Item 1. Business
General
ENSCO International Incorporated is an international offshore contract drilling company. As of February 17, 2009, our offshore rig fleet included 43 jackup rigs, two ultra-deepwater semisubmersible rigs and one barge rig. Additionally, we have six ultra-deepwater semisubmersible rigs under construction.
We are one of the leading providers of offshore contract drilling services to the international oil and gas industry. Our operations are concentrated in the geographic regions of Asia Pacific (which includes Asia, the Middle East, Australia and New Zealand), Europe/Africa and North and South America. In this report, the terms "Ensco," "Company," "we," "us" and "our" mean ENSCO International Incorporated and all subsidiaries included in our consolidated financial statements.
We provide drilling services on a "day rate" contract basis. Under day rate contracts, we provide the drilling rig and rig crews and receive a fixed amount per day for drilling the well. Our customers bear substantially all of the ancillary costs of constructing the well and supporting drilling operations, as well as the economic risk relative to the success of the well. In addition, our customers may pay all or a portion of the cost of moving our equipment and personnel to and from the well site. We do not provide "turnkey" or other risk-based drilling services.
We have assembled one of the largest and most capable offshore drilling rig fleets in the world. We have grown our fleet through corporate acquisitions, rig acquisitions and new rig construction. A total of 31 jackup rigs in our current fleet were obtained through the acquisitions of Penrod Holding Corporation in 1993, Dual Drilling Company in 1996 and Chiles Offshore Inc. in 2002. 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 acquired full ownership of ENSCO 102, a harsh environment jackup rig, and ENSCO 106, an ultra-high specification jackup rig. Both rigs were initially constructed through joint ventures with Keppel FELS Limited ("KFELS"), a major international shipyard. In January 2006 and March 2007, we completed construction of ENSCO 107 and ENSCO 108, both of which are ultra-high specification jackup rigs.
We have contracted KFELS to construct seven ultra-deepwater semisubmersible rigs (the "ENSCO 8500 Series®"), the first of which was delivered in September 2008 and is projected to commence operations in the Gulf of Mexico under a four-year contract in April 2009. During 2006, we entered into agreements to construct ENSCO 8501 and ENSCO 8502, with deliveries expected in the second quarter of 2009 and first quarter of 2010, respectively. During 2007, we entered into an agreement to construct the ENSCO 8503 with delivery expected in the fourth quarter of 2010. During 2008, we entered into agreements to construct ENSCO 8504, ENSCO 8505 and ENSCO 8506, with deliveries expected in the second half of 2011 and the first and second half of 2012, respectively. The ENSCO 8500 Series® ultra-deepwater semisubmersible rigs are based on our proprietary design and are enhanced versions of the ENSCO 7500 capable of drilling in up to 8,500 feet of water. The ENSCO 8501, ENSCO 8502 and ENSCO 8503 have secured long-term drilling contracts of three and one half years, two years and two years, respectively.
Our business strategy has been to focus on jackup rig and ultra-deepwater semisubmersible rig operations and de-emphasize other operations and assets considered to be non-core or that do not meet our standards for financial performance. Accordingly, we sold our marine transportation service vessel fleet, two platform rigs and two barge rigs in 2003. We sold one jackup rig and two platform rigs to KFELS in 2004 in connection with the execution of the ENSCO 107 construction agreement. We also disposed of five barge rigs and one platform rig in 2005 and our one remaining platform rig in 2006.
We were formed as a Texas corporation in 1975 and were reincorporated in Delaware in 1987. Our principal office is located at 500 North Akard Street, Suite 4300, Dallas, Texas, 75201-3331, and our telephone number is (214) 397-3000. Our website is www.enscointernational.com.
Contract Drilling Operations
We are in the process of developing a fleet of ultra-deepwater semisubmersible rigs. ENSCO 8500 was delivered by KFELS and arrived in the Gulf of Mexico in mid-December 2008. In connection with the arrival of our first ENSCO 8500 Series® rig, we reorganized the management of our operations, establishing a separate business unit to manage our fleet of ultra-deepwater semisubmersible rigs.
As part of this reorganization, we evaluated our remaining assets and operations, consisting of 43 jackup rigs and one barge rig organized into three business units based on major geographic region, and now consider these three business units as operating segments. Accordingly, our business now consists of four operating segments: (1) Deepwater, (2) Asia Pacific, (3) Europe/Africa and (4) North and South America. Each of our four operating segments provides one service, contract drilling. We have included segment information for prior periods to conform to our current year presentation.
We engage in the drilling of offshore oil and natural gas wells in domestic and international markets by providing our drilling rigs and crews under contracts with major international, government-owned and independent oil and gas companies. We currently own and operate 43 jackup rigs, two ultra-deepwater semisubmersible rigs and one barge rig. Of the 43 jackup rigs, 19 are located in the Asia Pacific geographic region, 10 are located in the Europe/Africa geographic region and 14 are located in the North and South America geographic region. ENSCO 7500 is currently mobilizing from the Gulf of Mexico to Australia where it is expected to resume operations in April 2009. ENSCO 8500 is currently located in the Gulf of Mexico where it is undergoing deepwater sea trials and is expected to commence operations under a four-year contract in April 2009. Our barge rig is currently stacked in Singapore. In addition, we have six ultra-deepwater semisubmersible rigs under construction by KFELS at a shipyard in Singapore.
Our drilling rigs are used to drill and complete oil and natural gas wells. Demand for our drilling services is based upon many factors which are beyond our control, including:
• market price of oil and natural gas and the stability thereof,
• production levels and related activities of the Organization of Petroleum Exporting Countries ("OPEC") and other oil and natural gas producers,
• global oil supply and demand,
• regional natural gas supply and demand,
• worldwide expenditures for offshore oil and natural gas drilling,
• long-term effect of worldwide energy conservation measures,
• the development and use of alternatives to hydrocarbon-based energy sources, and
• worldwide economic activity.
Our drilling contracts are the result of negotiations with our customers, and most contracts are awarded upon competitive bidding. Our drilling contracts generally contain the following commercial terms:
• contract duration extending over a specific period of time or a period necessary to drill one or more wells,
• term extension options in favor of our customer, generally upon advance notice to us, at mutually agreed, indexed or fixed rates,
• provisions permitting early termination of the contract (i) if the rig is lost or destroyed or (ii) by the customer if operations are suspended for a specified period of time due to breakdown of major rig equipment, unsatisfactory performance, "force majeure" events beyond our control and the control of the customer or other specified conditions,
• some of our drilling contracts permit early termination of the contract by the customer without cause, generally exercisable upon advance notice and in some cases without making an early termination payment to us,
• payment of compensation to us (generally in U.S. dollars although some contracts require a portion of the compensation to be paid in local currency) on a "day work" basis such that we receive a fixed amount for each day ("day rate") that the drilling unit is operating under contract (lower rates or no compensation generally apply during periods of equipment breakdown and repair or in the event operations are suspended or interrupted by other specified conditions, some of which may be beyond our control),
• payment by us of the operating expenses of the drilling unit, including crew labor and incidental rig supply costs, and
• provisions allowing us to recover certain labor and other operating cost increases from our customers through day rate adjustment or otherwise.
Financial information regarding our operating segments and geographic regions is presented in Note 13 to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data." Additional financial information regarding our operating segments is presented in "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations."
Backlog Information
Our contract drilling backlog reflects firm commitments, typically represented by signed drilling contracts, and was calculated by multiplying the contracted operating day rate by the firm contract period. The contracted operating day rate excludes certain types of non-recurring revenues for rig mobilization, demobilization, contract preparation and customer reimbursables.
Our contract backlog of business as of February 1, 2009 and 2008 was $4,035.0 million and $3,858.3 million, respectively. Our Deepwater backlog increased by $457.3 million primarily due to the ENSCO 8503 contract secured in May 2008. Our Asia Pacific and Europe/Africa backlog decreased by an aggregate $599.2 million primarily due to decreased contract durations and day rates for our international rigs. Our North and South America backlog increased by $318.6 million primarily due to long-term drilling contracts secured in Mexico. The table below provides a detail of our annual backlog by operating segment as of February 1, 2009 (in millions):
Our Deepwater backlog includes $1,176.9 million associated with three of our ultra-deepwater semisubmersible rigs under construction. Additional information on rig construction risks is presented in "Item 1A.
Item 1A. Risk Factors
There are numerous factors that affect our business and operating results, many of which are beyond our control. The following is a description of significant factors that might cause our future operating results to differ materially from those currently expected. The risks described below are not the only risks facing our Company. Additional risks and uncertainties not specified herein, not currently known to us or currently deemed to be immaterial also may materially adversely affect our business, financial condition, operating results and/or cash flows.
THE SUCCESS OF OUR BUSINESS LARGELY DEPENDS ON THE LEVEL OF ACTIVITY IN THE OIL AND GAS INDUSTRY WHICH CAN BE SIGNIFICANTLY AFFECTED BY VOLATILE OIL AND NATURAL GAS PRICES. The success of our business largely depends on the level of activity in offshore oil and natural gas exploration, development and production in markets worldwide. Oil and natural gas prices, and market expectations of potential changes in these prices, may significantly affect the level of drilling activity. An actual decline, or the perceived risk of a decline, in oil and/or natural gas prices could cause oil and gas companies to reduce their overall level of activity or spending, in which case demand for our services may decrease and revenues may be adversely affected through lower rig utilization and/or lower 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 natural 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 government 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,
• 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, and
• global economic conditions.
THE OFFSHORE CONTRACT DRILLING INDUSTRY HISTORICALLY HAS BEEN CYCLICAL, WITH PERIODS OF LOW DEMAND AND EXCESS RIG AVAILABILITY THAT COULD RESULT IN ADVERSE EFFECTS ON OUR BUSINESS. Financial operating results in the offshore contract drilling industry historically have been very cyclical and primarily are related to the demand for drilling rigs and the available supply of rigs.
Demand for rigs is directly related to the regional and worldwide levels of offshore exploration and development spending by oil and gas companies, which is beyond our control. Offshore exploration and development spending may fluctuate substantially from year to year and from region to region.
The supply of offshore drilling rigs is limited and new rigs require substantial capital investment and a long period of time to construct. There are 120 new jackup and semisubmersible rigs reported to be on order for delivery by the end of 2012. Approximately 60 of these rigs are scheduled for delivery in 2009, representing an approximate 10% increase in the total worldwide fleet of jackups and semisubmersible rigs. There are no assurances that the market in general, or a geographic region in particular, will be able to fully absorb the supply of new rigs in future periods.
The increase in supply of offshore drilling rigs in 2009 and future periods could result in an oversupply of offshore drilling rigs and could cause a decline in utilization and/or day rates, a situation which will be exacerbated by a decline in demand for drilling rigs. Lower utilization and/or day rates in one or more of the regions in which we operate could adversely affect our revenues, utilization and profitability.
Certain events, such as the limited availability of insurance for certain perils in some geographic areas, rig loss or damage due to hurricanes, blowouts, craterings, punchthroughs and other operational events, may impact the supply of rigs in a particular market and cause rapid fluctuations in rig demand, utilization and day rates.
Future periods of decreased demand and/or excess rig supply may require us to idle rigs or enter into lower day 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. A decrease in demand for drilling rigs or an increase in rig supply could adversely affect our financial condition, operating results and cash flows.
DUE TO THE DETERIORATION OF THE GLOBAL ECONOMY, RECENT DECLINE IN OIL AND NATURAL GAS PRICES AND SUBSTANTIAL UNCERTAINTY IN THE CAPITAL MARKETS, OUR CUSTOMERS MAY REDUCE SPENDING ON EXPLORATION AND DEVELOPMENT DRILLING AND CUSTOMERS AND/OR VENDORS AND SUPPLIERS MAY NOT BE ABLE TO FULFILL THEIR COMMITMENTS AND/OR FUND FUTURE OPERATIONS AND OBLIGATIONS, WHICH COULD HAVE A MATERIAL ADVERSE EFFECT ON OUR BUSINESS. The success of our business largely depends on the level of activity in offshore oil and natural gas exploration and development drilling worldwide.
Oil and natural gas prices, and market expectations of potential changes in these prices, significantly impact the level of worldwide drilling activity. Oil and natural gas prices have declined significantly during recent months in a deteriorating global economic environment. A sustained decline in oil and natural gas prices could cause oil and gas companies to reduce their overall level of drilling activity and spending. Disruption in the capital markets could also cause oil and gas companies to reduce their overall level of drilling activity and spending.
Historically, when drilling activity and spending decline, utilization and day rates also decline and drilling may be reduced or discontinued, resulting in an oversupply of drilling rigs. The oversupply of drilling rigs could be exacerbated by the projected entry of newbuild rigs into the market. When idled or stacked, drilling rigs do not earn revenue, but require cash expenditures for crews, fuel, insurance, berthing and associated items.
A sustained decline in oil and natural gas prices, together with the global economic crisis, could adversely affect our financial condition, operating results and cash flows.
WE MAY SUFFER LOSSES IF OUR CUSTOMERS TERMINATE OR SEEK TO RENEGOTIATE OUR CONTRACTS, IF OPERATIONS ARE SUSPENDED OR INTERRUPTED OR IF A RIG BECOMES A TOTAL LOSS. Our drilling contracts often are subject to termination without cause upon specific notice by the customer. Although contracts may require the customer to pay an early termination payment, such payment may not fully compensate for the loss of the contract and some of our contracts permit termination by the customer without an early termination payment. In periods of rapid market downturn, our customers may not honor the terms of existing contracts (including contracts for new rigs under construction), may terminate contracts or may seek to renegotiate contract day rates and terms to conform with depressed market conditions.
Drilling contracts customarily specify automatic termination or termination at the option of the customer in the event of a total loss of the drilling rig and often include provisions addressing termination rights or reduction or cessation of day rates if operations are suspended or interrupted for extended periods due to breakdown of major rig equipment, unsatisfactory performance, force majeure or other specified conditions, some of which may be beyond our control. Our financial condition, operating results and cash flows may be adversely affected by early termination of contracts, contract renegotiations or cessation of day rates while operations are suspended.
WE MAY INCUR ASSET IMPAIRMENTS AS A RESULT OF THE DETERIORATING GLOBAL ECONOMY AND THE POTENTIAL RESULTING DECLINE IN DEMAND FOR OFFSHORE DRILLING RIGS. 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. The offshore drilling industry historically has been highly cyclical and it is not unusual for rigs to be unutilized or underutilized for significant periods of time and subsequently resume full or near full utilization when business cycles change. Likewise, during periods of supply and demand imbalance, rigs are frequently contracted at, near or below cash break-even rates for extended periods of time, until day rates increase when demand comes back into balance with supply. However, if the global economic environment continues to deteriorate and the offshore drilling industry were to incur a significant prolonged downturn, impairment charges may occur with respect to specific individual rigs, groups of rigs, such as a specific type of drilling rig, or rigs in a certain geographic region.
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. In most instances, our calculation of the fair value of our reporting units is based on estimates of future cash flows to be generated by our drilling rigs, which reflect management's judgments and assumptions regarding future industry conditions and operations, including expected utilization, day rates, expense levels and capital requirements for each of our drilling rigs. If the global economic environment continues to deteriorate and the offshore drilling industry were to incur a significant prolonged downturn, our expectations of future cash flows may decline and ultimately result in goodwill impairment.
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. Although no customer represented more than 10% of revenues in 2008, our five largest customers accounted for approximately 40% of consolidated revenues in the aggregate. Our financial condition, operating results and cash flows may be materially adversely affected if any major customer terminates its contracts with us, fails to renew its existing contracts with us, requires renegotiation of our contracts or declines to award new contracts to us.
FAILURE TO RECRUIT AND RETAIN SKILLED PERSONNEL COULD IMPEDE OUR OPERATIONS AND FINANCIAL RESULTS. We require skilled personnel to operate our drilling rigs and to provide technical services and support for our business. Competition for skilled and other labor has intensified as additional rigs are added to the worldwide fleet. There are 120 new jackup and semisubmersible rigs reported to be on order for delivery by the end of 2012, approximately 60 of which are scheduled for delivery in 2009. These rigs will require new skilled and other personnel to operate. In periods of high utilization, it is more difficult and costly to recruit and retain qualified employees. 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.
During the recent robust market, we experienced a tightening in our labor markets largely due to the loss of experienced personnel to our customers, competitors and other businesses involved in oil and natural gas exploration activities. In response to these market conditions, we increased compensation paid to employees and incurred other costs to retain our workforce, including bonus and retention programs for certain personnel. Notwithstanding the global economic downturn, we may be required to maintain or increase existing levels of compensation to retain our skilled workforce. Further, due to prior downturns in the oil and gas industry, much of the skilled workforce is nearing retirement age, which may further exacerbate the shortage of skilled personnel. We also are subject to potential further unionization of our labor force or legislative or regulatory action that may impact working conditions, paid time off or other conditions of employment. If such labor trends continue, they could further increase our costs or limit our ability to fully staff and operate our rigs.
OUR DRILLING CONTRACTS WITH NATIONAL OIL COMPANIES EXPOSE US TO GREATER RISKS THAN WE NORMALLY ASSUME. We currently have nine jackup rigs contracted with national oil companies, including a subsidiary of the national oil company of Venezuela. The terms of these international contracts may expose us to greater commercial, political and operational risks than we normally assume in international contracts, such as exposure to greater environmental liability, the risk that the contract may be terminated by our customer without cause on short-term notice, contractually or by governmental action, under certain conditions that may not provide us an early termination payment, collection risks and political risks. While we believe that the financial, commercial and risk allocation terms of these contracts and our operating safeguards in place mitigate these risks, we can provide no assurance that the increased risk exposure will not have an adverse impact on our future operations or that we will not increase the number of rigs contracted to national oil companies with commensurate additional contractual risks.
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 all drilling rigs are affected by general economic and industry conditions, each type of drilling rig can be affected differently by changes in demand for drilling equipment. We currently have 43 jackup rigs, two ultra-deepwater semisubmersible rigs and one barge rig. Additionally, we have six ultra-deepwater semisubmersible rigs under construction.
Our drilling fleet is heavily concentrated in the premium jackup rig market. If the market for premium jackup rigs should decline relative to the markets for other drilling rig types, our operating results could be more adversely affected relative to our competitors with drilling fleets that are less concentrated in premium jackup rigs.
OUR INTERNATIONAL OPERATIONS INVOLVE ADDITIONAL RISKS NOT ASSOCIATED WITH DOMESTIC OPERATIONS.
A significant portion of our contract drilling operations is conducted in countries outside the United States. Revenues from international operations were 80%, 77% and 62% of our total revenues during 2008, 2007 and 2006, respectively. Our international operations and our international shipyard rig construction and enhancement projects are subject to political, economic and other uncertainties, including:
• terrorist acts, war and civil disturbances,
• expropriation, nationalization, deprivation or confiscation of our equipment,
• expropriation or nationalization of a customer's property or drilling rights,
• repudiation or nationalization of contracts,
• assaults on property or personnel,
• piracy, kidnapping and extortion demands,
• exchange restrictions,
• currency fluctuations,
• changes in the manner or rate of taxation,
• limitations on the ability to repatriate income or capital to the United States,
• limitations on our ability to recover amounts due,
• increased risk of government and vendor/supplier corruption,
• changes in political conditions, and
• changes in monetary policies.
We historically have maintained insurance coverage and obtained contractual indemnities that protect us from some, but not all, of the risks associated with our non-U.S. operations such as nationalization, deprivation, confiscation, political and war risks. However, there can be no assurance that any particular type of contractual or insurance protection will be available in the future or that we will be able to purchase our desired level of insurance coverage at commercially feasible rates. In circumstances where we have insurance protection for some or all of the risks associated with non-U.S. operations, such insurance may be subject to cancellations on short notice, and it is unlikely that we will be able to remove our rig or rigs from the affected area within the notice period. Accordingly, a significant event for which we are uninsured or underinsured, or for which we have not received an enforceable contractual indemnity from a customer, could cause a material adverse effect on our financial position, operating results and cash flows.
We are subject to various tax laws and regulations in substantially all of the non-U.S. countries in which we operate or have a legal presence. We evaluate applicable tax laws and employ various business structures and operating strategies in non-U.S. countries to obtain the optimal level of taxation on our revenues, income, assets and personnel. Actions by international tax authorities that impact our business structures and operating strategies, such as changes to tax treaties, laws and regulations, or the interpretation or repeal of same, adverse rulings in connection with audits or otherwise or other challenges, may substantially increase our tax expense.
Our international operations also face the risk of fluctuating currency values, which can impact our revenues, operating costs and capital expenditures. In addition, some of the countries in which we operate have occasionally enacted exchange controls. Historically, these risks have been limited by invoicing and receiving payment in U.S. dollars or freely convertible international currency and, to the extent possible, by limiting acceptance of foreign currency to amounts which approximate our expenditure requirements in such currencies. However, there is no assurance that our contracts will contain such terms in the future.
We currently conduct contract drilling operations in certain countries that have experienced substantial fluctuations in the value of their currency compared to the U.S. dollar. Our drilling contracts generally stipulate payment wholly or substantially in U.S. dollars, which reduces the impact currency fluctuations have on our earnings and cash flows. However, there is no assurance that our contracts will contain such payment terms in the future.
A substantial amount of the costs and expenditures incurred by our international operations, including a portion of the construction payments for the ENSCO 8500 Series® rigs, are settled in the local currencies of the countries in which we operate, exposing us to risks associated with fluctuation in the value of these currencies relative to the U.S. dollar. We use foreign currency forward contracts to reduce this exposure. However, the relative weakening in the value of the U.S. dollar in relation to the local currencies in these countries may increase our costs and expenditures.
Our international operations are also subject to various laws and regulations in countries in which we operate, including laws and regulations relating to the operation of drilling rigs and the requirement for equipment thereon. Governments in some non-U.S. countries have become increasingly active in regulating and controlling the ownership of oil, natural gas and mineral concessions and companies holding concessions, the exploration of oil and natural gas and other aspects of the oil and gas industry in their countries. In addition, government action, including initiatives by OPEC, may continue to cause oil and/or natural gas price volatility. In some areas of the world, government activity has adversely affected the amount of exploration and development work performed by major international oil companies and may continue to do so. There can be no assurance that such laws and regulations or activities will not have a material adverse effect on our future operations.
WE HAVE SUBSTANTIAL RISK ASSOCIATED WITH ENSCO 69 OPERATIONS FOR A NATIONAL OIL COMPANY IN VENEZUELA. Since May 2007, ENSCO 69 has been contracted to Petrosucre, a subsidiary of PDVSA, the national oil company of Venezuela. PDVSA subsidiaries lack funding and generally have not been paying their contractors and service providers. As of January 31, 2009, we had a total receivable balance of approximately $36.0 million under the ENSCO 69 contracts.
In late January 2009, we suspended drilling operations upon completion of the well in progress after Petrosucre failed to meet commitments relative to the payment of past due amounts. Petrosucre resumed ENSCO 69 drilling operations under observation by our supervisory rig personnel, utilizing Petrosucre employees and a portion of the Venezuelan rig crews that were utilized by us. Petrosucre has advised us that it temporarily is taking over operations on the rig. We currently are engaged in discussions and exchanging correspondence with Petrosucre regarding each party's contractual rights and obligations.
The ENSCO 69 contracts are governed by Venezuelan law and there can be no assurances as to the ultimate outcome of the pending dispute. The payment dispute and other risks associated with international operations for national oil companies, including expropriation or confiscation of our rig, could have a material adverse effect upon our financial position, operating results or cash flows.
CHANGES IN LAWS, EFFECTIVE INCOME TAX RATES OR ADVERSE OUTCOMES RESULTING FROM EXAMINATION OF OUR TAX RETURNS COULD ADVERSELY AFFECT OUR FINANCIAL RESULTS. Our future effective income tax rates could be adversely affected by changes in tax laws, both domestically and internationally. They could also be adversely affected by lower than anticipated earnings in countries where we have lower statutory rates and higher than anticipated earnings in countries where we have higher statutory rates, by changes in the valuation of our deferred tax assets and liabilities or by changes in tax treaties, regulations, accounting principles or interpretations thereof in one or more countries in which we operate. In addition, we are subject to the continuous examination of our income tax returns by the Internal Revenue Service and other tax authorities. We regularly assess the likelihood of adverse outcomes resulting from these examinations to determine the adequacy of our provision for income taxes. There can be no assurance that such examinations will not have an adverse effect on our financial condition, operating results or cash flows.
RIG CONSTRUCTION, UPGRADE AND ENHANCEMENT PROJECTS ARE SUBJECT TO RISKS, INCLUDING DELAYS AND COST OVERRUNS, WHICH COULD HAVE A MATERIAL ADVERSE EFFECT ON OUR OPERATING RESULTS. THE RISKS ARE CONCENTRATED BECAUSE OUR SIX ULTRA-DEEPWATER SEMISUBMERSIBLE RIGS CURRENTLY UNDER CONSTRUCTION ARE AT A SINGLE SHIPYARD IN SINGAPORE. THREE OF THESE RIGS DO NOT HAVE DRILLING CONTRACTS. There are 120 new jackup and semisubmersible rigs reported to be on order or under construction with expected delivery dates through 2012. As a result, shipyards and third party equipment vendors are under significant resource constraints to meet delivery obligations. Such constraints may lead to substantial delivery and commissioning delays and/or equipment failures and/or quality deficiencies. Furthermore, new drilling rigs may face start-up or other operational complications following completion of construction work, or other unexpected difficulties including equipment failures, design or engineering problems that could result in significant downtime at reduced or zero day rates or the cancellation or termination of drilling contracts.
We currently have six ultra-deepwater semisubmersible rigs under construction. In addition, we may construct additional rigs and continue to upgrade the capability and extend the service lives of our existing rigs. Rig construction, upgrade, life extension and repair projects are subject to the risks of delay or cost overruns inherent in any large construction project, including the following:
• failure of third party equipment to meet quality and/or performance standards,
• delays in equipment deliveries or shipyard construction,
• shortages of materials or skilled labor,
• damage to shipyard facilities, including damage resulting from fire, explosion, flooding, severe weather or terrorism,
• unforeseen design or engineering problems,
• unanticipated actual or purported change orders,
• strikes, labor disputes or work stoppages,
• financial or operating difficulties of equipment vendors or the shipyard while constructing, upgrading, refurbishing or repairing a rig or rigs,
• unanticipated cost increases,
• foreign currency fluctuations impacting overall cost,
• inability to obtain the requisite permits or approvals,
• force majeure, and
• additional risks inherent to shipyard projects in an international location.
Our risks are concentrated because our six ultra-deepwater semisubmersible rigs currently under construction are at a single shipyard in Singapore. Although based on the design of ENSCO 7500 which has operated without significant downtime since its delivery in 2000, these six rigs and the recently delivered ENSCO 8500 have a common risk of unforeseen design or engineering problems. Furthermore, ENSCO 8501, ENSCO 8502 and ENSCO 8503 are subject to firm, fixed day rate drilling contracts upon completion of construction and significant shipyard project cost overruns or delays could impact the projected financial results or the viability of the contracts and have a materially adverse effect on our financial condition, operating results and cash flows.
ENSCO 8504, ENSCO 8505 and ENSCO 8506 have not secured drilling contracts upon completion of their construction. These rigs are scheduled to be delivered in the second half of 2011 and first and second half of 2012, respectively. There is no assurance that we will secure drilling contracts for these rigs or that the drilling contracts we may be able to secure will be based upon rates and terms that will provide a reasonable rate of return on these investments. Our failure to secure contractual commitments for these rigs at rates and terms that result in a reasonable return prior to the completion of construction may result in a material adverse effect on our financial condition, operating results and cash flows. If we are able to secure drilling contracts prior to completion, we will be exposed to the risk of delays that could impact the projected financial results or the viability of the contract and could have a material adverse effect on our financial condition, operating results and cash flows.
WE HAVE INVESTED A PORTION OF OUR CASH IN AUCTION RATE SECURITIES AND WE MAY BE REQUIRED TO HOLD THEM INDEFINITELY DUE TO AN ILLIQUID MARKET. As of December 31, 2008, we held $72.3 million (par value) of auction rate securities. During 2008, auctions for most of our auction rate securities failed. An auction failure, which is not a default in the underlying debt instrument, occurs when there are more sellers than buyers at a scheduled interest rate auction date and parties desiring to sell their auction rate securities are unable to do so. When an auction fails, the interest rate is adjusted according to the provisions of the associated security agreement, which may result in an interest rate that is higher than the interest rate the issuer pays in connection with successful auctions.
Substantially all of our auction rate securities are currently rated Aaa by Moody's, AAA by Standard & Poor's and/or AAA by Fitch. An aggregate $68.6 million (par value), or 95%, of our auction rate securities were issued by state agencies and are supported by student loans for which repayment is substantially guaranteed by the U.S. government under the Federal Family Education Loan Program.
Auction failures and the resulting lack of liquidity have affected the entire auction rate securities market, and we are currently unable to determine whether these conditions will be of an extended duration. While it is estimated that approximately half of the $330.0 billion auction rate securities market has been refinanced, student loan supported auction rate securities remain mostly constrained and illiquid. Although $5.9 million of our student loan supported auction rate securities were redeemed at par value during the year ended December 31, 2008, we are currently unable to determine whether other issuers of our auction rate securities will attempt and/or be able to refinance.
Some broker/dealers previously indicated that they planned to develop secondary markets for auction rate securities, but no such market has materialized. Consequently, we are currently unable to determine if alternative markets that provide for orderly purchases and sales of auction rate securities will develop. Several major brokerage firms have announced regulatory settlements in which they will initially offer to repurchase auction rate securities from retail investors, charities and small businesses, and use best efforts to provide liquidity to institutional investors within the next several years. However, we are currently unable to determine whether these brokerage firms will be able to comply with the terms of their regulatory settlements. Moreover, the deteriorating global economic environment may impede auction rate security repurchases.
Although we acquired our auction rate securities with the intention of selling them in the near term, we do not currently expect to experience liquidity problems or alter any business plans if we maintain our investment in these securities indefinitely. Our auction rate securities have final maturity dates ranging from 2025 to 2047.
THE POTENTIAL FOR GULF OF MEXICO HURRICANE RELATED WINDSTORM DAMAGE COULD CAUSE 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 result in rig loss or damage or could cause termination of drilling contracts on lost or severely damaged rigs or curtailment of operations on damaged drilling rigs with reduced or suspended day rates for significant periods of time until the damage can be repaired. Moreover, even if our drilling rigs are not directly damaged by such storms, we may experience disruptions in our operations due to damage to our customers' platforms and other related facilities in the area. To date, our drilling operations in the Gulf of Mexico have not been materially impacted by hurricanes, although we sustained the total loss of one jackup rig during 2004, one platform rig during 2005 and one jackup rig during 2008 by reason of hurricane damage, with associated loss of contract revenues. We currently have 12 jackup rigs and one ultra-deepwater semisubmersible rig in the Gulf of Mexico.
Insurance companies incurred substantial losses in the offshore drilling, exploration and production industries as a consequence of hurricanes that occurred in the Gulf of Mexico during 2004, 2005 and 2008. 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, 2008, we obtained $155.0 million of annual aggregate coverage for jackup rig hull and machinery losses arising from Gulf of Mexico hurricane related windstorm damage with a $50.0 million per occurrence deductible (these limits do not apply to our ultra-deepwater semisubmersible rigs as long as the rigs take action to evade the storm by moving off location according to established procedures). This amount of coverage is significantly less than our historical coverage, and we have no assurance that we will be able to obtain insurance for Gulf of Mexico hurricane related windstorm damage in the future due to capacity limitations and high premium cost.
Our limited insurance coverage exposes us to a significant level of risk due to rig damage or loss related to severe weather conditions caused by Gulf of Mexico hurricanes or windstorms and could have a material adverse effect on our financial position, operating results and cash flows. Our current liability insurance policies maintain coverage for Gulf of Mexico hurricane related windstorm exposures, including excess removal of wreckage and debris, and have self-retained interest (generally equivalent to a deductible) of $10.0 million per occurrence.
We have established operational procedures designed to mitigate risk to our jackup rigs in the Gulf of Mexico during hurricane season. In addition to procedures designed to better secure the drilling package on jackup rigs, improve jackup leg stability and increase the air gap to position the hull above waves, our procedures involve analysis of prospective drilling locations, which may include enhanced bottom surveys. These procedures may result in a decision to decline to operate on a customer designated location during hurricane season notwithstanding that the location, water depth and other standard operating conditions are within a rig's normal operating range. Our procedures and the associated regulatory requirements addressing Mobile Offshore Drilling Unit operations in the Gulf of Mexico during hurricane season may result in a loss or reduction of work for our rigs at certain customer drilling locations, with a corresponding reduction in rig utilization or day rates in the Gulf of Mexico.
THE LOSS OF ENSCO 74 MAY EXPOSE US TO COSTS ASSOCIATED WITH REMOVAL OF WRECKAGE AND DEBRIS, LIABILITIES FOR PROPERTY LOSS OR DAMAGE, PERSONAL INJURY OR DEATH OR ENVIRONMENTAL LIABILITIES THAT MAY NOT BE FULLY RECOVERABLE UNDER OUR INSURANCE OR CONTRACTUAL INDEMNITIES. We have been unable to locate the hull of ENSCO 74, which is presumed to have sunk in the Gulf of Mexico in September 2008 as a result of Hurricane Ike. Portions of the rig's legs remain underwater adjacent to the customer's platform. We could be exposed to costs associated with removal of wreckage or debris if the hull is ultimately located and we are required to remove it. Furthermore, the sunken hull of ENSCO 74 may expose us to liabilities if it constitutes a hazard to navigation, and may expose us to various potential liabilities for property loss or damage, personal injury or death. Additionally, the ENSCO 74 hull contains certain fuel, oil, lubes and paint which, if released into the ocean, may create environmental liabilities and exposure to penalties, fines and clean-up costs. Our liability insurance and contractual indemnities may not fully protect us from such cost, liability or exposure.
We may also be required to remove the leg sections of ENSCO 74 from the seabed. Although we expect the cost of removal of the leg sections to be covered by available insurance and contractual indemnification, we may not be fully protected from such costs, liability or exposure.
OUR BUSINESS INVOLVES NUMEROUS OPERATING HAZARDS, AND WE ARE NOT FULLY INSURED AGAINST ALL OPERATING HAZARDS. Contract drilling and offshore oil and gas operations in general are subject to numerous risks, including the following:
• rig or other property damage, liability or loss, including removal of wreckage or debris, resulting from hurricanes and other severe weather conditions, collisions, groundings, blowouts, fires, explosions and other accidents or terrorism,
• blowouts, fires, explosions and other loss of well control events causing damage to wells, reservoirs, production facilities and other properties and which may require wild well control, including drilling of relief wells,
• craterings, punchthroughs or other events causing rigs to capsize, sink or otherwise incur significant damage or total loss,
• extensive uncontrolled rig or well fires, blowouts, oil spills or other discharges of pollutants causing damage to the environment,
• machinery breakdowns, equipment failures, personnel shortages, failure of subcontractors and vendors to perform or supply goods and services and other events causing the suspension or cancellation of drilling operations, and
• unionization or similar collective actions by our employees or employees of subcontractors causing suspension of drilling operations or significant increases in operating costs.
In addition to these risks to property and the environment, many of the hazards and risks associated with our operations, and accidents or other events resulting from such hazards and risks, as well as our routine operations, expose our personnel, as well as personnel of our customers, subcontractors, vendors and other third parties, to the risk of personal injury or death.
Although we currently maintain broad insurance coverage, subject to certain significant deductibles and levels of self-insurance or risk retention, it does not cover all types of losses and, in some situations such as rig loss or damage resulting from Gulf of Mexico hurricane related windstorm exposures, may not provide full coverage for damages, 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 historically have maintained insurance coverage for damage to or loss of our drilling rigs in amounts not less than the estimated fair market value thereof. However, in the event of total loss, such coverage is unlikely to be sufficient to recover the cost of a newly constructed replacement rig. Since we do not maintain business interruption or loss of hire insurance, we are fully exposed to loss of drilling contract revenue resulting from rig loss or damage.
We generally obtain contractual indemnification obligating our customers to protect and indemnify us for all or part of the liabilities resulting from pollution and damage to the environment, damage to wells, reservoirs and other customer property, control of wild wells, drilling of relief wells and certain non-rig crew personnel injuries. Such indemnification protection may be qualified or limited, and may exclude certain perils or events or the application of local law. In some circumstances, we are unable to obtain indemnification protection for some or all of the risks generally assumed by our customers, including risks and liabilities relating to environmental damage, well loss or damage or wild well control. The inability to obtain such indemnification, the failure of a customer to meet indemnification obligations or losses or liabilities resulting from uninsured or underinsured events could have a material adverse effect on our financial position, operating results and cash flows.
Our contracts generally protect us in whole or part from certain losses sustained as a result of our negligence, most frequently as respects pollution and damage to the environment, damage to wells or reservoirs, control of wild wells, drilling of relief wells and consequential damages. 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.
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 oil spills or similar discharges of pollutants or contaminants into the environment or improper disposal of hazardous waste generated in the course of our operations. To date, such laws and regulations have not had a material adverse effect on our operating results, and we have not experienced an accident that has exposed us to material liability for discharges of pollutants into the environment. However, there can be no assurance that such laws and regulations or accidents will not expose us to material liability in the future.
OPA 90 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 as well as 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.
Events in recent years have generally 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 have been enacted into law which would materially limit or prohibit offshore drilling in our principal areas of operation. However, we are adversely affected by moratoria on drilling in certain areas of the Gulf of Mexico and elsewhere. If new laws are enacted or other government action is taken that restrict or prohibit offshore drilling in our principal areas of operation or impose environmental protection requirements that materially increase the cost of offshore drilling, exploration, development or production of oil and natural gas, we could be materially adversely affected.
LAWS AND GOVERNMENTAL REGULATIONS MAY ADD TO COSTS, LIMIT OUR DRILLING ACTIVITY OR REDUCE DEMAND FOR OUR DRILLING SERVICES. 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 gas industry. Accordingly, we will be directly affected by the approval and adoption of laws and regulations limiting or curtailing exploration and development drilling for oil and natural gas for economic, environmental, safety and other policy reasons. We may be exposed to risks related to new laws or regulations pertaining to climate change, carbon emissions or energy use that could decrease the use of oil or natural gas, thus reducing demand for hydrocarbon-based fuel and our drilling services. Governments also may pass laws or regulations encouraging or mandating the use of alternative energy sources, such as wind power and solar energy, which may reduce demand for oil and natural gas and our drilling services. Furthermore, we may be required to make significant capital expenditures or incur substantial additional costs to comply with new governmental laws and regulations. It is also possible that legislative and regulatory activity could adversely affect our operations by limiting drilling opportunities or significantly increasing our operating costs.
TERRORIST ATTACKS, PIRACY AND MILITARY ACTION COULD HAVE A MATERIAL ADVERSE EFFECT ON OUR BUSINESS. Terrorist acts, piracy, kidnapping, extortion or acts of war may cause damage to or disruption of our domestic or international operations, employees, property and equipment or customers, suppliers and subcontractors, which may not be covered by insurance or an enforceable contractual indemnity and could significantly impact our financial position, operating results and cash flows. These acts create many economic and political uncertainties and the potential for future similar acts, the national and international responses and other acts of war or hostility could create many economic and political uncertainties, including an impact upon oil and natural gas drilling, exploration and development. This could adversely affect our business in ways that cannot readily be determined.
LEGAL PROCEEDINGS COULD AFFECT US ADVERSELY. We are involved in litigation, including various claims, disputes and regulatory proceedings that arise in the ordinary course of business, many of which are uninsured and relate to commercial, employment or regulatory activities. We also are concluding an internal investigation relating to compliance with the anti-bribery, recordkeeping and accounting provisions of the U.S. Foreign Corrupt Practices Act ("FCPA") that focuses on activities related to our former operations in Nigeria and the associated accounting entries and internal accounting controls, and have self-reported to the appropriate U.S. government authorities.
Although we cannot accurately predict the outcome of our litigation, claims, disputes, regulatory proceedings and investigations or the amount or impact of any associated liability or other sanctions, these matters could adversely affect our financial position, operating results or cash flows.
Item 1B.
Item 1B. Unresolved Staff Comments
None.
Item 2.
Item 2. Properties
Contract Drilling Fleet
The following table provides certain information about the rigs in our drilling fleet by operating segment as of February 17, 2009:
(1)
ENSCO 8500 was delivered by KFELS in September 2008 and arrived in the Gulf of Mexico in mid-December 2008. The rig is currently undergoing deepwater sea trials and is projected to commence operations under a four-year contract with Anadarko and Eni in April 2009.
(2)
Rig is currently under construction. The "year built" provided is based on the current construction schedule.
(3)
ENSCO 8501, ENSCO 8502 and ENSCO 8503 have secured long-term drilling contracts in the Gulf of Mexico of three and one half years, two years and two years, respectively. We are currently marketing ENSCO 8504, ENSCO 8505 and ENSCO 8506 and anticipate they will be contracted in advance of delivery. For additional information on our rigs under construction, see "Cash Flow and Capital Expenditures" included in "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations."
The equipment on our drilling rigs includes engines, drawworks, derricks, pumps to circulate the drilling fluid, blowout preventers, drill string and related equipment. The engines power a drive mechanism that turns the drill string and drill bit so that the hole is drilled by grinding subsurface materials, which are then returned to the rig by the drilling fluid. The intended well depth, water depth and drilling conditions are the principal factors that determine the size and type of rig most suitable for a particular drilling job.
Jackup rigs stand on the ocean floor with their hull and drilling equipment elevated above the water on connected leg supports. Jackup rigs are generally preferred over other rig types in water depths of 400 feet or less, primarily because jackup rigs provide a more stable drilling platform with above water blowout prevention equipment. All of our jackup rigs are of the independent leg design. All but one of our jackup rigs is equipped with a cantilever that allows the drilling equipment to extend outward from the hull over fixed platforms enabling drilling of both exploratory and development wells. The jackup rig hull supports the drilling equipment, jacking system, crew quarters, storage and loading facilities, helicopter landing pad and related equipment and supplies.
Semisubmersible rigs are floating offshore drilling units with pontoons and columns that partially submerge to a predetermined depth when sea water is permitted to enter the hull. Semisubmersible rigs can be held in a fixed location over the ocean floor either by being anchored to the sea bottom with mooring chains or dynamically positioned by computer-controlled propellers or "thrusters." ENSCO 7500, which is capable of drilling in water depths up to 8,000 feet, is a dynamically positioned rig that also can be adapted for moored operations. The ENSCO 8500 Series® rigs are enhanced versions of the ENSCO 7500, capable of drilling in up to 8,500 feet of water, and can be upgraded to 10,000 foot 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, we believe the ENSCO 8500 Series® rigs will be especially well-suited for deepwater development drilling.
Over the life of a typical rig, several of the major components are replaced due to normal wear and tear or technological advancements in drilling equipment. All of our rigs are in good condition. As of February 15, 2009, we own all of the rigs in our fleet.
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 lease office space domestically in Houston, Texas and internationally in Australia, Abu Dhabi, Denmark, Dubai, India, Indonesia, Malaysia, Mexico, New Zealand, Qatar, Saudi Arabia, Singapore, Thailand, Tunisia and Venezuela.
Item 3.
Item 3. Legal Proceedings
FCPA Internal Investigation
Following disclosures by other offshore service companies announcing internal investigations involving the legality of amounts paid to and by customs brokers in connection with temporary importation of rigs and vessels into Nigeria, the Audit Committee of our Board of Directors and management commenced an internal investigation in July 2007. The investigation initially focused on our payments to customs brokers relating to the temporary importation of ENSCO 100, our only rig that recently operated offshore Nigeria.
As is customary for companies operating offshore Nigeria, we had engaged independent customs brokers to process customs clearance of routine shipments of equipment, materials and supplies and to process the ENSCO 100 temporary importation permits, extensions and renewals. One or more of the customs brokers that our subsidiary in Nigeria used to obtain the ENSCO 100 temporary import permits, extensions and renewals also provided this service to other offshore service companies that have undertaken FCPA compliance internal investigations.
The principal purpose of our investigation was to determine whether any of the payments made to or by our customs brokers were inappropriate under the anti-bribery provisions of the FCPA or whether any violations of the recordkeeping or internal accounting controls provisions of the FCPA occurred. Our Audit Committee engaged a Washington, D.C. law firm with significant experience in investigating and advising upon FCPA matters to assist in the internal investigation.
Following notification to the Audit Committee and to KPMG LLP, our independent registered public accounting firm, in consultation with the Audit Committee's outside legal counsel, we voluntarily notified the United States Department of Justice and the SEC that we had commenced an internal investigation. We expressed our intention to cooperate with both agencies, comply with their directives and fully disclose the results of the investigation. The internal investigation process has involved extensive reviews of documents and records, as well as production to the authorities, and interviews of relevant personnel. In addition to the temporary importation of ENSCO 100, the investigation has examined our customs clearance of routine shipments and immigration activities in Nigeria.
The internal investigation has essentially been concluded. A meeting to review the results of the investigation with the authorities was held on February 24, 2009. We expect to discuss a possible negotiated disposition with the authorities during the second or third quarter of 2009. It currently is anticipated that the matter will be concluded within that period.
Although we believe the U.S. authorities will take into account our voluntary disclosure, our cooperation with the agencies and the remediation and compliance enhancement activities that are underway, we are unable to predict the ultimate disposition of this matter, whether we will be charged with violation of the anti-bribery, recordkeeping or internal accounting controls provisions of the FCPA or whether the scope of the investigation will be extended to other issues in Nigeria or to other countries. We also are unable to predict what potential corrective measures, fines, sanctions or other remedies, if any, the agencies may seek against us or any of our employees.
In November 2008, our Board of Directors approved enhanced FCPA compliance recommendations issued by the Audit Committee's outside counsel and the Company embarked upon an enhanced compliance initiative that included appointment of a Chief Compliance Officer and a Director - Corporate Compliance. We have engaged consultants to assist us in implementing the compliance recommendations approved by our Board of Directors, which will include an enhanced compliance policy, increased training and testing, prescribed contractual provisions for our service providers that interface with foreign government officials, due diligence for the selection of such service providers, and an increased Company-wide awareness initiative that includes periodic issuance of FCPA Alerts.
Since ENSCO 100 completed its contract commitment and departed Nigeria in August 2007, this matter is not expected to have a material effect on or disrupt our current operations. As noted above, we are unable to predict the outcome of this matter or estimate the extent to which we may be exposed to any resulting potential liability, sanctions or significant additional expense.
ENSCO 29 Wreck Removal
A portion of the ENSCO 29 platform drilling rig was lost over the side of a customer's platform as a result of Hurricane Katrina during the third quarter of 2005. Although beneficial ownership of ENSCO 29 was subsequently transferred to our insurance underwriters when the rig was determined to be a total loss, management believes we may be legally required to remove ENSCO 29 wreckage and debris from the seabed and currently estimates that the removal cost could range from $5.0 million to $15.0 million. Our property insurance policies include coverage for ENSCO 29 wreckage and debris removal costs up to $3.8 million. We also have liability insurance policies that provide specified coverage for wreckage and debris removal costs in excess of the $3.8 million coverage provided under our property insurance policies.
Our liability insurance underwriters have issued letters reserving rights and effectively denying coverage by questioning the applicability of coverage for the potential ENSCO 29 wreckage and debris removal costs. In August 2007, we commenced litigation in the Texas District Court of Dallas County against certain underwriters at Lloyd's and insurance companies, Bryan Johnson and BC Johnson Associates, LLC (collectively "the Underwriters") alleging breach of contract, wrongful denial, bad faith and other claims which seek a declaration that removal of wreckage and debris is covered under our liability insurance, monetary damages, attorneys' fees and other remedies. The Underwriters removed the case to the United States District Court for the Northern District of Texas, Dallas Division. The case was then remanded back to the Texas District Court by the United States District Court. The Underwriters then appealed the remand to the United States Court of Appeals. The litigation is in an early stage, and oral argument in United States Court of Appeals has been scheduled for March 2009.
While we anticipate that any ENSCO 29 wreckage and debris removal costs incurred will be largely or fully covered by insurance, a $1.2 million provision, representing the portion of the $5.0 million low end of the range of estimated removal cost we believe is subject to liability insurance coverage, was recognized during the third quarter of 2006.
Asbestos Litigation
In August 2004, we and certain current and former subsidiaries were named as defendants, along with numerous other third party companies as co-defendants, in three multi-party lawsuits filed in the Circuit Courts of Jones County (Second Judicial District) and Jasper County (First Judicial District), Mississippi. The lawsuits sought an unspecified amount of monetary damages on behalf of individuals alleging personal injury or death, primarily under the Jones Act, purportedly resulting from exposure to asbestos on drilling rigs and associated facilities during the period 1965 through 1986.
In compliance with the Mississippi Rules of Civil Procedure, the individual claimants in the original multi-party lawsuits whose claims were not dismissed were ordered to file either new or amended single plaintiff complaints naming the specific defendant(s) against whom they intended to pursue claims. As a result, out of more than 600 initial multi-party claims, we have been named as a defendant by 65 individual plaintiffs. Of these claims, 62 claims or lawsuits are pending in Mississippi state courts and three are pending in the U.S. District Court as a result of their removal from state court.
The majority of these cases currently are under an informal stay of discovery issued by a Special Master presiding over these matters while discovery is conducted for a designated group of plaintiffs, several of which involve us. To date, written discovery and plaintiff depositions have taken place in seven cases pending against us. No further activity will occur in these cases until they are selected for trial. Currently, none of the cases pending against us in Mississippi has been set for trial.
We intend to vigorously defend against these claims and have filed responsive pleadings preserving all defenses and challenges to jurisdiction and venue. However, discovery is still ongoing and, therefore, available information regarding the nature of all pending claims is limited. At present, we cannot reasonably determine how many of the claimants may have valid claims under the Jones Act or estimate a range of potential liability exposure, if any.
In addition to the pending cases in Mississippi, we have eight other asbestos or lung injury claims pending against us in litigation in various other jurisdictions. Although we do not expect the final disposition of the Mississippi and other asbestos 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.
Other Matters
In addition to the foregoing, we are named defendants in certain other lawsuits, claims or proceedings incidental to our business and are involved from time to time as parties to governmental investigations or proceedings, including matters related to taxation, all arising in the ordinary course of business. Although the outcome of such lawsuits or other proceedings cannot be predicted with certainty and the amount of any liability that could arise with respect to such lawsuits or other proceedings cannot be predicted accurately, management does not expect these matters to have a material adverse 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 2008.
PART II
Item 5.
Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of
Equity Securities
The following table provides the high and low sales price 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 1,112 stockholders of record on February 1, 2009.
We began paying a $.025 per share quarterly cash dividend on our common stock during the third quarter of 1997 and have continued to pay this quarterly dividend through December 31, 2008. Cash dividends totaling $.10 per share were paid in both 2008 and 2007. 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 on common stock issued or to be issued in connection with our equity compensation plans, see "Part III, Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters."
The following table provides a summary of our repurchases of common stock during the quarter ended December 31, 2008:
During the quarter ended December 31, 2008, our repurchases of common stock were from employees in connection with the settlement of income tax withholding obligations arising from the vesting of share awards.
In March 2006, our Board of Directors authorized the repurchase of up to $500.0 million of our outstanding common stock. In August 2007, following completion of the authorized repurchase, our Board of Directors authorized the repurchase of an additional $500.0 million of our outstanding common stock (the "2007 authorization"). In September 2008, our Board of Directors authorized the repurchase of an additional $500.0 million of our outstanding common stock (the "2008 authorization"). No repurchases of our common stock were made under the Board approved authorizations during the quarter ended December 31, 2008.
The chart below presents a comparison of the five-year cumulative total return, assuming $100 invested on December 31, 2003 and the reinvestment of dividends, 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 December 31, 2003 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 a leading provider of offshore contract drilling services to the international oil and gas industry. We own and operate a fleet of 46 drillings rigs, including 43 jackup rigs, two semisubmersible rigs and one barge rig. We are heavily concentrated in premium jackup rigs, but are currently in the process of developing a fleet of semisubmersible rigs. The worldwide semisubmersible rig fleet is generally divided into three categories: midwater, deepwater and ultra-deepwater. Our two semisubmersible rigs, ENSCO 7500 and ENSCO 8500, as well as our additional six semisubmersible rigs currently under construction, are ultra-deepwater semisubmersible rigs, capable of drilling at depths of 8,000 feet or greater. Our 46 drilling rigs are located throughout the world and concentrated in the major geographic regions of Asia Pacific (which includes Asia, the Middle East, Australia and New Zealand), Europe/Africa and North and South America.
We provide our drilling services to major international, government-owned and independent oil and gas companies on a "day rate" contract basis. Under day rate contracts, we provide the drilling rig and rig crews and receive a fixed amount per day for drilling the well. Our customers bear substantially all of the ancillary costs of constructing the well and supporting drilling operations, as well as the economic risk relative to the success of the well. Drilling contracts are, for the most part, awarded on a competitive bid basis. We do not provide "turnkey" or other risk-based drilling services.
Our revenues, operating income and net income increased to record levels during 2008 as a result of strong rig demand, high utilization and increased day rates in all geographic regions. ENSCO 8500, the first of our ENSCO 8500 Series Rigs®, was delivered during the third quarter and arrived in the Gulf of Mexico in mid-December 2008. The rig is currently undergoing deepwater sea trials and is projected to commence operations under a four-year contract in April 2009. Additionally, ENSCO 8501 is scheduled to be delivered during the latter half of the second quarter of 2009 and is expected to commence operations under its long-term drilling contract late in the third quarter.
During 2008, we also began construction of ENSCO 8504 and finalized construction agreements on ENSCO 8505 and ENSCO 8506. We entered into a long-term drilling contract for ENSCO 8503 in the Gulf of Mexico that is scheduled to commence during the first quarter of 2011. In addition to the substantial capital investment we made in our Deepwater fleet, we repurchased 3.7 million shares of our common stock at a cost of $256.0 million during 2008. We funded both our ultra-deepwater semisubmersible fleet expansion and share repurchase initiatives with cash flow generated from operations. We believe our strong balance sheet, including $789.6 million of cash and cash equivalents as of December 31, 2008, and favorable contract backlog will enable us to sustain an adequate level of liquidity during 2009.
Oil and natural gas prices have declined substantially in recent months due primarily to a decrease in demand for oil and natural gas resulting from the deteriorating global economy. In addition, substantial uncertainty in the capital markets has severely limited access to financing. These conditions are having an adverse effect on our business. Some of our current and prospective customers are deferring and curtailing drilling programs, which will result in a further reduction in demand for drilling rigs and a decline in utilization and day rates. In addition, certain of our customers and suppliers may be unable to access the capital markets to fund business operations which could adversely affect our business.
During 2008, over 30 new jackup and semisubmersible rigs were delivered and another 120 are reported to be on order or under construction. Current volatility in oil and natural gas prices and uncertainty in the capital markets will affect the construction and delivery of rigs currently on order or under construction. Several drilling contractors have announced cancellations of orders for new rigs or delayed construction of previously ordered rigs, and it is uncertain whether cancellations and delays will continue during 2009.
Our Industry
Historically, financial operating results in the offshore contract drilling industry have been cyclical and directly related to the demand for drilling rigs and the available supply of drilling rigs.
Drilling Rig Demand
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 natural gas,
• regional and global economic conditions and changes therein,
• political, social and legislative environments in the U.S. and other major oil-producing countries,
• production and inventory levels and related activities of the Organization of Petroleum Exporting Countries ("OPEC") and other oil and natural gas producers,
• technological advancements that impact the methods or cost of oil and natural gas exploration and development,
• disruption to exploration and development activities due to hurricanes and other severe weather conditions, and
• the impact that these and other events have on the current and expected future prices of oil and natural gas.
There was substantial volatility in drilling rig demand during 2008. During the first nine months of the year, jackup rig demand remained strong and continued to meet or exceed supply in all major geographic regions. Record high oil and natural gas prices resulted in increased exploration and development spending by oil and gas companies. Day rates during the first nine months of 2008 were near record levels for most rig classes, utilization remained high and drilling contracts generally contained favorable terms and conditions for drilling companies.
However, as the year came to a close, deterioration of the global economy, tightening credit markets and significant declines in oil and natural gas prices led to an abrupt reduction in demand for jackup rigs. Day rates softened as contractors attempted to lock-in drilling programs and maintain their existing contract backlog amid growing concerns over financing, declining oil and natural gas prices and pressure from operators to reduce day rates. The global financial crisis coupled with substantial volatility in oil and natural gas prices has created uncertainty regarding drilling programs and jackup rig demand for 2009 and beyond.
Despite the global financial crisis and the decline in oil and natural gas prices, demand for ultra-deepwater semisubmersible rigs remained high throughout 2008 on a worldwide basis. Intense competition among oil and gas companies to contract ultra-deepwater semisubmersible rigs resulted in record high day rates. Given that deepwater projects are typically more expensive and longer in duration than shallow-water jackup projects, deepwater operators tend to take a longer-term view of the global economy and oil and natural gas prices. We do not expect day rates for ultra-deepwater semisubmersible rigs to be as adversely impacted by declining rig demand as other rig classes and expect oil and gas companies to sustain their investment in deepwater projects resulting in continued high utilization levels during 2009.
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 future industry conditions, demand trends or future operating results. Periods of low rig demand often result in excess rig supply, which generally results in reductions in utilization levels and day rates; periods of high rig demand often result in a shortage of rigs, which generally results in increased utilization levels and day rates.
Drilling Rig Supply
During the past several years, the supply of available jackup and semisubmersible rigs has been unable to meet the increasing demand of oil and gas companies on a global basis. As a result of this global supply and demand imbalance, various industry participants ordered the construction of over 180 new jackup and semisubmersible rigs, over 60 of which were delivered during the last three years. Approximately 60 additional jackup and semisubmersible rigs are scheduled for delivery in 2009.
The new rig deliveries scheduled for 2009 include over 30 jackup rigs, the majority of which are not contracted for work upon delivery from the shipyard. These new drilling rigs will increase supply and likely reduce utilization and day rates as rigs are absorbed into the active fleet, especially in light of the recent decline in oil and natural gas prices and jackup rig demand. However, the current supply of jackup rigs is limited and 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. Utilization and day rates in specific markets could fluctuate significantly while utilization and day rates in other markets may be relatively unaffected. Additionally, several rig construction cancellations have been recently announced and the tightening credit market has created substantial uncertainty as to whether construction of other rigs will be completed.
Newbuild deliveries scheduled for 2009 include over 20 semisubmersible rigs, the majority of which are contracted for work upon delivery from the shipyard. Demand continues to exceed the supply of semisubmersible rigs, and it is expected that newbuild semisubmersible rigs will be absorbed into the market, perhaps without significant effect on utilization and day rates.
The limited availability of insurance for certain perils in some geographic regions and rig loss or damage due to hurricanes, blowouts, craterings, punchthroughs and other operational events may impact the supply of jackup or semisubmersible rigs in a particular market and cause fluctuations in rig demand, utilization and day rates.
Newbuild rigs scheduled for delivery in 2009 and beyond will require skilled personnel to operate. Notwithstanding the global economic downturn, we may be required to maintain or increase existing levels of compensation to retain our skilled workforce. Although competition for skilled labor has not materially affected us to date, competition for such personnel could increase our future operating expenses or impact our ability to fully staff and operate our rigs.
BUSINESS ENVIRONMENT
Deepwater
Demand for ultra-deepwater semisubmersible rigs on a worldwide basis continues to outpace supply resulting in high utilization levels and day rates. It is anticipated that oil and gas companies will sustain their investment in deepwater projects, resulting in near full utilization for the worldwide ultra-deepwater semisubmersible rig fleet for the foreseeable future. Although we do not anticipate day rates dropping significantly, the ability to sustain current day rates will depend in large part on the length and magnitude of the current global economic crisis and on oil and natural gas prices.
In addition to the ENSCO 8500, which is projected to commence a four-year contract in April 2009, we have six ENSCO 8500 Series® rigs under construction with scheduled delivery dates during the second quarter of 2009, the first and fourth quarters of 2010, the second half of 2011 and the first and second half of 2012. Three of the six ENSCO 8500 Series® rigs under construction have secured long-term drilling contracts in the Gulf of Mexico. Our ENSCO 7500 ultra-deepwater semisubmersible rig is currently mobilizing from the Gulf of Mexico to Australia and is expected to commence operations under a new contract in April 2009.
Asia Pacific
Jackup rig drilling contracts in the Asia Pacific region historically have been for substantially longer durations than those in other geographic regions. Since day rates for such contracts generally are fixed, or fixed subject to adjustment for variations in the contractor's costs, our Asia Pacific operations generally are not subject to the same level of day rate volatility as other regions where shorter term contracts are more prevalent. During 2006, demand for jackup rigs exceeded the supply of available rigs resulting in high jackup rig utilization levels and increasing day rates. During 2007, the prevailing demand, coupled with limited rig availability, enabled drilling contractors to continue experiencing high utilization and day rates.
During 2008, day rates stabilized and utilization levels remained high as increased rig demand was largely offset by new rig deliveries. The tightening credit market, coupled with the precipitous decline in oil and natural gas prices during the latter half of 2008, will negatively impact rig demand during 2009. Some of the new rig deliveries that were scheduled to occur during 2009 may be delayed or cancelled, and it is unclear the extent to which new rig deliveries will impact rig supply in the region. However, we anticipate that rig supply will exceed demand during 2009 which, coupled with reduced demand, is expected to result in a reduction in utilization and day rates.
Europe/Africa
Our Europe/Africa offshore drilling operations are mainly conducted in northern Europe where moderate duration jackup rig contracts are prevalent. During 2006, oil and gas companies increased their spending as a result of higher oil and natural gas prices. In addition, a strong backlog of firm commitments and contract extension options in northern Europe resulted in little or no jackup rig availability. This supply and demand imbalance resulted in near full utilization and a substantial increase in day rates. During 2007, oil and gas companies continued to increase their spending in this region, and the additional demand coupled with limited supply increased day rates further.
During 2008, shortfalls in rig availability continued, causing a slight increase in day rates over the prior year and sustained high utilization levels. However, the decline in oil and natural gas prices during the latter half of 2008 resulted in several cancelled tenders and unexercised contract extension options. In addition to declining rig demand, a limited number of newbuild jackup rigs are expected to be added to the region in the near term. We anticipate that these factors will lead to a reduction in utilization and day rates during 2009.
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 realized in the Europe/Africa and Asia Pacific regions during recent years were attributable to contractual cost adjustment provisions.
North and South America
Our North and South America offshore drilling operations are mainly conducted in the Gulf of Mexico where jackup rig contracts are normally entered into for relatively short durations and day rates are adjusted to current market rates upon contract renewal. Therefore, day rates in this region are more volatile than in regions where longer duration contracts are more prevalent.
Day rates increased during the first half of 2006 as drilling contractors relocated rigs out of the Gulf of Mexico to take advantage of longer duration international contracts. However, day rates began to moderate in the second half of the year due to a decrease in demand, as oil and gas companies focused their exploration and development efforts elsewhere. During 2007, demand continued to decline and day rates softened as a result of competition for work among drilling contractors. Oil and gas companies continued to shift their focus to more economically attractive prospects in the deeper waters of the Gulf of Mexico and elsewhere. As a result, jackup rig demand declined further, resulting in an adverse effect on utilization and day rates.
Demand for jackup rigs in the Gulf of Mexico stabilized during 2008, and jackup rig supply continued to decline as rigs were relocated to more economically attractive regions. As a result, utilization levels and day rates began to improve during the first half of the year. In September 2008, Hurricane Gustav and Hurricane Ike forced more than two weeks of work stoppages and damaged or destroyed several rigs and platforms in the Gulf of Mexico, including the total loss of ENSCO 74, thereby reducing the supply of available jackup rigs. However, we anticipate that the deterioration of the global economy and decline in oil and natural gas prices will negatively impact jackup rig demand. Despite the reduced supply of available jackup rigs, we expect a reduction in utilization and day rates during 2009.
Our North and South America offshore drilling operations are also conducted in Mexico and Venezuela. During 2007 and 2008, demand for rigs increased as the national oil company in Mexico increased its drilling requirements in an attempt to offset continued depletion of its major oil and natural gas fields. As a result, drilling contractors obtained pricing at international day rates. Demand for jackup rigs in Mexico remains high despite the recent deterioration in the global economy and decline in oil and natural gas prices. Future day rates will depend on the magnitude of the national oil company in Mexico's short-term drilling requirements and the availability of drilling rigs from other markets.
The jackup market in Venezuela is limited and drilling in the region is mostly contracted through PDVSA, the national oil company of Venezuela. PDVSA subsidiaries lack funding and generally have not been paying their contractors and service providers. It is uncertain how long, and to what extent, the current environment in Venezuela will impact the offshore drilling industry in the region. Additional information on risks associated with our Venezuelan operations is presented in "Item 1A. Risk Factors."
RESULTS OF OPERATIONS
The following table summarizes our consolidated operating results for each of the years in the three-year period ended December 31, 2008 (in millions):
During 2008, revenues increased by $361.8 million, or 17%, and operating income increased by $228.9 million, or 19%, as compared to 2007. The increases were primarily due to improved average day rates earned by our international jackup and ultra-deepwater semisubmersible rigs and improved utilization of our Gulf of Mexico jackup rigs. The increase in operating income was partially offset by increased personnel costs and repair and maintenance expense across the majority of our fleet.
During 2007, revenues increased by $318.8 million, or 18%, and operating income increased by $188.4 million, or 19%, as compared to 2006. The increases were primarily due to improved average day rates earned by our international jackup rigs, partially offset by a reduction in average day rates earned by, and utilization of, our Gulf of Mexico jackup rigs.
Oil and natural gas prices have declined substantially in recent months due primarily to a decrease in demand for oil and natural gas resulting from the deteriorating global economy. Some of our current and prospective customers are deferring and/or curtailing drilling programs, which will result in a reduction in demand for drilling rigs and a decline in utilization and day rates. While we have significant contract backlog during 2009, if current economic conditions persist, we believe it is unlikely the revenue and operating income levels achieved during 2008 and 2007 will be sustained.
Rig Locations, Utilization and Average Day Rates
As discussed below, we manage our business through four operating segments. However, our rigs are mobile and our jackup rigs frequently move between our geographic region segments. The following table summarizes our offshore drilling rigs by segment as of December 31, 2008, 2007 and 2006:
(1)
During the third quarter of 2008, we accepted delivery of ENSCO 8500 and mobilized the rig to the Gulf of Mexico. The rig is currently undergoing deepwater sea trials and is expected to commence operations in the Gulf of Mexico under a four-year contract in April 2009.
(2)
Upon completion of its construction during 2007, we accepted delivery of ENSCO 108, an ultra-high specification jackup rig that commenced drilling operations in Indonesia.
(3)
During 2007, we mobilized ENSCO 105 from the Gulf of Mexico to Tunisia.
(4)
During 2007, we entered into an agreement to construct ENSCO 8503 with delivery expected during the fourth quarter of 2010. During 2008, we entered into agreements to construct ENSCO 8504, ENSCO 8505 and ENSCO 8506 with deliveries expected during the second half of 2011 and the first and second half of 2012, respectively.
(5)
The total number of rigs for each period excludes rigs reclassified as discontinued operations.
The following table summarizes our rig utilization and average day rates from continuing operations by operating segment for each of the years in the three-year period ended December 31, 2008:
(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 revenues, adjusted to exclude certain types of non-recurring reimbursable revenues and lump sum revenues, by the aggregate number of contract days, adjusted to exclude contract days associated with certain mobilizations, demobilizations, shipyard contracts and standby contracts.
(3)
Rig utilization and average day rates for the Asia Pacific operating segment include our jackup rigs only. The ENSCO I barge rig has been excluded.
Detailed explanations of our operating results, including discussions of revenues, contract drilling expense and depreciation expense by operating segment, are provided below.
Operating Income
We are in the process of developing a fleet of ultra-deepwater semisubmersible rigs. In connection therewith, we contracted Keppel FELS Limited ("KFELS"), a major international shipyard based in Singapore, to construct seven ultra-deepwater semisubmersible rigs (the "ENSCO 8500 Series®"). ENSCO 8500 was delivered by KFELS in September 2008 and arrived in the Gulf of Mexico in mid-December 2008. The rig is currently undergoing deepwater sea trials and is projected to commence operations under a four-year contract in April 2009. In connection with the arrival of our first ENSCO 8500 Series® rig, we reorganized the management of our operations, establishing a separate business unit to manage our fleet of ultra-deepwater semisubmersible rigs.
As part of this reorganization, we evaluated our remaining assets and operations, consisting of 43 jackup rigs and one barge rig organized into three business units based on major geographic region, and now consider these three business units as operating segments. Accordingly, our business now consists of four operating segments: (1) Deepwater, (2) Asia Pacific, (3) Europe/Africa and (4) North and South America. Each of our four operating segments provides one service, contract drilling.
The following tables summarize our operating income for each of the years in the three-year period ended December 31, 2008. General and administrative expense and depreciation expense incurred by our corporate office are not allocated to our operating segments for purposes of measuring segment operating income and were included in "Reconciling Items."
Year Ended December 31, 2008
(in millions)
Year Ended December 31, 2007
(in millions)
Year Ended December 31, 2006
(in millions)
Deepwater
During 2008, Deepwater revenues increased by $11.6 million, or 16%, as compared to 2007. The increase in revenues was primarily due to a 68% increase in the ENSCO 7500 average day rate, partially offset by the deferral of ENSCO 7500 revenue during the fourth quarter. In October 2008, we amended our existing drilling contract and agreed to relocate the rig to Australia where we will commence drilling operations in April 2009 at a day rate of approximately $550,000. Revenues earned during the mobilization period are being deferred and will be recognized ratably upon commencement of drilling operations through September 2010, the end of the firm commitment period of the contract. Contract drilling expense increased by $2.4 million, or 8%, as compared to 2007, primarily due to increased personnel costs and repair and maintenance expense, partially offset by the deferral of costs during the mobilization of ENSCO 7500 to Australia. The increase in personnel costs was due to the staffing of an office in Houston, Texas during 2008 to support our newly established Deepwater business unit and increased ENSCO 7500 staffing levels to facilitate training in preparation for delivery of our ENSCO 8500 Series® rigs.
During 2007, Deepwater revenues increased by $11.9 million, or 20%, as compared to 2006. The increase in revenues was primarily due to a 4% increase in the ENSCO 7500 average day rate, which resulted from a cost escalation rate adjustment provision in the contract, and an increase in utilization to 97% from 87% during the prior year, as ENSCO 7500 was idle for approximately one month in the prior year while undergoing minor enhancement and contract preparatory work. Contract drilling expense increased by $2.5 million, or 10%, as compared to 2006, primarily due to increased personnel costs and reimbursable expense, partially offset by a reduction in repair and maintenance expense.
Asia Pacific
During 2008, Asia Pacific revenues increased by $140.2 million, or 15%, as compared to 2007. The increase in revenues was primarily due to a 16% increase in jackup rig average day rates and the increased size of our Asia Pacific fleet, partially offset by a decline in jackup rig utilization to 95% from 99% during the prior year. The increase in average day rates resulted from stronger demand due to higher levels of spending by oil and gas companies coupled with limited rig availability in the region. The addition of ENSCO 108 to the fleet in the first quarter of 2007 resulted in an additional $28.1 million of revenues and $4.8 million of contract drilling expense during 2008 as compared to the prior year. The decline in utilization was the result of scheduled maintenance projects on ENSCO 53, ENSCO 54, ENSCO 56, ENSCO 57 and ENSCO 96. Contract drilling expense increased by $50.0 million, or 18%, as compared to 2007, primarily due to increased personnel costs and increased repair and maintenance expense associated with the aforementioned maintenance projects, and to a lesser extent, the addition of ENSCO 108 to the fleet. Depreciation expense increased by $4.1 million, or 5%, as compared to 2007. The increase was primarily attributable to depreciation associated with ENSCO 108, depreciation associated with ENSCO 96 and ENSCO 104 capital enhancement projects completed during the fourth quarter of 2007 and depreciation on minor upgrades and improvements to our Asia Pacific fleet completed during 2007 and 2008.
During 2007, Asia Pacific revenues increased by $327.2 million, or 56%, as compared to 2006. The increase in revenues was primarily due to a 47% increase in jackup rig average day rates and the increased size of our Asia Pacific fleet. The increase in average day rates resulted from stronger demand due to higher levels of spending by oil and gas companies coupled with limited rig availability in the region. The addition of ENSCO 84 and ENSCO 108 to the fleet resulted in an additional $101.5 million of revenues and $21.2 million of contract drilling expense during 2007 as compared to the prior year. ENSCO 84 mobilized to the region in late September 2006, and ENSCO 108 was delivered by a shipyard during the first quarter of 2007. Contract drilling expense increased by $45.9 million, or 20%, as compared to 2006, primarily due to the increased size of our Asia Pacific fleet. Excluding the impact of the two additional rigs, contract drilling expense increased by $24.7 million, or 11%, as compared to the prior year, primarily due to increased personnel costs and repair and maintenance expense. The increase was partially offset by a $2.7 million estimated loss recognized in the prior year related to damage sustained by ENSCO 107 while pre-loading on a drilling location offshore Vietnam. Depreciation expense increased by $5.8 million, or 8%, as compared to 2006. The increase was primarily attributable to depreciation associated with ENSCO 108 and ENSCO 84 and depreciation on minor upgrades and improvements to our Asia Pacific fleet completed during 2006 and 2007.
Europe/Africa
During 2008, Europe/Africa revenues increased by $133.3 million, or 20%, as compared to 2007. The increase in revenues was primarily attributable to an 11% increase in average day rates, an increase in utilization to 96% from 93% during the prior year and the relocation of ENSCO 105 to the region during 2007. The increase in average day rates was attributable to limited rig availability in the region coupled with improved demand resulting from increased spending by oil and gas companies. The increase in utilization was primarily due to the mobilization of ENSCO 100 from Nigeria to the North Sea during the prior year. The relocation of ENSCO 105 to the Europe/Africa region during the second quarter of 2007 contributed an additional $30.5 million of revenues and $9.0 million of contract drilling expense as compared to the prior year. Contract drilling expense increased by $38.3 million, or 18%, as compared to 2007, primarily due to increased mobilization and repair and maintenance expense, the addition of ENSCO 105 to the fleet and increased personnel costs, partially offset by a reduction in reimbursable expense. Depreciation expense increased by $2.6 million, or 6%, as compared to 2007. The increase was primarily attributable to depreciation associated with the ENSCO 85 capital enhancement project completed during the first quarter of 2008, depreciation associated with ENSCO 105 and depreciation on minor upgrades and improvements to our Europe/Africa fleet completed during 2007 and 2008.
During 2007, Europe/Africa revenues increased by $173.7 million, or 35%, as compared to 2006. The increase in revenues was primarily attributable to the addition of ENSCO 105 to our Europe/Africa jackup fleet during the first quarter of 2007 and a 33% increase in average day rates, partially offset by a decrease in utilization to 93% from 100% during the prior year. The addition of ENSCO 105 contributed an additional $55.7 million of revenues and $21.0 million of contract drilling expense during 2007 as compared to the prior year. The improvement in average day rates was attributable to improved demand resulting from increased spending by oil and gas companies. The decline in utilization was primarily due to the mobilization of ENSCO 100 from Nigeria to the North Sea, which commenced in August 2007. Contract drilling expense increased by $50.4 million, or 32%, as compared to 2006, primarily due to the addition of ENSCO 105 to the Europe/Africa fleet, $5.5 million of costs associated with the departure of ENSCO 100 from Nigeria and a $4.2 million increase in reimbursable costs associated with ENSCO 100. Excluding the impact of the aforementioned items, contract drilling expense increased by $19.7 million, or 12%, as compared to the prior year due to increased personnel costs and repair and maintenance expense, partially offset by a reduction in fleet-wide mobilization expense. Depreciation expense increased by $4.0 million, or 11%, as compared to 2006. The increase was primarily attributable to depreciation associated with ENSCO 105 and depreciation on minor upgrades and improvements to our Europe/Africa fleet completed during 2006 and 2007.
North and South America
During 2008, North and South America revenues increased by $76.7 million, or 18%, as compared to 2007. The increase in revenues was primarily due to an increase in utilization to 97% from 79% during the prior year, partially offset by a 3% decline in average day rates. The increase in utilization was attributable to decreased rig supply, as drilling contractors mobilized rigs to international locations, and an increase in customer demand. Although we realized day rate increases during the majority of 2008, day rates earned during the current year were generally lower than day rates earned during the early portions of 2007. The increase in revenues was also partially offset by ENSCO 105, which generated $7.1 million of revenues and $2.1 million of contract drilling expense during the first quarter of 2007 prior to relocation from the region. Contract drilling expense increased by $38.6 million, or 24%, as compared to 2007, primarily due to increased personnel costs, a $13.8 million bad debt provision recorded during the fourth quarter of 2008 related to our operations in Venezuela and the impact of increased utilization, partially offset by decreased mobilization expense and the relocation of ENSCO 105 during the prior year. Depreciation expense increased by $5.0 million, or 11%, as compared to 2007. The increase was primarily attributable to depreciation associated with the ENSCO 83 and ENSCO 93 capital enhancement projects completed during the second quarter of 2007 and first quarter of 2008, respectively, and depreciation on minor upgrades and improvements to our North and South America fleet completed during 2007 and 2008, partially offset by the reduced size of our North and South America fleet.
During 2007, North and South America revenues decreased by $194.0 million, or 31%, as compared to 2006. The decrease in revenues was partially due to the reduced size of our North and South America fleet as ENSCO 105 relocated from the Gulf of Mexico during the first quarter of 2007 and ENSCO 84 relocated from the region during the third quarter of 2006. Excluding the impact of ENSCO 105 and ENSCO 84, revenues decreased by $126.0 million, or 23%, as compared to the prior year. A 14% decrease in average day rates and a decline in utilization to 79% from 90% during 2006 also contributed to the reduction in revenues from the prior year. The decrease in average day rates and utilization was due to a decline in demand by oil and gas companies as they reduced spending on shallow water drilling in the region. Contract drilling expense increased by $7.6 million, or 5%, as compared to 2006. Excluding the impact of the two rigs relocated from the region, contract drilling expense increased by $23.2 million, or 17%, primarily due to increased personnel costs, insurance costs and repair and maintenance expense. Depreciation expense declined by $1.5 million, or 3%, as compared to 2006. The decrease was primarily attributable to the reduced size of our North and South America fleet, offset by depreciation on capital enhancement and upgrade projects completed during 2006 and 2007.
Other
During 2008, general and administrative expense decreased by $5.7 million, or 10%, as compared to 2007. The decline was primarily attributable to a $11.3 million expense incurred during the prior year in connection with a retirement agreement with our former Chairman and Chief Executive Officer ("CEO"), partially offset by increased professional fees and personnel costs and costs associated with our 2008 branding initiative.
During 2007, general and administrative expense increased by $14.9 million, or 33%, as compared to 2006. The increase was primarily attributable to the aforementioned retirement agreement with our former CEO and an increase in professional fees, personnel costs and share-based compensation expense as compared to the prior year.
Other Income (Expense)
The following table summarizes other income (expense) for each of the years in the three-year period ended December 31, 2008 (in millions):
During 2008, interest income declined as compared to the prior year due to lower average interest rates, partially offset by an increase in cash balances invested. During 2007, interest income increased as compared to the prior year due to an increase in cash balances invested.
Our interest expense declined during 2008 and 2007 as compared to their respective prior years due to a decline in outstanding debt over these periods. Capitalized interest declined during 2008 due to the significant reduction in interest expense incurred as compared to the prior year. All interest expense incurred during 2008 was capitalized. Capitalized interest during 2007 increased as compared to 2006 due to an increase in the amount invested in our new rig construction projects.
Foreign currency translation adjustments and foreign currency transaction gains and losses, including certain gains and losses on derivative instruments, were included in other, net, on our consolidated statements of income. Other, net, included $10.4 million of net foreign currency exchange losses, $9.2 million of net foreign currency exchange gains and $2.8 million of net foreign currency exchange losses during 2008, 2007 and 2006, respectively.
During 2008, other, net, also included an unrealized loss of $8.1 million associated with the valuation of our auction rate securities. Our fair value measurements are discussed in Note 8 to our consolidated financial statements. During 2007, other, net, also included a $3.1 million net gain resulting from the settlement of litigation we initiated in relation to a non-operational dispute with a third party service provider.
Provision for Income Taxes
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 frequently move 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.
Income tax expense was $242.4 million, $248.3 million and $243.0 million during the years ended December 31, 2008, 2007 and 2006, respectively. The effective income tax rates during the years ended December 31, 2008, 2007 and 2006 were 17.3%, 20.4% and 24.7%, respectively. The decrease in effective income tax rates was due primarily to an increase in earnings generated by non-U.S. subsidiaries whose earnings are being permanently reinvested and taxed at lower rates.
Discontinued Operations
In September 2008, ENSCO 74 was lost as a result of Hurricane Ike and is now presumed to have sunk in the Gulf of Mexico. Portions of the rig's legs remain underwater adjacent to the customer's platform, and the hull has not been located despite search efforts by us and third parties. Management concluded the rig was a total loss under the terms of our insurance policies based on the condition of the legs and the inability to locate the rig's hull.
We recognized a $36.2 million pre-tax loss in connection with the disposal of ENSCO 74, which was included in loss (gain) on disposal of discontinued operations, net, in the consolidated statement of income for the year ended December 31, 2008. The operating results of ENSCO 74 were reclassified as discontinued operations in the consolidated statements of income for each of the years in the three-year period ended December 31, 2008. See Note 11 to our consolidated financial statements for discussion of our insurance coverage and a summary of the pre-tax loss on disposal of discontinued operations.
In January 2006, we effectively sold the ENSCO 29 platform rig by transferring beneficial ownership to our insurance underwriters after concluding the rig was a total loss under our insurance policies subsequent to sustaining substantial damage during Hurricane Katrina. Additionally, we sold the ENSCO 25 platform rig in December 2006. The operating results of ENSCO 29 and ENSCO 25 were reclassified as discontinued operations in the consolidated statement of income for the year ended December 31, 2006.
The following table summarizes (loss) income from discontinued operations for each of the years in the three-year period ended December 31, 2008 (in millions):
Fair Value Measurements
On January 1, 2008, we adopted SFAS No. 157, "Fair Value Measurements" ("SFAS 157"), as it relates to financial assets and liabilities. SFAS 157 refines the definition of fair value, provides a framework for measuring fair value and expands disclosures about fair value measurements. Our auction rate securities were measured at fair value as of December 31, 2008 using significant Level 3 inputs as defined by SFAS 157. See Note 8 to our consolidated financial statements for additional information on the fair value hierarchy under SFAS 157. See Note 2 to our consolidated financial statements for additional information on our auction rate securities, including a description of the securities and underlying collateral, a discussion of the uncertainties relating to their liquidity and our accounting treatment under SFAS No. 115, "Accounting for Certain Debt and Equity Securities (as amended)". As a result of continued auction failures, quoted prices for our auction rate securities did not exist as of December 31, 2008 and, accordingly, we concluded that Level 1 inputs were not available.
We determined that use of a valuation model was the best available technique for measuring the fair value of our auction rate securities. We used an income approach valuation model to estimate the price that would be received in exchange for our auction rate securities in an orderly transaction between market participants ("exit price") as of December 31, 2008. The exit price was derived as the weighted-average present value of expected cash flow over various periods of illiquidity, using a risk-adjusted discount rate that was based on the credit risk and liquidity risk of our auction rate securities.
While our valuation model was based on both Level 2 (credit quality and interest rates) and Level 3 inputs, we determined that the Level 3 inputs were most significant to the overall fair value measurement, particularly the estimates of risk-adjusted discount rates and ranges of expected periods of illiquidity. The valuation model also reflected our intention to hold our auction rate securities until they can be redeemed by issuers, repurchased by brokerage firms or sold in a market that facilitates orderly transactions and our belief that we have the ability to maintain our investment in these securities indefinitely. We reviewed these inputs to our valuation model, evaluated the results and performed sensitivity analysis on key assumptions. Based on our review, we concluded that the fair value measurement of our auction rate securities as of December 31, 2008 was appropriate.
Based on the results of our fair value measurement, we recognized an unrealized loss of $8.1 million for the year ended December 31, 2008, included in other, net, in our consolidated statement of income. The carrying value of our auction rate securities, classified as long-term investments on our consolidated balance sheet, was $64.2 million as of December 31, 2008.
The $8.1 million unrealized loss recognized for the year ended December 31, 2008 resulted primarily from liquidity risk (rather than credit risk) associated with our auction rate securities. We anticipate realizing the par value of our auction rate securities because we intend to hold them until they are redeemed, repurchased or sold in a market that facilitates orderly transactions.
Assets measured at fair value using significant Level 3 inputs constituted 1.2% of our total assets as of December 31, 2008. No assets or liabilities were valued using Level 3 inputs as of December 31, 2007.
LIQUIDITY AND CAPITAL RESOURCES Although our business has historically been very cyclical, we have relied on our cash flow from continuing operations to meet liquidity needs and fund the majority of our cash requirements. We have maintained a strong financial position through the disciplined and conservative use of debt. A substantial amount of our cash flow is invested in the expansion and enhancement of our fleet of drilling rigs in general, and construction of our ENSCO 8500 Series® rigs in particular.
We believe the deteriorating global economic environment and substantial decline in oil and natural gas prices will lead to a decline in jackup rig utilization and day rates in 2009, the extent of which is currently unknown. It is likely that this will result in a decline in our cash flow from operations during the second half of 2009 and during 2010. However, based on our $789.6 million of cash and cash equivalents as of December 31, 2008 and our current contractual backlog, we believe our remaining obligations associated with the construction of the ENSCO 8500 Series® rigs will be funded from existing cash and cash equivalents and future operating cash flow.
During the three-year period ended December 31, 2008, our primary source of cash was an aggregate $3,277.0 million generated from continuing operations. Our primary uses of cash during the same period included an aggregate $1,819.4 million for the construction, enhancement and other improvement of our drilling rigs and $948.3 million for the repurchase of our common stock.
Detailed explanations of our liquidity and capital resources for each of the years in the three-year period ended December 31, 2008 are set forth below.
Cash Flow and Capital Expenditures
Our cash flow from continuing operations and capital expenditures on continuing operations for each of the years in the three-year period ended December 31, 2008 were as follows (in millions):
During 2008, cash flow from continuing operations decreased by $74.0 million, or 6%, as compared to the prior year. The decrease resulted primarily from a $72.3 million investment in trading securities, a $179.7 million increase in cash payments related to contract drilling expenses and a $148.9 million increase in cash payments related to income taxes, partially offset by a $312.2 million increase in cash receipts from drilling services.
During 2007, cash flow from continuing operations increased by $291.3 million, or 32%, as compared to the prior year. The increase resulted primarily from a $379.0 million increase in cash receipts from drilling services, partially offset by a $100.2 million increase in cash payments related to contract drilling expenses.
We continue to expand the size and quality of our drilling rig fleet. During the three-year period ended December 31, 2008, we invested $1,399.1 million in the construction of new drilling rigs and an additional $191.4 million upgrading the capability and extending the service lives of our existing fleet. In addition to the ENSCO 8500, which was delivered in September 2008 and is expected to commence operations in the Gulf of Mexico in April 2009, we added two new ultra-high specification jackup rigs to our fleet during the past three years, ENSCO 107 in January 2006 and ENSCO 108 in March 2007.
During 2008, we entered into agreements with KFELS in Singapore to construct ENSCO 8504, ENSCO 8505 and ENSCO 8506 for estimated total construction costs of $512.0 million, $537.0 million and $560.0 million, respectively. We now have six ENSCO 8500 Series® ultra-deepwater semisubmersible rigs under construction with scheduled delivery dates during the second quarter of 2009, the first and fourth quarters of 2010, the second half of 2011 and the first and second half of 2012. Three of the six ENSCO 8500 Series® rigs under construction have secured long-term drilling contracts in the Gulf of Mexico.
Based on our current projections, we expect capital expenditures during 2009 to include approximately $515.0 million for construction of our ENSCO 8500 Series® rigs, approximately $125.0 million for rig enhancement projects and $100.0 million for minor upgrades and improvements. Depending on market conditions and opportunities, we may make additional capital expenditures to upgrade rigs for customer requirements and construct or acquire additional rigs.
Financing and Capital Resources
Our long-term debt, total capital and long-term debt to total capital ratios as of December 31, 2008, 2007 and 2006 are summarized below (in millions, except percentages):
*
Total capital includes long-term debt plus stockholders' equity.
We have a $350.0 million unsecured revolving credit facility (the "Credit Facility") with a syndicate of banks that matures in June 2010. We had no amounts outstanding under the Credit Facility as of December 31, 2008, 2007 and 2006. In addition, we filed a Form S-3 Registration Statement with the Securities and Exchange Commission ("SEC") on January 13, 2009, which provides us with the ability to issue debt and/or equity securities. The registration statement was immediately effective and expires in January 2012. We currently maintain an investment grade credit rating of Baa1 from Moody's.
As of December 31, 2008, we had an aggregate $142.7 million outstanding under two separate bond issues guaranteed by the United States Maritime Administration ("MARAD") that require semiannual principal and interest payments. We also make semiannual interest payments on $150.0 million of 7.20% debentures due in 2027.
In March 2006, our Board of Directors authorized the repurchase of up to $500.0 million of our outstanding common stock. In August 2007, following completion of the authorized repurchase, our Board of Directors approved the 2007 authorization to repurchase an additional $500.0 million of our outstanding common stock. In September 2008, our Board of Directors approved the 2008 authorization to repurchase an additional $500.0 million of our outstanding common stock.
From inception of our stock repurchase programs in March 2006 through December 31, 2007, we repurchased an aggregate 12.8 million shares at a cost of $681.6 million (an average cost of $53.05 per share). During the first nine months of 2008, we repurchased 3.7 million shares of our common stock at a cost of $256.0 million (an average cost of $69.92 per share) under the 2007 authorization. No shares were repurchased under our stock repurchases programs during the fourth quarter. As of December 31, 2008, $562.4 million remained available for repurchases of our outstanding common stock under the 2007 and 2008 authorizations.
Contractual Obligations
We have various contractual commitments related to our new rig construction agreements, debt and operating leases. We expect to fund these commitments from our existing cash and cash equivalents and future operating cash flow. The actual timing of our new rig construction payments may vary based on the completion of various construction milestones, which are beyond our control. The table below summarizes our significant contractual obligations as of December 31, 2008 and the periods in which such obligations are due (in millions):
Our contractual obligations table does not include unrecognized tax benefits. We adopted the recognition and disclosure provisions of FASB Interpretation No. 48, "Accounting for Uncertainty in Income Taxes - an interpretation of FASB Statement No. 109" ("FIN 48"), on January 1, 2007 and had $26.8 million of unrecognized tax benefits as of December 31, 2008. Substantially all of our unrecognized tax benefits related to uncertain tax positions that were not under review by taxing authorities. Therefore, we are unable to specify the future periods in which we may be obligated to settle such amounts.
Additionally, our contractual obligations table does not include derivative instruments. As of December 31, 2008, we had foreign currency forward contracts outstanding to exchange an aggregate $474.1 million U.S. dollars for various foreign currencies, including $298.5 million for Singapore dollars. As of December 31, 2008, our consolidated balance sheet included net foreign currency derivative liabilities of $20.3 million. All of our outstanding foreign currency forward contracts mature during the next three years.
Liquidity
Our liquidity position as of December 31, 2008, 2007 and 2006 is summarized below (in millions, except ratios):
We believe the deteriorating global economic environment and substantial decline in oil and natural gas prices is likely to result in a decline in our cash flow from operations during the second half of 2009 and during 2010. Based on our $789.6 million of cash and cash equivalents as of December 31, 2008 and our current contractual backlog, we believe the remaining $1,605.2 million of contractual obligations associated with the construction of the ENSCO 8500 Series® rigs will be funded from existing cash and cash equivalents and future operating cash flow.
We expect to fund our short-term liquidity needs, including approximately $785.0 million of contractual obligations and anticipated capital expenditures, as well as any dividends, stock repurchases or working capital requirements, from our cash and cash equivalents and operating cash flow. We expect to fund our long-term liquidity needs, including contractual obligations, anticipated capital expenditures and dividends, from our cash and cash equivalents, investments, operating cash flow and, if necessary, funds borrowed under our $350.0 million unsecured revolving credit facility or other future financing arrangements.
In addition to $789.6 million of cash and cash equivalents, we also held $72.3 million (par value) of investments in auction rate securities as of December 31, 2008, which were classified as long-term investments on our consolidated balance sheet. Although we acquired these securities with the intention of selling them in the near term, we plan to hold them until they can be redeemed by issuers, repurchased by brokerage firms or sold in a market that facilitates orderly transactions. We do not expect to experience liquidity problems if we hold these securities indefinitely. See Note 2 to our consolidated financial statements for additional information on our auction rate securities.
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 drilling contracts in U.S. dollars, which significantly reduces the portion of our cash flows and assets denominated in foreign currencies. We also employ various strategies, including the use of 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. As of December 31, 2008, we had foreign currency forward contracts outstanding to exchange an aggregate $474.1 million U.S. dollars for various foreign currencies, including $298.5 million for Singapore dollars. We currently have six ultra-deepwater semisubmersible rigs under construction with a major international shipyard in Singapore. As of December 31, 2008, approximately $341.9 million of the aggregate remaining contractual obligations associated with these construction projects was denominated in Singapore dollars of which $291.0 million was hedged through foreign currency forward contracts.
We utilize derivative instruments and undertake foreign currency hedging activities in accordance with our established policies for the management of market risk. We do not enter into derivative instruments for trading or other speculative purposes. We believe that our use of derivative instruments and related hedging activities does not expose us to material interest rate risk, foreign currency exchange rate risk, commodity price risk, credit risk or any other material market or price risk.
If we were to incur a hypothetical 10% adverse change in foreign currency exchange rates, net unrealized losses associated with our foreign currency denominated assets and liabilities and related foreign currency forward contracts as of December 31, 2008 would approximate $39.2 million, including $30.7 million related to our Singapore dollar exposures. All of our foreign currency forward contracts mature during the next three years.
We have generated substantial cash balances, portions of which are invested in securities that meet our requirements for quality and return. Investment of our cash balances exposes us to market risk. We held $72.3 million (par value) of auction rate securities with a carrying value of $64.2 million as of December 31, 2008. During 2008, auctions for most of our auction rate securities failed. An auction failure, which is not a default in the underlying debt instrument, occurs when there are more sellers than buyers at a scheduled interest rate auction date and parties desiring to sell their auction rate securities are unable to do so. We intend to hold these securities until they can be redeemed by issuers, repurchased by brokerage firms or sold in a market that facilitates orderly transactions and, due to significant uncertainties related to the auction rate securities market, we will be exposed to the risk of changes in the fair value of these securities in future periods.
To measure the fair value of our auction rate securities as of December 31, 2008, we used an income approach valuation model to estimate the price that would be received in exchange for our auction rate securities in an orderly transaction between market participants ("exit price"). The exit price was derived as the weighted-average present value of expected cash flow over various periods of illiquidity, using a risk-adjusted discount rate that was based on the credit risk and liquidity risk of our auction rate securities. If we were to incur a hypothetical 10% adverse change in the periods of illiquidity and a 10% adverse change in the risk-adjusted discount rate, the additional net unrealized loss on our auction rates securities as of December 31, 2008 would approximate $2.4 million. See Note 2 to our consolidated financial statements for additional information on our auction rate securities and Note 8 to our consolidated financial statements for more information on our fair value measurements.
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 our consolidated financial statements. These policies, along with our underlying judgments and assumptions made in their application, have a significant impact on our consolidated financial statements. We identify our critical accounting policies as those that are the most pervasive and important to the portrayal of our financial position and operating results, and that require the most difficult, subjective and/or complex judgments by management regarding estimates in matters that are inherently uncertain. Our critical accounting policies are those related to property and equipment, impairment of long-lived assets and goodwill and income taxes.
Property and Equipment
As of December 31, 2008, the carrying value of our property and equipment totaled $3,871.3 million, which represents 66.4% of total assets. This carrying value reflects the application of our property and equipment accounting policies, which incorporate management's estimates, judgments and assumptions relative to the capitalized costs, useful lives and salvage values of our rigs.
We develop and apply property and equipment accounting policies that are designed to appropriately and consistently capitalize those costs incurred to enhance, improve and extend the useful lives of our assets and expense those costs incurred to repair or maintain the existing condition or useful lives of our assets. The development and application of such policies requires judgments and assumptions by management relative to the nature of, and benefits from, expenditures on our assets. We establish property and equipment accounting policies that are designed to depreciate our assets over their estimated useful lives. The judgments and assumptions used by management in determining the 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, judgments and assumptions in the establishment of our property and equipment accounting policies, especially those involving the useful lives of our rigs, would likely result in materially different carrying values of assets and operating results.
The useful lives of our drilling rigs are difficult to estimate due to a variety of factors, including technological advances that impact the methods or cost of oil and natural 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 represented 89% of the gross cost and net carrying amount of our depreciable property and equipment as of December 31, 2008. Our jackup rigs are depreciated over useful lives ranging from 15 to 30 years. Our ultra-deepwater semisubmersible rigs are 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, 2008 for various assumed changes in the useful lives of our drilling rigs effective January 1, 2008:
Impairment of Long-Lived Assets and Goodwill
We evaluate the carrying value of our property and equipment, primarily our drilling rigs, when events or changes in circumstances indicate that the carrying value of such rigs may not be recoverable. Generally, extended periods of idle time and/or inability to contract rigs at economical rates are an indication that a rig may be impaired. However, the offshore drilling industry has historically been highly cyclical and it is not unusual for rigs to be unutilized or underutilized for significant periods of time and subsequently resume full or near full utilization when business cycles change. Likewise, during periods of supply and demand imbalance, rigs are frequently contracted at or near cash break-even rates for extended periods of time until demand comes back into balance with supply. Impairment situations may arise with respect to specific individual rigs, groups of rigs, such as a specific type of drilling rig, or rigs in a certain geographic location. Our rigs are mobile and may generally be moved from markets with excess supply, if economically feasible. Our jackup rigs and ultra-deepwater semisubmersible rigs are suited for, and accessible to, broad and numerous markets throughout the world.
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. Our four operating segments represent our reporting units in accordance with SFAS No. 142, "Goodwill and Other Intangible Assets (as amended)". In most instances, our calculation of the fair value of our reporting units is based on estimates of future discounted cash flows to be generated by our drilling rigs, which reflect management's judgments and assumptions regarding future industry conditions and operations, including expected utilization, day rates, expense levels and capital requirements for each of our drilling rigs. If the aggregate fair value of our reporting units exceeds our market capitalization, we evaluate the reasonableness of the implied control premium through a comparison to implied control premiums from recent market transactions within our industry. To the extent that the implied control premium based on the aggregate fair value of our reporting units is not reasonable, we adjust the discount rate used in our discounted cash flow model accordingly.
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 test performed as of December 31, 2008, 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, which reflect management's judgments and assumptions regarding future industry conditions and operations, as well as management's estimates of expected utilization, day rates, expense levels and capital requirements. The estimates, judgments and assumptions used by management in the application of our asset impairment policies reflect both historical experience and an assessment of current operational, industry, market, economic and political environments. The use of different estimates, judgments, assumptions and expectations regarding future industry conditions and operations would likely result in materially different 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. As of December 31, 2008, we had a $320.6 million net deferred income tax liability, a $34.3 million liability for income taxes currently payable and a $26.8 million liability for unrecognized tax benefits.
The carrying values of deferred income tax assets and liabilities reflect the application of our income tax accounting policies in accordance with SFAS No. 109, "Accounting for Income Taxes" ("SFAS 109"), and are based on management's estimates, judgments and assumptions regarding future operating results and levels of taxable income, as well as 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.
In December 2007, substantially all of the undistributed earnings of our non-U.S. subsidiaries were distributed to the U.S. parent company. A U.S. deferred tax liability has not been recognized for the remaining undistributed earnings of our non-U.S. subsidiaries because it is the intention of these subsidiaries to reinvest such earnings indefinitely. Should our non-U.S. subsidiaries 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. See Note 10 to our consolidated financial statements for additional information on the undistributed earnings of our non-U.S. subsidiaries.
The carrying values of liabilities for unrecognized tax benefits reflect our application of the provisions of FASB Interpretation No. 48, "Accounting for Uncertainty in Income Tax - an interpretation of SFAS No. 109" and are based on management's interpretation of applicable tax laws and incorporate management's estimates, judgments and assumptions regarding the use of tax planning strategies in various taxing jurisdictions. The use of different estimates, judgments and assumptions in connection with accounting for income taxes, especially those involving the deployment of tax planning strategies, may result in materially different carrying values of income tax assets and liabilities and operating results. See Note 10 to our consolidated financial statements for additional information on our unrecognized tax benefits.
We operate in many international jurisdictions where tax laws relating to the offshore drilling industry are not well developed. In jurisdictions where available statutory law and regulations are incomplete or underdeveloped, we obtain professional guidance and consider existing industry practices before utilizing tax planning strategies and meeting our tax obligations. Tax returns are routinely subject to audit in most jurisdictions and tax liabilities are frequently finalized through a negotiation process. While we have not historically experienced significant adjustments to previously recognized tax assets and liabilities as a result of finalizing tax returns, there can be no assurance that significant adjustments will not arise in the future. In addition, there are several factors that could cause the future level of uncertainty relating to our tax assets and liabilities to increase, including the following:
• During recent years, the portion of our overall operations conducted in international tax jurisdictions has increased.
•
In order to utilize tax planning strategies and conduct international operations efficiently, our subsidiaries frequently enter into transactions with affiliates that are generally subject to complex tax regulations and are frequently reviewed by tax authorities.
•
We may conduct future operations in certain tax jurisdictions where tax laws are not well developed, and it may be difficult to secure adequate professional guidance.
•
Tax laws, regulations, agreements and treaties change frequently, requiring us to modify existing tax strategies to conform to such changes.
NEW ACCOUNTING PRONOUNCEMENTS In June 2008, the FASB issued Staff Position EITF 03-6-1 "Determining Whether Instruments Granted in Share-Based Payment Transactions are Participating Securities" ("FSP EITF 03-6-1"). FSP EITF 03-6-1 addresses whether instruments granted in share-based payment transactions are participating securities prior to vesting and, therefore, need to be included in the earnings allocation in computing earnings per share ("EPS") under the two-class method described in paragraphs 60 and 61 of SFAS No. 128, "Earnings Per Share". FSP EITF 03-6-1 is effective for fiscal years and interim periods beginning after December 15, 2008 and requires retrospective adjustment for all comparable prior periods presented. We do not expect adoption of FSP EITF 03-6-1 to have a material effect on our EPS computations or disclosures.
In March 2008, the FASB issued SFAS No. 161, "Disclosures about Derivative and Hedging Activities" ("SFAS 161"). This standard amends SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities" ("SFAS 133"), to change the disclosure requirements for derivative instruments and hedging activities. This standard requires enhanced disclosures about (a) how and why an entity uses derivative instruments, (b) how derivative instruments and related hedged items are accounted for under SFAS 133 and its related interpretations and (c) how derivative instruments and related hedged items affect an entity's financial position, operating results and cash flows. SFAS 161 is effective for fiscal years and interim periods beginning after November 15, 2008. Adoption of SFAS 161 will result in increased financial statement disclosures, but will not affect our financial position, operating results or cash flows.
In February 2008, the FASB issued Staff Position 157-2 "Partial Deferral of the Effective Date of Statement 157" ("FSP 157-2"). FSP 157-2 delays the effective date of SFAS 157 for nonfinancial assets and nonfinancial liabilities, except for items that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually), to fiscal years beginning after November 15, 2008. The adoption of SFAS 157 for financial assets and financial liabilities, effective January 1, 2008, did not have a material effect on our financial position, operating results or cash flows. See Note 8 to our consolidated financial statements. We do not expect adoption of SFAS 157 for nonfinancial assets and liabilities on January 1, 2009 to have a material effect on our financial position, operating results or cash flows.
In December 2007, the FASB issued SFAS No. 141 (revised 2007), "Business Combinations" ("SFAS 141(R)"). This standard establishes principles and requirements for how an acquirer in a business combination recognizes and measures the identifiable assets acquired, the liabilities assumed and any noncontrolling interest in the acquiree in its financial statements. SFAS 141(R) also establishes principles and requirements for how an acquirer recognizes and measures goodwill acquired in a business combination and establishes disclosure requirements to facilitate an evaluation of the nature and financial effects of a business combination. SFAS 141(R) is effective for business combinations that occur during the first annual reporting period beginning on or after December 15, 2008. The effect of adoption of this standard will be limited to any acquisitions that close subsequent to December 31, 2008.
In December 2007, the FASB issued SFAS No. 160, "Noncontrolling Interests in Consolidated Financial Statements" ("SFAS 160"). This standard amends Accounting Research Bulletin No. 51, "Consolidated Financial Statements", to establish accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. SFAS 160 clarifies that a noncontrolling interest should be reported as equity in the consolidated financial statements and requires net income attributable to both the parent and the noncontrolling interest to be disclosed separately on the face of the consolidated statement of income. SFAS 160 is effective for fiscal years and interim periods beginning after December 15, 2008. We do not expect adoption of this standard to 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, 2008 to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.
KPMG LLP, the independent registered public accounting firm who audited our consolidated financial statements, have issued an audit report on our internal control over financial reporting. KPMG LLP's audit report on our internal control over financial reporting is included herein.
February 26, 2009
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, 2008 and 2007, and the related consolidated statements of income and cash flows for each of the years in the three-year period ended December 31, 2008. 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, 2008 and 2007, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2008, in conformity with U.S. generally accepted accounting principles.
As discussed in note 8 to the consolidated financial statements, effective January 1, 2008, the Company adopted the provisions of Statement of Financial Accounting Standards No. 157, Fair Value Measurements, as it relates to financial assets and liabilities. As discussed in note 10 to the consolidated financial statements, effective January 1, 2007, the Company adopted the provisions of Financial Accounting Standards Board Interpretation No. 48, Accounting for Uncertainty in Income Taxes.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), ENSCO International Incorporated's internal control over financial reporting as of December 31, 2008, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 26, 2009, expressed an unqualified opinion on the effectiveness of the Company's internal control over financial reporting.
/s/ KPMG LLP
Dallas, Texas
February 26, 2009
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM The Board of Directors and Stockholders
ENSCO International Incorporated:
We have audited ENSCO International Incorporated and subsidiaries' (Ensco) internal control over financial reporting as of December 31, 2008, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Ensco's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management's Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company's internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, Ensco maintained, in all material respects, effective internal control over financial reporting as of December 31, 2008, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of ENSCO International Incorporated and subsidiaries as of December 31, 2008 and 2007, and the related consolidated statements of income and cash flows for each of the years in the three-year period ended December 31, 2008, and our report dated February 26, 2009 expressed an unqualified opinion on those consolidated financial statements.
/s/ KPMG LLP
Dallas, Texas
February 26, 2009
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 providers of offshore contract drilling services to the international oil and gas industry. We have one of the largest and most capable offshore drilling rig fleets in the world comprised of 46 drilling rigs, including 43 jackup rigs, two ultra-deepwater semisubmersible rigs and one barge rig. Additionally, we have six ultra-deepwater semisubmersible rigs under construction. We drill and complete offshore oil and natural gas wells for major international, government-owned and independent oil and gas companies on a "day rate" contract basis, under which we provide our drilling rigs and rig crews and receive a fixed amount per day for drilling the well. Our customers bear substantially all of the ancillary costs of constructing the well and supporting drilling operations, as well as the economic risk relative to the success of the well.
Our contract drilling operations are integral to the exploration, development and production of oil and natural 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 natural gas, regional and global economic conditions and changes therein, political, social and legislative environments in the U.S. and other major oil-producing countries, production and inventory levels and related activities of the Organization of Petroleum Exporting Countries ("OPEC") and other oil and natural gas producers, technological advancements that impact the methods or cost of oil and natural gas exploration and development, disruption to exploration and development activities due to hurricanes and other severe weather conditions and the impact that these and other events have on the current and expected future pricing of oil and natural gas. See "Note 13 - Segment Information" for additional information on our operations by segment and 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 "Ensco," "Company," "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 ("GAAP") requires management to make certain estimates, judgments and assumptions that affect the reported amounts of assets and liabilities, the related revenues and expenses and disclosures of gain and loss contingencies as of the date of the financial statements. Actual results could differ from those estimates.
Foreign Currency Translation
The U.S. dollar is the functional currency of all our non-U.S. subsidiaries. The financial statements of these subsidiaries are remeasured in U.S. dollars based on a combination of both current and historical exchange rates. Currency translation adjustments and transaction gains and losses, including certain gains and losses on our derivative instruments, were included in other, net, on our consolidated statements of income. We incurred net foreign currency exchange losses of $10.4 million for the year ended December 31, 2008, net foreign currency exchange gains of $9.2 million for the year ended December 31, 2007 and net foreign currency exchange losses of $2.8 million for the year ended December 31, 2006.
Cash Equivalents and Short-Term Investments
Highly liquid investments with maturities of three months or less at the date of purchase are considered cash equivalents. Highly liquid investments with maturities of greater than three months but less than one year at the date of purchase are classified as short-term investments.
Property and Equipment
All costs incurred in connection with the acquisition, construction, enhancement and improvement of assets are capitalized, including allocations of interest incurred during periods that our drilling rigs are under construction or undergoing major enhancements and improvements. Repair and maintenance costs are charged to contract drilling expense in the period in which they occur. Upon sale or retirement of assets, the related cost and accumulated depreciation are removed from the balance sheet and the resulting gain or loss is included in contract drilling expense.
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. Buildings and improvements are depreciated over estimated useful lives ranging from 2 to 30 years. Other equipment, including computer and communications hardware and software costs, is depreciated over estimated useful lives ranging from 2 to 6 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 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.
The precipitous decline in oil and natural gas prices and the general deterioration of the global economy during the latter half of 2008 is resulting in a decrease in demand for drilling rigs and a corresponding reduction in utilization and day rates for our jackup rigs. The change in demand, utilization and day rates was deemed a triggering event for asset impairment purposes. We performed an undiscounted cash flow analysis as of December 31, 2008 for each of our drilling rigs to determine whether the net book value of each rig was recoverable. The determination of expected undiscounted cash flow amounts requires significant estimates, judgments and assumptions, including utilization, day rates, expense levels and capital expenditures, as well as cash flows generated upon disposition, for each of our drilling rigs. Due to the inherent uncertainties associated with these estimates, we performed sensitivity analysis on key assumptions as part of our recoverability test.
Based on our recoverability test performed as of December 31, 2008, we concluded that the net book value of our drilling rigs was recoverable and no impairment charges were recorded. Additionally, no asset impairment charges were recorded during the three-year period ended December 31, 2008. However, if the global economic environment continues to deteriorate and the offshore drilling industry were to incur a significant prolonged downturn, our expectations of future cash flows may decline and ultimately result in impairment of our drilling rigs.
Goodwill
In connection with the arrival of our first ENSCO 8500 Series® rig, we reorganized the management of our operations, establishing a separate business unit to manage our fleet of ultra-deepwater semisubmersible rigs. As part of this reorganization, we evaluated our remaining assets and operations, consisting of 43 jackup rigs and one barge rig organized into three business units based on major geographic region, and now consider these three business units as operating segments. Accordingly, our business now consists of four operating segments: (1) Deepwater, (2) Asia Pacific, (3) Europe/Africa and (4) North and South America. Each of our four operating segments provides one service, contract drilling.
Our four operating segments represent our reporting units in accordance with SFAS No. 142, "Goodwill and Other Intangible Assets (as amended)." As a result of our management reorganization from one operating segment and reporting unit to four operating segments and reporting units, we reassigned goodwill to our four reporting units based on a relative fair value allocation approach as follows (in millions):
Goodwill is not allocated to operating segments in the measure of segment assets regularly reported to and used by management. No goodwill was acquired or disposed of during the three-year period ended December 31, 2008.
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. Additionally, we reconciled the aggregate fair value of our reporting units to our market capitalization as part of our December 31, 2008 goodwill impairment test. Our aggregate fair value exceeded our market capitalization resulting in an implied control premium. We analyzed the implied control premium against the control premium identified in recent market transactions within our industry, including the merger of two of our largest competitors during 2007, and determined that the implied control premium based on the aggregate fair value of our reporting units was reasonable.
The determination of the fair value of our reporting units requires significant estimates, judgments and assumptions. These estimates, judgments and assumptions include the risk-adjusted discount rate, as well as utilization, day rates, expense levels, capital requirements and terminal values for each of our drilling rigs. Due to the inherent uncertainties associated with these estimates, we performed sensitivity analysis on key assumptions as part of our goodwill impairment test. We determined there was no impairment of goodwill as of December 31, 2008. However, if the global economic environment continues to deteriorate and the offshore drilling industry were to incur a significant prolonged downturn, our expectations of future cash flows may decline and ultimately result in impairment of our goodwill.
Operating Revenues and Expenses
Substantially all of our drilling 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 drill a well. Contract revenues and expenses are recognized on a per day basis, as the work is performed. Day rate revenues are typically earned, and contract drilling expense is 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 revenues. The costs incurred in connection with the mobilization and demobilization of equipment and personnel are included in contract drilling expense.
Mobilization fees received and costs incurred are deferred and recognized on a straight-line basis over the period that the related drilling services are performed. 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 were included in other current assets and other assets, net, and totaled $47.5 million and $29.2 million as of December 31, 2008 and 2007, respectively. Deferred mobilization revenue was included in accrued liabilities and other, and other liabilities and totaled $88.0 million and $53.3 million as of December 31, 2008 and 2007, respectively.
In connection with some contracts, we receive up-front lump-sum fees or similar compensation for capital improvements to our drilling rigs. Such compensation is deferred and recognized as revenue over the period that the related drilling services are performed. The cost of such capital improvements is capitalized and depreciated over the useful life of the asset. Deferred revenue associated with capital improvements was included in accrued liabilities and other, and other liabilities and totaled $2.2 million and $1.5 million as of December 31, 2008 and 2007, 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 were included in other current assets and other assets, net, and totaled $6.5 million and $10.4 million as of December 31, 2008 and 2007, 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 foreign currency risk and interest rate risk. 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 occasionally employ an interest rate risk management strategy that utilizes derivatives to minimize or eliminate unanticipated fluctuations in earnings and cash flows arising from changes in, and volatility of, interest rates. We 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 in accordance with SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities (as amended)". 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, in our 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 accumulated other comprehensive income. Amounts recorded in accumulated other comprehensive income associated with cash flow hedges are subsequently reclassified into contract drilling, depreciation or interest expense as earnings are affected by the underlying hedged forecasted transactions.
Gains and losses on a cash flow hedge, or a portion of a cash flow hedge, that no longer qualify as effective due to an unanticipated change in the forecasted transaction are recognized currently in earnings and included in other, net, in the consolidated statement of income based on the change in the fair 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 accumulated other comprehensive income are reclassified currently into earnings and included in other, net, in 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, in the consolidated statement of income.
We occasionally enter into derivatives that hedge the fair value of recognized assets or liabilities, but do not designate such derivatives as hedges or the derivatives otherwise do not qualify for hedge accounting. In these situations, there generally is 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, in the consolidated statement of income.
Derivatives with asset fair values are reported in other current assets or other assets, net, depending on maturity date. Derivatives with liability fair values are reported in accrued liabilities and other, or other liabilities, depending on maturity date. As of December 31, 2008 and 2007, our consolidated balance sheets included net foreign currency derivative liabilities of $20.3 million and net foreign currency derivative assets of $4.6 million, respectively.
Income Taxes
We conduct operations and earn income in numerous international countries and are subject to the laws of taxing jurisdictions within those countries, as well as U.S. Federal and state tax laws. Current income taxes are recognized for the amount of taxes payable or refundable based on the laws and income tax rates in the taxing jurisdictions in which operations are conducted and income is earned.
Deferred tax assets and liabilities are recognized for the anticipated future tax effects of temporary differences between the financial statement basis and the tax basis of our assets and liabilities using the enacted tax rates in effect at year-end. A valuation allowance for deferred tax assets is recorded when it is more-likely-than-not that the benefit from the deferred tax asset will not be realized.
In many of the international jurisdictions in which we operate, tax laws relating to the offshore drilling industry are not well developed and change frequently. Furthermore, we may enter into transactions with affiliates or employ other tax planning strategies that generally are subject to complex tax regulations. As a result of the foregoing, the tax liabilities and assets we recognize in our financial statements may differ from the tax positions taken, or expected to be taken, in our tax returns. We adopted the provisions of FASB Interpretation No. 48, "Accounting for Uncertainty in Income Tax - an interpretation of SFAS No. 109" ("FIN 48"), on January 1, 2007. In accordance with FIN 48, our tax positions are evaluated for recognition using a more-likely-than-not threshold, and those tax positions requiring recognition are measured as the largest amount of tax benefit that is greater than 50 percent likely of being realized upon effective settlement with a taxing authority that has full knowledge of all relevant information. Interest and penalties relating to income taxes are included in current income tax expense in our consolidated statement of income. See "Note 10 - Income Taxes" for additional information on our unrecognized tax benefits.
Our drilling rigs frequently move 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 involve a transfer of drilling rig ownership among our subsidiaries. Income taxes attributable to gains or losses 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 these determinations on a periodic basis and, in the event our expectations relative to future tax consequences change, the applicable deferred taxes are recognized.
In December 2007, substantially all of the undistributed earnings of our non-U.S. subsidiaries were distributed to the U.S. parent company. It is our policy and intention to indefinitely reinvest all remaining and future undistributed earnings of our non-U.S. subsidiaries in such subsidiaries. Accordingly, no U.S. deferred taxes are provided on the undistributed earnings of our non-U.S. subsidiaries. See "Note 10 - Income Taxes" for additional information on the undistributed earnings of our non-U.S. subsidiaries.
Share-Based Employee Compensation
We sponsor several share-based compensation plans that provide equity compensation to our employees, officers and directors. Effective January 1, 2006, we adopted the fair value recognition provisions of SFAS No. 123, (revised 2004) "Share-Based Payment" ("SFAS 123(R)"), using the modified-retrospective transition method. Under that transition method, compensation cost recognized in prior periods was restated to include share option compensation cost previously reported in our pro forma footnote disclosures. Share-based compensation cost is measured at fair value on the date of grant and recognized on a straight-line basis over the requisite service period (usually the vesting period). Beginning in 2006, the amount of compensation cost recognized in the consolidated statement of income is based on the awards ultimately expected to vest, and therefore, reduced for estimated forfeitures. See "Note 9 - Employee Benefit Plans" for additional information on the adoption of SFAS 123(R) and its impact on our consolidated financial statements.
Fair Value Measurements
On January 1, 2008, we adopted SFAS No. 157, "Fair Value Measurements" ("SFAS 157"), as it relates to financial assets and liabilities. SFAS 157 refines the definition of fair value, provides a framework for measuring fair value and expands disclosures about fair value measurements. The standard establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy assigns the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities ("Level 1") and the lowest priority to unobservable inputs ("Level 3"). Level 2 measurements are inputs that are observable for assets or liabilities, either directly or indirectly, other than quoted prices included within Level 1.
Our derivative instruments were measured at fair value on a recurring basis using Level 2 inputs as of December 31, 2008 and 2007. See "Note 5 - Derivative Financial Instruments" for additional information on our derivative instruments, including a description of our foreign currency hedging activities and related methods used to manage foreign currency exchange risk. The fair value measurement of our derivatives was based on market prices that are generally observable for similar assets or liabilities at commonly quoted intervals.
Our auction rate securities were measured at fair value as of December 31, 2008 using significant Level 3 inputs as defined by SFAS 157. See "Note 2 - Long-Term Investments" for additional information on our auction rate securities, including a description of the securities and underlying collateral, a discussion of the uncertainties relating to their liquidity and our accounting treatment under SFAS No. 115, "Accounting for Certain Debt and Equity Securities (as amended)".
We determined that use of a valuation model was the best available technique for measuring the fair value of our auction rate securities. We used an income approach valuation model to estimate the price that would be received in exchange for our auction rate securities in an orderly transaction between market participants ("exit price") as of December 31, 2008. The exit price was derived as the weighted-average present value of expected cash flow over various periods of illiquidity, using a risk-adjusted discount rate that was based on the credit risk and liquidity risk of our auction rate securities. See "Note 8 - Fair Value Measurements" for additional information on the fair value measurement of our auction rate securities.
Earnings Per Share
For each of the years in the three-year period ended December 31, 2008, there were no adjustments to net income for purposes of calculating basic and diluted earnings per share ("EPS"). The following table 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, 2008 (in millions):
Antidilutive shares of 1.4 million, 503,000 and 684,000 for the years ended December 31, 2008, 2007 and 2006, respectively, were excluded from the computation of diluted earnings per share.
In June 2008, the FASB issued Staff Position EITF 03-6-1, "Determining Whether Instruments Granted in Share-Based Payment Transactions are Participating Securities" ("FSP EITF 03-6-1"). FSP EITF 03-6-1 addresses determinations as to whether instruments granted in share-based payment transactions are participating securities prior to vesting and, therefore, need to be included in the earnings allocation in computing EPS under the two-class method described in paragraphs 60 and 61 of SFAS No. 128, "Earnings Per Share". FSP EITF 03-6-1 is effective for fiscal years and interim periods beginning after December 15, 2008 and will require retrospective adjustment for all comparable prior periods presented. We do not expect adoption of FSP EITF 03-6-1 to have a material effect on our EPS computations or disclosures.
Adoption of SAB 108
In September 2006, the Securities and Exchange Commission ("SEC") issued SAB 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.
During years prior to 2006, we used the rollover approach to quantify and evaluate the effects of financial statement misstatements. In applying the guidance of SAB 108 during 2006, we concluded the two misstatements described below, when evaluated using the iron curtain approach, were material to our December 31, 2006 consolidated financial statements.
In 1997, we adopted a policy pursuant to which the depreciation of a drilling 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 GAAP. We evaluated the financial statement misstatements resulting from the application of this policy and concluded their impact on each of our prior period consolidated financial statements was immaterial. In accordance with SAB 108, we elected to report the cumulative effect of the financial statement misstatements, a $17.6 million increase in accumulated depreciation, $2.6 million decrease in deferred tax liabilities and $15.0 million decrease in retained earnings, effective January 1, 2006.
We maintain relatively constant levels of consumable supplies and spare parts on each of our drilling rigs for use in our operations ("inventory"). Prior to the fourth quarter of 2006, we utilized an accounting policy under which inventory was charged to contract drilling expense at the time it was shipped to a drilling rig, although some of it was temporarily stored and consumed later. We had previously evaluated and concluded the impact of the financial statement misstatements resulting from the difference between the amount of inventory charged to contract drilling expense and the estimated amount of inventory consumed was immaterial to our prior period consolidated financial statements. We also concluded that this inventory accounting policy did not have a material impact on our December 31, 2006 financial statements. During the fourth quarter of 2006, we adopted an inventory accounting policy to record the inventory on our drilling rigs at the lower of cost or market in accordance with GAAP. As part of the adoption of this accounting policy and in accordance with SAB 108, we elected to report the cumulative effect of the financial statement misstatements, a $32.3 million increase in other current assets, $6.7 million increase in deferred tax liabilities and $25.6 million increase in retained earnings, effective January 1, 2006.
2. LONG-TERM INVESTMENTS
As of December 31, 2008, we held $72.3 million (par value) of long-term debt instruments with variable interest rates that periodically reset through an auction process ("auction rate securities"). Our auction rate securities were originally acquired in January 2008 and have final maturity dates ranging from 2025 to 2047. We did not own auction rate securities as of December 31, 2007.
Auctions for our auction rate securities failed beginning in February 2008. An auction failure, which is not a default in the underlying debt instrument, occurs when there are more sellers than buyers at a scheduled interest rate auction date and parties desiring to sell their auction rate securities are unable to do so. When an auction fails, the interest rate is adjusted according to the provisions of the associated security agreement, which may result in an interest rate that is higher than the interest rate the issuer pays in connection with successful auctions. Auctions for our auction rate securities continued to fail during the remainder of 2008, with the exception of the successful auction of $4.7 million of our securities in June 2008.
Our investments in auction rate securities as of December 31, 2008 were diversified across sixteen separate issues and each issue maintains scheduled interest rate auctions in either 28-day or 35-day intervals. Substantially all of our auction rate securities are currently rated Aaa by Moody's, AAA by Standard & Poor's and/or AAA by Fitch. An aggregate $68.6 million (par value), or 95%, of our auction rate securities were issued by state agencies and are supported by student loans for which repayment is substantially guaranteed by the U.S. government under the Federal Family Education Loan Program ("FFELP").
Auction failures and the resulting lack of liquidity have affected the entire auction rate securities market, and we are currently unable to determine whether these conditions will be of an extended duration. While it is estimated that approximately half of the $330.0 billion auction rate securities market has been refinanced, student loan supported auction rate securities remain mostly constrained and illiquid. Although $5.9 million of our student loan supported auction rate securities were redeemed at par value during the year ended December 31, 2008, we are currently unable to determine whether other issuers of our auction rate securities will attempt and/or be able to refinance.
Some broker/dealers previously indicated that they planned to develop secondary markets for auction rate securities, but no such market has materialized. Consequently, we are currently unable to determine if alternative markets that provide for orderly purchases and sales of auction rate securities will develop. Several major brokerage firms announced regulatory settlements in which they will initially offer to repurchase auction rate securities from retail investors, charities and small businesses and use best efforts to provide liquidity to institutional investors within the next several years. However, we are currently unable to determine whether these brokerage firms will be able to comply with the terms of their regulatory settlements. Moreover, the deteriorating global economic environment may impede auction rate security repurchases. Although we acquired our auction rate securities with the intention of selling them in the near term, due to the aforementioned uncertainties, our auction rate securities were classified as long-term investments on our consolidated balance sheet as of December 31, 2008.
Upon acquisition in January 2008, we designated our auction rate securities as trading securities in accordance with SFAS 115 as it was our intent to sell them in the near term. Due to illiquidity in the auction rate securities market, we intend to hold our auction rate securities until they can be redeemed by issuers, repurchased by brokerage firms or sold in a market that facilitates orderly transactions. Although we will hold our auction rate securities longer than originally anticipated, we continue to designate them as trading securities.
Our auction rate securities were measured at fair value as of December 31, 2008, and an unrealized loss of $8.1 million for the year ended December 31, 2008 was included in other, net, in our consolidated statement of income. The carrying value of our auction rate securities was $64.2 million as of December 31, 2008. Cash flows from purchases and sales of our auction rate securities were classified as operating activities in our consolidated statement of cash flows for the year ended December 31, 2008. See "Note 8 - Fair Value Measurements" for additional information on the fair value measurement of our auction rate securities.
3. PROPERTY AND EQUIPMENT
Property and equipment as of December 31, 2008 and 2007 consisted of the following (in millions):
Work in progress as of December 31, 2008 primarily consisted of $1,445.2 million related to the construction of our seven ultra-deepwater semisubmersible rigs and costs associated with various modification and enhancement projects. Although ENSCO 8500 was delivered during the third quarter of 2008, related amounts will remain classified as work in progress until the rig is placed into service in April 2009. Work in progress as of December 31, 2007 primarily consisted of $760.4 million related to the construction of four ultra-deepwater semisubmersible rigs, ENSCO 8500, ENSCO 8501, ENSCO 8502 and ENSCO 8503 and costs associated with various modification and enhancement projects.
4. LONG-TERM DEBT
Long-term debt as of December 31, 2008 and 2007 consisted 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 are guaranteed by the United States Maritime Administration ("MARAD") and will be repaid in 34 equal semiannual principal installments of $2.3 million ending in October 2020. Interest on the bonds is payable semiannually, in April and October, at a fixed rate of 4.65%. The bonds are collateralized by ENSCO 105, and we have guaranteed the performance of our obligations under the bonds to MARAD.
In January 2001, we issued $190.0 million of 15-year bonds to provide long-term financing for ENSCO 7500. The bonds are guaranteed by MARAD and will be repaid in 30 equal semiannual principal installments of $6.3 million ending in December 2015. Interest on the bonds is payable semiannually, in June and December, at a fixed rate of 6.36%. The bonds are collateralized by ENSCO 7500, and we have guaranteed the performance of our obligations under the bonds to MARAD.
Debentures Due 2027
In November 1997, we issued $150.0 million of unsecured 7.20% Debentures due November 15, 2027 (the “Debentures”) in a public offering. Interest on the Debentures is payable semiannually in May and November and may be redeemed at any time at our option, in whole or in part, at a price equal to 100% of the principal amount thereof plus accrued and unpaid interest, if any, and a make-whole premium. The indenture under which the Debentures were issued contains limitations on the incurrence of indebtedness secured by certain liens and limitations on engaging in certain sale/leaseback transactions and certain merger, consolidation or reorganization transactions. The Debentures are not subject to any sinking fund requirements.
Revolving Credit Facility
We have a $350.0 million unsecured revolving credit facility (the "Credit Facility") with a syndicate of lenders for general corporate purposes. The Credit Facility has a five-year term, expiring in June 2010. Advances under the Credit Facility bear interest at LIBOR plus an applicable margin rate (currently .35% per annum), depending on our credit rating. We pay a facility fee (currently .10% per annum) on the total $350.0 million commitment, which is also based on our credit rating, and pay an additional utilization fee on outstanding advances if such advances equal or exceed 50% of the total $350.0 million commitment. We had no amounts outstanding under the Credit Facility as of December 31, 2008 and 2007.
Maturities
The aggregate maturities of our long-term debt, excluding unamortized discounts of $1.2 million as of December 31, 2008, were as follows (in millions):
5. DERIVATIVE FINANCIAL INSTRUMENTS
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 drilling contracts in U.S. dollars, which significantly reduces the portion of our cash flows and assets denominated in foreign currencies. We also employ various strategies, including the use of 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. As of December 31, 2008, we had foreign currency forward contracts outstanding to exchange an aggregate $474.1 million U.S. dollars for various foreign currencies, including $298.5 million for Singapore dollars. We currently have six ultra-deepwater semisubmersible rigs under construction with a major international shipyard in Singapore. As of December 31, 2008, approximately $341.9 million of the aggregate remaining contractual obligations associated with these construction projects was denominated in Singapore dollars of which $291.0 million was hedged through foreign currency forward contracts.
We utilize derivative instruments and undertake foreign currency hedging activities in accordance with our established policies for the management of market risk. We do not enter into derivative instruments for trading or other speculative purposes. We believe that our use of derivative instruments and related hedging activities does not expose us to any material interest rate risk, foreign currency exchange rate risk, commodity price risk, credit risk or any other material market or price risk. As of December 31, 2008 and 2007, our consolidated balance sheets included net foreign currency derivative liabilities of $20.3 million and net foreign currency derivative assets of $4.6 million, respectively.
If we were to incur a hypothetical 10% adverse change in foreign currency exchange rates, net unrealized losses associated with our foreign currency denominated assets and liabilities and related foreign currency forward contracts as of December 31, 2008 would approximate $39.2 million, including $30.7 million related to our Singapore dollar exposures. All of our outstanding foreign currency forward contracts mature during the next three years.
As of December 31, 2008, the estimated amount of net unrealized losses on derivative instruments, net of tax, that will be reclassified to earnings during the next twelve months was as follows (in millions):
6. COMPREHENSIVE INCOME
Accumulated other comprehensive loss as of December 31, 2008 and 2007 was comprised of net unrealized losses on derivative instruments, net of tax. The components of our comprehensive income, net of tax, for each of the years in the three-year period ended December 31, 2008, were as follows (in millions):
7. STOCKHOLDERS' EQUITY
In March 2006, our Board of Directors authorized the repurchase of up to $500.0 million of our outstanding common stock. In August 2007, following completion of the authorized repurchase, our Board of Directors authorized the repurchase of an additional $500.0 million of our outstanding common stock (the "2007 authorization"). In September 2008, our Board of Directors authorized the repurchase of an additional $500.0 million of our outstanding common stock (the "2008 authorization").
During the year ended December 31, 2008, we repurchased 3.7 million shares of our common stock at a cost of $256.0 million (an average cost of $69.92 per share) under the 2007 authorization. As of December 31, 2008 and 2007, outstanding shares of our common stock, net of treasury shares, totaled 141.8 million and 143.9 million, respectively.
Activity in our various stockholders' equity accounts for each of the years in the three-year period ended December 31, 2008 was as follows (in millions):
8. FAIR VALUE MEASUREMENTS On January 1, 2008, we adopted SFAS 157, as it relates to financial assets and liabilities. SFAS 157 refines the definition of fair value, provides a framework for measuring fair value and expands disclosures about fair value measurements. The standard establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy assigns the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities ("Level 1") and the lowest priority to unobservable inputs ("Level 3"). Level 2 measurements are inputs that are observable for assets or liabilities, either directly or indirectly, other than quoted prices included within Level 1.
In October 2008, the FASB issued Staff Position No. FAS 157-3, "Determining the Fair Value of a Financial Asset in a Market That Is Not Active" ("FSP FAS 157-3"), which amended SFAS 157 by clarifying the application of SFAS 157 when the market for a financial asset is inactive. FSP FAS 157-3 became effective upon issuance, including prior periods for which financial statements had not been issued. Adoption of FSP FAS 157-3 did not have a material effect on our fair value measurements as of December 31, 2008.
The following fair value hierarchy table categorizes information regarding our assets and liabilities measured at fair value on a recurring basis as of December 31, 2008 and 2007 (in millions):
Derivative Instruments
Our derivative instruments were measured at fair value on a recurring basis using Level 2 inputs as of December 31, 2008 and 2007. See "Note 5 - Derivative Financial Instruments" for additional information on our derivative instruments, including a description of our foreign currency hedging activities and related methods used to manage foreign currency exchange risk. The fair value measurement of our derivatives was based on market prices that are generally observable for similar assets or liabilities at commonly quoted intervals.
Auction Rate Securities
Our auction rate securities were measured at fair value on a recurring basis using significant Level 3 inputs as of December 31, 2008. See "Note 2 - Long-Term Investments" for additional information on our auction rate securities, including a description of the securities and underlying collateral, a discussion of the uncertainties relating to their liquidity and our accounting treatment under SFAS 115. The following table summarizes our fair value measurements using significant Level 3 inputs, and changes therein, for the year ended December 31, 2008 (in millions):
(*) Unrealized losses are included in other, net, in the consolidated statement of income.
Before utilizing Level 3 inputs in our fair value measurements, we considered whether observable inputs were available. As a result of continued auction failures, quoted prices for our auction rate securities did not exist as of December 31, 2008. Accordingly, we concluded that Level 1 inputs were not available. Brokerage statements received from the five broker/dealers that held our auction rate securities included their estimated market value as of December 31, 2008. Four broker/dealers valued our auction rate securities at par and the fifth valued our auction rate securities at 84% of par. Due to the lack of transparency into the methodologies used to determine the estimated market values, we concluded that estimated market values provided on our brokerage statements did not constitute valid inputs, and we did not utilize them in measuring the fair value of our auction rate securities as of December 31, 2008.
We determined that use of a valuation model was the best available technique for measuring the fair value of our auction rate securities. We used an income approach valuation model to estimate the price that would be received in exchange for our auction rate securities in an orderly transaction between market participants ("exit price") as of December 31, 2008. The exit price was derived as the weighted-average present value of expected cash flow over various periods of illiquidity, using a risk-adjusted discount rate that was based on the credit risk and liquidity risk of our auction rate securities.
While our valuation model was based on both Level 2 (credit quality and interest rates) and Level 3 inputs, we determined that our Level 3 inputs were most significant to the overall fair value measurement, particularly the estimates of risk-adjusted discount rates and ranges of expected periods of illiquidity. The valuation model also reflected our intention to hold our auction rate securities until they can be redeemed by issuers, repurchased by brokerage firms or sold in a market that facilitates orderly transactions and our belief that we have the ability to maintain our investment in these securities indefinitely.
9. EMPLOYEE BENEFIT PLANS
Adoption of SFAS 123(R)
We grant share options and non-vested share awards to our employees, officers and directors. Effective January 1, 2006, we adopted the fair value recognition provisions of SFAS 123(R) using the modified-retrospective transition method. Under that transition method, compensation cost recognized in prior periods was restated to include share option compensation cost previously reported in our pro forma footnote disclosures required by SFAS No. 123, "Accounting for Stock-Based Compensation (as amended)" ("SFAS 123").
Share-based compensation expense recognized in the consolidated statements of income was based on awards ultimately expected to vest and reduced for estimated forfeitures. SFAS 123(R) requires forfeitures to be estimated at the time of grant and revised, if necessary, in subsequent periods if actual forfeitures differ from those estimates. Estimated forfeitures were based on historical experience. Prior to the adoption of SFAS 123(R), we accounted for forfeitures as they occurred. On January 1, 2006, we estimated that 13.7% of share options and 8.2% of non-vested share awards were not expected to vest. Accordingly, we recognized a cumulative adjustment to reduce share-based compensation expense by $600,000, net of tax, for unvested share options and non-vested share awards that were recognized in the financial statements as a result of applying the modified-retrospective transition method. The estimate was included in cumulative effect of accounting change for adoption of SFAS 123(R), net, in the consolidated statement of income for the year ended December 31, 2006.
Subsequent to the adoption of SFAS 123(R), compensation cost for all equity awards, regardless of when they were granted, is recognized based on the number of awards expected to vest. All subsequent changes in estimated forfeitures, including changes in estimates relating to share options and non-vested share awards granted prior to the adoption of SFAS 123(R), is based on historical experience and will be recognized as a cumulative adjustment to compensation cost in the period in which they occur.
Share Options
In May 2005, our stockholders approved the 2005 Long-Term Incentive Plan (the "LTIP Plan"). The LTIP 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 LTIP Plan, 10.0 million shares of common stock are reserved for issuance as awards of share options, non-vested share awards or performance shares of which a maximum 7.5 million new shares are reserved for issuance as awards of share options to officers, non-employee directors and key employees who are in a position to contribute materially to our growth, development and long-term success. Share options granted to officers and employees generally become exercisable in 25% increments over a four-year period and to the extent not exercised, expire on the seventh anniversary of the date of grant. Share options granted to non-employee directors are immediately exercisable and to the extent not exercised, expire on the seventh anniversary of the date of grant. The exercise price of share options granted under the LTIP Plan equals the market value of the underlying stock on the date of grant. As of December 31, 2008, options to purchase 1.2 million shares of our common stock were outstanding under the LTIP Plan. Additionally, there were 5.5 million shares of common stock available for issuance of share option awards under the LTIP 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. As of December 31, 2008, options to purchase 300,000 shares of our common stock were outstanding under the 1998 Plan and the Directors' Plan.
The following table summarizes share option compensation expense recognized during each of the years in the three-year period ended December 31, 2008 (in millions):
The fair value of each option award is estimated on the date of grant using the Black-Scholes option valuation model. No share options were granted in 2008. The following weighted-average assumptions were utilized in the Black-Scholes model for the years ended December 31, 2007 and 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.
The following table summarizes share option activity for the year ended December 31, 2008 (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, 2008:
The following table summarizes information about share options outstanding as of December 31, 2008 (shares in thousands):
As of December 31, 2008, there was $9.0 million of total unrecognized compensation cost related to share options granted, which is expected to be recognized over a weighted-average period of 1.8 years.
Non-Vested Share Awards
Under the LTIP Plan, non-vested share awards may be issued to our officers, non-employee directors and key employees who are in a position to contribute materially to our growth, development and long-term success. Prior to the adoption of the LTIP 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 LTIP Plan provides for the issuance of non-vested share awards up to a maximum of 2.5 million new shares. Under the LTIP Plan, grants of non-vested share awards generally vest at a rate of 20% per year, as determined by a committee of the Board of Directors. All non-vested share awards have voting and dividend rights effective on the date of grant. Compensation expense is measured using the market value of the common stock on the date of grant and is recognized on a straight-line basis over the requisite service period (usually the vesting period). As of December 31, 2008, there were 386,000 shares of common stock available for issuance of non-vested share awards under the LTIP Plan.
During the first quarter of 2007, we entered into a retirement agreement with our former CEO and non-executive Chairman of our Board of Directors, the cost of which was recognized through his May 22, 2007 retirement date. The agreement provided that upon retirement, he would receive a grant of 92,000 non-vested share awards which vest at a rate of one-third per year upon each of the first three anniversaries of his retirement date. Furthermore, the agreement modified the vesting term of 28,750 unvested share options and 105,000 non-vested share awards previously granted to him so that such awards vested upon his retirement. We recognized an additional $10.4 million of non-vested share award compensation expense during 2007 as a result of the retirement agreement, of which $5.0 million related to the modification of his previous awards.
The following table summarizes non-vested share award compensation expense recognized during each of the years in the three-year period ended December 31, 2008 (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, 2008:
The following table summarizes non-vested share award activity for the year ended December 31, 2008 (shares in thousands):
As of December 31, 2008, there was $86.0 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 3.8 years.
Savings Plan
We have a profit sharing plan (the “ENSCO Savings Plan”) which covers eligible employees, as defined. Profit sharing contributions require Board of Directors approval and may be in cash or grants of our common stock. We recorded profit sharing contribution provisions of $16.6 million, $14.2 million and $12.6 million for the years ended December 31, 2008, 2007 and 2006, 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 generally make matching cash contributions that vest over a three-year period based on the amount of employee contributions and rates set by our Board of Directors. We match 100% of the amount contributed by the employee up to a maximum of 5% of eligible salary. Matching contributions totaled $5.0 million, $5.0 million and $4.7 million for the years ended December 31, 2008, 2007 and 2006, respectively. We also have 1.0 million shares of common stock reserved for issuance as matching contributions under the ENSCO Savings Plan.
Supplemental Executive Retirement Plan
The ENSCO Supplemental Executive Retirement Plans (the "SERP") provide a tax deferred savings plan for certain highly compensated employees whose participation in the profit sharing and 401(k) savings plan features of the ENSCO Savings Plan is restricted due to funding and contribution limitations of the Internal Revenue Code. The SERP is a non-qualified plan where eligible employees may defer a portion of their compensation for use after retirement. Eligibility for participation is determined by our Board of Directors or a Board committee. The matching provisions of the SERP are identical to the ENSCO Savings Plan, except that matching contributions under the SERP are further limited by contribution amounts under the 401(k) savings plan feature of the ENSCO Savings Plan.
In conjunction with the employment of our current Chief Executive Officer in February 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 $96,000, $79,000 and $1.2 million for the years ended December 31, 2008, 2007 and 2006, respectively. A SERP liability of $13.1 million and $15.2 million was included in other liabilities on our consolidated balance sheets as of December 31, 2008 and 2007, respectively.
10. INCOME TAXES We generated $383.2 million, $319.5 million and $472.3 million of income from continuing operations before income taxes in the U.S. and $1,019.2 million, $896.0 million and $511.1 million of income from continuing operations before income taxes in non-U.S. countries for the years ended December 31, 2008, 2007 and 2006, respectively.
The following table summarizes components of the provision for income taxes from continuing operations for each of the years in the three-year period ended December 31, 2008 (in millions):
The following table summarizes significant components of deferred income tax assets (liabilities) as of December 31, 2008 and 2007 (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 frequently move 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, 2008, differs from the U.S. statutory income tax rate as follows:
During 2006, we reversed a $1.7 million valuation allowance established in 2005 against a $5.5 million deferred tax asset for net operating loss carryforwards in Denmark, after determining it was more-likely-than-not the net operating loss carryforwards would be fully utilized. We utilized the remaining $1.3 million of these net operating loss carryforwards during 2007 and as of December 31, 2008 and 2007, we had no significant net operating loss carryforwards.
Unrecognized Tax Benefits
On January 1, 2007, we adopted the recognition and disclosure provisions of FIN 48. In accordance with FIN 48, tax positions are evaluated for recognition using a more-likely-than-not threshold, and those tax positions requiring recognition are measured as the largest amount of tax benefit that is greater than 50 percent likely of being realized upon effective settlement with a taxing authority that has full knowledge of all relevant information. As a result of adopting FIN 48, we reported a $5.8 million increase to our January 1, 2007 balance of retained earnings. As of December 31, 2008, we had $26.8 million of unrecognized tax benefits, of which $20.2 million would impact our effective income tax rate if recognized. A reconciliation of the beginning and ending amount of unrecognized tax benefits for the year ended December 31, 2008 and 2007, is as follows (in millions):
Accrued interest and penalties totaled $12.9 million and $19.2 million as of December 31, 2008 and 2007, respectively, and were included in other liabilities on our consolidated balance sheets. We recognized a net benefit of $6.8 million and net expense of $2.3 million associated with interest and penalties during 2008 and 2007, respectively. Interest and penalties are included in current income tax expense in our consolidated statements of income.
Our tax returns for 2005 and subsequent years remain subject to examination in all of our major international tax jurisdictions. Furthermore, tax years as early as 2002 remain subject to examination in some major international tax jurisdictions. We participate in the U.S. Internal Revenue Service's Compliance Assurance Process which, among other things, provides for the resolution of tax issues in a timely manner and generally eliminates the need for lengthy post-filing examinations. Only our 2008 U.S. Federal tax return remains subject to examination.
During the first quarter of 2008, in connection with an examination of a prior period tax return, we recognized a $5.4 million liability for unrecognized tax benefits associated with certain tax positions taken in prior years, which resulted in an $8.9 million net income tax expense, inclusive of interest and penalties.
During the first quarter of 2008, statutes of limitations applicable to certain of our tax positions lapsed resulting in a $2.9 million decrease in unrecognized tax benefits and an $11.5 million net income tax benefit, inclusive of interest and penalties.
During 2007, new information became available in one of our international tax jurisdictions that enabled us to conclude that an uncertain tax position established in prior years had been effectively settled. As a result, we recognized an aggregate $11.1 million current tax benefit during the year ended December 31, 2007, consisting of $9.0 million for the previously unrecognized tax benefit and $2.1 million of previously accrued penalties and interest.
Statutes of limitations applicable to certain of our tax positions will lapse during 2009. Therefore, it is reasonably possible that our unrecognized tax benefits will decrease during the next twelve months for the aggregate $800,000 of unrecognized tax benefits associated with these tax positions. As of December 31, 2008, $1.2 million of accrued interest and penalties related to these unrecognized tax benefits.
Intercompany Transfer of Drilling Rigs
In December 2007, we transferred ownership of three drilling rigs among two of our subsidiaries. The income tax liability attributable to the gain resulting from the intercompany sale totaled $96.5 million and was paid by the selling subsidiary during 2008. The pre-tax profit of the selling subsidiary resulting from the intercompany sale was eliminated from our consolidated financial statements. Similarly, the carrying value of the rigs in our consolidated financial statements remained at the historical net depreciated cost prior to the intercompany sale and did not reflect the asset disposition transaction of the selling subsidiary or the asset acquisition transaction of the acquiring subsidiary.
The expense associated with the $96.5 million of income taxes paid was deferred and is being amortized on a straight-line basis over the remaining useful lives of the associated rigs, which range from three to eight years. Similarly, the tax effects of $54.8 million of reversing temporary differences of the selling subsidiary were also deferred and are being amortized on the same basis and over the same periods as described above.
As of December 31, 2008 and 2007, the unamortized balance associated with deferred charges for income taxes paid in connection with intercompany transfers of drilling rigs totaled $91.3 million and $114.4 million, respectively, included in other assets, net, on our consolidated balance sheets. Current income tax expense for the years ended December 31, 2008, 2007 and 2006 included $23.1 million, $2.9 million and $2.1 million, respectively, of amortization of income taxes paid in connection with intercompany transfers of drilling rigs. Deferred income tax expense for the years ended December 31, 2008, 2007 and 2006 included benefits of $7.2 million, $3.9 million and $3.7 million, respectively, of amortization of deferred reversing temporary differences associated with intercompany transfers of drilling rigs.
Undistributed Earnings of our Non-U.S. Subsidiaries
We do not provide U.S. deferred taxes on the undistributed earnings of our non-U.S. subsidiaries because our policy and intention is to reinvest such earnings indefinitely.
In December 2007, our primary non-U.S. subsidiary declared a $1,200.0 million dividend to its U.S. parent company, which included the distribution of its $922.1 million of earnings and the return of $277.9 million of previously invested capital. We utilized foreign tax credits to offset substantially all U.S. tax obligations associated with the December 2007 repatriation of earnings by our non-U.S. subsidiary. As of December 31, 2008, $1,000.0 million of the dividend had been paid and the remaining $200.0 million is expected to be paid during 2009.
The earnings distribution was undertaken because it provided, with minimal U.S. tax impact, substantial funding flexibility for management initiatives, including the continuation and/or extension of our ongoing stock repurchase program and greater options relative to future fleet expansion efforts. This distribution was made in consideration of unique circumstances and, accordingly, it does not change our intention to reinvest the undistributed earnings of our non-U.S. subsidiaries indefinitely. Furthermore, both our U.S. and non-U.S. subsidiaries have significant net assets, liquidity, contract backlog and other financial resources available to meet their operational and capital investment requirements and otherwise allow management to continue to maintain its policy of reinvesting the undistributed earnings of its non-U.S. subsidiaries indefinitely.
As of December 31, 2008, the undistributed earnings of our non-U.S. subsidiaries totaled $867.6 million and are indefinitely reinvested. Should we make a distribution of these earnings in the form of dividends or otherwise, we may be subject to additional U.S. income taxes. The unrecognized deferred tax liability related to the undistributed earnings of our non-U.S. subsidiaries was $244.2 million as of December 31, 2008.
11. DISCONTINUED OPERATIONS
In September 2008, ENSCO 74 was lost as a result of Hurricane Ike and is now presumed to have sunk in the Gulf of Mexico. Portions of the rig's legs remain underwater adjacent to the customer's platform, and the hull has not been located despite search efforts by us and third parties. Management concluded the rig was a total loss under the terms of our insurance policies based on the condition of the legs and the inability to locate the rig's hull.
Physical damage to our rigs caused by a hurricane, the associated costs to mitigate the insured loss ("sue and labor") and removal, salvage and recovery costs, are all covered by our property insurance policies subject to a $50.0 million per occurrence retention (deductible). The insured value of ENSCO 74 was $100.0 million. Additional coverage for ENSCO 74 sue and labor costs and wreckage and debris removal costs under our property insurance policies is limited to $25.0 million and $50.0 million, respectively. Supplemental wreckage and debris removal coverage is provided under our liability insurance policies, subject to an annual aggregate limit of $500.0 million. We also have a customer contractual indemnification that provides for reimbursement of any ENSCO 74 wreckage and debris removal costs that are not recovered under our insurance policies.
Management believes it is probable that we will be required to remove the remaining leg sections of ENSCO 74 from the drill site because the legs are adjacent to the customer's platform and may interfere with future operations. Management estimates that the leg removal costs could range from $15.0 million to $30.0 million. Therefore, a $15.0 million liability, representing the low end of the range of estimated leg removal costs, and a corresponding receivable for recovery of those costs, was recognized during the third quarter of 2008. The liability was included in accrued liabilities and other and the receivable was included in other assets, net, on our December 31, 2008 consolidated balance sheet.
The following table summarizes the pre-tax loss incurred on the disposal of ENSCO 74 during the year ended December 31, 2008 (in millions):
The loss was included in (loss) gain on disposal of discontinued operations, net, in the consolidated statement of income for the year ended December 31, 2008. We received $45.2 million of insurance proceeds associated with the insured value of ENSCO 74 during the fourth quarter of 2008 and the remaining $4.8 million during the first quarter of 2009. The operating results of ENSCO 74 were reclassified as discontinued operations in the consolidated statements of income for each of the years in the three-year period ended December 31, 2008.
We may incur additional costs or liabilities associated with the ENSCO 74 hull, including costs for removal of wreckage or debris and third party or environmental (pollution) liabilities. As the ENSCO 74 hull has not been located, these potential costs or liabilities are not currently considered probable or reasonably estimable. Therefore, no provision for such costs was recognized as of December 31, 2008.
In December 2006, we sold the ENSCO 25 platform rig for $13.7 million and recognized a pre-tax gain of $5.0 million, which was 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 were reclassified as discontinued operations in the consolidated statement of income for the year ended December 31, 2006.
The ENSCO 29 platform rig sustained substantial damage during Hurricane Katrina in the third quarter of 2005. In January 2006, beneficial ownership of ENSCO 29 effectively transferred to our insurance underwriters when the rig was declared a 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 consisted of the $2.5 million excess of insurance proceeds over the $7.5 million net book value of the rig, plus $5.0 million for the de-recognition of a loss provision in the amount of an insurance deductible accrued upon hurricane damage in 2005. The gain was included in (loss) gain on disposal of discontinued operations, net, in the consolidated statement of income for the year ended December 31, 2006. During the third quarter of 2006, we recognized a $1.2 million provision ($800,000 net of tax) relating to issues involving ENSCO 29 wreckage and debris removal liability insurance coverage. See Note 12 "Commitments and Contingencies" for additional information on ENSCO 29 wreckage and debris removal. The operating results of ENSCO 29 and the $1.2 million provision for wreckage and debris removal were reclassified as discontinued operations in the consolidated statement of income for the year ended December 31, 2006.
The following table summarizes income from discontinued operations for each of the years in the three-year period ended December 31, 2008 (in millions):
Debt and interest expense are not allocated to our discontinued operations.
12. COMMITMENTS AND CONTINGENCIES
Leases
We are obligated under leases for certain of our offices and equipment. Rental expense relating to operating leases was $13.9 million, $12.0 million and $11.3 million during the years ended December 31, 2008, 2007 and 2006, respectively. Future minimum rental payments under our noncancellable operating lease obligations having initial or remaining lease terms in excess of one year are as follows: $6.7 million in 2009; $2.6 million in 2010; $1.6 million in 2011; $1.4 million in 2012 and $7.9 million thereafter.
Capital Commitments
The following table summarizes the aggregate contractual commitments related to our six ENSCO 8500 Series® rigs under construction (in millions):
The actual timing of these expenditures may vary based on the completion of various construction milestones, which are beyond our control.
FCPA Internal Investigation
Following disclosures by other offshore service companies announcing internal investigations involving the legality of amounts paid to and by customs brokers in connection with temporary importation of rigs and vessels into Nigeria, the Audit Committee of our Board of Directors and management commenced an internal investigation in July 2007. The investigation initially focused on our payments to customs brokers relating to the temporary importation of ENSCO 100, our only rig that recently operated offshore Nigeria.
As is customary for companies operating offshore Nigeria, we had engaged independent customs brokers to process customs clearance of routine shipments of equipment, materials and supplies and to process the ENSCO 100 temporary importation permits, extensions and renewals. One or more of the customs brokers that our subsidiary in Nigeria used to obtain the ENSCO 100 temporary import permits, extensions and renewals also provided this service to other offshore service companies that have undertaken FCPA compliance internal investigations.
The principal purpose of our investigation was to determine whether any of the payments made to or by our customs brokers were inappropriate under the anti-bribery provisions of the FCPA or whether any violations of the recordkeeping or internal accounting controls provisions of the FCPA occurred. Our Audit Committee engaged a Washington, D.C. law firm with significant experience in investigating and advising upon FCPA matters to assist in the internal investigation.
Following notification to the Audit Committee and to KPMG LLP, our independent registered public accounting firm, in consultation with the Audit Committee's outside legal counsel, we voluntarily notified the United States Department of Justice and the SEC that we had commenced an internal investigation. We expressed our intention to cooperate with both agencies, comply with their directives and fully disclose the results of the investigation. The internal investigation process has involved extensive reviews of documents and records, as well as production to the authorities, and interviews of relevant personnel. In addition to the temporary importation of ENSCO 100, the investigation has examined our customs clearance of routine shipments and immigration activities in Nigeria.
The internal investigation has essentially been concluded. A meeting to review the results of the investigation with the authorities was held on February 24, 2009. We expect to discuss a possible negotiated disposition with the authorities during the second or third quarter of 2009. It currently is anticipated that the matter will be concluded within that period.
Although we believe the U.S. authorities will take into account our voluntary disclosure, our cooperation with the agencies and the remediation and compliance enhancement activities that are underway, we are unable to predict the ultimate disposition of this matter, whether we will be charged with violation of the anti-bribery, recordkeeping or internal accounting controls provisions of the FCPA or whether the scope of the investigation will be extended to other issues in Nigeria or to other countries. We also are unable to predict what potential corrective measures, fines, sanctions or other remedies, if any, the agencies may seek against us or any of our employees.
In November 2008, our Board of Directors approved enhanced FCPA compliance recommendations issued by the Audit Committee's outside counsel and the Company embarked upon an enhanced compliance initiative that included appointment of a Chief Compliance Officer and a Director - Corporate Compliance. We have engaged consultants to assist us in implementing the compliance recommendations approved by our Board of Directors, which will include an enhanced compliance policy, increased training and testing, prescribed contractual provisions for our service providers that interface with foreign government officials, due diligence for the selection of such service providers, and an increased Company-wide awareness initiative that includes periodic issuance of FCPA Alerts.
Since ENSCO 100 completed its contract commitment and departed Nigeria in August 2007, this matter is not expected to have a material effect on or disrupt our current operations. As noted above, we are unable to predict the outcome of this matter or estimate the extent to which we may be exposed to any resulting potential liability, sanctions or significant additional expense.
ENSCO 29 Wreck Removal
A portion of the ENSCO 29 platform drilling rig was lost over the side of a customer's platform as a result of Hurricane Katrina during the third quarter of 2005. Although beneficial ownership of ENSCO 29 was transferred to our insurance underwriters when the rig was determined to be a total loss, management believes we may be legally required to remove ENSCO 29 wreckage and debris from the seabed and currently estimates that the removal cost could range from $5.0 million to $15.0 million. Our property insurance policies include coverage for ENSCO 29 wreckage and debris removal costs up to $3.8 million. We also have liability insurance policies that provide specified coverage for wreckage and debris removal costs in excess of the $3.8 million coverage provided under our property insurance policies.
Our liability insurance underwriters have issued letters reserving rights and effectively denying coverage by questioning the applicability of coverage for the potential ENSCO 29 wreckage and debris removal costs. In August 2007, we commenced litigation in the Texas District Court of Dallas County against certain underwriters at Lloyd's and insurance companies, Bryan Johnson and BC Johnson Associates, LLC (collectively "the Underwriters") alleging breach of contract, wrongful denial, bad faith and other claims which seek a declaration that removal of wreckage and debris is covered under our liability insurance, monetary damages, attorneys' fees and other remedies. The Underwriters removed the case to the United States District Court for the Northern District of Texas, Dallas Division. The case was then remanded back to the Texas District Court by the United States District Court. The Underwriters then appealed the remand to the United States Court of Appeals. The litigation is in an early stage, and oral argument in United States Court of Appeals has been scheduled for March 2009.
While we anticipate that any ENSCO 29 wreckage and debris removal costs incurred will be largely or fully covered by insurance, a $1.2 million provision, representing the portion of the $5.0 million low end of the range of estimated removal cost we believe is subject to liability insurance coverage, was recognized during the third quarter of 2006.
Asbestos Litigation
In August 2004, we and certain current and former subsidiaries were named as defendants, along with numerous other third party companies as co-defendants, in three multi-party lawsuits filed in the Circuit Courts of Jones County (Second Judicial District) and Jasper County (First Judicial District), Mississippi. The lawsuits sought an unspecified amount of monetary damages on behalf of individuals alleging personal injury or death, primarily under the Jones Act, purportedly resulting from exposure to asbestos on drilling rigs and associated facilities during the period 1965 through 1986.
In compliance with the Mississippi Rules of Civil Procedure, the individual claimants in the original multi-party lawsuits whose claims were not dismissed were ordered to file either new or amended single plaintiff complaints naming the specific defendant(s) against whom they intended to pursue claims. As a result, out of more than 600 initial multi-party claims, we have been named as a defendant by 65 individual plaintiffs. Of these claims, 62 claims or lawsuits are pending in Mississippi state courts and three are pending in the U.S. District Court as a result of their removal from state court.
The majority of these cases currently are under an informal stay of discovery issued by a Special Master presiding over these matters while discovery is conducted for a designated group of plaintiffs, several of which involve us. To date, written discovery and plaintiff depositions have taken place in seven cases pending against us. No further activity will occur in these cases until they are selected for trial. Currently, none of the cases pending against us in Mississippi has been set for trial.
We intend to vigorously defend against these claims and have filed responsive pleadings preserving all defenses and challenges to jurisdiction and venue. However, discovery is still ongoing and, therefore, available information regarding the nature of all pending claims is limited. At present, we cannot reasonably determine how many of the claimants may have valid claims under the Jones Act or estimate a range of potential liability exposure, if any.
In addition to the pending cases in Mississippi, we have eight other asbestos or lung injury claims pending against us in litigation in various other jurisdictions. Although we do not expect the final disposition of the Mississippi and other asbestos lawsuits to have a material adverse effect upon our financial position, operating results or cash flows, there can be no assurances as to the ultimate outcome of the lawsuits.
Working Time Directive
Legislation known as the U.K. Working Time Directive ("WTD") was introduced in August 2003 and may be applicable to our employees and employees of other drilling contractors that work offshore in U.K. territorial waters or in the U.K. sector of the North Sea. Certain trade unions representing offshore employees have claimed that drilling contractors are not in compliance with the WTD in respect of paid time off (vacation time) for employees working offshore on a rotational basis (generally equal time working and off). The related issues are subject to pending or potential judicial, administrative and legislative review.
A Labor Tribunal in Aberdeen, Scotland, rendered decisions in claims involving other offshore drilling contractors and offshore service companies on February 21, 2008. The Tribunal decisions effectively held that employers of offshore workers in the U.K. Sector employed on an equal time on/time off rotation are obligated to accord such rotating personnel two-weeks annual paid time off from their scheduled offshore work assignment period. Both sides of the matter, employee and employer groups, have appealed the Tribunal decision. The appeals were heard in December 2008 and are expected to be decided early in 2009. The extent to which the decisions will impact us financially or cause us to modify our employment or compensation practices is uncertain.
We also have received inquiries from the Danish and Dutch authorities regarding applicability of the WTD as adopted by Denmark and The Netherlands to employees on our rigs operating in the Danish and Dutch sectors of the North Sea.
Based on information currently available, we do not expect the resolution of these matters to have a material adverse effect on our financial position, operating results or cash flows.
ENSCO 69 Dispute
Since May 2007, ENSCO 69 has been contracted to Petrosucre, a subsidiary of PDVSA, the national oil company of Venezuela. PDVSA subsidiaries lack funding and generally have not been paying their contractors and service providers. As of December 31, 2008, Petrosucre accounts receivable totaled $28.5 million, and our December 31, 2008 consolidated balance sheet included $14.3 million of Petrosucre accounts receivable, net of allowance for doubtful accounts. As of January 31, 2009, we had gross accounts receivable of approximately $36.0 million under the ENSCO 69 contracts.
In January 2009, we suspended drilling operations upon completion of the well in progress after Petrosucre failed to meet commitments relative to the payment of past due invoices. Petrosucre resumed ENSCO 69 drilling operations under observation by our supervisory rig personnel, utilizing Petrosucre employees and a portion of the Venezuelan rig crews that were utilized by us. Petrosucre has advised us that it temporarily is taking over operations on the rig. We are currently engaged in discussions and exchanging correspondence with Petrosucre regarding each party's contractual rights and obligations.
The ENSCO 69 contracts are governed by Venezuelan law, and there can be no assurances as to the ultimate outcome of the pending dispute which could have a material adverse effect upon our assets, financial position, operating results or cash flows. ENSCO 69 has an insured value of $65.0 million under a package policy, including coverage for certain political risks, subject to a $10.0 million deductible.
Other Matters
In addition to the foregoing, we are named defendants in certain other lawsuits, claims or proceedings incidental to our business and are involved from time to time as parties to governmental investigations or proceedings, including matters related to taxation, arising in the ordinary course of business. Although the outcome of such lawsuits or other proceedings cannot be predicted with certainty and the amount of any liability that could arise with respect to such lawsuits or other proceedings cannot be predicted accurately, management does not expect these matters to have a material adverse effect on our financial position, operating results or cash flows.
13. SEGMENT INFORMATION
We are in the process of developing a fleet of ultra-deepwater semisubmersible rigs. In connection therewith, we contracted a major international shipyard based in Singapore to construct seven ultra-deepwater semisubmersible rigs (the "ENSCO 8500 Series®"). ENSCO 8500 was delivered by the shipyard in September 2008 and arrived in the Gulf of Mexico in mid-December 2008. The rig is currently undergoing deepwater sea trials and is projected to commence operations under a four-year contract in April 2009. In connection with the arrival of our first ENSCO 8500 Series® rig, we reorganized the management of our operations, establishing a separate business unit to manage our fleet of ultra-deepwater semisubmersible rigs.
As part of this reorganization, we evaluated our remaining assets and operations, consisting of 43 jackup rigs and one barge rig organized into three business units based on major geographic region, and now consider these three business units as operating segments. Accordingly, our business now consists of four operating segments: (1) Deepwater, (2) Asia Pacific, (3) Europe/Africa and (4) North and South America. Each of our four operating segments provides one service, contract drilling.
Segment information for each of the years in the three-year period ended December 31, 2008 is presented below. General and administrative expense and depreciation expense incurred by our corporate office are not allocated to our operating segments for purposes of measuring segment operating income and were included in "Reconciling Items." Assets not allocated to our operating segments were also included in "Reconciling Items." As of December 31, 2008, 2007 and 2006, total asset reconciling items consisted primarily of cash and cash equivalents and goodwill.
Year Ended December 31, 2008
(in millions)
Year Ended December 31, 2007
(in millions)
Year Ended December 31, 2006
(in millions)
Information about Geographic Areas
As of December 31, 2008, our Deepwater operating segment consisted of one ultra-deepwater semisubmersible rig located in the Gulf of Mexico, one ultra-deepwater semisubmersible rig mobilizing to Australia and six ultra-deepwater semisubmersible rigs under construction in Singapore. Our Asia Pacific operating segment consisted of 19 jackup rigs and one barge rig deployed in various locations throughout Asia, the Middle East, Australia and New Zealand. Our Europe/Africa operating segment consisted of eight jackup rigs deployed in various territorial waters of the North Sea and two jackup rigs located offshore Tunisia. Our North and South America operating segment consisted of 12 jackup rigs located in the Gulf of Mexico, one jackup rig located offshore Mexico and one jackup rig located offshore Venezuela.
For purposes of our geographic areas disclosures, we attribute revenues to the geographic location where such revenue is earned and assets to the geographic location of the drilling rig as of December 31 of the applicable year. For new construction projects, assets are attributed to the location of future operation if known or to the location of construction if the ultimate location of operation is undetermined. Information by country for those countries that account for more than 10% of total revenues or 10% of our long-lived assets was as follows (in millions):
14. SUPPLEMENTAL FINANCIAL INFORMATION
Consolidated Balance Sheet Information
Accounts receivable, net, as of December 31, 2008 and 2007 consisted of the following (in millions):
Other current assets as of December 31, 2008 and 2007 consisted of the following (in millions):
Other assets, net, as of December 31, 2008 and 2007 consisted of the following (in millions):
Accrued liabilities and other as of December 31, 2008 and 2007 consisted of the following (in millions):
Other liabilities as of December 31, 2008 and 2007 consisted of the following (in millions):
Consolidated Statement of Income Information
Repair and maintenance expense related to continuing operations for each of the years in the three-year period ended December 31, 2008 was 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, 2008 was as follows (in millions):
Capitalized interest totaled $21.6 million in 2008, $30.4 million in 2007 and $18.9 million in 2006. Excluded from investing activities on our consolidated statements of cash flows were capital expenditure accruals of $105.1 million in 2008, $96.1 million in 2007 and $27.2 million in 2006.
Financial Instruments
The carrying amounts and estimated fair values of our debt instruments as of December 31, 2008 and 2007 were 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 as of December 31, 2008 and 2007.
As of December 31, 2008, we held $72.3 million (par value) of auction rate securities measured at fair value in accordance with SFAS 157. The carrying value of our auction rate securities was $64.2 million as of December 31, 2008. We did not own auction rate securities as of December 31, 2007. See "Note 8 - Fair Value Measurements" for additional information on fair value measurement of our auction rate securities.
We have cash, receivables and payables denominated in foreign currencies. These financial assets and liabilities create exposure to foreign currency exchange rate risk. When warranted, we hedge such risk by purchasing foreign currency forward contracts. We do not enter into such contracts for trading or other speculative purposes. As of December 31, 2008 and 2007, the fair value of such contracts was a net liability of $20.3 million and a net asset of $4.6 million, respectively.
Concentration of Credit Risk
We are exposed to credit risk relating to our receivables from customers, our cash and cash equivalents and investments and our use of derivative instruments in connection with the management of foreign currency exchange rate risk. We minimize our credit risk relating to receivables from customers, which consist primarily of major international and independent oil and natural gas producers, as well as government-owned oil and gas companies, by performing ongoing credit evaluations. We also maintain reserves for potential credit losses, which to date have been within management's expectations. We minimize our credit risk relating to cash and investments by focusing on diversification and quality of instruments. Cash balances are maintained in major, highly-capitalized commercial banks. Cash equivalents consist of a portfolio of high-grade instruments. Custody of cash and cash equivalents is maintained at several major financial institutions, and we monitor the financial condition of those financial institutions. Substantially all of our investments were issued by state agencies and are substantially guaranteed by the U.S. government under FFELP. 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 2008, 2007 and 2006, no customer provided more than 10% of consolidated revenues.
15. UNAUDITED QUARTERLY FINANCIAL DATA
The following table summarizes our unaudited quarterly consolidated income statement data for the years ended December 31, 2008 and 2007 (in millions, except per share amounts):
16. SUBSEQUENT EVENT
Since May 2007, ENSCO 69 has been contracted to Petrosucre, a subsidiary of the national oil company of Venezuela. In late January 2009, we suspended drilling operations upon completion of the well in progress after Petrosucre failed to meet commitments relative to the payment of past due invoices. Petrosucre resumed ENSCO 69 drilling operations under observation by our supervisory rig personnel, utilizing Petrosucre employees and a portion of the Venezuelan rig crews that were utilized by us. Petrosucre has advised us that it temporarily is taking over operations on the rig. We currently are engaged in discussions and exchanging correspondence with Petrosucre regarding each party's contractual rights and obligations.
As of December 31, 2008, Petrosucre accounts receivable totaled $28.5 million, and our December 31, 2008 consolidated balance sheet included $14.3 million of Petrosucre accounts receivable, net of allowance for doubtful accounts. As of January 31, 2009, our gross Petrosucre accounts receivable totaled approximately $36.0 million.
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, 2008, 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, 2008 and incorporated herein by reference.
The information required by this item with respect to our executive officers is set forth in "Executive Officers" in Part I of this annual report on Form 10-K.
Information with respect to Section 16(a) of the Exchange Act is included under "Section 16(a) Beneficial Ownership Reporting Compliance" in our Proxy Statement and is incorporated herein by reference.
The guidelines and procedures of the Board of Directors are outlined in our Corporate Governance Policy. The committees of the Board of Directors operate under written charters adopted by the Board of Directors. The Corporate Governance Policy and committee charters are available on our website at www.enscointernational.com in the Governance section and are available in print without charge by contacting our Investor Relations Department at 214-397-3045.
We have a Code of Business Conduct Policy that applies to all of our employees, including our principal executive officer, principal financial officer and controller. The Code of Business Conduct Policy is available on our website at www.enscointernational.com in the Governance section and is available in print without charge by contacting our Investor Relations Department. We intend to disclose any amendments to or waivers from our Code of Business Conduct Policy by posting such information on our website. Our Proxy Statement contains governance disclosures, including information on our Code of Business Conduct Policy, the Ensco Corporate Governance Policy, the director nomination process, shareholder director nominations, shareholder communications to the Board of Directors and director attendance at the Annual Meeting of Stockholders.
Item 11.
Item 11. Executive Compensation
The information required by this item is contained in our Proxy Statement and incorporated herein by reference.
Item 12.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder
Matters
The following table summarizes certain information related to our compensation plans under which shares of our Common Stock are authorized for issuance as of December 31, 2008:
*
In connection with the acquisition of Chiles Offshore Inc. ("Chiles") in 2002, we assumed Chiles' stock option plan and the outstanding stock options thereunder. As of December 31, 2008, options to purchase 98 shares of our common stock, at a weighted-average exercise price of $23.12 per share, were outstanding under this plan. No shares of our common stock are available for future issuance under this plan, no further share options will be granted under this plan and the plan will be terminated upon the earlier of the exercise or expiration date of the last outstanding option.
Additional information required by this item is included in our Proxy Statement and 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 our Proxy Statement and incorporated herein by reference.
Item 14.
Item 14. Principal Accounting Fees and Services
The information required by this item is contained in our Proxy Statement and 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 4, 2008 (incorporated by reference to Exhibit 3.1 to the Registrant's Current Report on Form 8-K dated November 4, 2008, File No. 1-8097).
4.1 - 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).
4.2 - 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).
4.3 - Form of Debenture (incorporated by reference to Exhibit 4.4 to the Registrant's Current Report on Form 8-K dated November 24, 1997, File No. 1-8097).
+10.1 - ENSCO International Incorporated 1996 Non-Employee Directors Stock Option Plan (incorporated by reference to Exhibit 4.1 to the Registrant's Registration Statement on Form S-8 filed August 23, 1996, Registration No. 333-10733).
+10.2 - 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).
10.3 - 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).
+10.4 - 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).
10.5 - 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).
10.6 - 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).
10.7 - 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).
10.8 - 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).
+10.9 - 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).
+10.10 - 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).
+10.11 - 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).
10.12 - 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).
+10.13 - 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).
+10.14 - 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).
+10.15 - 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).
+10.16 - 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).
+10.17 - 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).
+10.18 - 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).
+10.19 - 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).
+10.20 - 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).
+10.21 - 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).
+10.22 - 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).
+10.23 - 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).
+10.24 - 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).
+10.25 - Amendment No. 7 to the ENSCO Savings Plan (As Revised and Restated Effective January 1, 1997), dated as of November 9, 2005 (incorporated by reference to Exhibit 10.29 to the Registrant's Annual Report on Form 10-K for the year ended December 31, 2006, File No. 1-8097).
+10.26 - 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).
+10.27 - 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).
+10.28 - 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).
+10.29 - 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).
+10.30 - 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).
+10.31 - 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).
+10.32 - 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).
+10.33 - 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).
+10.34 - Amendment to the ENSCO International Incorporated 2005 Long-Term Incentive Plan, dated as of December 26, 2006 (incorporated by reference to Exhibit 10.39 to the Registrant's Annual Report on Form 10-K for the year ended December 31, 2006, File No. 1-8097).
+10.35 - Amendment No. 9 to the ENSCO Savings Plan (As Revised and Restated Effective January 1, 1997), dated as of December 26, 2006 (incorporated by reference to Exhibit 10.40 to the Registrant's Annual Report on Form 10-K for the year ended December 31, 2006, File No. 1-8097).
+10.36 - Amendment No. 10 to the ENSCO Savings Plan (As Revised and Restated Effective January 1, 1997), dated as of December 26, 2006 (incorporated by reference to Exhibit 10.41 to the Registrant's Annual Report on Form 10-K for the year ended December 31, 2006, File No. 1-8097).
+10.37 - Retirement Agreement dated February 28, 2007 between the Company and Carl F. Thorne (incorporated by reference to Exhibit 10.1 to the Registrant's Current Report on Form 8-K dated February 28, 2007, File No. 1-8097).
+10.38 - Tax Payment Compensatory Agreement dated May 30, 2007 between the Company and Paul Mars (incorporated by reference to Exhibit 10.1 to the Registrant's Current Report on Form 8-K dated May 30, 2007, File No. 1-8097).
+10.39 - Summary of Changes in Compensation of Non-Employee Directors, effective November 6, 2007 (incorporated by reference to Item 8.01 of the Registrant's Current Report on Form 8-K dated November 6, 2007, File No. 1-8097).
+10.40 - 2008 Performance Measurement Criteria for Named Executive Officers under the ENSCO Cash Incentive Plan (incorporated by reference to Item 5.02 of the Registrants Current Report on Form 8-K dated November 6, 2007, File No. 1-8097).
+10.41 - Amendment No. 11 to the ENSCO Savings Plan (As Revised and Restated Effective January 1, 1997), dated as of November 6, 2007 (incorporated by reference to Exhibit 10.43 of the Registrant's Annual Report on Form 10-K for the year ended December 31, 2007, File No. 1-8097).
+10.42 - Amendment No. 1 to the 2005 ENSCO Supplemental Executive Retirement Plan, dated as of November 6, 2007 (incorporated by reference to Exhibit 10.44 of the Registrant's Annual Report on Form 10-K for the year ended December 31, 2007, File No. 1-8097).
+10.43 - 2007 Cash Bonus Awards for Named Executive Officers under the 2005 ENSCO Cash Incentive Plan (incorporated by reference to Item 5.02 of the Registrant's Current Report on Form 8-K dated March 14, 2008, File No. 1-8097.)
+10.44 - Amendment No. 1 to the ENSCO Supplemental Executive Retirement Plan (As Amended and Restated Effective January 1, 2004), dated as of March 11, 2008 (incorporated by reference to Exhibit 10.1 of the Registrant's Quarterly Report on Form 10-Q for the quarter ended March 31, 2008, File No. 1-8097).
+10.45 - Amendment No. 2 to the ENSCO 2005 Supplemental Executive Retirement Plan, dated as of March 11, 2008 (incorporated by reference to Exhibit 10.2 of the Registrant's Quarterly Report on Form 10-Q for the quarter ended March 31, 2008, File No. 1-8097).
+10.46 - Amendment No. 1 to the ENSCO Non-Employee Director Deferred Compensation Plan, dated as of March 11, 2008 (incorporated by reference to Exhibit 10.3 of the Registrant's Quarterly Report on Form 10-Q for the quarter ended March 31, 2008, File No. 1-8097).
+10.47 - Amendment No. 1 to the ENSCO 2005 Non-Employee Director Deferred Compensation Plan, dated as of March 11, 2008 (incorporated by reference to Exhibit 10.4 of the Registrant's Quarterly Report on Form 10-Q for the quarter ended March 31, 2008, File No. 1-8097).
+10.48 - Amendment No. 12 to the ENSCO Savings Plan (As Revised and Restated Effective January 1, 1997), dated as of March 11, 2008 (incorporated by reference to Exhibit 10.5 of the Registrant's Quarterly Report on Form 10-Q for the quarter ended March 31, 2008, File No. 1-8097).
+10.49 - Third Amendment to the ENSCO International Incorporated 2005 Long-Term Incentive Plan, dated as of April 1, 2008 (incorporated by reference to Exhibit 10.6 of the Registrant's Quarterly Report on Form 10-Q for the quarter ended March 31, 2008, File No. 1-8097).
+10.50 - Fourth Amendment to the ENSCO International Incorporated 2005 Long-Term Incentive Plan, dated as of May 21, 2008 (incorporated by reference to Exhibit 10.1 of the Registrant's Quarterly Report on Form 10-Q for the quarter ended June 30, 2008, File No. 1-8097).
+10.51 - Amendment to the ENSCO International Incorporated 2005 Cash Incentive Plan, dated as of May 21, 2008 (incorporated by reference to Exhibit 10.2 of the Registrant's Quarterly Report on Form 10-Q for the quarter ended June 30, 2008, File No. 1-8097).
+10.52 - Employment Offer Letter dated May 19, 2008 and accepted on May 22, 2008 between the Registrant and Mark Burns (incorporated by reference to Exhibit 10.3 of the Registrant's Quarterly Report on Form 10-Q for the quarter ended June 30, 2008, File No. 1-8097).
+10.53 - Employment Offer Letter dated June 23, 2008 and accepted July 22, 2008 between the Registrant and Carey Lowe (incorporated by reference to Exhibit 10.1 of the Registrant's Quarterly Report on Form 10-Q for the quarter ended September 30, 2008, File No. 1-8097).
+10.54 - Fifth Amendment to the ENSCO International Incorporated Long-Term Incentive Plan, effective November 4, 2008 except as otherwise specifically conditioned and provided therein (incorporated by reference to Item 10.1 of the Registrant's Current Report on Form 8-K dated November 7, 2008, File No. 1-8097).
+10.55 - 2009 Performance Criteria for Named Executive Officers under the ENSCO Cash Incentive Plan (incorporated by reference to Item 5.02 of the Registrant's Current Report on Form 8-K dated December 30, 2008, File No. 1-8097).
+*10.56 - ENSCO 2005 Supplemental Executive Retirement Plan (As Amended and Restated effective January 1, 2005), dated November 4, 2008.
+*10.57 - Amendment No. 2 to the ENSCO Supplemental Executive Retirement Plan (As Amended and Restated effective January 1, 2004), dated November 4, 2008.
+*10.58 - Amendment No. 13 to the ENSCO Savings Plan (As Revised and Restated Effective January 1, 1997), dated November 4, 2008.
+*10.59 - Second Amendment to the ENSCO International Incorporated 2005 Cash Incentive Plan, dated as of November 4, 2008.
+*10.60 - Amendment No. 2 to the ENSCO 2005 Non-Employee Director Deferred Compensation Plan, dated as of November 4, 2008.
+*10.61 - Trust Deed with respect to the Trust to be known as The Ensco Multinational Savings Plan between Ensco International Incorporated (as Plan Sponsor) and Citco Trustees (Cayman) Limited (as Original Trustee), effective as of January 1, 2009.
*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
** Furnished 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 herewith as permitted by paragraph (b)(4)(iii)(A) of Item 601 of Regulation S-K.
SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized, on February 26, 2009.
ENSCO International Incorporated
(Registrant)
By /s/ DANIEL W. RABUN
Daniel W. Rabun
Chairman, President and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the Registrant and in the capacities and on the date indicated.
Signatures
Title
Date
/s/ DAVID M. CARMICHAEL
David M. Carmichael
Director
February 26, 2009
/s/ J. RODERICK CLARK
J. Roderick Clark
Director
February 26, 2009
/s/ C. CHRISTOPHER GAUT
C. Christopher Gaut
Director
February 26, 2009
/s/ GERALD W. HADDOCK
Gerald W. Haddock
Director
February 26, 2009
/s/ THOMAS L. KELLY II
Thomas L. Kelly II
Director
February 26, 2009
/s/ KEITH O. RATTIE
Keith O. Rattie
Director
February 26, 2009
/s/ RITA M. RODRIGUEZ
Rita M. Rodriguez
Director
February 26, 2009
/s/ PAUL E. ROWSEY, III
Paul E. Rowsey, III
Director
February 26, 2009
/s/ JAMES W. SWENT III
James W. Swent III
Senior Vice President -
Chief Financial Officer
February 26, 2009
/s/ DAVID A. ARMOUR
David A. Armour
Vice President - Finance
February 26, 2009
/s/ DOUGLAS J. MANKO
Douglas J. Manko
Controller
February 26, 2009