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UNITED STATES
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ý | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 2007 |
OR |
o | 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 |
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) |
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Title of each class Common Stock, par value $.10 |
Name of each exchange on which registered New York Stock Exchange |
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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: 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). 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. |
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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 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 |
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FORWARD-LOOKING STATEMENTS
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. |
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| 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. | |
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. 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). |
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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 | |||||||||||||
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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 | |
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. In 2007, no customer represented more than 10% of our revenues and our five largest customers accounted for approximately 35% of our consolidated revenues in the aggregate. Competition The offshore contract drilling industry is highly competitive with numerous industry participants. Drilling contracts are, for the most part, awarded on a competitive bid basis. Price competition is often the primary factor in determining which contractor is awarded a contract, although quality of service, operational and safety performance, equipment suitability and availability, location of equipment, reputation and technical expertise are also factors. We have numerous competitors in the offshore contract drilling industry, several of which are larger and have greater resources than us 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. |
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| 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. |
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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. |
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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 | ||
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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. |
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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. |
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| 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. |
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| 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. |
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| 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. |
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. |
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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. 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. |
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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. 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. |
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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. |
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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 |
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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(*) |
BARGE RIG | |||||||||||
Rig Name | Year Built | Maximum Drilling Depth |
Current Location |
Current Customer | |||||||
---|---|---|---|---|---|---|---|---|---|---|---|
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. |
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. |
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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. 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. |
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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 | |||||||||||
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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 |
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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). |
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| 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. |
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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. |
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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. |
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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 | ||||
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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. |
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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. |
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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. |
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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. |
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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 | ) | ||||
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. |
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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 RESOURCESAlthough 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. |
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 | |||||
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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. |
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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 | |
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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 |
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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 |
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. |
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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. |
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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. |
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ENSCO INTERNATIONAL INCORPORATED AND SUBSIDIARIES |
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. |
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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. |
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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. |
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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. |
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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. |
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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. |
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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 | ||||
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. |
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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 | ||
3. LONG-TERM DEBT Long-term debt at December 31, 2007 and 2006 consists of the following (in millions): |
2007 | 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 | |||
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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 | |||
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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. |
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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 | ) | |||||||
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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 |
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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. |
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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 | ||||
|
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 | % |
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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 |
|
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. |
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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 |
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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 TAXESWe 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. |
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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 | ) | |
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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 | ||||||||||
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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. |
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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. |
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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): |
2006 | 2005 | ||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|
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 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. |
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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. |
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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. 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. |
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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 | ||||
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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 |
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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. |
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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 |
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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 | |||||||||||||
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. |
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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. | ||
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Additional information required by this item is included in our Proxy Statement and is incorporated herein by reference. |
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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 | 46 |
Consolidated Statements of Income | 47 |
Consolidated Balance Sheets | 48 |
Consolidated Statements of Cash Flows | 49 |
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 |
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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). |
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+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). |
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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). |
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+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). |
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+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). |
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+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. |
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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 |
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