Item 1. Business
General
ENSCO International Incorporated is an international offshore contract drilling company. As of February 15, 2007, our offshore rig fleet included 43 jackup rigs, one ultra-deepwater semisubmersible rig and one barge rig. Additionally, we have three ultra-deepwater semisubmersible rigs and one ultra-high specification jackup rig under construction. Our offshore contract drilling operations are integral to the exploration, development and production of oil and natural gas and we are one of the leading providers of offshore contract drilling services to the international oil and gas industry. Our operations are concentrated in the geographic regions of Asia Pacific (which includes Asia, the Middle East, Australia, and New Zealand), Europe/Africa, and North and South America. In this report, the terms "ENSCO," "Company," "we," "us" and "our" mean ENSCO International Incorporated and all subsidiaries included in our consolidated financial statements.
We have assembled one of the largest and most capable offshore drilling rig fleets in the world. Corporate acquisitions, rig acquisitions and new rig construction have contributed to the overall growth of our fleet and in 2006, we completed our ten-year, $1.3 billion fleet enhancement program which upgraded the capability and extended the service lives of our premium jackup rigs.
Through acquisitions of Penrod Holding Corporation in 1993, Dual Drilling Company in 1996 and Chiles Offshore Inc. in 2002, we acquired a total of 32 jackup rigs. From 1994 to 1999, we acquired five additional jackup rigs and completed construction of seven barge rigs. In 2000, we completed construction of ENSCO 101, a harsh environment jackup rig, and ENSCO 7500, a dynamically positioned ultra-deepwater semisubmersible rig capable of drilling in water depths of up to 8,000 feet.
During 2004 and 2005, we purchased a harsh environment jackup rig, ENSCO 102, and an ultra-high specification jackup rig, ENSCO 106. Both rigs were constructed through joint ventures with Keppel FELS Limited ("KFELS"), a major international shipyard. In January 2006, we accepted delivery of the newly constructed ENSCO 107, an ultra-high specification jackup rig. During the first quarter of 2007, we expect to take delivery of ENSCO 108, an additional ultra-high specification jackup rig currently under construction.
We also have contracted KFELS to construct three ultra-deepwater semisubmersible rigs (the "ENSCO 8500 SeriesTM "). In 2005, we entered into the ENSCO 8500 construction agreement with delivery anticipated in the second quarter of 2008. In 2006, we entered into agreements to construct ENSCO 8501 and ENSCO 8502, with deliveries expected during the first and fourth quarters of 2009, respectively. The ENSCO 8500 SeriesTM ultra-deepwater semisubmersibles are based on our proprietary design and are enhanced versions of the ENSCO 7500 capable of drilling in up to 8,500 feet of water, and can readily be upgraded to 10,000 feet water-depth capability if required. The ENSCO 8500 and ENSCO 8501 are subject to long-term drilling contracts of four years and three and one half years, respectively.
Our business strategy has been to focus on jackup rig and ultra-deepwater semisubmersible rig operations and we have de-emphasized those operations and assets considered to be non-core or that do not meet our standards for financial performance. Accordingly, we sold our marine transportation fleet, two platform rigs and two barge rigs in 2003. We sold one jackup rig and two platform rigs to KFELS in 2004 in connection with the execution of the ENSCO 107 construction agreement. We also sold five barge rigs and one platform rig in 2005 and sold our one remaining platform rig during the fourth quarter of 2006.
We were formed as a Texas corporation in 1975 and were reincorporated in Delaware in 1987. Our principal office is located at 500 North Akard Street, Suite 4300, Dallas, Texas, 75201-3331, and our telephone number is (214) 397-3000. Our website is www.enscous.com.
Contract Drilling Operations
Our operations consist of one reportable segment: contract drilling services. We engage in the drilling of offshore oil and gas wells in domestic and international markets under contracts with major international, government-owned and independent oil and gas companies.
As of February 15, 2007, we own and operate 43 jackup rigs, one ultra-deepwater semisubmersible rig and one barge rig. Of the 43 jackup rigs, 18 are located in the Asia Pacific region, nine are located in the Europe/Africa region and 16 are located in the North and South America region. Our ultra-deepwater semisubmersible rig is located in the Gulf of Mexico and our barge rig is located in Indonesia.
Our contract drilling services and equipment are used to drill and complete oil and gas wells. Demand for our drilling services is based upon many factors which are beyond our control, including:
• market price of oil and gas and the stability thereof,
• production levels and related activities of the Organization of Petroleum Exporting Countries ("OPEC") and other oil and gas producers,
• regional supply and demand for natural gas,
• worldwide expenditures for offshore oil and gas drilling,
• level of worldwide economic activity,
• long-term effect of worldwide energy conservation measures, and
• the development and use of alternatives to hydrocarbon-based energy sources.
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 the well site. We do not provide "turnkey" or other risk-based drilling services.
Financial information regarding our operating segment and geographic regions is presented in Note 11 to the Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data." Additional financial information regarding our operating segment is presented in "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations."
Backlog Information
Our current and historic backlog of business for contract drilling services as of February 1, 2007 and 2006 were $3,177.4 million and $2,473.3 million, respectively. The increase in our backlog is due primarily to the overall increase in day rates from the prior year. The table below provides a detail of our backlog by geographic region and rig type as of February 1, 2007 and includes $813.7 million of backlog associated with three of our rigs under construction (in millions):
Major Customers
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 the major international oil companies and large independent oil companies. In 2006, no customer represented more than 10% of our revenues and our five largest customers for 2006 accounted for approximately 42% 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.
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 operating costs.
Environmental Matters
Our operations are subject to local, state, federal and international laws and regulations controlling the discharge of materials into the environment, pollution, contamination, and hazardous waste disposal or otherwise relating to the protection of the environment. Laws and regulations specifically applicable to our business activities could impose significant liability on us for damages, clean-up costs, fines and penalties in the event of the occurrence of oil spills or similar discharges of pollutants or contaminants into the environment or improper disposal of hazardous waste in the course of our operations. To date, such laws and regulations have not had a material adverse effect on our operating results, and we have not experienced an accident that has exposed us to material liability for discharges of pollutants into the environment. However, events in recent years have heightened environmental concerns about the oil and gas industry. From time to time, legislative proposals have been introduced that would materially limit or prohibit offshore drilling in certain areas. To date, no proposals which would materially limit or prohibit offshore drilling in our principal areas of operation have been enacted into law. However, we are adversely affected by a moratorium on drilling in certain areas of the Gulf of Mexico. If new laws are enacted or if other environmental related or other governmental action is taken that restrict or prohibit offshore drilling in our principal areas of operation or impose environmental protection requirements that materially increase the cost of offshore drilling, exploration, development or production of oil and gas, we could be materially adversely affected.
The United States Oil Pollution Act of 1990 ("OPA 90"), as amended, and other federal statutes applicable to us and our operations, as well as similar state statutes in Texas, Louisiana and other coastal states, address oil spill prevention and control and significantly expand liability, fine and penalty exposure across many segments of the oil and gas industry. Such statutes and related regulations, both federal and state, impose a variety of obligations on us related to the prevention of oil spills and liability for resulting damages. For instance, OPA 90 imposes strict and, with limited exceptions, joint and several liability upon each responsible party for oil removal costs and a variety of fines, penalties and damages. A failure to comply with these statutes, including OPA 90, may subject us to civil or criminal enforcement action, which may not be covered by contractual indemnification or insurance, and could have a material adverse effect on our financial position, operating results and cash flows.
International 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 61% and 60% in 2006 and 2005, respectively. Our international operations and our international shipyard rig construction and enhancement projects are subject to political, economic and other uncertainties, such as the risks of:
• terrorist acts, war and civil disturbances,
• expropriation, nationalization or deprivation of our equipment,
• expropriation or nationalization of a customer's property or drilling rights,
• repudiation of contracts,
• assaults on property or personnel,
• exchange restrictions,
• currency fluctuations,
• taxation,
• limitations on the ability to repatriate income or capital to the United States,
• changing local and international political conditions, and
• international and domestic monetary policies.
We have historically maintained insurance coverage and obtained contractual indemnities that protect us from some, but not all, of the risks associated with our non-U.S. operations. However, there can be no assurance that any particular type of contractual or insurance coverage will be available in the future or that we will be able to purchase our desired level of insurance coverage at commercially feasible rates. Accordingly, a significant event for which we are uninsured or underinsured, or for which we fail to receive a contractual indemnity from a customer, could cause a material adverse effect on our financial position, operating results and cash flows.
We are subject to various tax laws and regulations in substantially all of the non-U.S. countries in which we operate or have a legal presence. We evaluate applicable tax laws and employ various business structures and operating strategies in non-U.S. countries to obtain the optimal level of taxation on our revenues, income, assets and personnel. Actions by international tax authorities that impact our business structures and operating strategies, such as changes to tax treaties, laws and regulations, or repeal of same, adverse rulings in connection with audits, or other challenges, may substantially increase our tax expense.
Our international operations also face the risk of fluctuating currency values, which can impact revenues and operating costs denominated in foreign currencies. In addition, some of the countries in which we operate have occasionally enacted exchange controls. Historically, we have been able to limit these risks 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 we will be able to negotiate 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 devaluations of their currency compared to the U.S. dollar. However, since our drilling contracts generally stipulate payment wholly or substantially in U.S. dollars, we have experienced no significant losses due to the devaluation of such currencies. However, there is no assurance that we will be able to negotiate such payment terms in the future.
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 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 done by major oil companies and may continue to do so. There can be no assurance that such laws and regulations or activities will not have a material adverse effect on our operations in the future.
Executive Officers
The table below sets forth certain information regarding our principal officers including our current executive officers:
Name
Age
Position
Daniel W. Rabun
President and Chief Executive Officer, Director
William S. Chadwick, Jr.
Executive Vice President - Chief Operating Officer
Jay W. Swent
Senior Vice President - Chief Financial Officer
Phillip J. Saile
Senior Vice President - Business Development and SHE
Richard A. LeBlanc
Vice President - Investor Relations
H. E. Malone, Jr.
Vice President - Finance
Paul Mars
President - ENSCO Offshore International Company
Charles A. Mills
Vice President - Human Resources and Security
Cary A. Moomjian, Jr.
Vice President, General Counsel and Secretary
David A. Armour
Controller
Ramon Yi
Treasurer
Set forth below is certain additional information concerning our executive officers, including the business experience of each executive officer for at least the last five years:
Daniel W. Rabun joined ENSCO in March 2006 as President and as a member of the Board of Directors. In November 2006, he was elected to his present position of Chief Executive Officer effective January 1, 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 has provided legal advice and counsel to us for over fifteen years, and served as one of our directors during 2001. He holds a Bachelor of Business Administration in Accounting from the University of Houston and a Juris Doctorate from Southern Methodist University. He has been a Certified Public Accountant since 1976 and was admitted to the Texas Bar in 1983.
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 2, 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 was elected to his present position of Senior Vice President and Chief Financial Officer effective July 28, 2003. Mr. Swent previously held various financial executive positions in the information technology, telecommunications and manufacturing industries, including 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. He is a graduate of the University of California at Berkeley, where he received a Bachelor of Science Degree in Finance and Masters Degree in Business Administration.
Phillip J. Saile joined ENSCO in August 1987 and was elected Senior Vice President - Business Development and SHE in August 2005. In addition, he serves as the Senior Executive having oversight responsibility for Engineering. Prior to assuming his current position, Mr. Saile served as Senior Vice President, Member - Office of the President and Chief Operating Officer, and as Vice President - Operations until June 2002 when he became President and Chief Operating Officer of ENSCO Offshore International Company, a subsidiary of the parent company, a position he held until July 2005. 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 Master of Business Administration Degree, both 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 Master 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. Mr. Mars previously served as General Manager for the Europe and Africa Business Unit. Prior to joining ENSCO, Mr. Mars served in various capacities as an employee of Smedvig Offshore Limited and Transworld North Sea Drilling Services Limited. Mr. Mars holds a Bachelor of Science Honors Degree in Naval Architecture from the University of Newcastle upon Tyne, England.
Charles A. Mills joined ENSCO in June 2004 as Vice President - Human Resources and Security. He has over 27 years oil and gas industry experience in human resources and managerial positions most recently from 1989 to 2002 with Hunt Oil Company where he was Senior Vice President Human Resources and Corporate Services. Prior to 1989, Mr. Mills held a number of executive and management positions with Tenneco Oil E & P and Shell Oil Company. Mr. Mills holds a Bachelor of Science degree in Management from the University of West Florida.
Cary A. Moomjian, Jr. joined ENSCO in January 2002 and thereupon was elected Vice President, General Counsel and Secretary. Mr. Moomjian has over thirty years of experience in the oil and gas industry. From 1976 to 2001, Mr. Moomjian served in various management and executive capacities as an employee of Santa Fe International Corporation, including Vice President, General Counsel and Secretary from 1993 to 2001. Mr. Moomjian 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 earned a Bachelor of Arts degree from Harvard University in 1975 and a Master of Business Administration 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 the brother-in-law of Carl F. Thorne, the non-executive Chairman of the Board of Directors.
Employees
We employed approximately 3,900 full-time employees worldwide as of February 1, 2007.
Available Information
Our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and amendments to those reports that we file or furnish to the Securities and Exchange Commission (the "SEC") in accordance with the Securities Exchange Act of 1934, as amended, are available on our website at www.enscous.com as soon as reasonably practicable after we electronically file the information with, or furnish it to, the SEC.
Item 1A.
Item 1A. Risk Factors
There are numerous factors that affect our business and our operating results, many of which are beyond our control. The following is a description of significant factors that might cause our future operating results to differ materially from those currently expected. The risks described below are not the only risks facing our Company. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition and/or operating results.
THE SUCCESS OF OUR BUSINESS WILL DEPEND ON THE LEVEL OF ACTIVITY IN THE OIL AND NATURAL GAS INDUSTRY, WHICH IS SIGNIFICANTLY AFFECTED BY VOLATILE OIL AND GAS PRICES. The success of our business will largely depend on the level of activity in offshore oil and natural gas exploration, development and production in markets worldwide. Oil and natural gas prices, and market expectations of potential changes in these prices, significantly affect the level of drilling activity. An actual decline, or the perceived risk of a decline, in oil or natural gas prices could cause oil and gas companies to reduce their overall level of spending, in which case demand for our equipment and services may decrease and revenues may be adversely affected through lower rig utilization and lower average day rates. Worldwide military, political, environmental and economic events also contribute to oil and natural gas price volatility. Numerous other factors may affect oil and natural gas prices and the level of demand for our services, including:
• demand for oil and gas,
• the ability of OPEC to set and maintain production levels and pricing,
• the level of production by non-OPEC countries,
• domestic and international tax policy,
• laws and governmental regulations that restrict exploration and development of oil and natural gas in various jurisdictions,
• advances in exploration and development technology,
• disruption to exploration and development activities due to hurricanes and other severe weather conditions, and
• the worldwide military or political environment, including uncertainty or instability resulting from an escalation or additional outbreak of armed hostilities or other crises in oil or natural gas producing areas of the Middle East or geographic areas in which we operate, or acts of terrorism.
THE OFFSHORE CONTRACT DRILLING INDUSTRY IS 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 drilling rigs is limited and new rigs require a substantial capital investment and a long period of time to construct. There are approximately one hundred new jackup and semisubmersible rigs reported to be on order for delivery by the end of 2010. There are no assurances that the market will be able to fully absorb the supply of new rigs in future periods.
It is time consuming to move offshore rigs between geographic areas. 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 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.
Periods of decreased demand and 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.
EXCESS RIG AVAILABILITY RESULTING FROM THE DELIVERY OF NEW DRILLING UNITS COULD RESULT IN ADVERSE EFFECTS ON OUR BUSINESS. During prior periods of high utilization and day rates, drilling companies have increased the supply of rigs by ordering construction of new units. On prior occasions, this has resulted in an oversupply of drilling units and has caused a subsequent decline in utilization and day rates, sometimes for extended periods of time. There are approximately one hundred new jackup and semisubmersible rigs reported to be on order for construction with delivery dates ranging from 2007 through 2010.The completion of these new drilling rigs will increase supply and could reduce day rates or utilization as a result of softening of the affected markets as rigs are absorbed into the active fleet. Any further increase in construction of new drilling units would likely exacerbate the potential negative impact on 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.
FAILURE TO OBTAIN AND RETAIN SKILLED PERSONNEL COULD IMPEDE OUR OPERATIONS. We require skilled personnel to operate our drilling rigs and to provide technical services and support for our business. Competition for skilled and other labor has intensified as additional rigs are activated or are added to the worldwide fleet. Furthermore, there are approximately one hundred new jackup and semisubmersible rigs reported to be on order for delivery by the end of 2010, all of which will require new skilled and other personnel to operate. In periods of high utilization, such as the current period, it is more difficult to recruit and retain qualified individuals. Although competition for skilled and other labor has not materially affected us to date, competition for such personnel could increase our future operating expenses, with a resulting reduction in net income, or impact our ability to fully staff and operate our rigs.
We have experienced a tightening in our labor markets within the last year and recently sustained an increase in turnover rates due largely to the loss of experienced personnel to our customers, competitors and other businesses involved in oil and gas exploration activities. In response to these market conditions, we have increased compensation and have incurred other costs to retain our workforce, including a retention program for certain personnel. If these labor trends continue, they could further increase our costs or limit our ability to fully staff and operate our rigs.
THE OFFSHORE CONTRACT DRILLING INDUSTRY IS HIGHLY COMPETITIVE WHICH COULD LEAD US TO ACCEPT LOWER DAY RATES AND LESS FAVORABLE CONTRACT TERMS DURING INDUSTRY DOWNTURNS. The offshore contract drilling industry is highly competitive with numerous industry participants. The industry has experienced consolidation in recent years and may experience additional consolidation. Furthermore, recent mergers among oil and natural gas exploration and production companies have reduced the number of available customers.
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, reputation and technical expertise are also factors. We compete with numerous offshore drilling contractors, several of which are larger and have greater resources than us.
During good industry market cycles we experience higher utilization, receive relatively high average day rates and generally are able to negotiate more favorable contract terms. During adverse industry market cycles, we compete more aggressively for contracts at lower day rates and may have to accept contractual liability and indemnity provisions that provide a lower level of protection against potential losses. Lower day rates and/or utilization will adversely affect our operating results. Increased contractual liability exposure may also have an adverse effect on operating results because of uninsured or underinsured risks, or in relation to increased cost of insurance.
WE MAY SUFFER LOSSES IF OUR CUSTOMERS TERMINATE OR SEEK TO RENEGOTIATE OUR CONTRACTS. Our drilling contracts often are cancelable upon specific notice by the customer. Although contracts may require the customer to pay an early termination payment upon cancellation, such payment may not fully compensate for the loss of the contract. In periods of rapid market downturn, our customers may not honor the terms of existing contracts, may terminate contracts or may seek to renegotiate contract rates and terms to conform with depressed market conditions. Furthermore, contracts customarily specify automatic termination or termination at the option of the customer in the event of a total loss of the drilling rig and often include provisions addressing termination rights or cessation of day rates if operations are suspended for extended periods by reason of excessive downtime for repairs, acts of God or other specified conditions. Our operating results may be adversely affected by early termination of contracts, contract renegotiations or cessation of day rates while operations are suspended.
OUR BUSINESS MAY BE MATERIALLY ADVERSELY AFFECTED IF CERTAIN CUSTOMERS CEASE TO DO BUSINESS WITH US. We provide our services to major international, government-owned and independent oil and gas companies. However, the number of our potential customers has decreased in recent years as a result of mergers among the major international oil companies and large independent oil companies. Although no customer represented more than 10% of revenues in 2006, our five largest customers accounted for approximately 42% of consolidated revenues in the aggregate. Our operating results may be materially adversely affected if any major customer terminates its contracts with us, fails to renew its existing contracts with us, or declines to award new contracts to us.
WE HAVE INCREASED OUR LEVEL OF SELF-INSURANCE FOR GULF OF MEXICO HURRICANE RELATED WINDSTORM DAMAGE COVERAGE WHICH EXPOSES US TO ADDITIONAL RISK AND CAUSES US TO ALTER OUR OPERATING PROCEDURES DURING HURRICANE SEASON WHICH COULD ADVERSELY AFFECT OUR BUSINESS. Certain areas in and near the Gulf of Mexico experience hurricanes and other extreme weather conditions on a relatively frequent basis. Some of our drilling rigs in the Gulf Coast Region are located in areas that could cause them to be susceptible to damage and/or total loss by these storms and we have a larger concentration of rigs in the Gulf Coast Region than most of our competitors. Damage caused by high winds and turbulent seas could potentially result in loss of rigs or could cause us to curtail operations on damaged drilling rigs for significant periods of time until damage can be repaired. Moreover, even if our drilling rigs are not directly damaged by such storms, we may experience disruptions in our operations due to damage to our customers' platforms and other related facilities in the area. To date, our drilling operations in the Gulf of Mexico have not been materially impacted by hurricanes, although we sustained the total loss of one jackup rig in 2004 and one platform rig in 2005 by reason of hurricane damage. We currently have 15 jackup rigs and one ultra-deepwater semisubmersible rig in the Gulf of Mexico.
Insurance companies incurred substantial losses in the offshore drilling, exploration and production industries as a consequence of hurricanes that occurred in the Gulf of Mexico during 2005 and 2004. 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, 2006, we obtained $100.0 million of annual aggregate coverage for hull and machinery losses arising from Gulf of Mexico hurricane related windstorm damage with a $50.0 million per occurrence deductible. This amount of coverage is significantly less than in prior years. The change in our insurance coverage exposes us to additional 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 insurance policies maintain liability coverage for Gulf of Mexico hurricane related windstorm exposures, including removal of wreckage and debris, at the same level as in the prior year, albeit at a substantial increased cost.
We have implemented new operational procedures designed to mitigate risk to our jackup rigs in the Gulf of Mexico during hurricane season. In addition to procedures designed to better secure the drilling package on jackup rigs, improve jackup leg stability and increase the air gap to position the hull above waves, the new procedures involve analysis of prospective drilling locations, which may include enhanced bottom surveys. Implementation of these procedures may result in a decision to decline to operate on a customer designated location during hurricane season notwithstanding that the location, water depth and other standard operating conditions are within a rig's normal operating range. Implementation of our new procedures and associated regulatory requirements addressing Mobile Offshore Drilling Unit operations in the Gulf of Mexico during hurricane season may result in a loss or reduction of work for our rigs at certain customer drilling locations, with consequential reduction in rig utilization or day rates in the Gulf of Mexico.
OUR BUSINESS INVOLVES NUMEROUS OPERATING HAZARDS AND WE ARE NOT FULLY INSURED AGAINST ALL OF THESE HAZARDS. Contract drilling and offshore oil and gas operations in general are subject to numerous risks, including the following:
• rig or other property damage or loss resulting from hurricanes and other severe weather conditions, collisions, groundings, blowouts, fires, explosions and other accidents or terrorism,
• blowouts, fires, explosions and other loss of well control events causing damage to wells, reservoirs, production facilities and other properties and which may require wild well control, including drilling of relief wells,
• craterings, punchthroughs or other events causing rigs to capsize, sink or otherwise incur significant damage,
• extensive uncontrolled fires, blowouts, oil spills or other discharges of pollutants causing damage to the environment,
• machinery breakdowns, equipment failures, personnel shortages, failure of subcontractors and vendors to perform or supply goods and services and other events causing the suspension or cancellation of drilling operations, and
• unionization or similar collective actions by our employees or employees of subcontractors causing suspension of drilling operations or significant increases in operating costs.
In addition, many of the hazards and risks associated with our operations, and accidents or other events resulting from such hazards and risks, expose our personnel, as well as personnel of our customers, subcontractors, vendors and other third parties, to risk of personal injury or death.
Although we currently maintain broad insurance coverage, subject to certain significant deductibles and levels of self-insurance or risk retention, it does not cover all types of losses and, in some situations such as rig loss or damage resulting from Gulf of Mexico hurricane related windstorm exposures, may not provide full coverage of 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. We do not maintain business interruption or loss of hire insurance.
We generally obtain contractual indemnification from our customers whereby such customers generally agree to protect and indemnify us for 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. The inability to obtain such indemnification, the failure of a customer to meet indemnification obligations, the failure of one or more of our insurance providers to meet claim obligations, or losses or liabilities resulting from uninsured or underinsured events could have a material adverse effect on our financial position, operating results and cash flows.
Our contracts generally protect us from certain losses sustained as a result of our negligence. However, losses resulting from contracts that do not contain such protection could have a material adverse affect on our financial position, operating results and cash flows. Losses resulting from our gross negligence or willful misconduct may not be protected contractually by specific provision or by application of law, and our insurance may not provide adequate protection for such losses.
The cost of many of the types of insurance coverage maintained by us has increased significantly during recent years. In addition, insurance market conditions have resulted in retention of additional risk by us, primarily through higher insurance deductibles. Very few insurance underwriters offer certain types of insurance coverage we maintain, and there can be no assurance that any particular type of insurance coverage will continue to be available in the future, that we will not accept retention of additional risk through higher insurance deductibles, self-insurance risk retention or otherwise, or that we will be able to purchase our desired level of insurance coverage at commercially feasible rates.
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 2005 and 2004. 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, 2006, we obtained $100.0 million of annual aggregate coverage for our hull and machinery losses arising from Gulf of Mexico hurricane related windstorm damage with a $50.0 million per occurrence deductible. This amount of coverage is significantly less than in prior years. The change in our insurance coverage exposes us to additional 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 insurance policies maintain liability coverage for Gulf of Mexico hurricane related windstorm exposures, including removal of wreckage and debris, at the same level as in the prior year, albeit at a substantial increased cost.
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 61% and 60% in 2006 and 2005, respectively. Our international operations and our international shipyard rig construction and enhancement projects are subject to political, economic and other uncertainties, such as the risks of:
• terrorist acts, war and civil disturbances,
• expropriation, nationalization or deprivation of our equipment,
• expropriation or nationalization of a customer's property or drilling rights,
• repudiation of contracts,
• assaults on property or personnel,
• exchange restrictions,
• currency fluctuations,
• taxation,
• limitations on the ability to repatriate income or capital to the United States,
• changing local and international political conditions, and
• international and domestic monetary policies.
We have historically maintained insurance coverage and obtained contractual indemnities that protect us from some, but not all, of the risks associated with our non-U.S. operations. However, there can be no assurance that any particular type of contractual or insurance coverage will be available in the future or that we will be able to purchase our desired level of insurance coverage at commercially feasible rates. Accordingly, a significant event for which we are uninsured or underinsured, or for which we fail to receive a contractual indemnity from a customer, could cause a material adverse effect on our financial position, operating results and cash flows.
We are subject to various tax laws and regulations in substantially all of the non-U.S. countries in which we operate or have a legal presence. We evaluate applicable tax laws and employ various business structures and operating strategies in non-U.S. countries to obtain the optimal level of taxation on our revenues, income, assets and personnel. Actions by international tax authorities that impact our business structures and operating strategies, such as changes to tax treaties, laws and regulations, or repeal of same, adverse rulings in connection with audits, or other challenges, may substantially increase our tax expense.
Our international operations also face the risk of fluctuating currency values, which can impact revenues and operating costs denominated in foreign currencies. In addition, some of the countries in which we operate have occasionally enacted exchange controls. Historically, we have been able to limit these risks 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 we will be able to negotiate 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 devaluations of their currency compared to the U.S. dollar. However, since our drilling contracts generally stipulate payment wholly or substantially in U.S. dollars, we have experienced no significant losses due to the devaluation of such currencies. However, there is no assurance that we will be able to negotiate such payment terms in the future.
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 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 done by major 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 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.
Moreover, 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.
The United States Oil Pollution Act of 1990 ("OPA 90"), as amended, and other federal statutes applicable to us and our operations, as well as similar state statutes in Texas, Louisiana and other coastal states, address oil spill prevention and control and significantly expand liability, fine and penalty exposure across many segments of the oil and gas industry. Such statutes and related regulations, both federal and state, impose a variety of obligations on us related to the prevention of oil spills and liability for resulting damages. For instance, OPA 90 imposes strict and, with limited exceptions, joint and several liability upon each responsible party for oil removal costs and a variety of fines, penalties and damages. A failure to comply with these statutes, including OPA 90, may subject us to civil or criminal enforcement action, which may not be covered by contractual indemnification or insurance, and could have a material adverse effect on our financial position, operating results and cash flows.
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 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 to comply with governmental laws and regulations. It is also possible that these laws and regulations could adversely affect our operations in the future by limiting drilling opportunities or significantly increasing 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 43 jackup rigs, one ultra-deepwater semisubmersible rig and one barge rig. Additionally, we have three ultra-deepwater semisubmersible rigs and one ultra-high specification jackup rig 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.
NEW TECHNOLOGIES MAY CAUSE OUR CURRENT DRILLING METHODS TO BECOME OBSOLETE, RESULTING IN AN ADVERSE EFFECT ON OUR BUSINESS. The offshore contract drilling industry is subject to the introduction of new drilling techniques and services using new technologies, some of which may be subject to patent protection. As competitors and others use or develop new technologies, we may be placed at a competitive disadvantage and competitive pressures may force us to implement new technologies at a substantial cost. In addition, competitors may have greater financial, technical and personnel resources that allow them to enjoy technological advantages and implement new technologies before we can. We cannot be certain that we will be able to implement technologies on a timely basis or at a cost that is acceptable to us. The technologies that we use or implement in the future may become obsolete, and we may be adversely affected.
CHANGES IN LAWS, EFFECTIVE TAX RATES OR ADVERSE OUTCOMES RESULTING FROM EXAMINATION OF OUR TAX RETURNS COULD ADVERSELY AFFECT OUR FINANCIAL RESULTS. Our future effective tax rates could be adversely affected by changes in tax laws, both domestically and internationally. They could also be adversely affected by earnings being lower than anticipated in countries where we have lower statutory rates and higher than anticipated in countries where we have higher statutory rates, by changes in the valuation of our deferred tax assets and liabilities, or by changes in tax treaties, regulations, accounting principles or interpretations thereof in one or more countries in which we operate. In addition, we are subject to the continuous examination of our income tax returns by the Internal Revenue Service and other tax authorities. We regularly assess the likelihood of adverse outcomes resulting from these examinations to determine the adequacy of our provision for taxes. There can be no assurance that such examinations will not have an adverse effect on our operating results and financial condition.
RIG UPGRADE, ENHANCEMENT AND CONSTRUCTION PROJECTS ARE SUBJECT TO RISKS INCLUDING DELAYS AND COST OVERRUNS WHICH COULD HAVE A MATERIAL ADVERSE IMPACT ON OUR OPERATING RESULTS. THE RISKS ARE CONCENTRATED BECAUSE OUR FOUR RIGS CURRENTLY UNDER CONSTRUCTION ARE AT ONE SHIPYARD IN SINGAPORE. We have three ultra-deepwater semisubmersible rigs and one ultra-high specification jackup rig under construction at a shipyard in Singapore. In addition, we may construct additional rigs and continue to upgrade the capability and extend the service lives of other rigs. Rig construction, upgrade, life extension and repair projects are subject to the risks of delay or cost overruns inherent in any large construction project, including the following:
• reliance on third party equipment vendors,
• delays in equipment deliveries or shipyard construction,
• shortages of materials or skilled labor,
• unforeseen 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,
• inability to obtain any of the requisite permits or approvals,
• force majeure, and
• additional risks inherent to shipyard projects in an international location.
Our risks are concentrated because our four rigs currently under construction are at one shipyard in Singapore. Our ultra-high specification jackup rig (ENSCO 108) and two of the ultra-deepwater semisubmersible rigs (ENSCO 8500 and ENSCO 8501) are subject to firm, fixed day rate drilling contracts upon completion of construction and significant shipyard project cost overruns or delays could impact the projected financial results or validity of the contracts and materially and adversely affect our financial condition and operating results. Our third ultra-deepwater semisubmersible rig under construction (ENSCO 8502) currently does not have a contractual commitment upon completion. If we are unable to secure a contractual commitment for the rig prior to the completion of construction, it may result in a material adverse affect on our financial condition or operating results. If we are able to secure a contract prior to completion, then we are exposed to the risk of delays which could impact the projected financial results or validity of the contract and materially and adversely affect our financial condition and operating results.
TERRORIST ATTACKS AND MILITARY ACTION COULD RESULT IN A MATERIAL ADVERSE EFFECT ON OUR BUSINESS. Terrorist acts or acts of war may cause damage to or disruption of our United States or international operations, employees, property and equipment, or customers, suppliers and subcontractors, which could significantly impact our financial position, operating results and cash flows. Terrorist acts create many economic and political uncertainties and the potential for future terrorist acts, the national and international responses to terrorism and other acts of war or hostility could create many economic and political uncertainties, including an impact upon oil and gas drilling, exploration and development. This could adversely affect our business in ways that cannot readily be determined.
Item 1B.
Item 1B. Unresolved Staff Comments
None.
Item 2.
Item 2. Properties
Contract Drilling
The table below provides certain information about the rigs in our drilling fleet as of February 15, 2007:
JACKUP RIGS
ULTRA-DEEPWATER SEMISUBMERSIBLE RIGS
(1)
ENSCO 67 is mobilizing to Indonesia where it is scheduled to commence a contract with ConocoPhillips in March 2007.
(2)
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 and ENSCO 8501 are subject to long-term drilling contracts of four years and three and one half years, respectively. ENSCO 108 is scheduled to commence a one year contract upon construction completion.
(3)
ENSCO 83 is in a shipyard undergoing enhancement procedures.
The equipment on our drilling rigs includes engines, drawworks, derricks, pumps to circulate the drilling fluid, blowout preventers, drill string and related equipment. The engines power a drive mechanism that turns the drill string and drill bit so that the hole is drilled by grinding subsurface materials, which are then carried to the surface by the drilling fluid. The intended well depth, water depth and drilling conditions are the principal factors that determine the size and type of rig most suitable for a particular drilling job.
Jackup rigs stand on the ocean floor with their hull and drilling equipment elevated above the water on connected leg supports. Jackup rigs are generally preferred over other rig types in water depths of 400 feet or less, primarily because jackup rigs provide a more stable drilling platform with above water blowout prevention equipment. All of our jackup rigs are of the independent leg design. All but one of the 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.
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. ENSCO 8500, ENSCO 8501 and ENSCO 8502 will be enhanced versions of the ENSCO 7500. The ENSCO 8500 SeriesTM rigs will be capable of drilling in up to 8,500 feet of water, and can readily 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 SeriesTM rigs will be especially well-suited for deepwater development drilling.
Barge rigs are towed to the drilling location and are held in place by anchors while drilling activities are conducted. Our barge rig has all of the crew quarters, storage facilities and related equipment mounted on the floating barge, with the drilling equipment cantilevered from the stern of the barge.
Over the life of a typical rig, several of the major components are replaced due to normal wear and tear or due to technological advancements in drilling equipment. All of our rigs are in good condition and as of February 15, 2007, 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, New Zealand, Nigeria, Qatar, Saudi Arabia, Singapore and Venezuela.
Item 3.
Item 3. Legal Proceedings
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 seek 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, as decided by the Mississippi Supreme Court in Harold's Auto Parts, Inc., et al vs. Flower Mangialardi, et al, 889 So. 2d 493 (Miss 2004), individual claimants in the original multi-party lawsuits whose claims were not dismissed were ordered to either file 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 pending claims, we have been named as a defendant by 61 individual plaintiffs. Of these claims, there are a total of 59 claims or lawsuits pending in Mississippi state courts and two pending in United States District Court as a result of their removal from state court.
We currently intend to vigorously defend against these claims and have filed responsive pleadings preserving all defenses and challenges to jurisdiction and venue. However, inasmuch as discovery is in the very early stages and available information regarding the nature of these claims is limited, we cannot reasonably determine if the claimants have valid claims under the Jones Act or estimate a range of potential liability exposure, if any. At present, none of the pending Mississippi asbestos lawsuits have been set for trial and, while we do not expect the final disposition of these lawsuits to have a material adverse effect upon our financial position, operating results or cash flows, there can be no assurances as to the ultimate outcome of the lawsuits.
In addition to the foregoing, we and our subsidiaries are named defendants in certain other lawsuits and are involved from time to time as parties to governmental proceedings, including matters related to taxation, arising in the ordinary course of business. Although the outcome of lawsuits or other proceedings involving us and our subsidiaries cannot be predicted with certainty and the amount of any liability that could arise with respect to such lawsuits or other proceedings cannot be predicted accurately, we do not expect these matters to have a material effect on our financial position, operating results or cash flows.
Item 4.
Item 4. Submission of Matters to a Vote of Security Holders
There were no matters submitted to a vote of our security holders during the fourth quarter of 2006.
PART II
Item 5.
Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases
of Equity Securities
The table below provides the high and low sales prices of our common stock, $.10 par value, for each period indicated during the last two fiscal years:
Our common stock (Symbol: ESV) is traded on the New York Stock Exchange. We had 1,020 stockholders of record on February 1, 2007.
We began 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, 2006. Cash dividends totaling $.10 per share were paid in both 2006 and 2005. 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 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, 2006:
On March 14, 2006, our Board of Directors authorized a stock repurchase program for the repurchase of up to $500.0 million of our outstanding common stock. During the three-month period ended December 31, 2006, we repurchased 1,116,000 shares of our common stock at a cost of $53.3 million (an average cost of $47.78 per share). Additionally, we repurchased 3,687 shares at an average cost of $50.87 per share from employees in connection with the settlement of income tax and related withholding obligations arising from the vesting of share awards during the three-month period ended December 31, 2006.
The chart below presents a comparison of the five year cumulative total return, assuming $100 invested on December 31, 2001, 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.*
* $100 invested on 12/31/01 in stock or index, including the reinvestment of dividends for fiscal years ending
December 31.
Item 6.
Item 6. Selected Financial Data
The selected financial data should be read in conjunction with "Item 7.
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations
INTRODUCTION
Our Business
We are an international offshore contract drilling company with a current operating fleet of 45 drilling rigs, including 43 jackup rigs, one ultra-deepwater semisubmersible rig and one barge rig. Additionally, we have three ultra-deepwater semisubmersible rigs and one ultra-high specification jackup rig under construction. Our offshore contract drilling operations are integral to the exploration, development and production of oil and natural gas and we are one of the leading providers of offshore drilling services to the international oil and gas industry.
We drill and complete oil and gas wells under contracts with major international, government-owned and independent oil and gas companies. The drilling services we provide are conducted 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 the well site. We do not provide "turnkey" or other risk-based drilling services.
Our drilling rigs are strategicly located throughout the world, with drilling operations concentrated in the major geographic regions of Asia Pacific (which includes Asia, the Middle East, Australia and New Zealand), Europe/Africa, and North and South America. We compete with other offshore drilling contractors on the basis of price, quality of service, operational and safety performance, equipment suitability and availability, reputation and technical expertise. Competition is usually on a regional basis, but offshore drilling rigs are mobile and may generally be moved from one region to another in response to demand.
Our Industry
Financial operating results in the offshore contract drilling industry have historically been very cyclical and are primarily related to the demand for drilling rigs and the available supply of rigs. 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. Such spending fluctuations result from many factors, including:
• 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 pricing of oil and natural gas.
The supply of 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 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.
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 or trends in 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.
BUSINESS ENVIRONMENT
General
During 2006, the offshore contract drilling industry generally continued to experience strong demand, lengthy backlogs and increasing day rates and utilization for all drilling rig types on a global basis. Leading day rates currently are at record levels for most rig classes and recently executed contracts typically have more favorable terms and conditions for drilling companies. However, during the second half of the year, the industry experienced some moderation in the demand for jackup rigs in the Gulf of Mexico due to the apparent deferral of drilling activity until after the hurricane season and the decline in the price of natural gas. If the current market conditions in the Gulf of Mexico continue, we anticipate additional jackup rigs may depart for international contract opportunities, which in turn, may bring rig supply into balance with demand.
At present, the supply of available offshore drilling rigs is unable to meet the growing demand of oil and gas companies on a global basis. In some regions, this unavailability has led oil and gas companies to postpone or cancel projects. As a result of the global supply imbalance and other commercial considerations, various industry participants have ordered construction of approximately one hundred new offshore rigs that are scheduled for delivery over the next several years. Furthermore, competition for skilled and other labor will continue to intensify as these new rigs enter the market in future periods.
Asia Pacific
Demand for jackup rigs in most Asia Pacific region markets was strong during 2004 as many of the major international and government-owned oil companies increased spending in those markets. However, Asia Pacific region day rates remained relatively stable during this period as we, and some of our competitors, mobilized additional rigs to the region in response to the increased demand. Demand continued to strengthen during 2005 and increased activity levels absorbed the additional rigs mobilized to the region and improved day rates. During 2006, demand for jackup rigs in most of the Asia Pacific region markets exceeded the supply of available rigs. As a result, jackup rig utilization levels remained high and day rates continued to improve. Jackup rig drilling contracts in the Asia Pacific region historically have been for substantially longer durations than those in other geographical regions. Since day rates for such contracts generally are fixed, or fixed subject to adjustment for variations in the contractor's costs, our Asia Pacific operations generally are not subject to the same level of day rate volatility as regions where shorter term contracts are prevalent.
Europe/Africa
Our Europe/Africa offshore drilling operations are mainly conducted in northern Europe where moderate duration jackup rig contracts are prevalent. During most of 2004, jackup rig demand and day rates in this region remained at reduced levels due to the decline in oil and gas company spending experienced in prior years. Beginning late in 2004, oil and gas companies increased their spending as a result of higher oil and natural gas prices and the growing demand for oil. This led to an increase in jackup rig demand and average day rates. The trend continued throughout 2005, and in 2006, a strong backlog of firm commitments and options in northern Europe resulted in little or no availability of jackup rigs which is expected to continue through the end of 2007. This caused demand to exceed the supply of available rigs which resulted in a substantial increase in day rates from the prior year.
Many of our jackup rig contracts in the Europe/Africa and Asia Pacific regions contain cost adjustment provisions. These provisions are designed to protect our operating margin during times when contract drilling expenses are increasing. The cost adjustment provisions usually result in an increase in contract day rates or cost reimbursement to offset operating cost increases since the inception of a contract, and may also include rate adjustment provisions addressing rate reductions in the event of a decrease in operating costs. A small portion of our average day rate increases experienced in the Europe/Africa and Asia Pacific regions are attributable to contractual cost adjustment provisions.
North and South America
Our North and South America offshore drilling operations are mainly conducted in the Gulf of Mexico. The U.S. natural gas market and trends in oil and gas company spending largely determine offshore drilling industry conditions and demand for rigs in this region. Gulf of Mexico jackup rig contracts are normally entered into for relatively short durations and day rates are adjusted to current market rates upon contract renewal. Some Gulf of Mexico rigs remain contracted with the same customer for several years, but the contractual day rates are periodically renegotiated by reference to prevailing market day rates and adjusted accordingly.
In 2004, the supply of jackup rigs in the Gulf of Mexico declined from prior year levels as we, and several of our competitors, continued to mobilize rigs to international markets in response to contract opportunities. Although day rate trends were mixed during the first half of 2004, average day rates for jackup rigs in the Gulf of Mexico improved significantly during the second half, due to both the reduced supply of rigs and increased spending by oil and gas companies.
During 2005, day rates of Gulf of Mexico jackup rigs continued to increase as a result of a further reduction in the supply of rigs in the region. In mid-2005, several of our competitors announced the planned departure of rigs contracted outside the region and these rigs became unavailable during the latter half of 2005 to prepare for mobilization. Additionally, Hurricane Katrina and Hurricane Rita disrupted drilling operations and severely damaged or destroyed several rigs operating in the region thereby reducing the number of available rigs even further.
During the first five months of 2006, jackup rig day rates in the Gulf of Mexico experienced a fairly rapid increase due to the decreased supply of available rigs in the region and the announcement by us and several of our competitors regarding the planned departure of additional rigs contracted to work in international waters. Drilling contractors continued to move jackup rigs out of the Gulf of Mexico to take advantage of increasing international demand and day rates, with contract terms that are typically longer than Gulf of Mexico contracts. However, the impact of the decreased supply of available jackup rigs was more than offset by a decrease in demand that began late in the second quarter as oil and gas companies were reluctant to start new projects in view of the upcoming hurricane season. Additionally, a decrease in the price of natural gas, increased insurance costs, and the limited availability of insurance coverage resulting in uninsured exposure, also made this region less attractive to oil and gas companies. As a result, jackup rig day rates began to moderate late in the second quarter of 2006 and remained under pressure during the rest of the year.
RESULTS OF OPERATIONS
In recent years, we have disposed of several assets, including the exchange of three rigs in connection with a construction agreement in 2004, the sale of six barge rigs and a platform rig in 2005, the loss of a jackup rig in 2004 and a platform rig in 2005 as a result of damage caused by hurricanes, and the sale of a platform rig in 2006. The operating results of these assets have been reclassified as discontinued operations in the consolidated statements of income for each of the years in the three year-period ended December 31, 2006. (See "Discontinued Operations" below for further information regarding the operating results and disposal of these assets.)
The table below summarizes our consolidated operating results for each of the years in the three-year period ended December 31, 2006 (in millions):
In 2006, our net income increased by $484.8 million, or 170%, and operating income increased by $622.7 million, or 158%, as compared to 2005. The increases are primarily due to improved average day rates in all operating areas and improved utilization of Europe/Africa and Asia Pacific jackup rigs, as compared to the prior year.
In 2005, our net income increased by $191.9 million, or 206%, and operating income increased by $237.1 million, or 151%, as compared to 2004. The increases are primarily due to improved average day rates for our jackup rigs and ENSCO 7500 and improved utilization of the Europe/Africa jackup rigs and ENSCO 7500, as compared to the prior year.
Detailed explanations of our operating results for each of the years in the three-year period ended December 31, 2006, including discussions of revenues and contract drilling expense based on geographical location and type of rig, are provided below.
Revenues and Contract Drilling Expense
The table below provides 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, 2006 (in millions, except utilization and day rates):
(1)
Rig utilization is derived by dividing the number of days under contract, including days associated with compensated mobilizations, by the number of days in the period.
(2)
Average day rates are derived by dividing contract drilling revenue by the aggregate number of contract days, adjusted to exclude certain types of non-recurring reimbursable revenue and lump sum revenue and contract days associated with certain mobilizations, demobilizations, shipyard contracts and standby contracts.
The table below summarizes the number of our offshore drilling rigs at December 31, 2006, 2005 and 2004:
(1)
During 2006, we mobilized ENSCO 84 from the Gulf of Mexico to Qatar in the Asia Pacific region. During 2005, we mobilized ENSCO 76 from Trinidad and Tobago to Saudi Arabia to commence a three-year contract in September 2005.
(2)
At December 31, 2005, ENSCO 102 was en route from the Asia Pacific region to the United Kingdom where it commenced a one-year contract in February 2006.
(3)
Upon completion of its construction in the first quarter of 2005, we acquired the ultra-high specification jackup rig, ENSCO 106, from a joint venture in which we held a 25% interest. Upon completion of its construction in the first quarter of 2006, we accepted delivery of the ultra-high specification jackup rig, ENSCO 107.
(4)
The total number of rigs for each period excludes rigs reclassified as discontinued operations and rigs under construction.
Asia Pacific Jackup Rigs
In 2006, revenues for our Asia Pacific jackup rigs increased by $209.6 million, or 59%, and contract drilling expense increased by $40.7 million, or 24%, as compared to 2005. The increase in revenues is due primarily to a 29% increase in average day rates and an increase in utilization to 98% in the current year 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 from the prior year due primarily to increased utilization, increased personnel, maintenance and repair expense and a $2.7 million loss related to leg damage sustained by ENSCO 107 while pre-loading on a drilling location offshore Vietnam in June 2006.
In 2005, revenues for our Asia Pacific jackup rigs increased by $86.1 million, or 32%, and contract drilling expense increased by $34.1 million, or 25%, as compared to 2004. The increase in revenues is primarily due to the increased size of the Asia Pacific jackup rig fleet. We relocated three rigs to the Asia Pacific region during the second and third quarters of 2004, which commenced operations after completing enhancement and contract preparation procedures. Additionally, we acquired ENSCO 106 in February 2005, which commenced operations shortly thereafter. Contract drilling expense increased primarily due to the increased size of the Asia Pacific jackup rig fleet in 2005.
Europe/Africa Jackup Rigs
In 2006, revenues for our Europe/Africa jackup rigs increased by $255.6 million, or 106%, and contract drilling expense increased by $43.9 million, or 38%, as compared to 2005. The increase in revenues is primarily attributable to a 77% increase in the 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 the current year. The improvement in day rates and utilization is primarily attributable to increased spending by oil and gas companies and a decrease in the supply of available jackup rigs. Contract drilling expense increased from the prior year due primarily to the addition of ENSCO 102, which added $25.2 million of expense in the current year, and to increased personnel costs, rig mobilization expense, and repair and maintenance expense.
In 2005, revenues for our Europe/Africa jackup rigs increased by $95.5 million, or 65%, and contract drilling expense increased by $16.0 million, or 16%, as compared to 2004. The increase in revenues is primarily attributable to a 39% increase in average day rates and an increase in utilization to 96% in 2005 from 82% in 2004. The improvement in day rates and utilization is attributable to increased spending by oil and gas companies. Contract drilling expense increased due to increased utilization and an increase in reimbursable expenses.
North and South America Jackup Rigs
In 2006, revenues for our North and South America jackup rigs increased by $303.8 million, or 83%, and contract drilling expense increased by $30.5 million, or 22%, as compared to 2005. The increase in revenues is due primarily 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, continued to mobilize rigs contracted for work in international markets out of the Gulf of Mexico. Shorter term contracts, generally prevalent in the Gulf of Mexico, allow day rates to increase or decrease at a faster pace than those of regions with predominantly longer term contracts. Therefore, the increases in day rates for Gulf of Mexico jackup rigs have typically exceeded the day rate increases experienced in international regions during periods of increasing rig demand, decreasing rig supply, or both. The increase in contract drilling expense is primarily attributable to increased personnel costs, insurance costs and rig mobilization expense as compared to the prior year.
In 2005, revenues for our North and South America jackup rigs increased by $91.5 million, or 33%, and contract drilling expense decreased by $9.6 million, or 7%, as compared to 2004. The increase in revenues is due primarily to a 52% increase in average day rates, partially offset by a $36.2 million decrease in revenue attributable to the relocation of three jackup rigs from the region in 2004 and one in early 2005. The increase in average day rates is primarily attributable to a reduction in the supply of available rigs in the region. The decrease in the supply of jackup rigs was partially due to several of our competitors' rigs being taken out of operation in the second half of 2005 to prepare for international contract commitments. Additionally, Hurricane Katrina and Hurricane Rita disrupted drilling operations and severely damaged or destroyed several rigs operating in the region thereby reducing the number of available rigs even further. The decrease in contract drilling expense is primarily attributable to $4.0 million of costs incurred during the second quarter of 2004 relating to the termination of a rig transportation contract associated with the delayed relocation of two jackup rigs from the Gulf of Mexico to the Middle East and to an $18.5 million decrease in expense due to the reduced size of the fleet in 2005, partially offset by an increase in repair costs and the receipt of a $500,000 insurance premium rebate in 2004, which resulted from the low level of claims experienced during a prior policy year.
North America Semisubmersible Rig
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 is 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.
In 2005, revenues for ENSCO 7500 increased by $28.2 million, or 118%, and contract drilling expense increased by $5.7 million, or 35%, as compared to 2004. The increase in revenues and contract drilling expense is attributable to the rig being idle while undergoing minor improvements, regulatory inspection and maintenance procedures during approximately six months of 2004.
Depreciation and Amortization
Our depreciation and amortization expense for 2006 increased by $21.6 million, or 14%, as compared to 2005. The increase is 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.
Our depreciation and amortization expense for 2005 increased by $20.4 million, or 15%, as compared to 2004. The increase is primarily attributable to depreciation on capital enhancement projects completed in 2005 and 2004 and depreciation on ENSCO 106, which was placed into service in March of 2005.
General and Administrative
Our general and administrative expense for 2006 increased by $12.6 million, or 39%, as compared to 2005. The increase is primarily attributable to an increase in salary expense and share-based compensation expense.
Our general and administrative expense for 2005 decreased by $1.1 million, or 3%, as compared to 2004. The decrease is primarily attributable to non-recurring costs incurred in 2004 related to information systems consulting services, Sarbanes-Oxley Act compliance initiatives and other projects, partially offset by an increase in personnel costs in 2005.
Other Income (Expense)
The table below summarizes the components of other income (expense) for each of the years in the three-year period ended December 31, 2006 (in millions):
The increase in our interest income in 2006 is due to higher average interest rates and an increase in cash balances invested. The increase in interest income in 2005 is due to higher average interest rates. The decrease in interest expense during 2006 and 2005 is primarily due to a decrease in outstanding debt.
The increase in our capitalized interest during 2006 is due to an increase in the amount invested in the ENSCO 108, ENSCO 8500, ENSCO 8501 and ENSCO 8502 new rig construction projects. The increase in capitalized interest during 2005 also is attributable to the amount invested in new rig construction projects, primarily ENSCO 107, ENSCO 108 and ENSCO 8500, in addition to the enhancement projects associated with ENSCO 67 and ENSCO 87.
Provision for Income Taxes
The income tax rates imposed in the tax jurisdictions in which our non-U.S. subsidiaries conduct operations vary, as does the tax base to which the rates are applied. In some cases, tax rates may be applicable to gross revenue, statutory or negotiated deemed profits, or other bases utilized under local tax laws, rather than to net income. In addition, our drilling rigs are frequently moved from one tax jurisdiction to another. As a result, our consolidated effective income tax rate may vary substantially from one reporting period to another, depending on the relative components of our earnings generated in tax jurisdictions with higher tax rates or lower tax rates.
Our income tax expense was $252.7 million in the year ended December 31, 2006 and our effective income tax rate was 25.0%. In the year ended December 31, 2005, our income tax expense was $100.5 million and our effective income tax rate was 27.1%. In the year ended December 31, 2004, our income tax expense was $29.9 million and our effective income tax rate was 24.2%.
The increase in income tax expense from 2005 to 2006 is primarily attributable to increased profitability, partially offset by a reduction in our effective income tax rate. The decrease in our effective tax rate is primarily due to an increase in the relative components of our earnings from tax jurisdictions with lower tax rates.
The increase in income tax expense from 2004 to 2005 is primarily attributable to increased profitability and an increase in our effective income tax rate. The increase in our effective tax rate is primarily due to a decrease in the relative components of our earnings from tax jurisdictions with lower tax rates.
Discontinued Operations
In recent years we have focused on our jackup rig and ultra-deepwater semisubmersible rig operations and de-emphasized those operations and assets considered to be non-core or that do not meet our standards for financial performance. Accordingly, we sold a jackup rig and two platform rigs to KFELS in 2004 in connection with the execution of the ENSCO 107 construction agreement, we sold five barge rigs and one platform rig in 2005 and we sold our one remaining platform rig, ENSCO 25, during the fourth quarter of 2006.
We also effectively sold the ENSCO 64 jackup rig in 2005 and the ENSCO 29 platform rig in 2006 by transferring beneficial ownership to our insurance underwriters because each rig became a constructive total loss under our insurance policies subsequent to sustaining substantial damage caused by hurricanes.
The operating results of all of the aforementioned rigs have been reclassified as discontinued operations in the consolidated statements of income for each of the years in the three-year period ended December 31, 2006. The table below summarizes our income (loss) from discontinued operations for each of the years in the three-year period ended December 31, 2006 (in millions):
There is no debt or interest expense allocated to our discontinued operations. See Note 9 to the Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for information concerning discontinued operations.
Adoption of New Accounting Standard
We grant share options, previously referred to as "stock options," and non-vested share awards, previously referred to as "restricted stock," 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"). 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, our prior period consolidated financial statements have been restated to include share option compensation cost previously reported in the pro forma footnote disclosures required by SFAS 123.
LIQUIDITY AND CAPITAL RESOURCES Although our business is very cyclical, we have historically 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, 2006, our primary sources of cash included an aggregate $1,538.6 million generated from continuing operations, an aggregate $168.9 million from the disposition of assets, including $156.6 million from the disposal or insurance recovery related to various discontinued operations in 2006 and 2005, and $116.8 million from the exercise of stock options. During the three-year period ended December 31, 2006, our primary uses of cash included an aggregate $1,310.2 million for the acquisition, construction, enhancement and other improvement of our drilling rigs, $160.0 million for the repurchase of common stock, $98.4 million for the repayment of loans and $45.6 million for the payment of dividends.
Detailed explanations of our liquidity and capital resources for each of the years in the three-year period ended December 31, 2006 are set forth below.
Cash Flow from Continuing Operations and Capital Expenditures
The table below summarizes 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, 2006 (in millions):
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.
Cash flow from our continuing operations in 2005 increased by $108.4 million, or 45%, from 2004. The increase resulted primarily from a $250.6 million increase in cash receipts from drilling services partially offset by a $23.0 million increase in cash payments for contract drilling expenses and a $129.2 million increase in cash payments related to income taxes.
We continue to expand the size and quality of our drilling rig fleet. During the past three years, we have invested $461.5 million upgrading the capability and extending the service lives of our drilling rigs and an additional $520.8 million related to new rig construction.
During 2004 and 2005, we exercised our purchase options and acquired a harsh environment jackup rig, ENSCO 102, for a net payment of $94.6 million and an ultra-high specification jackup rig, ENSCO 106, for a net payment of $79.6 million. Both rigs were constructed through joint ventures with KFELS. Construction of ENSCO 107, an ultra-high specification jackup rig, was completed on January 23, 2006, at which time we made the final installment payment of $27.5 million and accepted delivery.
We have three ultra-deepwater semisubmersible rigs and one ultra-high specification jackup rig currently under construction by KFELS in Singapore. ENSCO 108 commenced construction in April 2005 and is expected to be delivered during the first quarter of 2007. ENSCO 108 will be an enhanced KFELS MOD V-B design jackup rig modified to ENSCO specifications and nearly identical to ENSCO 107.
In September 2005, we entered into an agreement with KFELS to construct ENSCO 8500, with delivery anticipated in the second quarter of 2008. The total construction cost of the rig is currently expected to be approximately $312.0 million. In January 2006, we entered into an agreement with KFELS to construct ENSCO 8501 for a total construction cost of approximately $338.0 million. Delivery of ENSCO 8501 is expected during the first quarter of 2009. In September 2006, we entered into an agreement with KFELS to construct ENSCO 8502 for a total construction cost of approximately $385.0 million, Delivery of ENSCO 8502 is expected during the fourth quarter of 2009. The ENSCO 8500 SeriesTM ultra-deepwater semisubmersibles are based on our proprietary design and are enhanced versions of the ENSCO 7500 capable of drilling in up to 8,500 feet of water, and can readily be upgraded to 10,000 feet water-depth capability if required. Enhancements over ENSCO 7500, our existing ultra-deepwater semisubmersible rig, 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 SeriesTM rigs will be especially well-suited for deepwater development drilling. The ENSCO 8500 and ENSCO 8501 are subject to long term drilling contracts of four years and three and one-half years, respectively.
Based on our existing projections, we currently expect that capital expenditures in 2007 will include approximately $65.0 million for minor upgrades and improvements, approximately $50.0 million for rig enhancement projects and approximately $310.0 million for new construction which includes progress payments for ENSCO 108, ENSCO 8500, ENSCO 8501 and ENSCO 8502. Depending on market conditions and opportunities, we may also make additional capital expenditures to 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, 2006, 2005 and 2004 are summarized below (in millions, except percentages):
*
Total capital includes long-term debt plus stockholders' equity.
We have $150.0 million of outstanding notes that are classified in "Current maturities of long-term debt" on our December 31, 2006, consolidated balance sheet because they mature in November 2007. Accordingly, this obligation is not included in our December 31, 2006, long-term debt, total capital and long-term debt to total capital ratio above.
We have a $350.0 million unsecured revolving credit facility (the "2005 Credit Facility") with a syndicate of banks that matures in June 2010. We had no amounts outstanding under the 2005 Credit Facility at December 31, 2006 or 2005, and do not currently anticipate borrowing under the 2005 Credit Facility during 2007. We are in compliance with the financial covenants under the 2005 Credit Facility, which require the maintenance of a specified level of interest coverage and debt to total capitalization ratio. We maintain investment grade credit ratings of Baa1 from Moody's and BBB+ from Standard & Poor's.
On March 14, 2006, our Board of Directors authorized a stock repurchase program for the repurchase of up to $500.0 million of our outstanding common stock. During the year ended December 31, 2006, we repurchased 3.5 million shares of our common stock at a cost of $160.0 million (an average cost of $46.23 per share).
At December 31, 2006, we had $114.0 million outstanding under our 6.36% bonds due 2015, which are collateralized by the ENSCO 7500 semisubmersible drilling rig, and $63.0 million outstanding under our 4.65% bonds due 2020, which are collateralized by the ENSCO 105 jackup drilling rig. The bonds are guaranteed by the United States Department of Transportation, Maritime Administration ("MARAD") and we have guaranteed the performance of our obligations under the bonds to MARAD through two separate security agreements (the "Security Agreements"). The Security Agreements contain customary restrictive covenants that, among other things, require us to maintain certain levels of insurance coverage on ENSCO 7500 and ENSCO 105 and limit the amount of deductibles and/or levels of self-insurance retained by us to no more than $10.0 million per occurrence and $20.0 million annual aggregate for each rig. We have historically insured ENSCO 7500 and ENSCO 105 for amounts no less than their estimated fair market value, subject to certain deductibles and levels of self-insurance that are well within the requirements of the Security Agreements.
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 2005 and 2004. Accordingly, insurance companies substantially reduced the levels of insurance coverage available for losses arising from Gulf of Mexico hurricane related windstorm damage and dramatically increased the cost of such coverage. We renewed our insurance coverage effective as of July 1, 2006 and obtained coverage for losses arising from Gulf of Mexico hurricane related windstorm damage with limits and deductibles and/or levels of self-insurance that would not have complied with the insurance covenants contained in the Security Agreements. In consideration of us issuing letters of credit in favor of MARAD for an aggregate amount of $100.0 million, MARAD has waived our compliance with the insurance covenants in the Security Agreements as they relate to amounts of coverage and self-insurance retention for the period July 1, 2006 through July 1, 2007. Accordingly, we remain in compliance with the insurance covenants of the Security Agreements.
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, 2006, and the periods in which such obligations are due (in millions):
Liquidity
The table below summarizes our liquidity position at December 31, 2006, 2005 and 2004 (in millions, except ratios):
We expect to fund our short-term liquidity needs, including an aggregate $628.7 million of contractual obligations and anticipated capital expenditures during 2007, as well as any stock repurchases, dividends and working capital requirements from our cash and cash equivalents and operating cash flow.
We expect to fund our long-term liquidity needs, including contractual obligations and anticipated capital expenditures, from our cash and cash equivalents, investments, operating cash flow and, if necessary, funds drawn under the 2005 Credit Facility or other future financing arrangements.
We have historically funded the majority of our liquidity from operating cash flow. We anticipate a substantial amount of our cash flow in the near to intermediate-term will continue to be invested in the expansion and enhancement of our fleet of drilling rigs. As a significant portion of such expenditures are elective, we expect to be able to maintain adequate liquidity throughout future business cycles through the deferral or acceleration of our future capital investments, as necessary. Accordingly, while future operating cash flow cannot be accurately predicted, our management believes our long-term liquidity will continue to be funded primarily by operating cash flow.
MARKET RISK We have net assets and liabilities denominated in numerous foreign currencies and use various methods to manage our exposure to foreign currency exchange risk. We predominantly structure our contracts in U.S. dollars, which significantly reduces the portion of our cash flows and assets denominated in foreign currencies. We also employ various strategies, including the use of derivative instruments, to match foreign currency denominated assets with equal or near equal amounts of foreign currency denominated liabilities, thereby minimizing exposure to earnings fluctuations caused by changes in foreign currency exchange rates. We also utilize derivative instruments to hedge forecasted foreign currency denominated transactions. At December 31, 2006, we had contracts outstanding to exchange an aggregate $99.7 million U.S. dollars for various foreign currencies, all of which mature during the next thirteen months. If we were to incur a hypothetical 10% adverse change in foreign currency exchange rates, the net unrealized loss associated with our foreign currency denominated assets and liabilities and related foreign currency exchange contracts as of December 31, 2006 would approximate $1.5 million.
We use various derivative financial instruments to manage our exposure to interest rate risk. We occasionally use interest rate swap agreements to effectively convert the variable interest rate on debt to a fixed rate or the fixed rate on debt to a variable rate, and interest rate lock agreements to hedge against increases in interest rates on pending financing. At December 31, 2006, we had no outstanding interest rate swap agreements or interest rate lock agreements.
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. We believe that our use of derivative instruments and related hedging activities do not expose us to any material interest rate risk, foreign currency exchange rate risk, commodity price risk, credit risk or any other material market rate or price risk.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
The preparation of financial statements and related disclosures in conformity with U.S. generally accepted accounting principles requires our management to make estimates, judgments and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. Our significant accounting policies are included in Note 1 to the Consolidated Financial Statements. These policies, along with our underlying assumptions and judgments made in their application, have a significant impact on our consolidated financial statements. We identify our most critical accounting policies as those that are the most pervasive and important to the portrayal of our financial position and operating results, and that require the most difficult, subjective and/or complex judgments by our management regarding estimates in matters that are inherently uncertain. Our most critical accounting policies are those related to property and equipment, impairment of long-lived assets and goodwill, and income taxes.
Property and Equipment
At December 31, 2006, the carrying value of our property and equipment totaled $2,960.4 million, which represents 68% of total assets. This carrying value reflects the application of our property and equipment accounting policies, which incorporate our management's estimates, assumptions and judgments relative to the capitalized costs, useful lives and salvage values of our rigs.
We develop and apply property and equipment accounting policies that are designed to appropriately and consistently capitalize those costs incurred to enhance, improve and extend the useful lives of our assets and expense those costs incurred to repair or maintain the existing condition or useful lives of our assets. The development and application of such policies requires judgment and assumptions by our management relative to the nature of, and benefits from, expenditures on our assets. We establish property and equipment accounting policies that are designed to depreciate or amortize our assets over their estimated useful lives. The assumptions and judgments used by our management in determining the estimated useful lives of our property and equipment reflect both historical experience and expectations regarding future operations, utilization and performance of our assets. The use of different estimates, assumptions and judgments in the establishment of our property and equipment accounting policies, especially those involving the useful lives of our rigs, would likely result in materially different carrying values of assets and operating results.
Useful lives of rigs are difficult to estimate due to a variety of factors, including technological advances that impact the methods or cost of oil and gas exploration and development, changes in market or economic conditions, and changes in laws or regulations affecting the drilling industry. We evaluate the remaining useful lives of our rigs on a periodic basis, considering operating condition, functional capability and market and economic factors. Our most recent change in estimated useful lives occurred in January 1998, when we extended the useful lives of our drilling rigs by an average of five to six years.
Our fleet of 43 jackup rigs comprises over 73% of both the gross cost and net carrying amount of our property and equipment at December 31, 2006 and is depreciated over useful lives ranging from 15 to 30 years. Our ultra-deepwater semisubmersible rig is depreciated over a 30-year useful life. The following table provides an analysis of estimated increases and decreases in depreciation expense that would have been recognized for the year ended December 31, 2006 for various assumed changes in the useful lives of our drilling rigs effective January 1, 2006:
Impairment of Long-Lived Assets and Goodwill
We evaluate the carrying value of our property and equipment, primarily our drilling rigs, when events or changes in circumstances indicate that the carrying value of such rigs may not be recoverable. Generally, extended periods of idle time and/or inability to contract rigs at economical rates are an indication that a rig may be impaired. However, the offshore drilling industry is highly cyclical and it is not unusual for rigs to be unutilized or underutilized for significant periods of time and subsequently resume full or near full utilization when business cycles change. Likewise, during periods of supply and demand imbalance, rigs are frequently contracted at or near cash break-even rates for extended periods of time until demand comes back into balance with supply. Impairment situations may arise with respect to specific individual rigs, groups of rigs, such as a specific type of drilling rig, or rigs in a certain geographic location. Our rigs are mobile and may generally be moved from markets with excess supply, if economically feasible. Our jackup rigs and 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, 2006, there was no impairment of goodwill.
Asset impairment evaluations are, by nature, highly subjective. In most instances they involve expectations of future cash flows to be generated by our drilling rigs, and are based on our management's assumptions and judgments regarding future industry conditions and operations, as well as our management's estimates of future expected utilization, contract rates, expense levels and capital requirements of our drilling rigs. The estimates, assumptions and judgments used by our management in the application of our asset impairment policies reflect both historical experience and an assessment of current operational, industry, economic and political environments. The use of different estimates, assumptions, judgments and expectations regarding future industry conditions and operations would likely result in materially different carrying values of assets and operating results.
Income Taxes
We conduct operations and earn income in numerous international countries and are subject to the laws of tax jurisdictions within those countries, as well as U.S. federal and state tax laws. At December 31, 2006, we have a $344.3 million net deferred income tax liability and $81.2 million of accrued liabilities for income taxes payable.
The carrying values of deferred income tax assets and liabilities reflect the application of our income tax accounting policies in accordance with Statement of Financial Accounting Standards No. 109, "Accounting for Income Taxes" ("SFAS 109"), and are based on our management's assumptions and estimates regarding future operating results and levels of taxable income, as well as our management's judgments regarding the interpretation of the provisions of SFAS 109. Carryforwards and tax credits are assessed for realization as a reduction of future taxable income by using a more-likely-than-not determination. A U.S. deferred tax liability has not been recognized for undistributed earnings of our non-U.S. subsidiaries because it is not practicable to estimate. Should we elect to make a distribution of these earnings, or be deemed to have made a distribution of them through application of various provisions of the Internal Revenue Code, we may be subject to additional U.S. income taxes.
The carrying values of liabilities for income taxes currently payable are based on management's interpretation of applicable tax laws, and incorporate management's assumptions and judgments regarding the use of tax planning strategies in various taxing jurisdictions. The use of different estimates, assumptions and judgments in connection with accounting for income taxes, especially those involving 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 deploying 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 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 deploy tax planning strategies and conduct international operations efficiently, our subsidiaries frequently enter into transactions with affiliates, which are generally subject to complex tax regulations and frequently are reviewed by tax authorities.
•
We may conduct future operations in certain tax jurisdictions where tax laws are not well developed and it may be difficult to secure adequate professional guidance.
•
Tax laws, regulations, agreements and treaties change frequently, requiring us to modify existing tax strategies to conform to such changes.
NEW ACCOUNTING PRONOUNCEMENTS In September 2006, the FASB issued SFAS No. 157, "Fair Value Measurements" ("SFAS 157"). SFAS 157 defines fair value, provides a framework for measuring fair value in accordance with U.S. generally accepted accounting principles, and expands the disclosures required for fair value measurements. SFAS No. 157 applies to other accounting pronouncements that require fair value measurements; it does not require any new fair value measurements. This statement is effective for financial statements issued for fiscal years beginning after November 15, 2007. We do not expect this statement will have a material effect on our consolidated financial position, operating results or cash flows.
In June 2006, the FASB reached consensus on Emerging Issues Task Force ("EITF") No. 06-3, "How Taxes Collected from Customers and Remitted to Governmental Authorities Should be Presented in the Income Statement" ("EITF 06-3"). The scope of EITF 06-3 includes any tax assessed by a governmental authority that is directly imposed on a revenue-producing transaction between a seller and a customer and may include, but is not limited to, sales, use, value added, and excise taxes. The Task Force affirmed its conclusion that entities should present these taxes in the income statement on either a gross or a net basis, based on their accounting policy, which should be disclosed pursuant to Accounting Principles Board Opinion ("APB") No. 22, "Disclosure of Accounting Policies". If those taxes are significant, and are presented on a gross basis, the amounts of those taxes should be disclosed. The consensus on EITF 06-3 will be effective for interim and annual reporting periods beginning after December 15, 2006. We generally record our tax-assessed revenue transactions on a net basis in our consolidated statements of income and therefore, we do not anticipate that EITF 06-3 will have a material effect on our consolidated financial position, operating results or cash flows.
In June 2006, the FASB issued Interpretation No. 48, "Accounting for Uncertainty in Income Taxes - an interpretation of FASB Statement No. 109" ("FIN 48"). This interpretation clarifies the accounting for uncertainty in income taxes recognized in financial statements in accordance with FASB Statement No. 109, "Accounting for Income Taxes". FIN 48 will require companies to determine whether it is more-likely-than-not that a tax position taken or expected to be taken in a tax return will be sustained upon examination, including resolution of any related appeals or litigation processes, based on the technical merits of the position. If a tax position meets the more-likely-than-not recognition threshold, it is measured to determine the amount of benefit to recognize in the financial statements based on guidance in the interpretation. FIN 48 is effective for fiscal years beginning after December 15, 2006. We have not completed our evaluation of FIN 48, however, we do not anticipate the adoption of FIN 48 will have a material effect on our consolidated financial position, operating results or cash flows.
Item 7A.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk Information required under Item 7A. has been incorporated into "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Market Risk."
Item 8.
Item 8. Financial Statements and Supplementary Data MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER
FINANCIAL REPORTING Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f) or 15d-15(f). Our internal control over financial reporting system is designed to provide reasonable assurance to our management and Board of Directors regarding the preparation and fair presentation of published financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. Under the supervision and with the participation of management, including the Chief Executive Officer and Chief Financial Officer, we have conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, we have concluded that our internal control over financial reporting is effective as of December 31, 2006 to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.
KPMG LLP, the independent registered public accounting firm who audited our consolidated financial statements, have issued an audit report on our assessment of our internal control over financial reporting. KPMG LLP's attestation report on management's assessment of our internal control over financial reporting is included herein.
February 22, 2007
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM The Board of Directors and Stockholders
ENSCO International Incorporated:
We have audited the accompanying consolidated balance sheets of ENSCO International Incorporated and subsidiaries as of December 31, 2006 and 2005, and the related consolidated statements of income and cash flows for each of the years in the three-year period ended December 31, 2006. These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of ENSCO International Incorporated and subsidiaries as of December 31, 2006 and 2005, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2006, in conformity with U.S. generally accepted accounting principles.
As discussed in Note 1 to the consolidated financial statements, effective January 1, 2006, the Company adopted the provisions of Statement of Financial Accounting Standards No. 123 (revised 2004), Share Based Payment. Also, as discussed in Note 1 to the consolidated financial statements, the Company changed its method of quantifying errors in 2006.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of ENSCO International Incorporated and subsidiaries internal control over financial reporting as of December 31, 2006, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 22, 2007, expressed an unqualified opinion on management's assessment of, and the effective operation of, internal control over financial reporting.
/s/ KPMG LLP
Dallas, Texas
February 22, 2007
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM The Board of Directors and Stockholders
ENSCO International Incorporated:
We have audited management's assessment, included in the accompanying Management's Report on Internal Control Over Financial Reporting, that ENSCO International Incorporated and subsidiaries (ENSCO) maintained effective internal control over financial reporting as of December 31, 2006, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). ENSCO's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management's assessment and an opinion on the effectiveness of the Company's internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management's assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, management's assessment that ENSCO maintained effective internal control over financial reporting as of December 31, 2006, is fairly stated, in all material respects, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Also, in our opinion, ENSCO maintained, in all material respects, effective internal control over financial reporting as of December 31, 2006, based on criteria established in Internal Control-Integrated Framework issued by Committee of Sponsoring Organizations of the Treadway Commission (COSO).
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of ENSCO International Incorporated and subsidiaries as of December 31, 2006 and 2005, and the related consolidated statements of income and cash flows for each of the years in the three-year period ended December 31, 2006, and our report dated February 22, 2007 expressed an unqualified opinion on those consolidated financial statements.
/s/ KPMG LLP
Dallas, Texas
February 22, 2007
ENSCO INTERNATIONAL INCORPORATED AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(in millions, except per share amounts)
The accompanying notes are an integral part of these consolidated financial statements.
ENSCO INTERNATIONAL INCORPORATED AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(in millions, except par value amounts)
The accompanying notes are an integral part of these consolidated financial statements.
ENSCO INTERNATIONAL INCORPORATED AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in millions)
The accompanying notes are an integral part of these consolidated financial statements.
ENSCO INTERNATIONAL INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. DESCRIPTION OF THE BUSINESS AND SUMMARY OF SIGNIFICANT ACCOUNTING
POLICIES
Business
ENSCO International Incorporated is one of the leading international providers of offshore contract drilling services to the oil and gas industry. We have one of the largest and most capable offshore drilling rig fleets in the world which is comprised of 45 drilling rigs, including 43 jackup rigs, one ultra-deepwater semisubmersible rig and one barge rig. Additionally, we have three ultra-deepwater semisubmersible rigs and one ultra-high specification jackup rig under construction. We drill and complete offshore oil and gas wells under contracts with major international, government-owned and independent oil and gas companies. We provide drilling services 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 wells. The customer bears substantially all of the ancillary costs of constructing the wells and supporting drilling operations, as well as the economic risk relative to the success of the wells.
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 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, 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. Gains and losses caused by the remeasurement process are included in "other, net" on the consolidated statements of income. We had net translation losses of $2.8 million for the year ended December 31, 2006, and net translation gains of $700,000 and $900,000 for the years ended December 31, 2005 and 2004, respectively.
Cash Equivalents and Short-Term Investments
Highly liquid investments with maturities of three months or less at the date of purchase are considered cash equivalents. Highly liquid investments with maturities of greater than three months but less than one year 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 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, 2006. Property and equipment held for sale is recorded at the lower of net book value or net realizable value.
Goodwill
Goodwill is recorded at fair value and arose in connection with prior acquisitions. 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, 2006, 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. Effective October 1, 2004, we changed our method of accounting for the fees received and related costs incurred to mobilize our rigs from one geographic area to another. Mobilization fees received and costs incurred are now deferred and recognized over the period that the related drilling services are performed on a straight-line basis.
Prior to October 1, 2004, only the excess of mobilization fees received over costs incurred or the excess of mobilization costs incurred over fees received, as applicable, was deferred and recognized on a straight-line basis over the period that the related drilling services were performed. We changed our method of accounting for mobilization fees and costs because we believe it is more appropriate to defer all mobilization fees and costs during the mobilization period and subsequently recognize them over the period that the drilling services are performed. If the method of accounting for mobilization fees and costs adopted on October 1, 2004, had been utilized in prior periods, our operating income and net income would not have changed and the change in the amounts of operating revenue and contract drilling expenses within previously reported periods would not have been material.
Demobilization fees and related costs are recognized as incurred, upon contract completion. Costs associated with the mobilization of equipment and personnel to more promising market areas without contracts are expensed as incurred.
Deferred mobilization costs are included in prepaid expenses and other current assets and other assets, net, and totaled $15.0 million, at both December 31, 2006 and 2005. Deferred mobilization revenue is included in accrued liabilities and other liabilities and totaled $29.2 million and $25.0 million at December 31, 2006 and 2005, 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 liabilities and totaled $2.7 million and $4.4 million at December 31, 2006 and 2005, 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 prepaid expenses and other current assets and other assets, net, and totaled $4.1 million and $6.1 million at December 31, 2006 and 2005, 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 qualifies as effective due to an unanticipated change in forecasted transactions are recognized currently in earnings and included in "other, net" on the consolidated statement of income based on the change in the market value of the cash flow hedge. When a forecasted transaction is no longer probable of occurring, gains and losses on the cash flow hedge previously recorded in the accumulated other comprehensive loss section of shareholders' equity are reclassified currently into earnings and included in "other, net" on the consolidated statement of income. In assessing the effectiveness of a cash flow hedge, the hedge's time value component is excluded from the measurement of hedge effectiveness and recognized currently in earnings in "other, net" on the consolidated statement of income.
We occasionally enter into derivatives that economically hedge certain risks, but we do not designate such derivatives as hedges or the derivatives otherwise do not qualify for hedge accounting. In these situations, there generally exists a natural hedging relationship where changes in the fair value of the derivatives offset changes in the fair value of the underlying hedged items. Changes in the fair value of these derivatives are recognized currently in earnings in "other, net" on the consolidated statement of income.
Derivatives with asset fair values are reported in other current assets or other assets, net, depending on maturity date. Derivatives with liability fair values are reported in accrued current liabilities or other liabilities, depending on maturity date. At December 31, 2006 and 2005, the fair value of our foreign currency derivatives was a net asset of $4.0 million and a net liability of $2.7 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. It is our policy and intention to permanently reinvest all of the 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.
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.
Interest and penalties relating to income taxes are included in current income tax expense.
Share-Based Employee Compensation
We sponsor several share-based compensation plans that provide equity compensation to our employees, officers and directors. Effective January 1, 2006, we adopted the fair value recognition provisions of Financial Accounting Standards No. 123, (revised 2004) "Share-Based Payment" ("SFAS 123(R)"), using the modified-retrospective transition method. Under that transition method, compensation cost recognized in prior periods has been 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, 2006, there were no adjustments to net income for purposes of calculating basic and diluted earnings per share. The following is a reconciliation of the weighted average common shares used in the basic and diluted earnings per share computations for each of the years in the three-year period ended December 31, 2006 (in millions):
Options to purchase 684,000 shares of common stock in 2006, 15,000 shares of common stock in 2005 and 3.3 million shares of common stock in 2004 were not included in the computation of diluted earnings per share because the exercise price of the options exceeded the average market price of the common stock.
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 are 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.
We have historically used the rollover approach to quantify and evaluate the effects of financial statement misstatements. In applying the guidance of SAB 108, we have concluded the two misstatements described below, when evaluated using the iron curtain approach, are material to the current year financial statements.
In 1997, we adopted a policy pursuant to which the depreciation of a rig was suspended during periods it was out of service while undergoing major upgrade and enhancement procedures. In 2005, we discontinued this policy after concluding it was not in accordance with U.S. generally accepted accounting principles. We evaluated the financial statement misstatements resulting from the application of this policy and concluded their impact on each of our prior period financial statements was immaterial. In accordance with SAB 108, we have 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"). Historically, 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 is temporarily stored and consumed later. We have 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 is immaterial to our prior period financial statements and current period interim financial statements. During the fourth quarter of 2006, we adopted an inventory accounting policy that records 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 have elected to report the cumulative effect of the financial statement misstatements relating to accounting for inventory, a $32.3 million increase in prepaid expenses and other current assets, $6.7 million increase in deferred tax liabilities and $25.6 million increase in retained earnings, effective January 1, 2006. The new inventory accounting policy discussed above did not have a material impact on our current period financial statements.
2. PROPERTY AND EQUIPMENT
Property and equipment at December 31, 2006 and 2005 consists of the following (in millions):
Work in progress at December 31, 2006 primarily consists of costs associated with various modification and enhancement projects and $455.0 million related to the construction of the ultra-high specification jackup rig, ENSCO 108, and our three ultra-deepwater semisubmersible rigs, ENSCO 8500, ENSCO 8501 and ENSCO 8502. Work in progress at December 31, 2005 primarily consists of costs associated with various modification and enhancement projects and $181.1 million related to the construction of two ultra-high specification jackup rigs, ENSCO 107 and ENSCO 108, and the ultra-deepwater semisubmersible rig, ENSCO 8500.
3. LONG-TERM DEBT
Long-term debt at December 31, 2006 and 2005 consists of the following (in millions):
Bonds Due 2020 and 2015
In October 2003, we issued $76.5 million of 17-year bonds to provide long-term financing for ENSCO 105. The bonds 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.
In January 2001, we issued $190.0 million of 15-year bonds to provide long-term financing for ENSCO 7500. The bonds are being 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.
Both bond issuances are guaranteed by the United States Department of Transportation, Maritime Administration ("MARAD") and we have guaranteed the performance of our obligations under the bonds to MARAD through two separate security agreements (the "Security Agreements"). The Security Agreements contain customary restrictive covenants that, among other things, require us to maintain certain levels of insurance coverage on ENSCO 7500 and ENSCO 105 and limit the amount of deductibles and/or levels of self-insurance retained by us to no more than $10.0 million per occurrence and $20.0 million annual aggregate for each rig. We have historically insured ENSCO 7500 and ENSCO 105 for amounts no less than their estimated fair market value, subject to certain deductibles and levels of self-insurance that are well within the requirements of the Security Agreements.
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 2005 and 2004. Accordingly, insurance companies substantially reduced the levels of insurance coverage available for losses arising from Gulf of Mexico hurricane related windstorm damage and dramatically increased the cost of such coverage. We renewed our insurance coverage effective as of July 1, 2006 and obtained coverage for losses arising from Gulf of Mexico hurricane related windstorm damage with limits and deductibles and/or levels of self-insurance that would not have complied with the insurance covenants contained in the Security Agreements. In consideration of us issuing letters of credit in favor of MARAD for an aggregate amount of $100.0 million, MARAD has waived our compliance with the insurance covenants in the Security Agreements as they relate to amounts of coverage and self-insurance retention for the period July 1, 2006 through July 1, 2007. Accordingly, we remain in compliance with the insurance covenants of the Security Agreements.
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”). Interest on the Notes and the Debentures is payable semiannually in May and November. The Notes and Debentures 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 Notes and 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 Notes and Debentures are not subject to any sinking fund requirements. The Notes are classified in "Current maturities of long-term debt" on the December 31, 2006, consolidated balance sheet.
Revolving Credit Facility
We have a $350.0 million unsecured revolving credit facility (the "2005 Credit Facility") with a syndicate of lenders for general corporate purposes. The 2005 Credit Facility has a five-year term, expiring in June 2010. Advances under the 2005 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 are in compliance with the financial covenants under the 2005 Credit Facility which require the maintenance of a specified level of interest coverage and debt to total capitalization ratio. We had no amounts outstanding under the 2005 Credit Facility at December 31, 2006 or 2005, and do not currently anticipate borrowing under the 2005 Credit Facility during 2007.
Maturities
The aggregate maturities of long-term debt, excluding un-amortized discounts of $1.4 million, for each of the five years subsequent to December 31, 2006, are as follows (in millions):
4. DERIVATIVE FINANCIAL INSTRUMENTS
The estimated amount of net unrealized gains on derivative instruments, net of tax at December 31, 2006, that will be reclassified to earnings during the next twelve months is as follows (in millions):
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 thirteen 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 comprehensive income for each of the years in the three-year period ended December 31, 2006, are as follows (in millions):
The accumulated other comprehensive loss section of stockholders' equity at December 31, 2006 and 2005 is comprised of net unrealized losses on derivatives, net of tax.
6. STOCKHOLDERS' EQUITY
Cash dividends of $.10 per share were paid in each of the years in the three-year period ended December 31, 2006. On March 14, 2006, our Board of Directors authorized a stock repurchase program for the repurchase of up to $500.0 million of our outstanding common stock. During the year ended December 31, 2006, we repurchased 3.5 million shares of our common stock at a cost of $160.0 million (an average cost of $46.23 per share). At December 31, 2006 and 2005, the outstanding shares of our common stock, net of treasury shares, were 151.8 million and 153.4 million, respectively.
A summary of activity in the various stockholders' equity accounts for each of the years in the three-year period ended December 31, 2006 is as follows (in millions):
7. EMPLOYEE BENEFIT PLANS
Adoption of New Accounting Standard
We grant share options, previously referred to as "stock options," and non-vested share awards, previously referred to as "restricted stock," 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 has been restated to include share option compensation cost previously reported in the pro forma footnote disclosures required by SFAS 123. Compensation cost recognized in each of the years in the two-year period ended December 31, 2005 has been restated to include: (a) compensation cost for all share options granted prior to, but not yet vested as of January 1, 2004, 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 each of the years in the two-year period 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 has been restated to adjust deferred income taxes, additional paid-in capital and retained earnings to reflect all share options granted prior to, but not yet vested as of January 1, 2005, and to reflect compensation cost recognized during the year ended December 31, 2005.
No restatement is necessary related 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 each of the years in the two-year period ended December 31, 2005 resulting from the adoption of SFAS 123(R) on January 1, 2006 (in millions, except per share amounts):
To reflect share option compensation cost recognized prior to January 1, 2006, deferred income tax assets increased by $6.8 million, additional paid-in capital increased by $72.6 million and retained earnings decreased by $65.8 million on the December 31, 2005 consolidated balance sheet.
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, have increased by $4.9 million, and for the year ended December 31, 2004, both have decreased by $1.9 million
Share-based compensation expense recognized in the consolidated statement of income for the year ended December 31, 2006, 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. Forfeitures were estimated 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 are 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 have been 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, will be 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), 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, employees and non-employee directors. 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, 2006, options to purchase 1.7 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, 2006, options to purchase 1.5 million shares of our common stock were outstanding under the 1998 Plan and the Directors' Plan.
The following table summarizes share option compensation expense recognized during each of the years in the three-year period ended December 31, 2006 (in millions):
The fair value of each option award is estimated on the date of grant using the Black-Scholes option valuation model with the following weighted average assumptions for each of the years in the three-year period ended December 31, 2006:
Expected volatility is based on the historical volatility of the market price of our common stock over the period of time equivalent to the expected term of the options granted. The expected term of options granted is derived from historical exercise patterns over a period of time equivalent to the term of the options granted. We have not experienced significant differences in the historical exercise patterns among officers, employees and non-employee directors for them to be considered separately for valuation purposes. The risk-free interest rate is based on the implied yield of U.S. Treasury zero-coupon issues on the date of grant with a remaining term approximating the expected term of the options granted.
A summary of share option activity for the year ended December 31, 2006, is as follows (shares and intrinsic value in thousands, term in years):
The following table summarizes the value of options granted and exercised during each of the years in the three-year period ended December 31, 2006:
The following table summarizes information about share options outstanding at December 31, 2006 (shares in thousands):
As of December 31, 2006, there was $25.7 million of total unrecognized compensation cost related to share options granted, which is expected to be recognized over a weighted-average period of 2.5 years.
Non-Vested Share Awards
Key employees, who are in a position to contribute materially to our growth and development and to our long-term success, are eligible for non-vested share awards. 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, shares of common stock subject to annual grants of non-vested share awards generally vest at a rate of 20% per year and grants of non-vested share awards to new or recently promoted employees generally vest at a rate of 10% 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, 2006, there were 1.8 million shares of common stock available for non-vested share awards under the 2005 Plan.
The following table summarizes non-vested share award compensation expense recognized during each of the years in the three-year period ended December 31, 2006 (in millions):
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, 2006:
A summary of non-vested share award activity for the year ended December 31, 2006, is as follows (shares in thousands):
As of December 31, 2006, there was $34.3 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 5.3 years.
Savings Plan
We have a profit sharing plan (the “ENSCO Savings Plan”) which covers eligible employees with more than one year of service, 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 $12.6 million, $5.0 million and $3.1 million for the years ended December 31, 2006, 2005 and 2004, 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 based on the amount of employee contributions and rates set by our Board of Directors. Matching contributions totaled $4.7 million, $4.2 million and $4.1 million in 2006, 2005 and 2004, 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. The matching and vesting 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 $1.2 million in 2006, $52,000 in 2005 and $51,000 in 2004. A SERP liability of $13.2 million and $8.6 million is included in other liabilities at December 31, 2006 and 2005, respectively.
8. INCOME TAXES We had income of $500.2 million, $208.2 million and $53.6 million from our continuing operations before income taxes in the U.S. and income of $511.1 million, $162.3 million and $70.2 million from our continuing operations before income taxes in non-U.S. countries for the years ended December 31, 2006, 2005 and 2004, respectively.
The components of the provision for income taxes from continuing operations for each of the years in the three-year period ended December 31, 2006 are as follows (in millions):
Significant components of deferred income tax assets (liabilities) as of December 31, 2006 and 2005 are comprised of the following (in millions):
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, 2006, differs from the U.S. statutory income tax rate as follows:
At December 31, 2006, we had non-expiring foreign net operating loss carryforwards of $1.3 million in Denmark. During 2006, we reversed a $1.7 million valuation allowance established in 2005 against a $5.5 million deferred tax asset for the net operating loss carryforwards in Denmark, as substantially all of the net operating loss carryforwards were utilized in 2006. Based on current earnings projections, our management has determined that it is more-likely-than-not that the remaining $1.3 million of net operating loss carryforwards will be fully utilized.
The income tax provision for the year ended December 31, 2006 includes a $7.3 million net benefit that resulted from the settlement of issues with certain tax authorities during 2006 relating to prior periods. The income tax provision for the year ended December 31, 2005 includes a $4.6 million net benefit that results from the resolution of various issues during 2005 in connection with an audit by tax authorities of our 2002 and 2003 U.S. tax returns.
Undistributed earnings of our non-U.S. subsidiaries, which are permanently reinvested, totaled $307.2 million at December 31, 2006. A U.S. deferred tax liability has not been quantified for these undistributed earnings because it is not practicable to estimate. Should we make a distribution of them in the form of dividends or otherwise, we may be subject to additional U.S. income taxes.
9. DISCONTINUED OPERATIONS
On December 27, 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 three-year period ended December 31, 2006.
The ENSCO 29 platform rig sustained substantial damage as a consequence of Hurricane Katrina in September 2005. On January 5, 2006, beneficial ownership of ENSCO 29 effectively transferred to our insurance underwriters because the rig was 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 is included in "Gain on disposal of discontinued operations, net" in the consolidated statement of income for the year ended December 31, 2006. The $7.5 million carrying value of the rig is classified in "Property and equipment, net" on the December 31, 2005 consolidated balance sheet. In September 2006, we recognized a $1.2 million provision ($800,000 net of tax) relating to issues involving ENSCO 29 wreckage and debris removal insurance coverage. (See Note 10 "Commitments and Contingencies".) The operating results of ENSCO 29 have been reclassified as discontinued operations in the consolidated statements of income for each of the years in the three-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 statements of income for each of the years in the two-year period 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 statements of income for each of the years in the two-year period ended December 31, 2005.
The ENSCO 64 jackup rig sustained substantial damage during Hurricane Ivan in September 2004. On April 15, 2005, beneficial ownership of ENSCO 64 effectively transferred to our insurance underwriters because the rig was a constructive total loss under the terms of our insurance policies. Accordingly, we transferred beneficial ownership of ENSCO 64 to insurance underwriters and received the rig's insured value of $65.0 million. On the date of transfer, the net book value of the rig was $52.8 million. We recognized a pre-tax gain of $11.7 million upon receipt of the insurance proceeds, which is included in "Gain on disposal of discontinued operations, net" in the consolidated statement of income for year ended December 31, 2005. The operating results of ENSCO 64 have been reclassified as discontinued operations in the consolidated statements of income for each of the years in the two-year period ended December 31, 2005.
In February 2004, we entered into an agreement with KFELS to exchange three rigs (ENSCO 23, ENSCO 24 and ENSCO 55) and $55.0 million for the construction of a new ultra-high specification jackup rig to be named ENSCO 107. The exchange of the three rigs occurred in May 2004 and was treated as a sale with no significant gain or loss recognized, as the fair value of the rigs approximated their aggregate net book value of $39.9 million. The operating results of ENSCO 23, ENSCO 24 and ENSCO 55 have been reclassified as discontinued operations in the consolidated statement of income for the year ended December 31, 2004.
Following is a summary of income (loss) from discontinued operations for each of the years in the three-year period ended December 31, 2006 (in millions):
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 $7.1 million in 2006, $5.3 million in 2005 and $5.2 million in 2004. Future minimum rental payments under our noncancellable operating lease obligations having initial or remaining lease terms in excess of one year are as follows: $5.6 million in 2007; $1.7 million in 2008; $400,000 in 2009; $200,000 in 2010 and $100,000 thereafter.
Contingencies
A portion of the ENSCO 29 platform drilling rig was lost over the side of a customer's platform during Hurricane Katrina in September 2005. Although beneficial ownership of ENSCO 29 was subsequently transferred to our insurance underwriters because the rig was a constructive total loss, management believes we may be required to remove the ENSCO 29 wreckage and debris from the seabed and currently estimates the removal cost could range from $5.0 million to $15.0 million. Our property insurance policies include coverage for ENSCO 29 wreckage and debris removal costs up to $3.8 million. We also retain 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 a reservation of rights letter raising issues regarding the applicability of coverage for the potential ENSCO 29 wreckage and debris removal costs. We will contest any assertion that the ENSCO 29 wreckage and debris removal is not subject to coverage under the liability insurance policies and intend to pursue all available remedies in the event our liability insurance underwriters deny coverage. 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 September 2004, the Republic of India amended the Finance Act, 1994, by enacting the Finance (No. 2) Act, 2004 (the "Act"), which purported to extend a 12.2% tax levied on services to the specific service of "survey and exploration of minerals." Based on the definition of "survey and exploration of minerals" contained in the Act, we do not believe our contract drilling operations in India should be considered taxable services, and thus, have neither paid nor recognized a liability for the tax. In March 2006, a Writ Petition, filed by the local chapter of the International Association of Drilling Contractors ("IADC"), challenging the applicability of the Act to contract drilling services, was admitted by an Indian Court and a hearing is currently pending. The position taken by the IADC in its Writ Petition is supported by the Oil and Natural Gas Corporation Limited, the government sponsored oil company in India. In addition, we have contractual indemnities from our customer that provide for full reimbursement of any tax that may be assessed. Therefore, if the Indian Court should determine the tax applies to contract drilling services, we would recognize, through December 31, 2006, both a $12.3 million expense and liability for such tax and an equal corresponding $12.3 million as reimbursable revenue and receivable from our customer. Accordingly, we do not expect the resolution of this matter to have a material effect on our financial position, operating results or cash flows.
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 seek 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, as decided by the Mississippi Supreme Court in Harold's Auto Parts, Inc., et al vs. Flower Mangialardi, et al, 889 So. 2d 493 (Miss 2004), the individual claimants in the original multi-party lawsuits whose claims were not dismissed were ordered to either file 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 pending claims, we have been named as a defendant by 61 individual plaintiffs. Of these claims, there are a total of 59 claims or lawsuits pending in Mississippi state courts and two pending in United States District Court as a result of their removal from state court.
We currently intend to vigorously defend against these claims and have filed responsive pleadings preserving all defenses and challenges to jurisdiction and venue. However, inasmuch as discovery is in the very early stages and available information regarding the nature of these claims is limited, we cannot reasonably determine if the claimants have valid claims under the Jones Act or estimate a range of potential liability exposure, if any. At present, none of the pending Mississippi asbestos lawsuits have been set for trial and, while we do not expect the final disposition of these lawsuits to have a material adverse effect upon our financial position, operating results or cash flows, there can be no assurances as to the ultimate outcome of the lawsuits.
Legislation known as the U.K. Working Time Directive 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 unions representing offshore employees have claimed that drilling contractors are not in compliance with the U.K. Working Time Directive in respect of paid time off (vacation time) for employees working offshore on a rotational basis (generally equal time working and off), and the related issues are subject to pending or potential judicial, administrative and legislative review. Based on the information available at this time, we do not expect the resolution of this matter 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 and are involved from time to time as parties to governmental proceedings, including matters related to taxation, all arising in the ordinary course of business. Although the outcome of lawsuits or other proceedings involving us and our subsidiaries cannot be predicted with certainty and the amount of any liability that could arise with respect to such lawsuits or other proceedings cannot be predicted accurately, management does not expect these matters to have a material effect on our financial position, operating results or cash flows.
11. SEGMENT INFORMATION
Our operations consist of one reportable segment: contract drilling services. At December 31, 2006, our contract drilling segment owned and operated a fleet of 45 offshore drilling rigs, including 43 jackup rigs, one ultra-deepwater semisubmersible rig and one barge rig.
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, 2006, our Asia Pacific operations consist of 18 jackup rigs deployed in various locations and one barge rig located in Indonesia. Our Europe/Africa operations consist of nine jackup rigs, eight of which are deployed in various territorial waters of the North Sea and one is located offshore Nigeria. Our North and South America operations consisted of 16 jackup rigs and one ultra-deepwater semisubmersible rig. Fifteen of our North and South America jackup rigs and our one ultra-deepwater semisubmersible rig are located in the U.S. waters of the Gulf of Mexico and one jackup rig is located offshore Venezuela.
We attribute revenues to the geographic location where such revenue is earned and assets to the geographic location of the drilling rig at December 31of the applicable year. For new construction projects, assets are attributed to the location of future operation if known or to the location of construction if the ultimate location of operation is undetermined. Information by country for those countries that account for more than 10% of total revenues or 10% of our long-lived assets is as follows (in millions):
12. SUPPLEMENTAL FINANCIAL INFORMATION
Consolidated Balance Sheet Information
Accounts receivable, net at December 31, 2006 and 2005 consists of the following (in millions):
Prepaid expenses and other current assets at December 31, 2006 and 2005 consist of the following (in millions):
Other assets, net at December 31, 2006 and 2005 consists of the following (in millions):
Accrued liabilities at December 31, 2006 and 2005 consists of the following (in millions):
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, 2006 is as follows (in millions):
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, 2006 is as follows (in millions):
Capitalized interest totaled $18.9 million in 2006, $8.9 million in 2005 and $3.9 million in 2004.
Financial Instruments
The carrying amounts and estimated fair values of our debt instruments at December 31, 2006 and 2005 are as follows (in millions):
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, 2006 and 2005. 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, 2006 and 2005, the fair value of such contracts was a net asset of $4.0 million and a net liability of $2.7 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 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 and investments consist of a portfolio of high-grade instruments. Custody of cash equivalents and investments 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 2006, no customer provided more than 10% of consolidated revenues. During 2005, one customer provided 12%, or $127.0 million, of consolidated revenues. During 2004, no customer provided more than 10% of consolidated revenues.
13. UNAUDITED QUARTERLY FINANCIAL DATA
A summary of unaudited quarterly consolidated income statement data for the years ended December 31, 2006 and 2005, is as follows (in millions, except per share amounts):
Item 9.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial
Disclosure
Not applicable.
Item 9A.
Item 9A. Controls and Procedures
CONCLUSION REGARDING THE EFFECTIVENESS OF DISCLOSURE CONTROLS AND PROCEDURES
Based on their evaluation as of the end of the period covered by this Annual Report on Form 10-K, our Chief Executive Officer and Chief Financial Officer have concluded that our disclosure controls and procedures, as defined in Rule 13a-15 under the Securities Exchange Act of 1934 (the "Exchange Act"), are effective.
During the fiscal quarter ended December 31, 2006, there were no changes in our internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. See "Item 8. Financial Statements and Supplementary Data" for Management's Report on Internal Control Over Financial Reporting.
Item 9B.
Item 9B. Other Information
Not applicable.
PART III
Item 10.
Item 10. Directors, Executive Officers and Corporate Governance
The information required by this item with respect to our directors, corporate governance matters and committees of the Board of Directors is contained in our Proxy Statement for the Annual Meeting of Stockholders ("the Proxy Statement") to be filed with the Commission not later than 120 days after the end of our fiscal year ended December 31, 2006 and is incorporated herein by reference.
The information required by this item with respect to our executive officers is set forth in "Executive Officers of the Registrant" in Part I of this annual report on Form 10-K.
Information with respect to Section 16(a) of the Exchange Act is included under "Section 16(a) Beneficial Ownership Reporting Compliance" in our Proxy Statement and is incorporated herein by reference.
The guidelines and procedures of the Board of Directors are outlined in our Corporate Governance Policy. The committees of the Board of Directors operate under written charters adopted by the Board of Directors. The Corporate Governance Policy and committee charters are available on our website at www.enscous.com in the Governance section and are available in print without charge by contacting our Investor Relations Department at 214-397-3045.
We have a Code of Business Conduct Policy that applies to all of our employees, including our principal executive officer, principal financial officer and controller. The Code of Business Conduct Policy is available our website at www.enscous.com in the Governance section and is available in print without charge by contacting our Investor Relations Department. We intend to disclose any amendments to, or waivers from our Code of Business Conduct Policy by posting such information on our website. The Proxy Statement also will contain governance disclosures, including information concerning the director nomination process, shareholder director nominations, shareholder communications to the Board of Directors and director attendance at the Annual Meeting of Stockholders.
Item 11.
Item 11. Executive Compensation
The information required by this item is contained in the Proxy Statement and is incorporated herein by reference.
Item 12.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder
Matters
The following table sets forth, as of December 31, 2006, certain information related to our compensation plans under which shares of our Common Stock are authorized for issuance:
*
In connection with the acquisition of Chiles Offshore Inc. ("Chiles") on August 7, 2002, we assumed Chiles' stock option plan and the outstanding stock options thereunder. At December 31, 2006, options to purchase 5,167 shares of our common stock, at a weighted-average exercise price of $24.08 per share, were outstanding under this plan. No shares of our common stock are available for future issuance under this plan, no further share options will be granted under this plan and the plan will be terminated upon the earlier of the exercise or expiration date of the last outstanding option.
Additional information required by this item is included in the Proxy Statement and is incorporated herein by reference.
Item 13.
Item 13. Certain Relationships and Related Transactions, and Director Independence
The information required by this item is contained in the Proxy Statement and is incorporated herein by reference.
Item 14.
Item 14. Principal Accounting Fees and Services
The information required by this item is contained in the Proxy Statement and is incorporated herein by reference.
PART IV
Item 15.
Item 15. Exhibits, Financial Statement Schedules
(a) The following documents are filed as part of this report:
1. Financial Statements
Reports of Independent Registered Public Accounting Firm
Consolidated Statements of Income
Consolidated Balance Sheets
Consolidated Statements of Cash Flows
Notes to Consolidated Financial Statements
2. Financial Statement Schedules:
The schedules for which provision is made in the applicable accounting regulations of the SEC are not required under the related instructions or are inapplicable and, therefore, have been omitted.
3. Exhibits
Exhibit
No.
3.1 - Amended and Restated Certificate of Incorporation of the Company (incorporated by reference to Exhibit A to the Company's Definitive Proxy Statement filed with the Commission on March 21, 2005, File No. 1-8097).
3.2 - Revised and Restated Bylaws of the Company, effective November 9, 2004 (incorporated by reference to Exhibit 99.1 to the Registrant's Current Report on Form 8-K dated November 9, 2004, 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 Note (incorporated by reference to Exhibit 4.3 to the Registrant's Current Report on Form 8-K dated November 24, 1997, File No. 1-8097).
4.5 - Form of Debenture (incorporated by reference to Exhibit 4.4 to the Registrant's Current Report on Form 8-K dated November 24, 1997, File No. 1-8097).
+10.1 - ENSCO International Incorporated 1993 Incentive Plan, as amended (incorporated by reference to Exhibit 10.1 to the Registrant's Annual Report on Form 10-K for the year ended December 31, 1993, File No. 1-8097).
+10.2 - 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).
+10.3 - 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).
+10.4 - 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).
10.5 - 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).
+10.6 - 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).
10.7 - Bond Purchase Agreement of ENSCO Offshore Company dated January 22, 2001, concerning $190,000,000 of United States Government Guaranteed Ship Financing Obligations (incorporated by reference to Exhibit 10.1 to the Registrant's Quarterly Report on Form 10-Q for the quarter ended March 31, 2001, File No. 1-8097).
10.8 - 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).
10.9 - 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).
10.10 - 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).
+10.11 - 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).
+10.12 - 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).
+10.13 - 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).
10.14 - Amended and Restated Credit Agreement among ENSCO International Incorporated and ENSCO Offshore International Company as Borrowers, the lenders signatory thereto, Citigroup Global Markets Inc. and J.P. Morgan Securities Inc. as Joint Lead Arrangers and Joint Book Managers, Citibank, N.A. as Administrative Agent, JPMorgan Chase Bank, NA, as Syndication Agent, DnB NOR Bank ASA, New York Branch as Issuing Bank, The Bank Of Tokyo-Mitsubishi, Ltd., DnB NOR Bank ASA, New York Branch, and Wells Fargo Bank, N.A. as Co-Documentation Agents, and Mizuho Corporate Bank, Ltd. and SunTrust Bank as Co-Agents concerning a $350 million unsecured revolving credit facility, dated as of June 23, 2005 (incorporated by reference to Exhibit 10.1 to the Registrant's Current Report on Form 8-K dated June 23, 2005, File No. 1-8097).
+10.15 - 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).
+10.16 - 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).
+10.17 - Amendment to the ENSCO International Incorporated 1993 Incentive Plan, as amended (incorporated by reference to Exhibit 10.20 to the Registrant's Annual Report on Form 10-K for the year ended December 31, 2002, File No. 1-8097).
+10.18 - 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).
+10.19 - 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).
+10.20 - 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).
+10.21 - 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).
+10.22 - ENSCO International Incorporated Key Employees' Incentive Compensation Plan, as revised and restated effective January 1, 2003 (incorporated by reference to Exhibit 10.1 to the Registrant's Quarterly Report on Form 10-Q for the quarter ended June 30, 2003, File No. 1-8097).
+10.23 - 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).
+10.24 - 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).
+10.25 - ENSCO 2005 Benefit Reserve Trust, effective January 1, 2005 (incorporated by reference to Exhibit 99.3 to the Registrant's Current Report on Form 8-K dated January 5, 2005, File No. 1-8097).
+10.26 - 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).
+10.27 - 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).
+10.28 - 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).
+*10.29 - Amendment No. 7 to the ENSCO Savings Plan (As Revised and Restated Effective January 1, 1997), dated as of November 9, 2005.
+10.30 - 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).
+10.31 - 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).
+10.32 - 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).
+10.33 - 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).
+10.34 - 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).
+10.35 - 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).
+10.36 - 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).
+10.37 - 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).
+10.38 - 2007 Performance Measurement Criteria for Named Executive Officers under the ENSCO Cash Incentive Plan (incorporated by reference to Item 1.01 to the Registrants Current Report on Form 8-K dated November 6, 2006, File No. 1-8097).
+*10.39 - Amendment to the ENSCO International Incorporated 2005 Long-Term Incentive Plan, dated as of December 26, 2006.
+*10.40 - Amendment No. 9 to the ENSCO Savings Plan (As Revised and Restated Effective January 1, 1997), dated as of December 26, 2006.
+*10.41 - Amendment No. 10 to the ENSCO Savings Plan (As Revised and Restated Effective January 1, 1997), dated as of December 26, 2006.
*21.1 - Subsidiaries of the Registrant.
*23.1 - Consent of Independent Registered Public Accounting Firm.
*31.1 - Certification of the Chief Executive Officer of Registrant pursuant to Rule 13a-14 or 15d-14 of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
*31.2 - Certification of the Chief Financial Officer of Registrant pursuant to Rule 13a-14 or 15d-14 of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
*32.1 - Certification of the Chief Executive Officer of Registrant pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
*32.2 - Certification of the Chief Financial Officer of Registrant pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
* Filed herewith
+ Management contracts or compensatory plans and arrangements required to be filed as exhibits pursuant
to Item 15(b) of this report.
We will furnish to the Securities and Exchange Commission upon request, all constituent instruments defining the rights of holders of our long-term debt not filed here with as permitted by paragraph (b)(4)(iii)(A) of Item 601 of Regulation S-K.
SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized, on February 22, 2007.
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 22, 2007
/s/ GERALD W. HADDOCK
Gerald W. Haddock
Director
February 22, 2007
/s/ THOMAS L. KELLY II
Thomas L. Kelly II
Director
February 22, 2007
/s/ MORTON H. MEYERSON
Morton H. Meyerson
Director
February 22, 2007
/s/ RITA M. RODRIGUEZ
Rita M. Rodriguez
Director
February 22, 2007
/s/ PAUL E. ROWSEY, III
Paul E. Rowsey, III
Director
February 22, 2007
/s/ JOEL V. STAFF
Joel V. Staff
Director
February 22, 2007
/s/ CARL F. THORNE
Carl F. Thorne
Director
February 22, 2007
/s/ J. W. SWENT
J. W. Swent
Senior Vice President -
Chief Financial Officer
February 22, 2007
/s/ H. E. MALONE, JR.
H. E. Malone, Jr.
Vice President - Finance
February 22, 2007
/s/ DAVID A. ARMOUR
David A. Armour
Controller
February 22, 2007