoPhillips
ENSCO 76	2000	MLT Super 116-C	350'/30,000'	Saudi Arabia	Saudi Aramco
ENSCO 84	1981/2005	MLT 82 SD-C	250'/25,000'	Qatar	Maersk
ENSCO 88	1982/2004	MLT 82 SD-C	250'/25,000'	Qatar	Ras Gas
ENSCO 94	1981/2001	Hitachi 250-C	250'/25,000'	Qatar	Ras Gas
ENSCO 95	1981/2005	Hitachi 250-C	250'/25,000'	Saudi Arabia	Saudi Aramco
ENSCO 96	1982/1997	Hitachi 250-C	250'/25,000'	Saudi Arabia	Saudi Aramco
ENSCO 97	1980/1997	MLT 82 SD-C	250'/25,000'	Saudi Arabia	Saudi Aramco
ENSCO 104	2002	KFELS MOD V-B	400'/30,000'	Indonesia	BP
ENSCO 106	2005	KFELS MOD V-B	400'/30,000'	Australia	Apache
ENSCO 107	2006	KFELS MOD V-B	400'/30,000'	New Zealand	Origin
ENSCO 108	2007	KFELS MOD V-B	400'/30,000'	Indonesia	BP
Europe/Africa
ENSCO 70	1981/1996	Hitachi K1032N	250'/30,000'	Denmark	DONG
ENSCO 71	1982/1995	Hitachi K1032N	225'/25,000'	Denmark	Maersk
ENSCO 72	1981/1996	Hitachi K1025N	225'/25,000'	Netherlands	Total
ENSCO 80	1978/1995	MLT 116-CE	225'/30,000'	United Kingdom	AGR Peak
ENSCO 85	1981/1995	MLT 116-C	300'/25,000'	Tunisia	PA Resources
ENSCO 92	1982/1996	MLT 116-C	225'/25,000'	United Kingdom	BP
ENSCO 100	1987/2000	MLT 150-88-C	350'/30,000'	United Kingdom	AGR Peak
ENSCO 101	2000	KFELS MOD V-A	400'/30,000'	United Kingdom	Maersk
ENSCO 102	2002	KFELS MOD V-A	400'/30,000'	United Kingdom	ConocoPhillips
ENSCO 105	2002	KFELS MOD V-B	400'/30,000'	Tunisia	BG
North & South America
ENSCO 60	1981/2003	Levingston 111-C	300'/25,000'	Gulf of Mexico	LLOG
ENSCO 68	1976/2004	MLT 84-CE	400'/30,000'	Gulf of Mexico	W & T
ENSCO 69	1976/1995	MLT 84-S	400'/25,000'	Venezuela	PDVSA
ENSCO 74	1999	MLT Super 116-C	400'/30,000'	Gulf of Mexico	Apache
ENSCO 75	1999	MLT Super 116-C	400'/30,000'	Gulf of Mexico	McMoRan
ENSCO 81	1979/2003	MLT 116-C	350'/30,000'	Mexico	Pemex
ENSCO 82	1979/2003	MLT 116-C	300'/30,000'	Gulf of Mexico	Energy XXI
ENSCO 83	1979/2007	MLT 82 SD-C	250'/25,000'	Gulf of Mexico	ATP
ENSCO 86	1981/2006	MLT 82 SD-C	250'/30,000'	Gulf of Mexico	W & T
ENSCO 87	1982/2006	MLT 116-C	350'/25,000'	Gulf of Mexico	Merit
ENSCO 89	1982/2005	MLT 82 SD-C	250'/25,000'	Gulf of Mexico	Chevron
ENSCO 90	1982/2002	MLT 82 SD-C	250'/25,000'	Gulf of Mexico	Apache
ENSCO 93	1982/2008	MLT 82 SD-C	250'/25,000'	Gulf of Mexico	Shipyard
ENSCO 98	1977/2003	MLT 82 SD-C	250'/25,000'	Gulf of Mexico	Leed
ENSCO 99	1985/2005	MLT 82 SD-C	250'/30,000'	Gulf of Mexico	Bois d'Arc

ULTRA-DEEPWATER SEMISUBMERSIBLE RIGS

Rig Name	Year Built	Rig Type	Maximum Water Depth/ Drilling Depth	Current Location	Current Customer

ENSCO 7500	2000	Dynamically Positioned	8,000'/30,000'	Gulf of Mexico	Chevron
ENSCO 8500	2008	Dynamically Positioned	8,500'/35,000'	Singapore	Under construction^(*)
ENSCO 8501	2009	Dynamically Positioned	8,500'/35,000'	Singapore	Under construction^(*)
ENSCO 8502	2009	Dynamically Positioned	8,500'/35,000'	Singapore	Under construction^(*)
ENSCO 8503	2010	Dynamically Positioned	8,500'/35,000'	Singapore	Under construction^(*)

Rig Name	Year Built	Maximum Drilling Depth	Current Location	Current Customer
BARGE RIG

ENSCO I	1999	18,000'	Indonesia	Bontang

^(*)

For additional information concerning our rigs under construction, see "Cash Flow from Continuing Operations and Capital Expenditures" included in "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations." The ENSCO 8500, ENSCO 8501 and ENSCO 8502 are subject to long-term drilling contracts in the Gulf of Mexico of four years, three and one half years and two years, respectively. The ENSCO 8503 is currently being marketed for a drilling contract, both domestically and internationally.

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

Jackup rigs stand on the ocean floor with their hull and drilling equipment elevated above the water on connected leg supports. Jackup rigs are generally preferred over other rig types in water depths of 400 feet or less, primarily because jackup rigs provide a more stable drilling platform with above water blowout prevention equipment. All of our jackup rigs are of the independent leg design. All but one of our jackup rigs are equipped with cantilevers that allow the drilling equipment to extend outward from the hull over fixed platforms enabling drilling of both exploratory and development wells. The jackup rig hull supports the drilling equipment, jacking system, crew quarters, storage and loading facilities, helicopter landing pad and related equipment and supplies.

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

Barge rigs are towed to the drilling location and are held in place by anchors while drilling activities are conducted. Our barge rig has all of the crew quarters, storage facilities and related equipment mounted on the floating barge, with the drilling equipment cantilevered from the stern of the barge.

Over the life of a typical rig, several of the major components are replaced due to normal wear and tear or due to technological advancements in drilling equipment. All of our rigs are in good condition. As of February 15, 2008, we own all of the rigs in our fleet.

Other Property

We lease our executive offices in Dallas, Texas and own offices and other facilities in Louisiana and Scotland. In addition to our executive offices, we currently rent office space domestically in Houston, Texas, and internationally in Australia, Brunei, Denmark, Dubai, India, Indonesia, Malaysia, Mexico, New Zealand, Nigeria, Qatar, Saudi Arabia, Singapore, Tunisia and Venezuela.

Item 3. Legal Proceedings

Following disclosures by other offshore oil 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 focusing on our payments to customs brokers relating to the temporary importation of ENSCO 100, our only rig recently operating offshore Nigeria. The principal purpose of the 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.

As is customary for companies operating offshore Nigeria, we engaged independent customs brokers to process ENSCO 100 temporary importation permits, extensions and renewal thereof. One or more of the customs brokers that our subsidiary in Nigeria used to obtain these permits, extensions and renewal also provided services to other offshore oil service companies that have commenced similar investigations.

Following consultation with outside legal counsel, notification to the Audit Committee, and notification to 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 early stage, and we are unable to predict whether either agency will initiate a separate investigation of this matter, expand the scope of the investigation to other issues in Nigeria or to other countries or, if an agency investigation is initiated, what potential corrective measures, sanctions or other remedies, if any, the agencies may seek against us or any of our employees.

This matter is not expected to have any material effect on or disrupt our current operations because ENSCO 100 completed its contract commitment and departed Nigeria in August of 2007. At this time, we cannot predict the effect of this matter upon any potential future operations in Nigeria or elsewhere.

Inasmuch as our internal investigation is in an early stage, we are unable to predict the outcome of the investigation or to determine whether the nature and scope of the investigation will be expanded 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 letters reserving rights and effectively denying coverage by questioning the applicability of coverage for the potential ENSCO 29 wreckage and debris removal costs. During August 2007, we commenced litigation against 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, monetary 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 66 individual plaintiffs. Of these claims, 63 claims or lawsuits are pending in Mississippi state courts and three 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 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 pending cases in Mississippi, we recently received a letter demanding that we defend and indemnify two parties that formerly held an interest in a predecessor company named in a lawsuit pending in the Superior Court of the State of California. The demand arises pursuant to the terms and conditions of an Assumption Agreement given by the Company's predecessor, Penrod Drilling Corporation ("Penrod"). The plaintiff seeks monetary damages allegedly arising from exposure to asbestos or products containing asbestos while employed by Penrod. Inasmuch as the Company has yet to conduct discovery, and because the allegations are vague, it is difficult to assess the exposure or predict the outcome of this lawsuit. While management does not expect the final disposition of the lawsuit to have a material adverse effect upon ENSCO's financial position, operating results or cash flows, there can be no assurances as to the ultimate outcome.

In addition to the foregoing, we and our subsidiaries 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, 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.

Item 4. Submission of Matters to a Vote of Security Holders

There were no matters submitted to a vote of our security holders during the fourth quarter of 2007.

PART II

Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases
of Equity Securities

The table below provides the high and low sales prices of our common stock, $.10 par value, for each period indicated during the last two fiscal years:

	First Quarter	Second Quarter	Third Quarter	Fourth Quarter	Year

2007 High	$56.59	$63.28	$67.61	$60.94	$67.61
2007 Low	$45.00	$53.12	$50.57	$51.80	$45.00

2006 High	$56.40	$58.75	$47.40	$55.75	$58.75
2006 Low	$42.82	$39.80	$37.36	$39.10	$37.36

Our common stock (Symbol: ESV) is traded on the New York Stock Exchange. We had 941 stockholders of record on February 1, 2008.

We began paying a $.025 per share quarterly cash dividend on our common stock during the third quarter of 1997 and have continued to pay this quarterly dividend through December 31, 2007. Cash dividends totaling $.10 per share were paid in both 2007 and 2006. We currently intend to continue paying quarterly dividends for the foreseeable future. However, our Board of Directors may change the timing, amount and payment of dividends on our common stock depending on several factors including our profitability, liquidity, financial condition, reinvestment opportunities and capital requirements.

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

The table below provides a summary of our repurchases of common stock during the three month period ended December 31, 2007:

Issuer Purchases of Equity Securities
					Total Number		Approximate
					of Shares		Dollar Value
					Purchased as		of Shares that
	Total				Part of Publicly		May Yet Be
	Number of				Announced		Purchased
	Shares		Average Price		Plans or		Under Plans
Period	Purchased		Paid per Share		Programs		or Programs

October 1 - October 31		1,000,832		$55.47		1,000,000		$367,000,000
November 1 - November 30		438,274		$54.55		434,700		$343,000,000
December 1 - December 31		446,279		$56.01		445,400		$318,000,000

Total		1,885,385		$55.38		1,880,100

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. 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 1.9 million shares of our common stock at a cost of $104.1 million (an average cost of $55.38 per share) during the three-month period ended December 31, 2007.

Additionally, we repurchased 5,285 shares at an average cost of $55.00 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 December 31, 2007.

The chart below presents a comparison of the five year cumulative total return, assuming $100 invested on December 31, 2002, and the reinvestment of dividends, if any, for our common stock, the Standard & Poor's 500 Stock Price Index and the Dow Jones U.S. Oil Equipment & Services Index.*

	Cumulative Total Return
	12/02	12/03	12/04	12/05	12/06	12/07

ENSCO International Incorporated	100.00	92.59	108.54	152.05	171.99	205.21
S & P 500	100.00	128.68	142.69	149.70	173.34	182.87
Dow Jones U.S. Oil Equipment & Services Index	100.00	114.70	155.29	235.66	267.40	387.58

* $100 invested on December 31, 2002 in stock or index, including the reinvestment of dividends for fiscal
years ending December 31.

Item 6. Selected Financial Data

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

		Year Ended December 31,
		2007		2006		2005		2004		2003
		(in millions, except per share amounts)
Consolidated Statement of Income Data
Revenues	$	2,143.8	$	1,813.5	$	1,034.3	$	731.3	$	732.9
Operating expenses
Contract drilling		684.1		576.7		454.4		407.8		421.9
Depreciation		184.3		175.0		153.4		133.0		117.8
General and administrative		59.5		44.6		32.0		33.1		27.2

Operating income		1,215.9		1,017.2		394.5		157.4		166.0
Other income (expense), net		37.8		(5.9	)	(24.0	)	(33.6	)	(32.8	)
Provision for income taxes		261.7		252.7		100.5		29.9		39.2

Income from continuing operations		992.0		758.6		270.0		93.9		94.0
Income (loss) from discontinued operations, net⁽¹⁾		--		10.5		14.9		(.9	)	5.1
Cumulative effect of accounting change, net⁽²⁾		--		.6		--		--		--

Net income	$	992.0	$	769.7	$	284.9	$	93.0	$	99.1

Earnings (loss) per share - basic
Continuing operations	$	6.76	$	4.98	$	1.78	$	.62	$	.63
Discontinued operations		--		.07		.10		(.01	)	.03
Cumulative effect of accounting change		--		.00		--		--		--

	$	6.76	$	5.06	$	1.88	$	.62	$	.66

Earnings (loss) per share - diluted
Continuing operations	$	6.73	$	4.96	$	1.77	$	.62	$	.63
Discontinued operations		--		.07		.10		(.01	)	.03
Cumulative effect of accounting change		--		.00		--		--		--

	$	6.73	$	5.04	$	1.87	$	.62	$	.66

Weighted average common shares outstanding:
Basic		146.7		152.2		151.7		150.5		149.6
Diluted		147.3		152.8		152.4		150.6		150.1

Cash dividends per common share	$	.10	$	.10	$	.10	$	.10	$	.10

Consolidated Balance Sheet Data
Working capital	$	625.8	$	602.3	$	347.0	$	277.9	$	355.9
Total assets		4,968.8		4,334.4		3,617.9		3,322.0		3,183.0
Long-term debt, net of current portion		291.4		308.5		475.4		527.1		549.9
Stockholders' equity		3,752.0		3,216.0		2,540.0		2,193.9		2,090.4
Cash flow from continuing operations		1,242.0		943.8		351.6		243.2		265.6

⁽¹⁾

See Note 9 to the Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for information concerning discontinued operations.

⁽²⁾

On January 1, 2006, we recognized a cumulative adjustment related to the adoption of SFAS 123(R). See Note 7 to the Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for information on the adoption of SFAS 123(R).

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

INTRODUCTION

Our Business

We are a leading provider of offshore contract drilling services to the international oil and gas industry. We own and operate a fleet of 46 drilling rigs and have four ultra-deepwater semisubmersible rigs under construction. Our drilling rigs are located throughout the world and concentrated in the major geographic regions of Asia Pacific (which includes Asia, the Middle East, Australia and New Zealand), Europe/Africa, and North and South America.

We provide our drilling services to major international, government-owned and independent oil and gas companies on a "day rate" contract basis. Under day rate contracts, we provide the drilling rig and rig crews and receive a fixed amount per day for drilling the well. Our customers bear substantially all of the ancillary costs of constructing the well and supporting drilling operations, as well as the economic risk relative to the success of the well. Drilling contracts are, for the most part, awarded on a competitive bid basis. We do not provide "turnkey" or other risk-based drilling services.

In 2007, our revenues and net income increased significantly to record levels as we continued to experience strong rig demand, high utilization and escalating day rates in a majority of the geographic regions in which we operate. We added our tenth new ultra high-specification jackup rig, ENSCO 108, to our fleet and commenced construction of ENSCO 8503, our fourth ENSCO 8500 Series® ultra-deepwater semisubmersible rig. We entered into a long-term drilling contract for ENSCO 8502 in the Gulf of Mexico that is scheduled to commence upon its delivery from the shipyard in 2009. In addition to the substantial capital investment being made to our deepwater fleet, our Board of Directors authorized an additional $500.0 million of stock repurchases following the completion of our initial $500.0 million stock repurchase authorization.

We are looking forward to the positive impact our deepwater initiative will have in 2008 as ENSCO 7500, our semisubmersible rig currently operating in the Gulf of Mexico, rolled to a significantly higher day rate in February. Furthermore, ENSCO 8500 is expected to commence its initial four-year contract in the Gulf of Mexico by late 2008 following completion of commissioning, mobilization and final outfitting.

Our Industry

Financial operating results in the offshore contract drilling industry have historically been very cyclical and are primarily related to the demand for drilling rigs and the available supply of rigs.

Drilling Rig Demand

	•	demand for oil and gas,
	•	regional and global economic conditions and expected changes therein,
	•	political, social and legislative environments in the U.S. and other major oil-producing countries,
	•	production levels and related activities of OPEC and other oil and gas producers,
	•	technological advancements that impact the methods or cost of oil and gas exploration and development,
	•	disruption to exploration and development activities due to hurricanes and other severe weather conditions, and
	•	the impact that these and other events have on the current and expected future prices of oil and natural gas.

During 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, especially during the June through November hurricane season. Throughout the year, major international and large independent oil and gas companies diverted spending to areas outside of the shallow waters of the Gulf of Mexico in search of more productive oil and gas fields. However, late in the fourth quarter it appeared that shallow-water activity among the Gulf of Mexico operators began to generate a slight pick-up in demand as the hurricane season came to an end and operator budgets and drilling plans were established for 2008.

Due to the high demand for jackup rigs on a global basis, leading day rates in 2007 were near record levels for most rig classes, utilization remained high and recently executed contracts typically had favorable terms and conditions for drilling companies. The unprecedented demand was derived, for the most part, from increased exploration and development spending by oil and gas companies as they took advantage of high oil and gas prices and the rapid growth of global energy consumption.

The demand for ultra-deepwater drilling rigs in 2007 exceeded the available supply, both internationally and in the Gulf of Mexico. The limited availability of deepwater rigs and intense competition among oil and gas companies to contract them has increased day rates to record highs. As oil and gas companies continue to increase their investment in deepwater projects, it is anticipated that demand and utilization of the global deepwater rig fleet will remain elevated sustaining the upward pressure on day rates.

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

Drilling Rig Supply

Although an estimated 50 newly constructed jackup and semisubmersible rigs are scheduled for delivery during 2008, the current supply of offshore drilling rigs is limited and new rigs require a substantial capital investment and a long period of time to construct. In addition, it is time consuming to move offshore rigs between markets. Accordingly, as demand changes in a particular market, the supply of rigs may not adjust quickly, and therefore the utilization and day rates of rigs in specific markets could fluctuate significantly. Certain events, such as limited availability of insurance for certain perils in some geographical areas, rig loss or damage due to hurricanes, blowouts, craterings, punchthroughs, and other operational events may impact the supply of rigs in a particular market and cause rapid fluctuations in rig demand, utilization and day rates.

During the past several years, the supply of available offshore drilling rigs has been unable to meet the increasing demand of oil and gas companies on a global basis. As a result of this global supply imbalance and other commercial considerations, various industry participants ordered the construction of over 120 new offshore rigs, approximately 50 of which are scheduled for delivery in 2008. The deliveries scheduled for 2008 include approximately 35 jackup rigs, the majority of which are not contracted for work upon delivery from the shipyard. The completion of these new drilling rigs will increase supply and could reduce day rates and/or utilization as a result of softening of the affected markets as rigs are absorbed into the active fleet.

The new rigs to be delivered in 2008 will require new skilled and other personnel to operate and it is estimated that competition for skilled and other labor will continue to intensify as a result. Furthermore, periods of high utilization, such as the current period, make it more difficult and costly to recruit and retain qualified employees. Although competition for skilled and other labor has not materially affected us to date, competition for such personnel could increase our future operating expenses with a resulting reduction in net income, or impact our ability to fully staff and operate our rigs.

BUSINESS ENVIRONMENT

Asia Pacific

Demand for jackup rigs in 2005 strengthened and day rates improved as increased activity levels absorbed the additional rigs that mobilized to this region in the prior year. During 2006, demand for jackup rigs in this region exceeded the supply of available rigs. As a result, jackup rig utilization levels remained high and day rates continued to increase. During 2007, the prevailing demand, coupled with limited rig availability, enabled drilling contractors to continue experiencing high day rates and utilization. Jackup rig drilling contracts in the Asia Pacific region historically have been for substantially longer durations than those in other geographical regions. Since day rates for such contracts generally 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 other regions where shorter term contracts are more prevalent.

Europe/Africa

Our Europe/Africa offshore drilling operations are mainly conducted in northern Europe where moderate duration jackup rig contracts are prevalent. Beginning in 2005, oil and gas companies increased their spending as a result of higher oil and natural gas prices and the growing demand for oil. This led to an increase in jackup rig demand and average day rates. The trend continued into 2006, when a strong backlog of firm 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 and resulted in a substantial increase in day rates from the prior year. During 2007, oil and gas companies continued to increase their spending in this region and, with the shortfall of available jackup rigs, the additional demand increased average day rates further.

Many of our jackup rig contracts in the Europe/Africa and Asia Pacific regions contain cost adjustment provisions. These provisions are designed to protect our operating margin during times when contract drilling expenses are increasing. The cost adjustment provisions usually result in an increase in contract day rates or cost reimbursement to offset operating cost increases since the inception of a contract, and may also include rate adjustment provisions addressing rate reductions in the event of a decrease in operating costs. A small portion of our average day rate increases experienced in the Europe/Africa and Asia Pacific regions are attributable to contractual cost adjustment provisions.

North and South America

Our North and South America offshore drilling operations are mainly conducted in the Gulf of Mexico where jackup rig contracts are normally entered into for relatively short durations and day rates are adjusted to current market rates upon contract renewal. Therefore, average day rates in this region appear more volatile than in regions where longer duration contracts are more prevalent.

During 2005, jackup rig day rates continued to increase from prior year levels as a result of a further reduction in the supply of rigs after several jackup rigs were relocated to international markets. Furthermore, two hurricanes in the region disrupted drilling operations and severely damaged or destroyed several rigs, which reduced the number of available rigs even further. Day rates continued to increase through the first half of 2006 as drilling contractors moved additional rigs out of the Gulf of Mexico to take advantage of longer duration international contracts. However, day rates began to moderate in the second half of 2006 due to a decrease in demand as oil and gas companies were reluctant to start new projects during the hurricane season. Additionally, a decrease in the price of natural gas as well as increased cost and limited availability of insurance coverage for hurricane (windstorm) loss or damage also made this region less attractive to oil and gas companies.

During the first half of 2007, demand continued to decrease and day rates softened as a result of competition for work among drilling contractors, particularly related to smaller premium jackup rigs. In the latter half of the year, oil and gas companies remained cautious during the hurricane season and continued to shift their focus to more economically attractive prospects in the deeper waters of the Gulf of Mexico and elsewhere. As a result, jackup rig demand decreased further, resulting in an adverse impact on utilization and day rates. Drilling contractors continued to pursue international opportunities and, despite the relocation of several jackup rigs from the region in 2007, 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 rig supply more into balance with demand.

Our North and South America offshore drilling operations are also conducted in the Latin American countries of Mexico and Venezuela. In 2007, the demand for rigs increased as the national oil company in Mexico increased its drilling requirements in an attempt to offset continued depletion of its oil reserve. As a result, to entice rigs into this market, drilling contractors were able to obtain pricing at international day rates. Day rates moderated in the later part of 2007 as drillings rigs in the Gulf of Mexico became idle and available for service in Mexico. The national oil company in Mexico has indicated that it plans to continue its increased drilling requirements during 2008. Day rates will depend on the magnitude of their drilling requirements and the availability of drilling rigs from the Gulf of Mexico.

Demand for deepwater semisubmersible rigs in the Gulf of Mexico continues to outpace supply resulting in high day rates and utilization for 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 third 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 drilling contracts in the Gulf of Mexico and we are marketing ENSCO 8503 and anticipate that it will be contracted in advance of delivery. As oil and gas companies continue to increase their investment in deepwater projects, it is anticipated that the semisubmersible rigs in the Gulf of Mexico, as well as other geographical regions of the world, will remain at near full utilization for the next several years.

RESULTS OF OPERATIONS

The following analysis highlights our consolidated operating results for each of the years in the three-year period ended December 31, 2007 (in millions):

	2007		2006			2005

Revenues	$	2,143.8	$	1,813.5		$	1,034.3
Operating expenses
Contract drilling		684.1		576.7			454.4
Depreciation		184.3		175.0			153.4
General and administrative		59.5		44.6			32.0

Operating income		1,215.9		1,017.2			394.5
Other income (expense), net		37.8		(5.9	)		(24.0	)
Provision for income taxes		261.7		252.7			100.5

Income from continuing operations		992.0		758.6			270.0
Income from discontinued operations, net		--		10.5			14.9
Cumulative effect of accounting change, net		--		.6			--

Net income	$	992.0	$	769.7		$	284.9

In 2007, our net income increased by $222.3 million, or 29%, and operating income increased by $198.7 million, or 20%, as compared to 2006. 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, as compared to the prior year.

In 2006, our net income increased by $484.8 million, or 170%, and operating income increased by $622.7 million, or 158%, as compared to 2005. The increases were primarily due to improved average day rates in all operating areas and improved utilization of Europe/Africa and Asia Pacific jackup rigs, as compared to the prior year.

Detailed explanations of our operating results, including discussions of revenue and contract drilling expense based on geographical location and type of rig, are provided below.

Revenues and Contract Drilling Expense

The following is an analysis of our revenues, contract drilling expense, rig utilization and average day rates from continuing operations for each of the years in the three-year period ended December 31, 2007 (in millions, except utilization and day rates):

	2007	2006	2005
Revenues
Jackup rigs:
Asia Pacific	$ 889.8	$ 564.5	$ 354.9
Europe/Africa	670.8	497.1	241.5
North and South America	487.5	670.0	366.2

Total jackup rigs	2,048.1	1,731.6	962.6
Semisubmersible rig - North America	72.8	60.9	52.0
Barge rig - Asia Pacific	22.9	21.0	19.7

Total	$2,143.8	$1,813.5	$1,034.3


Contract Drilling Expense
Jackup rigs:
Asia Pacific	$ 261.2	$ 213.8	$ 173.1
Europe/Africa	208.4	158.0	114.1
North and South America	175.0	166.4	135.9

Total jackup rigs	644.6	538.2	423.1
Semisubmersible rigs - North America	28.8	26.3	21.8
Barge rig - Asia Pacific	10.7	12.2	9.5

Total	$ 684.1	$ 576.7	$ 454.4

	2007	2006	2005


Rig utilization⁽¹⁾
Jackup rigs
Asia Pacific	99%	98%	84%
Europe/Africa	93%	100%	96%
North and South America	80%	90%	85%

Total jackup rigs	91%	95%	87%
Semisubmersible rig - North America	97%	87%	86%
Barge rig - Asia Pacific	95%	98%	98%

Total	91%	95%	87%


Average day rates⁽²⁾
Jackup rigs
Asia Pacific	$131,384	$ 89,568	$ 69,506
Europe/Africa	198,551	149,072	84,441
North and South America	108,883	122,058	67,801

Total jackup rigs	140,042	114,587	71,694
Semisubmersible rig - North America	199,432	191,163	161,527
Barge rig - Asia Pacific	66,699	57,168	52,684

Total	$139,882	$114,762	$ 73,553

⁽¹⁾

Rig utilization is derived by dividing the number of days under contract, including days associated with compensated mobilizations, by the number of days in the period.

⁽²⁾

Average day rates are derived by dividing contract drilling revenue by the aggregate number of contract days, adjusted to exclude certain types of non-recurring reimbursable revenue and lump sum revenue and contract days associated with certain mobilizations, demobilizations, shipyard contracts and standby contracts.

The following is a summary of our offshore drilling rigs by location at December 31, 2007, 2006 and 2005:

	2007	2006	2005
Jackup rigs:
Asia Pacific⁽¹⁾⁽²⁾	19	18	16
Europe/Africa⁽³⁾	10	9	9
North and South America⁽²⁾⁽³⁾	15	16	17
Under construction⁽¹⁾	--	1	2

Total jackup rigs	44	44	44
Semisubmersible rigs:
North America	1	1	1
Under construction⁽⁴⁾	4	3	1

Total semisubmersible rigs	5	4	2
Barge rig - Asia Pacific	1	1	1

Total⁽⁵⁾	50	49	47

⁽¹⁾

Upon completion of its construction in the first quarter of 2007, we accepted delivery of ENSCO 108, an ultra-high specification jackup rig that commenced drilling operations in Indonesia. Upon completion of its construction in the first quarter of 2006, we accepted delivery of ENSCO 107, an ultra-high specification jackup rig that commenced drilling operations in Vietnam.

⁽²⁾

During 2006, we mobilized ENSCO 84 from the Gulf of Mexico to Qatar.

⁽³⁾

During 2007, we mobilized ENSCO 105 from the Gulf of Mexico to Tunisia.

⁽⁴⁾

During 2007, we entered into an agreement to construct ENSCO 8503 with delivery expected in the third quarter of 2010. During 2006, we entered into agreements to construct ENSCO 8502 and ENSCO 8501 with deliveries expected in the first and fourth quarters of 2009, respectively.

⁽⁵⁾

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

Asia Pacific Jackup Rigs

In 2007, revenues for our Asia Pacific jackup rigs increased by $325.3 million, or 58%, as compared to 2006. The increase in revenues was primarily due to a 47% increase in average day rates and the increased size of our 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 rigs accounted for $101.5 million of the increase from prior year. 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 $47.4 million, or 22%, as compared to 2006, primarily due to the increased size of our fleet. Excluding the impact of the two additional rigs, contract drilling expense increased by $26.2 million, or 13%, as compared to the prior year due to 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 related to damage sustained by ENSCO 107 while pre-loading on a drilling location offshore Vietnam.

In 2006, revenues for our Asia Pacific jackup rigs increased by $209.6 million, or 59%, as compared to 2005. The increase in revenues was primarily due to a 29% increase in average day rates and an increase in utilization to 98% in 2006 from 84% in the prior year as a result of increased demand caused by higher levels of spending by oil and gas companies. Contract drilling expense increased by $40.7 million, or 24%, as compared to 2005, primarily due to increased utilization, increased personnel, maintenance and repair expense and a $2.7 million loss related to leg damage sustained by ENSCO 107 as noted above.

Europe/Africa Jackup Rigs

In 2007, revenues for our Europe/Africa jackup rigs increased by $173.7 million, or 35%, as compared to 2006. 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 $55.7 million of revenue in the current year, and to a 33% increase in average day rates. The increase in revenues was partially offset by a decrease in utilization to 93% in 2007 from 100% in 2006 primarily due to the mobilization of ENSCO 100 from Nigeria to the North Sea, which commenced in late August of 2007. 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 $50.4 million, or 32%, as compared to 2006, with the majority of the increase due to the relocation of ENSCO 105, $5.5 million of costs associated with the departure of ENSCO 100 from Nigeria and a $4.2 million increase in reimbursable costs associated with ENSCO 100. Excluding the impact of the three items above, contract drilling expense increased by $19.6 million, or 13%, as compared to the prior year due to increased personnel costs and repair and maintenance expense, partially offset by a reduction in fleet-wide mobilization expense.

In 2006, revenues for our Europe/Africa jackup rigs increased by $255.6 million, or 106%, as compared to 2005. The increase in revenues was primarily attributable to a 77% increase in average day rates and to a lesser extent, the addition of ENSCO 102 to the Europe/Africa jackup fleet in February 2006, which provided $57.2 million of revenue in 2006. The improvement in day rates and utilization was primarily attributable to increased spending by oil and gas companies and a decrease in the supply of available jackup rigs. Contract drilling expense increased by $43.9 million, or 38%, as compared to 2005, primarily due to the addition of ENSCO 102, which added $25.2 million of expense in 2006, and to increased personnel costs, rig mobilization expense, and repair and maintenance expense.

North and South America Jackup Rigs

In 2007, revenues for our North and South America jackup rigs decreased by $182.5 million, or 27% as compared to 2006. The decrease in revenues was partially due to the reduced size of our North and South America jackup fleet as ENSCO 105 relocated from the Gulf of Mexico during the first quarter of 2007 and ENSCO 84 relocated from the region during the third quarter of 2006. Excluding the impact of these two rigs, revenues decreased $114.4 million, or 19%, as compared to the prior year. An 11% decrease in average day rates and a decrease in utilization to 80% in 2007 from 90% in 2006 also contributed to the reduction in revenue from the prior year. The decrease in utilization and average day rates was due to a decrease in demand by oil and gas companies as they have reduced spending on shallow water drilling in this region. Contract drilling expense increased by $8.6 million, or 5%, as compared to 2006. Excluding the impact of the two rigs relocated from the region, contract drilling expense increased $24.3 million or 16%, primarily due to increased personnel, insurance, and repair and maintenance expense.

In 2006, revenues for our North and South America jackup rigs increased by $303.8 million, or 83%, as compared to 2005. The increase in revenues was primarily due to an 80% increase in average day rates attributable to the reduced supply of Gulf of Mexico jackup rigs as we, and several of our competitors, mobilized rigs contracted for work in international markets out of the Gulf of Mexico. Contract drilling expense increased by $30.5 million, or 22%, as compared to 2005, primarily due to increased personnel costs, insurance costs and rig mobilization expense as compared to the prior year.

North America Semisubmersible Rig

In 2007, revenues for ENSCO 7500 increased $11.9 million, or 20%, as compared to 2006. The increase in revenues was primarily due to a 4% increase in the average day rate which resulted from a cost escalation provision in the contract, and an increase in utilization to 97% in 2007 from 87% in 2006, as ENSCO 7500 was idle for approximately one month in the prior year while undergoing minor enhancement and preparatory work for its current contract. Contract drilling expense increased by $2.5 million, or 10%, as compared to 2006, primarily due to increased personnel costs and reimbursable expense partially offset by a reduction in repair and maintenance expense.

In 2006, revenues for ENSCO 7500 increased by $8.9 million, or 17%, and contract drilling expense increased $4.5 million, or 21%, as compared to 2005. The increase in revenues was primarily due to an 18% increase in the average day rate and the increase in contract drilling expense is mainly attributable to increased personnel costs.

Depreciation

Our depreciation expense for 2007 increased by $9.3 million, or 5%, as compared to 2006. 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 in 2007 and 2006.

Our depreciation expense for 2006 increased by $21.6 million, or 14%, as compared to 2005. The increase was primarily attributable to depreciation associated with capital enhancement projects completed in 2006 and 2005 and depreciation on ENSCO 107, which was placed into service in March of 2006.

General and Administrative

Our general and administrative expense for 2007 increased by $14.9 million, or 33%, as compared to 2006. The increase was primarily attributable to an $11.3 million expense incurred during the current year in connection with a retirement agreement entered into in February of 2007 with our former CEO and to an increase in professional fees, salary expense and share-based compensation expense as compared to the prior year.

Our general and administrative expense for 2006 increased by $12.6 million, or 39%, as compared to 2005. The increase was primarily attributable to an increase in salary expense and share-based compensation expense.

Other Income (Expense)

The following is an analysis of other income (expense) for each of the years in the three-year period ended December 31, 2007 (in millions):

	2007			2006			2005

Interest income	$	26.3		$	14.9		$	7.0
Interest expense, net:
Interest expense		(32.3	)		(35.4	)		(37.7	)
Capitalized interest		30.4			18.9			8.9

		(1.9	)		(16.5	)		(28.8	)
Other, net		13.4			(4.3	)		(2.2	)

	$	37.8		$	(5.9	)	$	(24.0	)

The increase in our interest income from 2006 to 2007 was primarily due to an increase in cash balances invested. The increase in our interest income from 2005 to 2006 was primarily due to higher average interest rates. Our interest expense decreased during the same periods due to a decrease in outstanding debt. Capitalized interest for 2007 and 2006 increased as compared to the prior year periods due to an increase in the amount invested in new rig construction projects.

Foreign currency translation adjustments and foreign currency transaction gains and losses, including certain gains and losses on derivative instruments, are included in other, net, on our consolidated statements of income. We had net foreign currency exchange gains of $9.2 million during 2007, net foreign currency exchange losses of $2.8 million during 2006, and net foreign currency exchange gains of $700,000 during 2005.

Provision for Income Taxes

The income tax rates imposed in the tax jurisdictions in which our non-U.S. 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 revenue, statutory or negotiated deemed profits, or other bases utilized under local tax laws, rather than to net income. In addition, our drilling rigs are frequently moved from one tax jurisdiction to another. As a result, 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.

Our income tax expense was $261.7 million, $252.7 million and $100.5 million in the years ended December 31, 2007, 2006 and 2005, respectively. Our effective income tax rates during those years were 20.9%, 25.0% and 27.1%, respectively.

Income tax expense for the years ended December, 31 2007, 2006 and 2005 includes net benefits of $14.5 million, $7.3 million and $4.6 million, respectively, relating to settlements with tax authorities or other resolutions of prior year tax issues. Excluding the impact of these net benefits, our effective income tax rates for 2007, 2006 and 2005 would have been 22.0%, 25.7% and 28.4%, respectively.

The reductions in our effective tax rate were primarily due to an increase in the relative portion of our earnings generated by foreign subsidiaries whose earnings are taxed at lower rates.

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. 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 three-year period ended December 31, 2007, our primary sources of cash included an aggregate $2,537.4 million generated from continuing operations and $144.8 million from the exercise of stock options. Our primary uses of cash included an aggregate $681.6 million for the repurchase of common stock, $1,525.6 million for the acquisition, construction, enhancement and other improvement of our drilling rigs and $242.6 million for the repayment of debt.

Detailed explanations of our liquidity and capital resources for each of the years in the three-year period ended December 31, 2007 are set forth below.

Cash Flow and Capital Expenditures

Our cash flow from continuing operations and capital expenditures on continuing operations for each of the years in the three-year period ended December 31, 2007 are as follows (in millions):

	2007	2006	2005

Cash flow from continuing operations	$1,242.0	$943.8	$351.6


Capital expenditures on continuing operations:
New rig construction	$367.7	$379.9	$139.3
Rig acquisition	--	--	80.5
Rig enhancements	65.0	92.7	207.0
Minor upgrades and improvements	87.2	56.0	50.3

	$ 519.9	$528.6	$477.1

Our cash flow from continuing operations in 2007 increased by $298.2 million, or 32%, from 2006. The increase resulted primarily from a $390.5 million increase in cash receipts from drilling services offset by a $99.9 million increase in cash payments related to contract drilling expenses.

Cash flow from our continuing operations in 2006 increased by $592.2 million, or 168%, from 2005. The increase resulted primarily from a $771.1 million increase in cash receipts from drilling services offset by a $126.9 million increase in cash payments related to contract drilling expenses and a $72.2 million increase in cash payments related to income taxes.

We continue to expand the size and quality of our drilling rig fleet. During the three-year period ended December 31, 2007, we invested $967.4 million in the acquisition and construction of new drilling rigs and an additional $364.7 million upgrading the capability and extending the service lives of our existing drilling rigs. We have added three new ultra-high specification jackup rigs to our fleet during the past three years, including ENSCO 106 in February 2005, ENSCO 107 in January 2006 and ENSCO 108 in March 2007.

In June 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 third quarter of 2008, first quarter of 2009 and fourth quarter of 2009, respectively, with an aggregate construction cost of approximately $1,035.0 million. The ENSCO 8500, ENSCO 8501 and ENSCO 8502 are subject to long-term drilling contracts upon completion of their construction.

Based on our current projections, we expect capital expenditures in 2008 to include approximately $430.0 million for progress payments on the construction of the four ENSCO 8500 Series® rigs, approximately $25.0 million for rig enhancement projects and $110.0 million for minor upgrades and improvements. Depending on market conditions and opportunities, we may also make additional capital expenditures to upgrade rigs for customer requirements and construct or acquire additional rigs.

Financing and Capital Resources

Our long-term debt, total capital and long-term debt to total capital ratios at December 31, 2007, 2006 and 2005 are summarized below (in millions, except percentages):

	2007	2006	2005

Long-term debt	$ 291.4	$ 308.5	$ 475.4
Total capital^*	4,043.4	3,524.5	3,015.4
Long-term debt to total capital	7.2%	8.8%	15.8%

Total capital includes long-term debt plus stockholders' equity.

We have a $350.0 million unsecured revolving credit facility (the "Credit Facility") with a syndicate of banks that matures in June 2010. We had no amounts outstanding under the Credit Facility at December 31, 2007, 2006 or 2005 and do not currently anticipate borrowing under the Credit Facility during 2008. We maintain an investment grade credit rating of Baa1 from Moody's.

In November 2007, we repaid our $150.0 million of 6.75% Notes, which were classified in "Current maturities of long-term debt" on our December 31, 2006, consolidated balance sheet. At December 31, 2007, we have an aggregate $159.9 million outstanding under two separate bond issues guaranteed by the United States Maritime Administration ("MARAD") that require semiannual principal and interest payments. We also make semiannual interest payments on $150.0 million of debentures due in 2027.

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 year ended December 31, 2007 totaled 9.4 million shares at a cost of $521.6 million (an average cost of $55.56 per share).

Since the inception of our stock repurchase programs in March 2006, we have repurchased an aggregate 12.8 million shares at a cost of $681.6 million (an average cost of $53.05 per share). As of December 31, 2007, approximately $318.4 million of the supplemental authorization remained available for repurchases of our outstanding common stock.

Contractual Obligations

We have various contractual commitments related to our debt, operating leases and new rig construction agreements. We expect to fund these commitments from our existing cash and cash equivalents and future operating cash flow. The table below summarizes our significant contractual obligations at December 31, 2007, and the periods in which such obligations are due (in millions):

		Payments due by period

				2009		2011
				and		and		After
		2008		2010		2012		2012		Total

Principal payments on long-term debt	$	19.1	$	34.4	$	34.4	$	223.9	$	311.8
Interest payments on long-term debt		19.7		36.4		32.4		173.4		261.9
Operating leases		6.4		5.3		2.9		7.8		22.4
New rig construction agreements		353.1		366.8		--		--		719.9

Total contractual cash obligations	$	398.3	$	442.9	$	69.7	$	405.1	$	1,316.0

The contractual obligations table above does 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 $13.5 million of unrecognized tax benefits as of December 31, 2007. Substantially all of our unrecognized tax benefits related to uncertain tax positions that were not under review by taxing authorities and therefore we are unable to specify the future periods in which we may be obligated to settle such amounts.

Liquidity

Our liquidity position at December 31, 2007, 2006 and 2005 is summarized below (in millions, except ratios):

	2007	2006	2005


Cash and cash equivalents	$629.5	$565.8	$268.5
Working capital	625.8	602.3	347.0
Current ratio	2.2	2.6	2.5

We expect to fund our short-term liquidity needs, including an aggregate $610.2 million of contractual obligations and anticipated capital expenditures during 2008, as well as any stock repurchases, dividends and 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 and anticipated capital expenditures, from our cash and cash equivalents, operating cash flow and, if necessary, funds borrowed under our $350.0 million unsecured revolving credit facility or 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 $318.4 million remained available for repurchases as of December 31, 2007. While future operating cash flow cannot be accurately predicted, based on our contractual backlog and current industry conditions, management expects our long-term liquidity will continue to be funded primarily by operating cash flow.

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 December 31, 2007, we had contracts outstanding to exchange an aggregate $297.2 million U.S. dollars for various foreign currencies, all of which mature during the next fourteen 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 December 31, 2007 would approximate $13.0 million.

We use various derivative financial instruments to manage our exposure to interest rate risk. We occasionally use interest rate swap agreements to effectively convert the variable interest rate on debt to a fixed rate or the fixed rate on debt to a variable rate, and interest rate lock agreements to hedge against increases in interest rates on pending financing. At December 31, 2007, we had no outstanding interest rate swap agreements or interest rate lock agreements.

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 does 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.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

The preparation of 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. 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 December 31, 2007, the carrying value of our property and equipment totaled $3,358.9 million, which represents 68% 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.

Useful lives of drilling rigs are difficult to estimate due to a variety of factors, including technological advances that impact the methods or cost of oil and gas exploration and development, changes in market or economic conditions, and changes in laws or regulations affecting the drilling industry. We evaluate the remaining useful lives of our rigs on a periodic basis, considering operating condition, functional capability, and market and economic factors. Our most recent change in estimated useful lives occurred in January 1998, when we extended the useful lives of our drilling rigs by an average of five to six years.

Our fleet of 44 jackup rigs comprises over 66% of both the gross cost and net carrying amount of our property and equipment at December 31, 2007 and is depreciated over useful lives ranging from 15 to 30 years. Our ultra-deepwater semisubmersible rig is depreciated over a 30-year useful life. The following table provides an analysis of estimated increases and decreases in depreciation expense that would have been recognized for the year ended December 31, 2007 for various assumed changes in the useful lives of our drilling rigs effective January 1, 2007:

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


10%		$(18.3)
20%		(33.4)
(10%)		19.0
(20%)		44.6

Impairment of Long-Lived Assets and Goodwill

We evaluate the carrying value of our property and equipment, primarily our drilling rigs, when events or changes in circumstances indicate that the carrying value of such rigs may not be recoverable. Generally, extended periods of idle time and/or inability to contract rigs at economical rates are an indication that a rig may be impaired. However, the offshore drilling industry 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 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 ultra-deepwater semisubmersible rig 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, 2007, 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, market, 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.

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 December 31, 2007, we had a $338.9 million net deferred income tax liability, a $181.4 million liability for income taxes currently payable and a $13.5 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 assumptions and estimates regarding future operating results and levels of taxable income, as well as our 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. In December 2007, substantially all of the undistributed earnings of our non-U.S. subsidiaries were distributed to our U.S. parent (see Note 8 to the Consolidated Financial Statements). A U.S. deferred tax liability has not been recognized for the remaining undistributed earnings of our non-U.S. subsidiaries because it is our intention to reinvest such earnings indefinitely. 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 reflect our application of the provisions of FASB Interpretation No. 48, "Accounting for Uncertainty in Income Taxes - an interpretation of SFAS 109" and are based on management's interpretation of applicable tax laws, and incorporate our 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 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 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 have historically 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:

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

NEW ACCOUNTING PRONOUNCEMENTS

In December 2007, the FASB issued SFAS No. 141 (revised 2007), "Business Combinations" ("SFAS 141(R)"). This standard establishes principles and requirements for how an acquirer in a business combination recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree. SFAS 141(R) also establishes principles and requirements for how an acquirer recognizes and measures the goodwill acquired in a business combination and it establishes disclosure requirements to facilitate an evaluation of the nature and financial effects of a business combination. SFAS 141(R) is effective for business combinations which occur during the first annual reporting period beginning on or after December 15, 2008. We expect the effect of adoption of this statement will be limited to any future acquisitions anticipated to close subsequent to December 31, 2008.

In December 2007, the FASB issued SFAS No. 160, "Noncontrolling Interests in Consolidated Financial Statements" ("SFAS 160"). This standard amends Accounting Research Bulletin 51, "Consolidated Financial Statements", to establish accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. It clarifies that a noncontrolling interest should be reported as equity in the consolidated financial statements. SFAS 160 also requires net income attributable to both the parent and the noncontrolling interest to be disclosed separately on the face of the consolidated statement of income. SFAS 160 is effective for fiscal years beginning after December 15, 2008. We do not expect this statement to have a material effect on our consolidated financial position, operating results or cash flows.

In March 2007, the FASB ratified EITF Issue No. 06-11, "Accounting for Income Tax Benefits of Dividends on Share-Based Payment Awards" ("EITF 06-11"). This statement establishes the requirement to recognize the income tax benefit realized from dividends paid to employees for equity classified non-vested shares, non-vested equity share units, and outstanding equity share options as an increase to additional paid-in capital. EITF 06-11 is effective for fiscal years beginning after December 15, 2007. We do not expect EITF 06-11 to have a material effect on our consolidated financial position, operating results or cash flows.

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"). This standard 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. This statement applies to other accounting pronouncements that require fair value measurements; it does not require any new fair value measurements. FAS 157 is effective for fiscal years beginning after November 15, 2007, but was amended on February 6, 2008 to defer the effective date for one year for certain nonfinancial assets and liabilities. We do not expect this statement to have a material effect on our consolidated financial position, operating results or cash flows.

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

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

Item 8. Financial Statements and Supplementary Data

MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER
FINANCIAL REPORTING

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f) or 15d-15(f). Our internal control over financial reporting system is designed to provide reasonable assurance to our management and Board of Directors regarding the preparation and fair presentation of published financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. Under the supervision and with the participation of management, including the Chief Executive Officer and Chief Financial Officer, we have conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, we have concluded that our internal control over financial reporting is effective as of December 31, 2007 to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.

KPMG LLP, the independent registered public accounting firm who audited our consolidated financial statements, have issued an audit report on our internal control over financial reporting. KPMG LLP's audit report on our internal control over financial reporting is included herein.

February 26, 2008

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Stockholders
ENSCO International Incorporated:

We have audited the accompanying consolidated balance sheets of ENSCO International Incorporated and subsidiaries as of December 31, 2007 and 2006, and the related consolidated statements of income and cash flows for each of the years in the three-year period ended December 31, 2007. These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of ENSCO International Incorporated and subsidiaries as of December 31, 2007 and 2006, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2007, in conformity with U.S. generally accepted accounting principles.

As discussed in note 8 to the consolidated financial statements, effective January 1, 2007, the Company adopted the provisions of Financial Accounting Standards Board Interpretation No. 48, Accounting for Uncertainty in Income Taxes. As discussed in note 1 to the consolidated financial statements, effective January 1, 2006, the Company adopted the provisions of Statement of Financial Accounting Standards No. 123 (revised 2004), Share Based Payment. Also, as discussed in note 1 to the consolidated financial statements, the Company changed its method of quantifying errors in 2006.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), ENSCO International Incorporated and subsidiaries' internal control over financial reporting as of December 31, 2007, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 26, 2008 expressed an unqualified opinion on the effectiveness of the Company's internal control over financial reporting.

/s/ KPMG LLP

Dallas, Texas
February 26, 2008

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Stockholders
ENSCO International Incorporated:

We have audited ENSCO International Incorporated and subsidiaries' (ENSCO) internal control over financial reporting as of December 31, 2007, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). ENSCO's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management's Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company's internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, ENSCO maintained, in all material respects, effective internal control over financial reporting as of December 31, 2007, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of ENSCO International Incorporated and subsidiaries as of December 31, 2007 and 2006, and the related consolidated statements of income and cash flows for each of the years in the three-year period ended December 31, 2007, and our report dated February 26, 2008 expressed an unqualified opinion on those consolidated financial statements.

/s/ KPMG LLP

Dallas, Texas
February 26, 2008

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

	Year Ended December 31,
	2007			2006		2005

OPERATING REVENUES	$	2,143.8	$	1,813.5	$	1,034.3

OPERATING EXPENSES
Contract drilling		684.1		576.7		454.4
Depreciation		184.3		175.0		153.4
General and administrative		59.5		44.6		32.0

		927.9		796.3		639.8


OPERATING INCOME		1,215.9		1,017.2		394.5

OTHER INCOME (EXPENSE)
Interest income		26.3		14.9		7.0
Interest expense, net		(1.9	)	(16.5	)	(28.8	)
Other, net		13.4		(4.3	)	(2.2	)

		37.8		(5.9	)	(24.0	)


INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES AND CUMULATIVE EFFECT OF ACCOUNTING CHANGE		1,253.7		1,011.3		370.5

PROVISION FOR INCOME TAXES
Current income tax expense		261.3		236.8		93.6
Deferred income tax expense		.4		15.9		6.9

		261.7		252.7		100.5


INCOME FROM CONTINUING OPERATIONS		992.0		758.6		270.0

DISCONTINUED OPERATIONS
Income from discontinued operations, net		--		3.3		1.0
Gain on disposal of discontinued operations, net		--		7.2		13.9

		--		10.5		14.9


INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE		992.0		769.1		284.9

CUMULATIVE EFFECT OF ACCOUNTING CHANGE FOR ADOPTION OF SFAS 123(R), NET		--		.6		--

NET INCOME	$	992.0	$	769.7	$	284.9


EARNINGS PER SHARE - BASIC
Continuing operations	$	6.76	$	4.98	$	1.78
Discontinued operations		--		.07		.10
Cumulative effect of accounting change		--		.00		--

	$	6.76	$	5.06	$	1.88


EARNINGS PER SHARE - DILUTED
Continuing operations	$	6.73	$	4.96	$	1.77
Discontinued operations		--		.07		.10
Cumulative effect of accounting change		--		.00		--

	$	6.73	$	5.04	$	1.87


WEIGHTED AVERAGE COMMON SHARES OUTSTANDING
Basic		146.7		152.2		151.7
Diluted		147.3		152.8		152.4

CASH DIVIDENDS PER COMMON SHARE	$	.10	$	.10	$	.10

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

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

		December 31,
		2007		2006
ASSETS

CURRENT ASSETS
Cash and cash equivalents	$	629.5	$	565.8
Accounts receivable, net		383.2		338.8
Other		116.6		82.6

Total current assets		1,129.3		987.2


PROPERTY AND EQUIPMENT, AT COST		4,704.7		4,129.5
Less accumulated depreciation		1,345.8		1,169.1

Property and equipment, net		3,358.9		2,960.4


GOODWILL		336.2		336.2

OTHER ASSETS, NET		144.4		50.6

	$	4,968.8	$	4,334.4


LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable	$	18.8	$	12.4
Accrued liabilities and other		465.6		205.4
Current maturities of long-term debt		19.1		167.1

Total current liabilities		503.5		384.9


LONG-TERM DEBT		291.4		308.5

DEFERRED INCOME TAXES		352.0		356.5

OTHER LIABILITIES		69.9		68.5

COMMITMENTS AND CONTINGENCIES

STOCKHOLDERS' EQUITY
Preferred stock, $1 par value, 20.0 million shares authorized
and none issued		--		--
Common stock, $.10 par value, 250.0 million shares authorized,
180.3 million and 178.7 million shares issued		18.0		17.9
Additional paid-in capital		1,700.5		1,621.3
Retained earnings		2,977.5		1,994.5
Accumulated other comprehensive loss		(4.2	)	(5.5	)
Treasury stock, at cost, 36.4 million shares and 26.9 million shares		(939.8	)	(412.2	)

Total stockholders' equity		3,752.0		3,216.0

	$	4,968.8	$	4,334.4

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

ENSCO INTERNATIONAL INCORPORATED AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in millions)

	Year Ended December 31,
	2007			2006		2005

OPERATING ACTIVITIES
Net income	$	992.0	$	769.7	$	284.9
Adjustments to reconcile net income to net cash provided
by operating activities of continuing operations:
Depreciation expense		184.3		175.0		153.4
Deferred income tax expense		.4		15.9		6.9
Share-based compensation expense		36.9		21.9		15.9
Excess tax (benefit) deficiency from share-based compensation		(6.6	)	(3.6	)	4.9
Amortization of other assets		8.1		6.2		6.0
Income from discontinued operations, net		--		(3.3	)	(1.0	)
Gain on disposal of discontinued operations, net		--		(7.2	)	(13.9	)
Other		.1		6.7		4.6
Changes in operating assets and liabilities:
Increase in accounts receivable		(44.4	)	(69.8	)	(86.0	)
Increase in other assets		(130.9	)	(23.8	)	(16.8	)
Increase (decrease) in accounts payable		6.5		(6.7	)	3.5
Increase (decrease) in accrued liabilities and other		195.6		62.8		(10.8	)

Net cash provided by operating activities of continuing operations		1,242.0		943.8		351.6


INVESTING ACTIVITIES
Additions to property and equipment		(519.9	)	(528.6	)	(477.1	)
Net proceeds from disposal of discontinued operations		--		23.7		132.9
Other		7.7		2.9		2.5

Net cash used in investing activities		(512.2	)	(502.0	)	(341.7	)


FINANCING ACTIVITIES
Repurchase of common stock under authorized program		(521.6	)	(160.0	)	--
Reduction of long-term borrowings		(167.2	)	(17.1	)	(58.3	)
Cash dividends paid		(14.8	)	(15.3	)	(15.2	)
Proceeds from exercise of share options		35.8		41.8		67.2
Excess tax benefit (deficiency) from share-based compensation		6.6		3.6		(4.9	)
Other		(4.1	)	(1.0	)	(3.2	)

Net cash used in financing activities		(665.3	)	(148.0	)	(14.4	)


Effect of exchange rate changes on cash and cash equivalents		(.8	)	(.2	)	(.7	)
Net cash provided by operating activities of discontinued operations		--		3.7		6.7


INCREASE IN CASH AND CASH EQUIVALENTS		63.7		297.3		1.5

CASH AND CASH EQUIVALENTS, BEGINNING OF YEAR		565.8		268.5		267.0


CASH AND CASH EQUIVALENTS, END OF YEAR	$	629.5	$	565.8	$	268.5

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

ENSCO INTERNATIONAL INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

Business

ENSCO International Incorporated is one of the leading providers of offshore contract drilling services to the international oil and gas industry. We have one of the largest and most capable offshore drilling rig fleets in the world which is comprised of 46 drilling rigs, including 44 jackup rigs, one ultra-deepwater semisubmersible rig and one barge rig. Additionally, we have four ultra-deepwater semisubmersible rigs under construction. We drill and complete offshore oil and gas wells for major international, government-owned and independent oil and gas companies on a "day rate" contract basis, under which we provide our drilling rigs and rig crews and receive a fixed amount per day for drilling the well. Our customers bear substantially all of the ancillary costs of constructing the well and supporting drilling operations, as well as the economic risk relative to the success of the well.

Our contract drilling operations are integral to the exploration, development and production of oil and gas. Our business levels and corresponding operating results are significantly affected by worldwide levels of offshore exploration and development spending by oil and gas companies. Levels of offshore exploration and development spending may fluctuate substantially from year to year and from region to region. Such fluctuations result from many factors, including demand for oil and gas, regional and global economic conditions, political, social and legislative environments in the U.S. and other major oil-producing countries, the production levels and related activities of OPEC and other oil and gas producers, technological advancements that impact the methods or cost of oil and gas exploration and development, disruption to exploration and development activities due to hurricanes and other severe weather conditions, and the impact that these and other events have on the current and expected future pricing of oil and natural gas (see Note 11 "Segment Information" for additional information concerning our operations by geographic region).

Principles of Consolidation

The accompanying consolidated financial statements include the accounts of ENSCO International Incorporated and its majority owned subsidiaries. All significant intercompany accounts and transactions have been eliminated. Certain previously reported amounts have been reclassified to conform to the current-year presentation. Unless the context otherwise requires, the terms "we," "us" and "our" refer to ENSCO International Incorporated and its consolidated subsidiaries.

Pervasiveness of Estimates

The preparation of financial statements in conformity with U.S. generally accepted accounting principles 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.

Foreign Currency Translation

The U.S. dollar is the functional currency of all our non-U.S. subsidiaries. The financial statements of these subsidiaries are remeasured in U.S. dollars based on a combination of both current and historical exchange rates. Currency translation adjustments and transaction gains and losses, including certain gains and losses on our derivative instruments, are included in other, net, on our consolidated statements of income. We had net foreign currency exchange gains of $9.2 million for the year ended December 31, 2007, net foreign currency exchange losses of $2.8 million for the year ended December 31, 2006 and net foreign currency exchange gains of $700,000 for the year ended December 31, 2005.

Cash Equivalents and Short-Term Investments

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

Property and Equipment

All costs incurred in connection with the acquisition, construction, enhancement and improvement of assets are capitalized, including allocations of interest incurred during periods that our drilling rigs are under construction or undergoing major enhancements and improvements. Maintenance and repair costs are charged to operating expenses. Upon sale or retirement of assets, the related cost and accumulated depreciation are removed from the accounts and the resulting gain or loss is included in income.

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

We evaluate the carrying value of our property and equipment for impairment when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. For property and equipment used in our operations, recoverability is determined by comparing the net carrying value of an asset to either an independent fair value appraisal of the asset or the expected undiscounted future cash flows, before interest, of the asset. The amount of impairment loss, if any, is measured as the difference between the net book value of the asset and its estimated fair value. We recorded no impairment charges during the three-year period ended December 31, 2007. Property and equipment held for sale is recorded at the lower of net book value or net realizable value.

Goodwill

We test goodwill for impairment on an annual basis, or when events or changes in circumstances indicate that a potential impairment exists. Based on our goodwill impairment analysis performed as of December 31, 2007, there was no impairment of goodwill.

Operating Revenues and Expenses

Substantially all of our drilling services contracts ("contracts") are performed on a day rate basis and the terms of such contracts are typically for a specific period of time or the period of time required to complete a specific task, such as drilling a well. Contract revenue and expenses are recognized on a per day basis, as the work is performed. Day rate revenues are typically earned, and contract drilling expenses are typically incurred, on a uniform basis over the terms of our contracts.

In connection with some contracts, we receive lump-sum fees or similar compensation for the mobilization of equipment and personnel prior to the commencement of drilling services or the demobilization of equipment and personnel upon contract completion. Fees received for the mobilization or demobilization of equipment and personnel are included in operating revenue. The costs incurred in connection with the mobilization and demobilization of equipment and personnel are included in contract drilling expense. Mobilization fees received and costs incurred are deferred and recognized over the period that the related drilling services are performed on a straight-line basis.

Demobilization fees and related costs are recognized as incurred, upon contract completion. Costs associated with the mobilization of equipment and personnel to more promising market areas without contracts are expensed as incurred.

Deferred mobilization costs are included in other current assets and other assets, net, and totaled $29.2 million and $15.0 million, at December 31, 2007 and 2006, respectively. Deferred mobilization revenue is included in accrued liabilities and other, and other liabilities and totaled $53.3 million and $29.2 million at December 31, 2007 and 2006, respectively.

In connection with some contracts, we receive up-front, lump-sum fees or similar compensation for capital improvements to our rigs. Such compensation is deferred and recognized as revenue over the related contract period. The cost of such capital improvements is capitalized and depreciated over the useful life of the asset. Deferred revenue associated with capital improvements is included in accrued liabilities and other, and other liabilities and totaled $1.5 million and $2.7 million at December 31, 2007 and 2006, respectively.

We must obtain certifications from various regulatory bodies in order to operate our drilling rigs and must maintain such certifications through periodic inspections and surveys. The costs incurred in connection with maintaining such certifications, including inspections, tests, surveys and drydock, as well as remedial structural work and other compliance costs, are deferred and amortized over the corresponding certification periods. Deferred regulatory certification and compliance costs are included in other current assets and other assets, net, and totaled $10.4 million and $4.1 million at December 31, 2007 and 2006, respectively.

In certain countries in which we operate, taxes such as sales, use, value added, gross receipts, and excise may be assessed by the local government on our revenues. We generally record our tax-assessed revenue transactions on a net basis in our consolidated statements of income.

Derivative Financial Instruments

We use derivative financial instruments ("derivatives") to reduce our exposure to various market risks, primarily interest rate risk and foreign currency risk. We employ an interest rate risk management strategy that occasionally utilizes derivatives to minimize or eliminate unanticipated fluctuations in earnings and cash flows arising from changes in, and volatility of, interest rates. We maintain a foreign currency 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 do not enter into derivatives for trading or other speculative purposes.

All derivatives are recorded on our consolidated balance sheet at fair value. Accounting for the gains and losses resulting from changes in the fair value of derivatives depends on the use of the derivative and whether it qualifies for hedge accounting. Derivatives qualify for hedge accounting when they are formally designated as hedges at inception of the associated derivative contract and are effective in reducing the risk exposure that they are designated to hedge. Our assessment for hedge effectiveness is formally documented at hedge inception and we review hedge effectiveness and measure any ineffectiveness throughout the designated hedge period on at least a quarterly basis.

Changes in the fair value of derivatives that are designated as hedges of the fair value of recognized assets or liabilities or unrecognized firm commitments ("fair value hedges") are recorded currently in earnings and included in other, net, on the consolidated statement of income. Changes in the fair value of derivatives that are designated as hedges of the variability in expected future cash flows associated with existing recognized assets or liabilities or forecasted transactions ("cash flow hedges") are recorded in the accumulated other comprehensive loss section of stockholders' equity. Amounts recorded in accumulated other comprehensive loss associated with cash flow hedges are subsequently reclassified into interest expense and contract drilling expenses as earnings are affected by the underlying hedged forecasted transaction.

Gains and losses on a cash flow hedge, or a portion of a cash flow hedge, that no longer qualify as effective due to an unanticipated change in forecasted transactions are recognized currently in earnings and included in other, net, on the consolidated statement of income based on the change in the market value of the cash flow hedge. When a forecasted transaction is no longer probable of occurring, gains and losses on the cash flow hedge previously recorded in the accumulated other comprehensive loss section of shareholders' equity are reclassified currently into earnings and included in other, net, on the consolidated statement of income. In assessing the effectiveness of a cash flow hedge, the hedge's time value component is excluded from the measurement of hedge effectiveness and recognized currently in earnings in other, net, on the consolidated statement of income.

We occasionally enter into derivatives that economically hedge certain risks, but we do not designate such derivatives as hedges or the derivatives otherwise do not qualify for hedge accounting. In these situations, there generally exists a natural hedging relationship where changes in the fair value of the derivatives offset changes in the fair value of the underlying hedged items. Changes in the fair value of these derivatives are recognized currently in earnings in other, net, on the consolidated statement of income.

Derivatives with asset fair values are reported in other current assets or other assets, net, depending on maturity date. Derivatives with liability fair values are reported in accrued liabilities and other, or other liabilities, depending on maturity date. At December 31, 2007 and 2006, the fair value of our foreign currency derivatives was a net asset of $4.6 million and $4.0 million, respectively.

Income Taxes

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

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

In many of the international jurisdictions where we operate, tax laws relating to the offshore drilling industry are not well developed and change frequently. Furthermore, we may enter into transactions with affiliates or employ other tax planning strategies that generally are subject to complex tax regulations. As a result of the foregoing, the tax liabilities and assets we recognize in our financial statements may differ from the tax positions taken, or expected to be taken, in our tax returns. We adopted the provisions of FASB Interpretation No. 48, "Accounting for Uncertainty in Income Tax - an interpretation of FASB Statement No. 109" on January 1, 2007 (see Note 8 "Income Taxes"). Under FIN 48, our tax positions are evaluated for recognition using a more-likely-than-not threshold, and those tax positions requiring recognition are measured as the largest amount of tax benefit that is greater than 50 percent likely of being realized upon ultimate settlement with a taxing authority that has full knowledge of all relevant information. Interest and penalties relating to income taxes are included in current income tax expense.

Our drilling rigs are frequently moved from one taxing jurisdiction to another based on where they are contracted to perform drilling services. The movement of drilling rigs among taxing jurisdictions may include a transfer of the ownership of the drilling rig among our subsidiaries. Income taxes attributable to gains resulting from intercompany sales of our drilling rigs, as well as the tax effect of any reversing temporary differences resulting from intercompany sales or transfers, are deferred and amortized on a straight-line basis over the remaining useful life of the rig.

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

In December 2007, substantially all of the undistributed earnings of our non-U.S. subsidiaries were distributed to our U.S. parent (see Note 8 "Income Taxes"). It is our policy and intention to indefinitely reinvest all remaining and future undistributed earnings of our non-U.S. subsidiaries in such subsidiaries. Accordingly, no U.S. deferred taxes are provided on the undistributed earnings of our non-U.S. subsidiaries.

Share-Based Employee Compensation

We sponsor several share-based compensation plans that provide equity compensation to our employees, officers and directors. Effective January 1, 2006, we adopted the fair value recognition provisions of Financial Accounting Standards No. 123, (revised 2004) "Share-Based Payment" ("SFAS 123(R)"), using the modified-retrospective transition method. Under that transition method, compensation cost recognized in prior periods was restated to include share option compensation cost previously reported in our pro forma footnote disclosures. Share-based compensation cost is measured at fair value on the date of grant and recognized on a straight line basis over the requisite service period (usually the vesting period). Beginning in 2006, the amount of compensation cost recognized in the consolidated statements of income is based on the awards ultimately expected to vest, and therefore, reduced for estimated forfeitures. (See Note 7 "Employee Benefit Plans" for information concerning the adoption of SFAS 123(R) and its impact on our consolidated financial statements.)

Earnings Per Share

For each of the years in the three-year period ended December 31, 2007, 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 for each of the years in the three-year period ended December 31, 2007 (in millions):

	2007	2006	2005

Weighted average common shares - basic	146.7	152.2	151.7
Potentially dilutive common shares:
Non-vested share awards	.1	.0	.1
Share options	.5	.6	.6

Weighted average common shares - diluted	147.3	152.8	152.4

Options to purchase 503,250 shares of common stock in 2007, 684,000 shares of common stock in 2006 and 15,000 shares of common stock in 2005 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.

Adoption of SAB 108

In September 2006, the Securities and Exchange Commission issued Staff Accounting Bulletin No. 108, "Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements" ("SAB 108"). SAB 108 became effective for our fiscal year ended December 31, 2006. SAB 108 provides guidance on how prior year financial statement misstatements should be taken into consideration when quantifying misstatements in current year financial statements for purposes of determining whether current year financial statements are materially misstated. The techniques most commonly used to accumulate and quantify misstatements were generally referred to as the "rollover" and "iron curtain" approaches. The rollover approach quantifies a misstatement based on the amount of error originating in the current year income statement. The iron curtain approach quantifies a misstatement based on the effects of correcting the misstatement existing in the balance sheet at the end of the current year, irrespective of the misstatement's year of origination. SAB 108 requires consideration of both the rollover and iron curtain approaches in quantifying and evaluating the effects of financial statement misstatements.

During years prior to 2006, we used the rollover approach to quantify and evaluate the effects of financial statement misstatements. In applying the guidance of SAB 108 during 2006, we concluded the two misstatements described below, when evaluated using the iron curtain approach, were material to our December 31, 2006 financial statements.

In 1997, we adopted a policy pursuant to which the depreciation of a rig was suspended during periods it was out of service while undergoing major upgrade and enhancement procedures. In 2005, we discontinued this policy after concluding it was not in accordance with U.S. generally accepted accounting principles. We evaluated the financial statement misstatements resulting from the application of this policy and concluded their impact on each of our prior period financial statements was immaterial. In accordance with SAB 108, we elected to report the cumulative effect of the financial statement misstatements, a $17.6 million increase in accumulated depreciation, $2.6 million decrease in deferred tax liabilities and $15.0 million decrease in retained earnings, effective January 1, 2006.

We maintain relatively constant levels of consumable supplies and spare parts on each of our drilling rigs for use in our operations ("inventory"). Prior to the fourth quarter of 2006, we utilized an accounting policy under which inventory was charged to contract drilling expense at the time it was shipped to a drilling rig, although some of it was temporarily stored and consumed later. We had previously evaluated and concluded the impact of the financial statement misstatements resulting from the difference between the amounts of inventory charged to contract drilling expense and the estimated amounts of inventory consumed was immaterial to our prior period financial statements. During the fourth quarter of 2006, we adopted an inventory accounting policy that recorded the inventory on our drilling rigs at the lower of cost or estimated value in accordance with U.S. generally accepted accounting principles. As part of the adoption of this accounting policy and in accordance with SAB 108, we elected to report the cumulative effect of the financial statement misstatements relating to accounting for inventory, a $32.3 million increase in other current assets, $6.7 million increase in deferred tax liabilities and $25.6 million increase in retained earnings, effective January 1, 2006. The inventory accounting policy discussed above did not have a material impact on our December 31, 2006 financial statements.

2. PROPERTY AND EQUIPMENT

Property and equipment at December 31, 2007 and 2006 consists of the following (in millions):

		2007		2006

Drilling rigs and equipment	$	3,816.4	$	3,586.5
Other		40.4		39.4
Work in progress		847.9		503.6

	$	4,704.7	$	4,129.5

Work in progress at December 31, 2007 primarily consisted of $760.4 million related to the construction of our four ultra-deepwater semisubmersible rigs, ENSCO 8500, ENSCO 8501, ENSCO 8502 and ENSCO 8503 and costs associated with various modification and enhancement projects. Work in progress at December 31, 2006 primarily consisted of $455.0 million related to the construction of ENSCO 108 and three ultra-deepwater semisubmersible rigs, ENSCO 8500, ENSCO 8501 and ENSCO 8502 and costs associated with various modification and enhancement projects.

3. LONG-TERM DEBT

Long-term debt at December 31, 2007 and 2006 consists of the following (in millions):

			2006

4.65% Bonds due 2020	$ 58.5		$ 63.0
6.36% Bonds due 2015	101.4		114.0
6.75% Notes due 2007	--		149.9
7.20% Debentures due 2027	148.7		148.7
Other	1.9		--

	310.5		475.6
Less current maturities	(19.1	)	(167.1	)

Total long-term debt	$291.4		$308.5

Bonds Due 2020 and 2015

In October 2003, we issued $76.5 million of 17-year bonds to provide long-term financing for ENSCO 105. The bonds are guaranteed by MARAD and will be repaid in 34 equal semiannual principal installments of $2.3 million ending in October 2020. Interest on the bonds is payable semiannually, in April and October, at a fixed rate of 4.65%. The bonds are collateralized by ENSCO 105 and we have guaranteed the performance of our obligations under the bonds to MARAD.

In January 2001, we issued $190.0 million of 15-year bonds to provide long-term financing for ENSCO 7500. The bonds are guaranteed by MARAD and will be repaid in 30 equal semiannual principal installments of $6.3 million ending in December 2015. Interest on the bonds is payable semiannually, in June and December, at a fixed rate of 6.36%. The bonds are collateralized by ENSCO 7500 and we have guaranteed the performance of our obligations under the bonds to MARAD.

Notes Due 2007 and Debentures Due 2027

In November 1997, we issued $300.0 million of unsecured debt in a public offering, consisting of $150.0 million of 6.75% Notes due November 15, 2007 (the “Notes”) and $150.0 million of 7.20% Debentures due November 15, 2027 (the “Debentures”). In November 2007, the Notes and accrued interest of $5.1 million were paid in full. Interest on the Debentures is payable semiannually in May and November and may be redeemed at any time at our option, in whole or in part, at a price equal to 100% of the principal amount thereof plus accrued and unpaid interest, if any, and a make-whole premium. The indenture under which the Debentures were issued contains limitations on the incurrence of indebtedness secured by certain liens, and limitations on engaging in certain sale/leaseback transactions and certain merger, consolidation or reorganization transactions. The Debentures are not subject to any sinking fund requirements.

Revolving Credit Facility

We have a $350.0 million unsecured revolving credit facility (the "Credit Facility") with a syndicate of lenders for general corporate purposes. The Credit Facility has a five-year term, expiring in June 2010. Advances under the Credit Facility bear interest at LIBOR plus an applicable margin rate (currently .35% per annum), depending on our credit rating. We pay a facility fee (currently .10% per annum) on the total $350.0 million commitment, which is also based on our credit rating, and pay an additional utilization fee on outstanding advances if such advances equal or exceed 50% of the total $350.0 million commitment. We had no amounts outstanding under the Credit Facility at December 31, 2007 or 2006.

Maturities

The aggregate maturities of our long-term debt, excluding un-amortized discounts of $1.3 million, for each of the five years subsequent to December 31, 2007, are as follows (in millions):


2008	$	19.1
2009		17.2
2010		17.2
2011		17.2
2012		17.2
Thereafter		223.9

Total	$	311.8

4. DERIVATIVE FINANCIAL INSTRUMENTS

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



Net unrealized gains to be reclassified to contract drilling expenses	$	2.8
Net unrealized losses to be reclassified to interest expense		(.7	)

Net unrealized gains to be reclassified to earnings	$	2.1

We utilize derivative instruments and undertake 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. All of our outstanding hedge contracts mature during the next fourteen months. Our management believes 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.

5. COMPREHENSIVE INCOME

The components of our comprehensive income for each of the years in the three-year period ended December 31, 2007, are as follows (in millions):

	2007			2006		2005

Net Income	$	992.0	$	769.7	$	284.9
Other comprehensive income (loss)
Net change in fair value of derivatives		8.2		5.8		(6.3	)
Reclassification of unrealized gains and losses on derivatives from other comprehensive (income) loss into net income		(6.9	)	(.4	)	3.3
Foreign currency translation adjustment		--		--		1.1

Net other comprehensive income (loss)		1.3		5.4		(1.9	)

Comprehensive income	$	993.3	$	775.1	$	283.0

Accumulated other comprehensive loss at December 31, 2007 and 2006 is comprised of net unrealized losses on derivative instruments, net of tax.

6. 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 year ended December 31, 2007 totaled 9.4 million shares at a cost of $521.6 million (an average cost of $55.56 per share).

At December 31, 2007 and December 31, 2006, the outstanding shares of our common stock, net of treasury shares, were 143.9 million and 151.8 million, respectively.

A summary of activity in the various stockholders' equity accounts for each of the years in the three-year period ended December 31, 2007 is as follows (in millions):

							Accumulated
			Additional				Other
	Common Stock		Paid-In		Retained		Comprehensive		Treasury
	Shares	Amounts	Capital		Earnings		Loss		Stock


BALANCE, December 31, 2004	174.5	$17.5	$1,476.0		$ 959.8		$ (9.0	)	$(250.4	)
Net income	--	--	--		284.9		--		--
Cash dividends paid	--	--	--		(15.2	)	--		--
Common stock issued under
share-based compensation
plans, net	2.3	.2	67.6		--		--		(.8	)
Tax deficiency from share-based
compensation expense	--	--	(4.8	)	--		--		--
Share-based compensation expense	--	--	16.1		--		--		--
Net other comprehensive loss	--	--	--		--		(1.9	)	--

BALANCE, December 31, 2005	176.8	17.7	1,554.9		1,229.5		(10.9	)	(251.2	)
Cumulative effect for adoption of SAB 108	--	--	--		10.6		--		--
Cumulative effect for adoption of SFAS 123(R)	--	--	(.8	)	--		--		--
Net income	--	--	--		769.7		--		--
Cash dividends paid	--	--	--		(15.3	)	--		--
Common stock issued under
share-based compensation
plans, net	1.9	.2	41.7		--		--		(1.0	)
Tax benefit from share-based
compensation	--	--	3.6		--		--		--
Repurchase of common stock	--	--	--		--		--		(160.0	)
Share-based compensation expense	--	--	21.9		--		--		--
Net other comprehensive income	--	--	--		--		5.4		--

BALANCE, December 31, 2006	178.7	17.9	1,621.3		1,994.5		(5.5	)	(412.2	)
Cumulative effect for adoption of FIN 48	--	--	--		5.8		--		--
Net income	--	--	--		992.0		--		--
Cash dividends paid	--	--	--		(14.8	)	--		--
Common stock issued under
share-based compensation
plans, net	1.6	.1	35.7		--		--		(6.0	)
Tax benefit from share-based
compensation	--	--	6.6		--		--		--
Repurchase of common stock	--	--	--		--		--		(521.6	)
Share-based compensation expense	--	--	36.9		--		--		--
Net other comprehensive income	--	--	--		--		1.3		--

BALANCE, December 31, 2007	180.3	$18.0	$1,700.5		$2,977.5		$ (4.2	)	$(939.8	)

7. EMPLOYEE BENEFIT PLANS

Adoption of New Accounting Standard

We grant share options and non-vested share awards to our employees, officers and directors. Prior to January 1, 2006, we accounted for share options using the recognition and measurement provisions of Accounting Principals Board Opinion No. 25, "Accounting for Stock Issued to Employees" ("APB 25"), as permitted by Statement of Financial Accounting Standards No. 123, "Accounting for Stock-Based Compensation" ("SFAS 123"). No compensation cost for share options was recognized in net income for periods prior to January 1, 2006, as all share options granted had an exercise price equal to the market value of the underlying common stock on the date of grant. Non-vested share awards were accounted for under the provisions of SFAS 123. Accordingly, compensation cost for non-vested share awards was measured using the market value of the common stock on the date of grant and was recognized on a straight line basis over the requisite service period (usually the vesting period).

Effective January 1, 2006, we adopted the fair value recognition provisions of Financial Accounting Standards No. 123, (revised 2004) "Share-Based Payment" ("SFAS 123(R)"), using the modified-retrospective transition method. Under that transition method, compensation cost recognized in prior periods was restated to include share option compensation cost previously reported in our pro forma footnote disclosures required by SFAS 123. Compensation cost recognized in the year ended December 31, 2005 was restated to include: (a) compensation cost for all share options granted prior to, but not yet vested as of January 1, 2005, based on the grant date fair value estimated in accordance with the original provisions of SFAS 123, and (b) compensation cost for all share options granted during the year ended December 31, 2005, based on the grant-date fair value estimated in accordance with the original provisions of SFAS 123. The December 31, 2005 consolidated balance sheet was restated to reflect all share option compensation cost recognized in periods prior to January 1, 2005, and to reflect compensation cost recognized during the year ended December 31, 2005.

No restatement was necessary in relation to our non-vested share awards upon adoption of SFAS 123(R), as compensation cost related to those awards, based on the fair value of our stock on the date of grant, was previously recognized in the financial statements. Under SFAS 123(R), non-vested share awards will continue to be measured using the market value of the common stock on the date of grant and recognized on a straight line basis over the requisite service period (usually the vesting period).

The following table summarizes share option compensation expense recognized during the year ended December 31, 2005 resulting from the adoption of SFAS 123(R) on January 1, 2006 (in millions, except per share amounts):

Contract Drilling	$ 7	.1
General and administrative	6	.2

Share option compensation expense included
in operating expenses	13	.3
Tax benefit	(4	.2)

Share option compensation expense included in
income from continuing operations	9	.1
Share option compensation expense included in
discontinued operations, net		.1

Total share option compensation expense
included in net income	$ 9	.2

Earnings per share impact - Basic	$.0	6
Earnings per share impact - Diluted	$.0	6

To reflect share option compensation cost recognized during periods prior to January 1, 2006, the December 31, 2005 balance sheet was adjusted upon adoption of SFAS 123(R) to increase deferred tax assets by $6.8 million and additional paid-in capital by $72.6 million, and to decrease retained earnings by $65.8 million.

Prior to the adoption of SFAS 123(R), tax benefits from share-based compensation plans were reported as cash provided by operating activities of continuing operations in the consolidated statements of cash flows. Under SFAS 123(R), the excess or shortfall of tax deductions, resulting from the exercise of share options and vesting of share awards, compared to the tax benefits resulting from the compensation expense recognized in connection with such exercised share options and vested share awards is reported as an excess tax benefit or tax deficiency, as applicable, under financing activities in the consolidated statements of cash flows. As a result of adopting SFAS 123(R) using the modified-retrospective transition method, both the previously reported amounts of cash provided by operating activities of continuing operations and cash used in financing activities in the consolidated statement of cash flows for the year ended December 31, 2005, increased by $4.9 million.

Share-based compensation expense recognized in the consolidated statements of income is based on awards ultimately expected to vest, and therefore, has been reduced for estimated forfeitures. SFAS 123(R) requires forfeitures to be estimated at the time of grant and revised, if necessary, in subsequent periods if actual forfeitures differ from those estimates. Estimated forfeitures were based on historical experience. Prior to the adoption of SFAS 123(R), we accounted for forfeitures as they occurred. On January 1, 2006, we estimated that 13.7% of share options and 8.2% of non-vested share awards were not expected to vest. Accordingly, we recognized a cumulative adjustment to reduce share-based compensation expense by $600,000, net of tax, for unvested share options and non-vested share awards that were recognized in the financial statements as a result of applying the modified-retrospective transition method. The estimate is included in "Cumulative effect of accounting change for adoption of SFAS 123(R), net" on the consolidated statement of income for the year ended December 31, 2006.

Subsequent to the adoption of SFAS 123(R), compensation cost for all equity awards, regardless of when they were granted, is recognized based on the number of awards expected to vest. All subsequent changes in estimated forfeitures, including changes in estimates relating to share options and non-vested share awards granted prior to the adoption of SFAS 123(R), are based on historical experience and will be recognized as a cumulative adjustment to compensation cost in the period in which they occur.

Share Options

In May 2005, our stockholders approved the 2005 Long-Term Incentive Plan (the "2005 Plan"). The 2005 Plan is similar to and essentially replaces our previously adopted 1998 Incentive Plan (the "1998 Plan") and 1996 Non-Employee Directors' Stock Option Plan (the "Directors' Plan"). No further awards will be granted under the previously adopted plans, however, those plans shall continue to apply to and govern awards made thereunder. Under the 2005 Plan, a maximum of 7.5 million new shares are reserved for issuance as awards of share options to officers, non-employee directors and key employees who are in a position to contribute materially to our growth, development and our long-term success. Share options granted to officers and employees generally become exercisable in 25% increments over a four-year period and to the extent not exercised, expire on the seventh anniversary of the date of grant. Share options granted to non-employee directors are immediately exercisable and to the extent not exercised, expire on the seventh anniversary of the date of grant. The exercise price of share options granted under the 2005 Plan equals the market value of the underlying stock on the date of grant. At December 31, 2007, options to purchase 1.9 million shares of our common stock were outstanding under the 2005 Plan.

Share options previously granted under the 1998 Plan become exercisable in 25% increments over a four-year period and to the extent not exercised, expire on the fifth anniversary of the date of grant. Share options previously granted under the Directors' Plan become exercisable six months after the date of grant and expire, if not exercised, five years thereafter. The exercise price of share options granted under the 1998 Plan and the Directors' Plan equals the market value of the underlying stock on the date of grant. At December 31, 2007, options to purchase 600,000 shares of our common stock were outstanding under the 1998 Plan and the Directors' Plan.

The following table summarizes share option compensation expense recognized during each of the years in the three-year period ended December 31, 2007 (in millions):

	2007		2006		2005

Contract drilling	$ 5.8		$ 6.5		$ 7.1
General and administrative	7.8		8.7		6.2

Share option compensation expense included in
operating expenses	13.6		15.2		13.3
Tax benefit	(3.8	)	(4.2	)	(4.2	)

Share option compensation expense included in
income from continuing operations	9.8		11.0		9.1
Share option compensation expense included in
discontinued operations, net	--		--		.1

Total share option compensation expense included
in net income	$ 9.8		$11.0		$ 9.2

The fair value of each option award is estimated on the date of grant using the Black-Scholes option valuation model with the following weighted average assumptions for each of the years in the three-year period ended December 31, 2007:

	2007		2006		2005

Risk-free interest rate	4.8	%	4.9	%	3.5	%
Expected life (in years)	4.7		4.8		5.1
Expected volatility	29.8	%	35.4	%	38.8	%
Dividend yield	.2	%	.2	%	.3	%

Expected volatility is based on the historical volatility of the market price of our common stock over the period of time equivalent to the expected term of the options granted. The expected term of options granted is derived from historical exercise patterns over a period of time equivalent to the term of the options granted. We have not experienced significant differences in the historical exercise patterns among officers, employees and non-employee directors for them to be considered separately for valuation purposes. The risk-free interest rate is based on the implied yield of U.S. Treasury zero-coupon issues on the date of grant with a remaining term approximating the expected term of the options granted.

A summary of share option activity for the year ended December 31, 2007, is as follows (shares and intrinsic value in thousands, term in years):

					Weighted
			Weighted		Average
			Exercise		Contractual		Intrinsic
Share Options	Shares		Price		Term		Value

Outstanding at January 1, 2007	3,204		$36	.25
Granted	535		60	.43
Exercised	(1,140	)	31	.46
Forfeited	(104	)	42	.60

Outstanding at December 31, 2007	2,495		$43	.37	4	.5	$41,139

Exercisable at December 31, 2007	862		$37	.13	3	.6	$19,418

The following table summarizes the value of options granted and exercised during each of the years in the three-year period ended December 31, 2007:

	2007	2006	2005


Weighted-average grant-date fair value of
share options granted (per share)	$20.44	$18.54	$13.02
Intrinsic value of share options exercised during
the year (in millions)	$ 30.0	$ 28.9	$ 20.4

The following table summarizes information about share options outstanding at December 31, 2007 (shares in thousands):

	Options Outstanding			Options Exercisable
		Weighted Average
	Number	Remaining	Weighted Average	Number	Weighted Average
Exercise Prices	Outstanding	Contractual Life	Exercise Price	Exercisable	Exercise Price

$23.40 - $27.85	504	1.6 years	$27.29	247	$27.28
29.55 - 33.55	555	3.7 years	32.91	300	32.49
43.64 - 47.12	345	5.4 years	46.51	167	46.45
50.09 - 62.99	1,091	5.9 years	55.12	148	52.53

	2,495	4.5 years	$43.37	862	$37.13

As of December 31, 2007, there was $21.1 million of total unrecognized compensation cost related to share options granted, which is expected to be recognized over a weighted-average period of 2.5 years.

Non-Vested Share Awards

Under the 2005 Plan, non-vested share awards may be issued to our officers, non-employee directors and key employees who are in a position to contribute materially to our growth, development and our long-term success. Prior to the adoption of the 2005 Plan, non-vested share awards were issued under the 1998 Plan and generally vested at a rate of 10% per year, as determined by a committee of the Board of Directors. No further non-vested share awards will be granted under the 1998 Plan, however, that plan shall continue to apply to and govern awards issued thereunder. The 2005 Plan provides for the issuance of non-vested share awards up to a maximum of 2.5 million new shares. Under the 2005 Plan, grants of non-vested share awards generally vest at a rate of 20% per year, as determined by a committee of the Board of Directors. All non-vested share awards have voting and dividend rights effective on the date of grant. Compensation expense is measured using the market value of the common stock on the date of grant and is recognized on a straight-line basis over the requisite service period (usually the vesting period). At December 31, 2007, there were 1.3 million shares of common stock available for non-vested share awards under the 2005 Plan.

During the first quarter of 2007, we entered into a retirement agreement with our former CEO and non-executive Chairman of our Board of Directors, the cost of which was recognized through his May 22, 2007 retirement date. The agreement provided that upon retirement, he would receive a grant of 92,000 non-vested share awards which will vest at a rate of one-third per year upon each of the first three anniversaries of his retirement date. Furthermore, the agreement modified the vesting term of 28,750 unvested share options and 105,000 non-vested share awards previously granted to him so that such awards would become fully vested upon his retirement. We recognized an additional $10.1 million of non-vested share award compensation expense during 2007 as a result of the retirement agreement, of which $5.0 million related to the modification of his previous awards.

The following table summarizes non-vested share award compensation expense recognized during each of the years in the three-year period ended December 31, 2007 (in millions):

	2007		2006		2005

Contract drilling	$ 5.5		$2.7		$1.0
General and administrative	17.5		4.0		1.6

Non-vested share award compensation expense
included in operating expenses	23.0		6.7		2.6
Tax benefit	(7.1	)	(2.0	)	(.8	)

Total non-vested share award compensation
expense included in net income	$15.9		$4.7		$1.8

The following table summarizes the value of non-vested share awards granted and vested during each of the years in the three-year period ended December 31, 2007:

	2007	2006	2005


Weighted-average grant-date fair value of
non-vested share awards granted (per share)	$60.18	$49.09	$35.34
Total fair value of non-vested share awards
vested during the period (in millions)	$ 19.8	$ 4.8	$ 2.9

A summary of non-vested share award activity for the year ended December 31, 2007, is as follows (shares in thousands):

			Weighted
			Average
			Grant-Date
Non-Vested Share Award	Shares		Fair Value

Non-vested at January 1, 2007	989		$39.83
Granted	548		60.18
Vested	(334	)	36.56
Forfeited	(50	)	47.98

Non-vested at December 31, 2007	1,153		$50.11

As of December 31, 2007, there was $44.9 million of total unrecognized compensation cost related to non-vested share awards granted, which is expected to be recognized over a weighted-average period of 4.5 years.

Savings Plan

We have a profit sharing plan (the “ENSCO Savings Plan”) which covers eligible employees, as defined. Profit sharing contributions require Board of Directors approval and may be in cash or grants of our common stock. We recorded profit sharing contribution provisions of $14.2 million, $12.6 million and $5.0 million for the years ended December 31, 2007, 2006 and 2005, respectively.

The ENSCO Savings Plan includes a 401(k) savings plan feature which allows eligible employees to make tax deferred contributions to the plan. We make matching cash contributions which vest over a three year period based on the amount of employee contributions and rates set by our Board of Directors. We match 100% of the amount contributed by the employee up to a maximum of 5% of eligible salary. Matching contributions totaled $5.0 million, $4.7 million and $4.2 million in 2007, 2006 and 2005, respectively. We also have reserved 1.0 million shares of common stock for issuance as matching contributions under the ENSCO Savings Plan.

Supplemental Executive Retirement Plan

The ENSCO 2005 Supplemental Executive Retirement Plan (the "SERP") provides a tax deferred savings plan for certain highly compensated employees whose participation in the profit sharing and 401(k) savings plan features of the ENSCO Savings Plan is restricted due to funding and contribution limitations of the Internal Revenue Code. The SERP is a non-qualified plan where eligible employees may defer a portion of their compensation for use after retirement. Eligibility for participation is determined by our Board of Directors or a Board committee. The matching provisions of the SERP are identical to the ENSCO Savings Plan, except that matching contributions under the SERP are further limited by contribution amounts under the 401(k) savings plan feature of the ENSCO Savings Plan. In conjunction with the employment of our new Chief Executive Officer in February of 2006, we made a discretionary $1.1 million cash contribution to the officer's SERP account for pension and other benefits forfeited at his previous employer. The contribution is fully vested and included in our matching contributions for 2006. Matching cash contributions totaled $79,000 in 2007, $1.2 million in 2006 and $52,000 in 2005. A SERP liability of $15.2 million and $13.2 million is included in other liabilities at December 31, 2007 and 2006, respectively.

8. INCOME TAXES

We had income of $357.7 million, $500.2 million and $208.2 million from our continuing operations before income taxes in the U.S. and income of $896.0 million, $511.1 million and $162.3 million from our continuing operations before income taxes in non-U.S. countries for the years ended December 31, 2007, 2006 and 2005, respectively.

The components of the provision for income taxes from continuing operations for each of the years in the three-year period ended December 31, 2007 are as follows (in millions):

	2007		2006	2005

Current income tax expense:
Federal	$113.4		$144.5	$ 59.9
State	4.8		1.0	1.3
International	143.1		91.3	32.4

	261.3		236.8	93.6


Deferred income tax expense (benefit):
Federal	4.3		15.8	11.5
International	(3.9	)	.1	(4.6	)

	.4		15.9	6.9


Total income tax expense	$261.7		$252.7	$100.5

Significant components of deferred income tax assets (liabilities) as of December 31, 2007 and 2006 are comprised of the following (in millions):

	2007		2006

Deferred tax assets:
Accrued liabilities	$ 13.7		$ 7.8
Share-based compensation	9.3		6.6
Deferred revenue	9.0		3.6
Other	2.7		.7

Total deferred tax assets	34.7		18.7

Deferred tax liabilities:
Property and equipment	(311.4	)	(322.7	)
Intercompany transfers of property	(43.7	)	(31.2	)
Deferred costs	(15.6	)	(7.1	)
Other	(2.9	)	(2.0	)

Total deferred tax liabilities	(373.6	)	(363.0	)

Net deferred tax liability	$(338.9	)	$(344.3	)


Net current deferred tax asset	$ 13.1		$ 12.2
Net noncurrent deferred tax liability	(352.0	)	(356.5	)

Net deferred tax liability	$(338.9	)	$(344.3	)

The income tax rates imposed in the taxing jurisdictions in which our non-U.S. 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 revenue, statutory or negotiated deemed profits, or other bases utilized under local tax laws, rather than to net income. In addition, our drilling rigs are frequently moved from one taxing jurisdiction to another. As a result, our consolidated effective income tax rate may vary substantially from year to year, depending on the relative components of our earnings generated in taxing jurisdictions with higher tax rates and lower tax rates. The consolidated effective income tax rate on continuing operations for each of the years in the three-year period ended December 31, 2007, differs from the U.S. statutory income tax rate as follows:

	2007		2006		2005

Statutory income tax rate	35.0	%	35.0	%	35.0	%
Foreign taxes	(13.6	)	(8.6	)	(7.0	)
Net benefit in connection with settlements
with tax authorities and other resolutions
of tax issues relating to prior years	(1.1	)	(.5	)	(1.2	)
Change in valuation allowance	--		(.2	)	.4
Other	.6		(.7	)	(.1	)

Effective income tax rate	20.9	%	25.0	%	27.1	%

The income tax provisions for the years ended December 31, 2007, 2006 and 2005 include net benefits of $14.5 million, $7.3 million and $4.6 million, respectively, relating to settlements with tax authorities or other resolutions of prior year tax issues. During 2006, we reversed a $1.7 million valuation allowance established in 2005 against a $5.5 million deferred tax asset for net operating loss carryforwards in Denmark, after determining it was more-likely-than-not that the net operating loss carryforwards would be fully utilized. We utilized the remaining $1.3 million of these net operating loss carryforwards during 2007 and at December 31, 2007, we had no net operating loss carryforwards.

Unrecognized Tax Benefits

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. At December 31, 2007, we had $13.5 million of unrecognized tax benefits, of which $10.0 million would impact our effective tax rate if recognized. A reconciliation of the beginning and ending amount of unrecognized tax benefits for the year ended December 31, 2007, is as follows (in millions):


Balance at January 1, 2007	$19.3
Increases in unrecognized tax benefits as a result of tax positions taken during the current year	1.3
Increases in unrecognized tax benefits as a result of tax positions taken during prior years	4.5
Decreases in unrecognized tax benefits as a result of tax positions taken during prior years	(11.0)
Settlements with taxing authorities	(.5)
Lapse of applicable statutes of limitations	(.6)
Impact of foreign currency exchange rates	.5

Balance at December 31, 2007	$13.5

Current income tax expense for the year ended December 31, 2007, includes $2.3 million of interest and penalties. Accrued interest and penalties at December 31, 2007, totaled $19.2 million and is included in other liabilities.

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 either 2002 and subsequent years or 2003 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 was inconsistent with a tax position we have taken and previously recognized approximately $41.3 million of aggregate tax benefits during the current and previous years. Upon evaluation of the draft interpretation, we concluded that our uncertain tax position in this jurisdiction continued to meet the more-likely-than-not recognition threshold of FIN 48. However, we also concluded it was reasonably possible that certain events could occur within the following twelve months that would have caused us to re-evaluate our tax position. During the fourth quarter of 2007, the taxing authority issued a final interpretation that differed from the draft interpretation issued previously and that reaffirmed our previous conclusion that our uncertain tax position met the more-likely-than-not recognition threshold of FIN 48. Furthermore, based on an evaluation of the final ruling, in conjunction with professional guidance and other available qualitative information, we determined the likelihood that we will re-evaluate this tax position within the next twelve months is remote.

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 year ended December 31, 2007, consisting of $9.0 million for the previously unrecognized tax benefit and $2.1 million of previously accrued penalties and interest. The $9.0 million tax benefit is included above in the reconciliation of unrecognized tax benefits for the year ended December 31, 2007, under "Decreases in unrecognized tax benefits as a result of tax positions taken during prior years."

Statutes of limitations applicable to certain of our tax positions will lapse during 2008 and, therefore, it is reasonably possible that our unrecognized tax benefits will decrease during the next twelve months for the aggregate $3.2 million of unrecognized tax benefits associated with these tax positions. At December 31, 2007, $16.0 million of accrued interest and penalties related to these unrecognized tax benefits.

Intercompany transfer of drilling rigs

In December 2007, we transferred ownership of three drilling rigs among two of our subsidiaries. The income tax liability attributable to the gain resulting from the intercompany sale of the three rigs totaled $96.5 million and will be paid by the selling subsidiary in 2008. However, recognition of the $96.5 million of income taxes payable has been deferred and is being amortized on a straight-line basis over the remaining useful lives of the associated drilling rigs, which range from three to eight years. Similarly, the tax effects of $54.8 million of reversing temporary differences of the selling subsidiary have also been deferred and are being amortized on the same basis and over the same periods as described above.

Undistributed Earnings of our Non-U.S. Subsidiaries

We do not provide U.S. deferred taxes on the undistributed earnings of our non-U.S. subsidiaries because our policy and intention is to reinvest such earnings indefinitely.

In December 2007, our primary non-U.S. subsidiary declared a $1,200.0 million dividend to its U.S. parent, which included the distribution of its $922.1 million of earnings and the return of $277.9 million of previously invested capital. The U.S. tax liability on the earnings repatriation was only $4.1 million, as we utilized foreign tax credits to offset substantially all previously untaxed earnings distributed. At December 31, 2007, $500.0 million of the dividend had been paid and the remaining $700.0 million is scheduled to be paid during 2008.

The earnings distribution was undertaken because it provided, with minimal U.S. tax impact, substantial funding flexibility for management initiatives, including the continuation and/or extension of our ongoing stock repurchase program and greater options relative to future fleet expansion efforts. This distribution was made in consideration of unique circumstances and, accordingly, it does not change our intention to reinvest the undistributed earnings of our non-U.S. subsidiaries indefinitely. Furthermore, both our U.S. and non-U.S. subsidiaries have significant net assets, liquidity, contract backlog and other financial resources available to meet their operational and capital investment requirements and otherwise allow management to continue to maintain its policy of reinvesting the undistributed earnings of its non-U.S. subsidiaries indefinitely.

At December 31, 2007, the undistributed earnings of our non-U.S. subsidiaries totaled $14.7 million and are indefinitely reinvested. Should we make a distribution of these earnings in the form of dividends or otherwise, we may be subject to additional U.S. income taxes.

9. 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, which is included in "Gain on disposal of discontinued operations, net" in the consolidated statement of income for the year ended December 31, 2006. The operating results of ENSCO 25 have been reclassified as discontinued operations in the consolidated statements of income for each of the years in the two-year period ended December 31, 2006.

The ENSCO 29 platform rig sustained substantial damage as a consequence of Hurricane Katrina in the third quarter of 2005. In January 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 $7.5 million net book value of the rig, 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 consolidated statement of income for the year ended December 31, 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 liability insurance coverage. (See Note 10 "Commitments and 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 consolidated statements of income for each of the years in the two-year period ended December 31, 2006.

On October 20, 2005, we sold the ENSCO 26 platform rig for $12.0 million and recognized a minimal gain. The operating results of ENSCO 26 have been reclassified as discontinued operations in the consolidated statement of income for the year ended December 31, 2005.

On June 30, 2005, we sold our South America/Caribbean barge rigs for $59.6 million and recognized a pre-tax gain of $9.6 million, which is included in "Gain on disposal of discontinued operations, net" in the consolidated statement of income for the year ended December 31, 2005. The net book value of the rigs was $45.1 million on the date of sale. The operating results of the six South America/Caribbean barge rigs have been reclassified as discontinued operations in the consolidated statement of income for the year ended December 31, 2005.

The ENSCO 64 jackup rig sustained substantial damage during Hurricane Ivan in September 2004. On April 15, 2005, beneficial ownership of ENSCO 64 effectively transferred to our insurance underwriters because the rig was a constructive total loss under the terms of our insurance policies. Accordingly, we transferred beneficial ownership of ENSCO 64 to insurance underwriters and received the rig's insured value of $65.0 million. On the date of transfer, the net book value of the rig was $52.8 million. We recognized a pre-tax gain of $11.7 million upon receipt of the insurance proceeds, which is included in "Gain on disposal of discontinued operations, net" in the consolidated statement of income for year ended December 31, 2005. The operating results of ENSCO 64 have been reclassified as discontinued operations in the consolidated statement of income for the year ended December 31, 2005.

Following is a summary of income from discontinued operations for each of the years in the two-year period ended December 31, 2006 (in millions):



Revenues	$14.9		$27.5
Operating expenses and other	9.7		25.6

Operating income before income taxes	5.2		1.9

Income tax expense	(1.9	)	(.9	)
Gain on disposal of discontinued operations, net	7.2		13.9

Income from discontinued operations	$10.5		$14.9

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

10. COMMITMENTS AND CONTINGENCIES

Leases

We are obligated under leases for certain of our offices and equipment. Rental expense relating to operating leases was $12.0 million in 2007, $11.3 million in 2006 and $8.9 million in 2005. Future minimum rental payments under our noncancellable operating lease obligations having initial or remaining lease terms in excess of one year are as follows: $6.4 million in 2008; $3.6 million in 2009; $1.7 million in 2010; $1.5 million in 2011 and $9.2 million thereafter.

Capital Commitments

As of December 31, 2007, we had an aggregate contractual commitment of $719.9 million related to the construction of our four ENSCO 8500 Series® rigs. We anticipate that approximately $353.1 million and $248.3 million of the total commitment will be paid in 2008 and 2009, respectively. However, the actual timing of these expenditures may vary based on the completion of various construction milestones, which are beyond our control.

Contingencies

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. A Labor Tribunal in Aberdeen, Scotland rendered decisions in claims involving other offshore service companies on February 21, 2008 and we are currently evaluating the extent to which the decisions will impact us. 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, 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 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.

11. SEGMENT INFORMATION

Our operations consist of one reportable segment: contract drilling services. At December 31, 2007, our contract drilling segment owned and operated a fleet of 46 offshore drilling rigs, including 44 jackup rigs, one ultra-deepwater semisubmersible rig and one barge rig. At December 31, 2007, our contract drilling segment also included four ultra-deepwater semisubmersible rigs under construction.

Our operations are concentrated in three geographic regions: Asia Pacific (which includes Asia, the Middle East, Australia and New Zealand), Europe/Africa, and North and South America. At December 31, 2007, our Asia Pacific operations consisted of 19 jackup rigs deployed in various locations and one barge rig located in Indonesia. Our Europe/Africa operations consisted of 10 jackup rigs, eight of which were deployed in various territorial waters of the North Sea and two of which were located offshore Tunisia. Our North and South America operations consisted of 15 jackup rigs and one ultra-deepwater semisubmersible rig. Fourteen of our North and South America jackup rigs and our one ultra-deepwater semisubmersible rig were located in the Gulf of Mexico and one jackup rig was located offshore Venezuela.

We attribute revenues to the geographic location where such revenue is earned and assets to the geographic location of the drilling rig at December 31 of the applicable year. For new construction projects, assets are attributed to the location of future operation if known or to the location of construction if the ultimate location of operation is undetermined. Information by country for those countries that account for more than 10% of total revenues or 10% of our long-lived assets is as follows (in millions):

	Revenues			Long-lived Assets
	2007	2006	2005	2007	2006	2005

United States	$ 529.9	$ 709.9	$414.2	$1,637.1	$1,219.5	$1,060.0
United Kingdom	392.5	325.9	157.8	425.5	242.7	381.3
Other foreign countries	1,221.4	777.7	462.3	1,296.3	1,498.2	1,222.3

Total	$2,143.8	$1,813.5	$1,034.3	$3,358.9	$2,960.4	$2,663.6

12. SUPPLEMENTAL FINANCIAL INFORMATION

Consolidated Balance Sheet Information

Accounts receivable, net at December 31, 2007 and 2006 consists of the following (in millions):

	2007		2006

Trade	$372.2		$332.0
Other	16.4		10.8

	388.6		342.8
Allowance for doubtful accounts	(5.4	)	(4.0	)

	$383.2		$338.8

Other current assets at December 31, 2007 and 2006 consists of the following (in millions):

	2007	2006

Inventory	$ 39.7	$35.4
Deferred mobilization costs	26.3	9.9
Deferred tax assets	15.1	12.2
Prepaid taxes	9.5	4.3
Prepaid expenses	8.3	9.3
Deferred regulatory certification and compliance costs	7.0	2.4
Derivative assets	6.2	3.9
Other	4.5	5.2

	$116.6	$82.6

Other assets, net at December 31, 2007 and 2006 consists of the following (in millions):

	2007	2006

Prepaid taxes on intercompany transfers of property	$114.4	$20.8
Supplemental executive retirement plans	15.8	13.7
Deferred finance costs	3.9	4.9
Deferred regulatory certification and compliance costs	3.4	1.7
Deferred mobilization costs	2.9	5.1
Other	4.0	4.4

	$144.4	$50.6

Accrued liabilities and other at December 31, 2007 and 2006 consists of the following (in millions):

	2007	2006

Taxes	$195.1	$ 58.4
Personnel	49.6	44.8
Other operating expenses	58.8	42.3
Capital expenditures	96.1	27.2
Deferred and prepaid revenue	61.2	27.2
Other	4.8	5.5

	$465.6	$205.4

Consolidated Statement of Income Information

Maintenance and repairs expense related to continuing operations for each of the years in the three-year period ended December 31, 2007 is as follows (in millions):

		2007		2006		2004

Maintenance and repairs expense		$100.4		$74.5		$62.2

Consolidated Statement of Cash Flows Information

Cash paid for interest and income taxes for each of the years in the three-year period ended December 31, 2007 is as follows (in millions):

	2007	2006	2005

Interest, net of amounts capitalized	$ 4.6	$ 15.3	$ 29.7
Income taxes	214.3	206.3	143.1

Capitalized interest totaled $30.4 million in 2007, $18.9 million in 2006 and $8.9 million in 2005. Excluded from investing activities on our consolidated statements of cash flows were capital expenditure accruals of $96.1 million in 2007, $27.2 million in 2006, and $36.8 million in 2005.

Financial Instruments

The carrying amounts and estimated fair values of our debt instruments at December 31, 2007 and 2006 are as follows (in millions):

	2007		2006
		Estimated		Estimated
	Carrying	Fair	Carrying	Fair
	Amount	Value	Amount	Value

4.65% Bonds, including current maturities	$ 58.5	$ 54.7	$ 63.0	$ 60.4
6.36% Bonds, including current maturities	101.4	108.7	114.0	118.7
6.75% Notes	--	--	149.9	151.4
7.20% Debentures	148.7	165.3	148.7	169.3

The estimated fair values of our debt instruments were determined using quoted market prices or third party valuations. The estimated fair value of our cash and cash equivalents, receivables, trade payables and other liabilities approximated their carrying values at December 31, 2007 and 2006. We have cash, receivables and payables denominated in foreign currencies. These financial assets and liabilities create exposure to foreign currency exchange risk. When warranted, we hedge such risk by purchasing options or futures contracts. We do not enter into such contracts for trading purposes or to engage in speculation. At December 31, 2007 and 2006, the fair value of such contracts was a net asset of $4.6 million and $4.0 million, respectively.

Concentration of Credit Risk

We are exposed to credit risk relating to our receivables from customers, our cash and cash equivalents and our use of derivative instruments in connection with the management of foreign currency risk. We minimize our credit risk relating to receivables from customers, which consist primarily of major international and independent oil and gas producers as well as government-owned oil companies, by performing ongoing credit evaluations. We also maintain reserves for potential credit losses, which to date have been within management's expectations. We minimize our credit risk relating to cash and investments by focusing on diversification and quality of instruments. Cash balances are maintained in major, highly-capitalized commercial banks. Cash equivalents consist of a portfolio of high-grade instruments. Custody of cash equivalents is maintained at several major financial institutions and we monitor the financial condition of those financial institutions. We minimize our credit risk relating to the counterparties of our derivative instruments by transacting with multiple, high-quality counterparties, thereby limiting exposure to individual counterparties, and by monitoring the financial condition of those counterparties.

During 2007 and 2006, no customer provided more than 10% of consolidated revenues. During 2005, one customer provided 12%, or $127.0 million, of consolidated revenues.

13. UNAUDITED QUARTERLY FINANCIAL DATA

A summary of unaudited quarterly consolidated income statement data for the years ended December 31, 2007 and 2006 is as follows (in millions, except per share amounts):

2007	First Quarter		Second Quarter		Third Quarter	Fourth Quarter	Year


Operating revenues	$514.1		$548.6		$551.9	$529.2	$2,143.8

Operating expenses
Contract drilling	162.8		168.8		178.7	173.8	684.1
Depreciation	45.1		46.8		47.1	45.3	184.3
General and administrative	16.0		19.1		11.5	12.9	59.5

Operating income	290.2		313.9		314.6	297.2	1,215.9

Interest income	6.2		6.3		7.1	6.7	26.3
Interest expense, net	(1.1	)	(.8	)	--	--	(1.9	)
Other income, net	4.5		2.3		2.7	3.9	13.4

Income from continuing operations before
income taxes	299.8		321.7		324.4	307.8	1,253.7
Provision for income taxes	67.5		67.3		57.7	69.2	261.7


Net income	$232.3		$254.4		$266.7	$238.6	$992.0


Earnings per share
Basic	$ 1.55		$ 1.72		$ 1.83	$ 1.66	$ 6.76
Diluted	$ 1.54		$ 1.72		$ 1.82	$ 1.66	$ 6.73

2006	First Quarter		Second Quarter		Third Quarter		Fourth Quarter		Year

Operating revenues	$381.6		$475.2		$486.1		$470.6		$1,813.5

Operating expenses
Contract drilling	127.9		146.4		150.5		151.9		576.7
Depreciation	42.0		44.1		44.3		44.6		175.0
General and administrative	10.4		10.5		11.3		12.4		44.6

Operating income	201.3		274.2		280.0		261.7		1,017.2

Interest income	2.3		2.7		4.3		5.6		14.9
Interest expense, net	(4.2	)	(4.9	)	(4.5	)	(2.9	)	(16.5	)
Other expense, net	(1.7	)	(1.2	)	(.4	)	(1.0	)	(4.3	)

Income from continuing operations before
income taxes and cumulative effect of
accounting change	197.7		270.8		279.4		263.4		1,011.3
Provision for income taxes	53.5		76.8		64.7		57.7		252.7

Income from continuing operations	144.2		194.0		214.7		205.7		758.6
Income from discontinued operations, net	5.0		.7		.1		4.7		10.5
Cumulative effect of accounting change, net	.6		--		--		--		.6


Net income	$149.8		$194.7		$214.8		$210.4		$ 769.7


Earnings per share - basic
Continuing operations	$ .94		$ 1.27		$ 1.41		$ 1.36		$ 4.98
Discontinued operations	.03		.00		.00		.03		.07
Cumulative effect of accounting change	.00		--		--		--		.00

	$ .98		$ 1.27		$ 1.41		$ 1.39		$ 5.06


Earnings per share - diluted
Continuing operations	$ .94		$ 1.26		$ 1.40		$ 1.36		$ 4.96
Discontinued operations	.03		.00		.00		.03		.07
Cumulative effect of accounting change	.00		--		--		--		.00

	$ .97		$ 1.27		$ 1.40		$ 1.39		$ 5.04

14. SUBSEQUENT EVENT

At February 25, 2008, we held $84.1 million of long-term debt instruments with variable interest rates periodically reset through an auction process ("auction rate securities"). Recent auctions associated with $57.8 million of our auction rate securities failed and the remaining $26.3 million of our auction rate securities that have not experienced auction failures are scheduled to undergo auctions in the next few days. An auction failure, which is not a default in the underlying debt instrument, occurs when there are more sellers than buyers at a scheduled interest rate auction date and parties desiring to sell their securities are unable to do so.

When an auction fails, the interest rate is adjusted according to the provisions of the associated security agreement, which generally results in an interest rate that is significantly higher than the interest rate the issuer pays in connection with successful auctions. Accordingly, issuers of auction rate securities generally have a strong incentive to refinance their auction rate securities if they believe future auction failures are likely. All of our auction rate securities are currently rated Aaa by Moody's, AAA by Standard & Poor's and/or AAA by Fitch, which is the highest rating issued by each respective rating agency. An aggregate $75.3 million of our auction rate securities were issued by state agencies and are supported by student loans whose repayment is substantially guaranteed by the U.S. government under the Federal Family Education Loan Program. The remaining $8.8 million of our auction rate securities were issued by municipalities and their repayment is insured by a bond insurance company that currently maintains a financial strength rating of Aaa by Moody's, AAA by Standard & Poor's and AAA by Fitch.

The auction failures and resulting lack of liquidity have developed very recently and are affecting the entire auction rate securities market. We are currently unable to determine whether the current situation will be temporary, whether issuers of auction rate securities will attempt and/or be able to refinance their debt, whether the credit ratings of our auction rate securities and insurer will deteriorate, or the impact that these and other events will have on the valuations of our auction rate securities. While we acquired our auction rate securities with the intention of holding them for a very short period of time, we do not expect to experience any liquidity problems or alter any business plans if we maintain our investment in these auction rate securities indefinitely.

All of our auction rate securities were originally acquired in January 2008 and we did not own any auction rate securities at December 31, 2007.

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

Not applicable.

Item 9A. Controls and Procedures

CONCLUSION REGARDING THE EFFECTIVENESS OF DISCLOSURE CONTROLS AND PROCEDURES

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

During the fiscal quarter ended December 31, 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. See "Item 8. Financial Statements and Supplementary Data" for Management's Report on Internal Control Over Financial Reporting.

Item 9B. Other Information

Not applicable.

PART III

Item 10. Directors, Executive Officers and Corporate Governance

The information required by this item with respect to our directors, corporate governance matters and committees of the Board of Directors is contained in our Proxy Statement for the Annual Meeting of Stockholders ("the Proxy Statement") to be filed with the Commission not later than 120 days after the end of our fiscal year ended December 31, 2007 and is incorporated herein by reference.

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

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

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

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

Item 11. Executive Compensation

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

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

The following table sets forth, as of December 31, 2007, certain information related to our compensation plans under which shares of our Common Stock are authorized for issuance:

					Number of securities
					remaining available for
	Number of securities				future issuance under
	to be issued upon		Weighted-average		equity compensation
	exercise of		exercise price of		plans (excluding
	outstanding options,		outstanding options,		securities reflected in
Plan category	warrants and rights		warrants and rights		column (a))

	(a)		(b)		(c)

Equity compensation plans approved by security holders		2,494,491		$43.37		6,579,542
Equity compensation plans not approved by security holders*		426		$23.40		--

Total		2,494,917		$43.37		6,579,542

*		In connection with the acquisition of Chiles Offshore Inc. ("Chiles") in 2002, we assumed Chiles' stock option plan and the outstanding stock options thereunder. At December 31, 2007, options to purchase 426 shares of our common stock, at a weighted-average exercise price of $23.40 per share, were outstanding under this plan. No shares of our common stock are available for future issuance under this plan, no further share options will be granted under this plan and the plan will be terminated upon the earlier of the exercise or expiration date of the last outstanding option.

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

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

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

Item 14. Principal Accounting Fees and Services

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

PART IV

Item 15. Exhibits, Financial Statement Schedules

(a)

The following documents are filed as part of this report:

1. Financial Statements

Reports of Independent Registered Public Accounting Firm

Consolidated Statements of Income

Consolidated Balance Sheets

Consolidated Statements of Cash Flows

		Notes to Consolidated Financial Statements	50

2. Financial Statement Schedules:

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

3. Exhibits

Exhibit
No.

3.1

Amended and Restated Certificate of Incorporation of the Company (incorporated by reference to Exhibit A to the Company's Definitive Proxy Statement filed with the Commission on March 21, 2005, File No. 1-8097).

3.2

Revised and Restated Bylaws of the Company, effective November 6, 2007 (incorporated by reference to Exhibit 3.1 to the Registrant's Current Report on Form 8-K dated November 6, 2007, File No. 1-8097).

4.1

Certificate of Designation of Series A Junior Participating Preferred Stock of the Company (incorporated by reference to Exhibit 4.6 to the Registrant's Annual Report on Form 10-K/A for the year ended December 31, 1995, File No. 1-8097).

4.2

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

4.3

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

4.4

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

⁺10.1

ENSCO International Incorporated 1996 Non-Employee Directors Stock Option Plan (incorporated by reference to Exhibit 4.1 to the Registrant's Registration Statement on Form S-8 filed August 23, 1996, Registration No. 333-10733).

⁺10.2

Amendment to ENSCO International Incorporated Incentive Plan, dated November 11, 1997 (incorporated by reference to Exhibit 10.2 to the Registrant's Annual Report on Form 10-K for the year ended December 31, 1997, File No. 1-8097).

⁺10.3

ENSCO International Incorporated Savings Plan, as revised and restated (incorporated by reference to Exhibit 10.17 to the Registrant's Annual Report on Form 10-K for the year ended December 31, 1997, File No. 1-8097).

10.4

Indemnification Agreement between the Company and its officers and directors (incorporated by reference to Exhibit 10.19 to the Registrant's Annual Report on Form 10-K for the year ended December 31, 1997, File No. 1-8097).

⁺10.5

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

10.6

Bond Purchase Agreement of ENSCO Offshore Company dated January 22, 2001, concerning $190,000,000 of United States Government Guaranteed Ship Financing Obligations (incorporated by reference to Exhibit 10.1 to the Registrant's Quarterly Report on Form 10-Q for the quarter ended March 31, 2001, File No. 1-8097).

10.7

United States Government Guaranteed Ship Financing Bond issued by ENSCO Offshore Company dated January 25, 2001 (incorporated by reference to Exhibit 10.2 to the Registrant's Quarterly Report on Form 10-Q for the quarter ended March 31, 2001, File No. 1-8097).

10.8

Supplement No.1, dated January 25, 2001, to the Trust Indenture dated December 15, 1999, between ENSCO Offshore Company and Bankers Trust Company (incorporated by reference to Exhibit 10.3 to the Registrant's Quarterly Report on Form 10-Q for the quarter ended March 31, 2001, File No. 1-8097).

10.9

Ratification of Guaranty by ENSCO International Incorporated in favor of the United States of America dated January 25, 2001 and associated Guaranty Agreement by ENSCO International Incorporated in favor of the United States of America dated December 15, 1999 (incorporated by reference to Exhibit 10.4 to the Registrant's Quarterly Report on Form 10-Q for the quarter ended March 31, 2001, File No. 1-8097).

⁺10.10

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

⁺10.11

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

⁺10.12

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

10.13

Amended and Restated Credit Agreement among ENSCO International Incorporated and ENSCO Offshore International Company as Borrowers, the lenders signatory thereto, Citigroup Global Markets Inc. and J.P. Morgan Securities Inc. as Joint Lead Arrangers and Joint Book Managers, Citibank, N.A. as Administrative Agent, JPMorgan Chase Bank, NA, as Syndication Agent, DnB NOR Bank ASA, New York Branch as Issuing Bank, The Bank Of Tokyo-Mitsubishi, Ltd., DnB NOR Bank ASA, New York Branch, and Wells Fargo Bank, N.A. as Co-Documentation Agents, and Mizuho Corporate Bank, Ltd. and SunTrust Bank as Co-Agents concerning a $350 million unsecured revolving credit facility, dated as of June 23, 2005 (incorporated by reference to Exhibit 10.1 to the Registrant's Current Report on Form 8-K dated June 23, 2005, File No. 1-8097).

⁺10.14

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

⁺10.15

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

⁺10.16

Amendment to the ENSCO International Incorporated 1996 Non-Employee Directors Stock Option Plan (incorporated by reference to Exhibit 10.21 to the Registrant's Annual Report on Form 10-K for the year ended December 31, 2002, File No. 1-8097).

⁺10.17

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

⁺10.18

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

⁺10.19

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

⁺10.20

ENSCO 2005 Supplemental Executive Retirement Plan, effective January 1, 2005 (incorporated by reference to Exhibit 99.1 to the Registrant's Current Report on Form 8-K dated January 5, 2005, File No. 1-8097).

⁺10.21

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

⁺10.22

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

⁺10.23

ENSCO 2005 Long-Term Incentive Plan, effective January 1, 2005 (incorporated by reference to Exhibit B to the Company's Definitive Proxy Statement filed with the Commission on March 21, 2005, File No. 1-8097).

⁺10.24

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

⁺10.25

Amendment No. 6 to the ENSCO Savings Plan (As Revised and Restated Effective January 1, 1997), dated as of September 1, 2005 (incorporated by reference to Exhibit 10.1 to the Registrant's Quarterly Report of Form 10-Q for the quarter ended September 30, 2005, File No. 1-8097).

⁺10.26

Amendment No. 7 to the ENSCO Savings Plan (As Revised and Restated Effective January 1, 1997), dated as of November 9, 2005.

⁺10.27

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

⁺10.28

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

⁺10.29

Employment Offer Letter Agreement dated February 28, 2006 and accepted on March 1, 2006 between the Company and William S. Chadwick, Jr. (incorporated by reference to Exhibit 10.1 to the Registrant's Current Report on Form 8-K dated February 28, 2006, File No. 1-8097).

⁺10.30

Amendment No. 8 to the ENSCO Savings Plan (As Revised and Restated Effective January 1, 1997), dated as of May 9, 2006 (incorporated by reference to Exhibit 10.1 to the Registrant's Quarterly Report on Form 10-Q for the quarter ended June 30, 2006, File No. 1-8097).

⁺10.31

Amendment to the ENSCO International Incorporated 1996 Non-Employee Directors Stock Option Plan, dated as of May 31, 2006 (incorporated by reference to Exhibit 10.2 to the Registrant's Quarterly Report on Form 10-Q for the quarter ended June 30, 2006, File No. 1-8097).

⁺10.32

Amendment to the ENSCO International Incorporated 2005 Long-Term Incentive Plan, dated as of May 31, 2006 (incorporated by reference to Exhibit 10.3 to the Registrant's Quarterly Report on Form 10-Q for the quarter ended June 30, 2006, File No. 1-8097).

⁺10.33

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

⁺10.34

Summary of Change in Compensation of Non-Employee Directors, effective May 9, 2006 (incorporated by reference to Exhibit 10. 5 to the Registrant's Quarterly Report on Form 10-Q/A for the quarter ended June 30, 2006, File No. 1-8097).

⁺10.35

2007 Performance Measurement Criteria for Named Executive Officers under the ENSCO Cash Incentive Plan (incorporated by reference to Item 1.01 to the Registrants Current Report on Form 8-K dated November 6, 2006, File No. 1-8097).

⁺10.36

Amendment to the ENSCO International Incorporated 2005 Long-Term Incentive Plan, dated as of December 26, 2006 (incorporated by reference to Exhibit 10.39 to the Registrant's Annual Report on Form 10-K for the year ended December 31, 2006, File No. 1-8097).

⁺10.37

Amendment No. 9 to the ENSCO Savings Plan (As Revised and Restated Effective January 1, 1997), dated as of December 26, 2006 (incorporated by reference to Exhibit 10.40 to the Registrant's Annual Report on Form 10-K for the year ended December 31, 2006, File No. 1-8097).

⁺10.38

Amendment No. 10 to the ENSCO Savings Plan (As Revised and Restated Effective January 1, 1997), dated as of December 26, 2006 (incorporated by reference to Exhibit 10.41 to the Registrant's Annual Report on Form 10-K for the year ended December 31, 2006, File No. 1-8097).

⁺10.39

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

⁺10.40

Tax Payment Compensatory Agreement dated May 30, 2007 between the Company and Paul Mars (incorporated by reference to Exhibit 10.1 to the Registrant's Current Report on Form 8-K dated May 30, 2007, File No. 1-8097).

⁺10.41

Summary of Changes in Compensation of Non-Employee Directors, effective November 6, 2007 (incorporated by reference to Item 8.01 of the Registrant's Current Report on Form 8-K dated November 6, 2007, File No. 1-8097).

⁺10.42

2008 Performance Measurement Criteria for Named Executive Officers under the ENSCO Cash Incentive Plan (incorporated by reference to Item 5.02 of the Registrants Current Report on Form 8-K dated November 6, 2007, File No. 1-8097).

⁺*10.43

Amendment No. 11 to the ENSCO Savings Plan (As Revised and Restated Effective January 1, 1997), dated as of November 6, 2007.

⁺*10.44

Amendment No. 1 to the 2005 ENSCO Supplemental Executive Retirement Plan, dated as of November 6, 2007.

*21.1

Subsidiaries of the Registrant.

*23.1

Consent of Independent Registered Public Accounting Firm.

*31.1

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

*31.2

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

*32.1

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

*32.2

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

* Filed herewith

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

We will furnish to the Securities and Exchange Commission upon request, all constituent instruments defining the rights of holders of our long-term debt not filed here with as permitted by paragraph (b)(4)(iii)(A) of Item 601 of Regulation S-K.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized, on February 26, 2008.

		ENSCO International Incorporated (Registrant)

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

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

Signatures	Title	Date

/s/ DAVID M. CARMICHAEL David M. Carmichael	Director	February 26, 2008

/s/ GERALD W. HADDOCK Gerald W. Haddock	Director	February 26, 2008

/s/ THOMAS L. KELLY II Thomas L. Kelly II	Director	February 26, 2008

/s/ MORTON H. MEYERSON Morton H. Meyerson	Director	February 26, 2008

/s/ RITA M. RODRIGUEZ Rita M. Rodriguez	Director	February 26, 2008

/s/ PAUL E. ROWSEY, III Paul E. Rowsey, III	Director	February 26, 2008

/s/ JOEL V. STAFF Joel V. Staff	Director	February 26, 2008

/s/ J. W. SWENT J. W. Swent	Senior Vice President - Chief Financial Officer	February 26, 2008

/s/ H. E. MALONE, JR. H. E. Malone, Jr.	Vice President - Finance	February 26, 2008

/s/ DAVID A. ARMOUR David A. Armour	Controller	February 26, 2008

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

2007 FORM 10-K

TABLE OF CONTENTS

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

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

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

WE MAY SUFFER LOSSES IF OUR CUSTOMERS TERMINATE OR SEEK TO RENEGOTIATE OUR CONTRACTS OR IF OPERATIONS ARE SUSPENDED OR INTERRUPTED RESULTING IN REDUCTION OR CESSATION OF DAY RATES.

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

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

WE HAVE SIGNIFICANT LEVELS OF SELF-INSURANCE FOR GULF OF MEXICO HURRICANE RELATED WINDSTORM DAMAGE COVERAGE WHICH EXPOSES US TO ADDITIONAL RISK AND CAUSES US TO ALTER OUR OPERATING PROCEDURES DURING HURRICANE SEASON WHICH COULD ADVERSELY AFFECT OUR BUSINESS.

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

OUR INTERNATIONAL OPERATIONS INVOLVE ADDITIONAL RISKS NOT ASSOCIATED WITH DOMESTIC OPERATIONS.

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

LAWS AND GOVERNMENTAL REGULATIONS MAY ADD TO COSTS OR LIMIT OUR DRILLING ACTIVITY.

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

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

TERRORIST ATTACKS AND MILITARY ACTION COULD RESULT IN A MATERIAL ADVERSE EFFECT ON OUR BUSINESS.

LEGAL PROCEEDINGS COULD AFFECT US ADVERSELY.

LIQUIDITY AND CAPITAL RESOURCES

MARKET RISK

NEW ACCOUNTING PRONOUNCEMENTS

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

Item 8. Financial Statements and Supplementary Data

MANAGEMENT'S REPORT ON INTERNAL CONTROL OVERFINANCIAL REPORTING

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

8. INCOME TAXES

SIGNATURES

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

MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER
FINANCIAL REPORTING