Exhibit 99.2
The following "Management's Discussion and Analysis of Financial Condition and Results of Operations" should be read in conjunction with our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data". Any references to Notes in the following "Management's Discussion and Analysis of Financial Condition and Results of Operations" refer to the Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" (attached as Exhibit 99.1 to this Report).
As further discussed in Note 11 to our consolidated financial statements, our consolidated financial statements for all periods presented herein have been updated to reclassify ENSCO 50 and ENSCO 51 as discontinued operations. This filing includes updates only to the portions of Item 6, Item 7 and Item 8 of the Form 10-K that specifically relate to the reclassification of ENSCO 50 and ENSCO 51 as discontinued operations and does not otherwise modify or update any other disclosures set forth in the Form 10-K.
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 oil and gas industry. We own and operate a fleet of 45 drilling rigs, including 40 jackup rigs, four ultra-deepwater semisubmersible rigs and one barge rig. We are concentrated in premium jackup rigs, but are currently in the process of developing a fleet of ultra-deepwater semisubmersible rigs, capable of drilling at depths of 8,500 feet or greater. Our 45 drilling rigs are located throughout the world and concentrated in the major geographic regions of Asia Pacific (which includes Asia, the Middle East and Australia), Europe and 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 a drilling rig and rig crews and receive a fixed amount per day for drilling a 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.
During 2008, our revenues, operating income and net income reached record levels as a result of strong rig demand, high utilization and increased day rates in all geographic regions. The decline in oil and natural gas prices from their record highs reached during 2008 and the deterioration of the global economy resulted in significantly reduced levels of jackup rig demand during 2009. Accordingly, our jackup rig operating results declined substantially from record-high levels generated during 2008 due to a decline in utilization of our jackup rigs in all geographic regions.
Operating results in our Deepwater segment improved during 2009. ENSCO 7500 operated in Australia at a day rate of approximately $550,000 for the majority of the year. ENSCO 8500 and ENSCO 8501 commenced operations in the Gulf of Mexico in June and October 2009, respectively. Additionally, ENSCO 8502 was delivered in January 2010 and is expected to commence operations in the Gulf of Mexico under a two-year drilling contract during the third quarter of 2010.
We also continued construction of ENSCO 8503, ENSCO 8504, ENSCO 8505 and ENSCO 8506. These rigs are scheduled for delivery during the fourth quarter of 2010, the second half of 2011 and the first and second half of 2012, respectively. We have funded our ultra-deepwater semisubmersible fleet expansion initiative with cash flows generated from continuing operations. We believe our strong balance sheet, including $1,141.4 million of cash and cash equivalents as of December 31, 2009, and over $2,900.0 million of contract backlog will enable us to sustain an adequate level of liquidity during 2010 and beyond.
Redomestication
On December 23, 2009, we completed a reorganization of the corporate structure of the group of companies controlled by our predecessor, Ensco Delaware, pursuant to which an indirect, wholly-owned subsidiary merged with Ensco Delaware, and Ensco plc became our publicly-held parent company. We are now incorporated under English law as a public limited company.
The redomestication changed Ensco's corporate structure, which included a change of our place of incorporation from Delaware to the U.K. and the relocation of our principal executive offices to London, England. The redomestication, among other things, established a corporate headquarters in the U.K. where we already have substantial operations and which is more centrally located within our area of worldwide operations. The U.K. has a stable and developed legal regime with established standards of corporate governance, including provisions addressing the rights of shareholders, and a favorable tax regime that should improve our ability to maintain a competitive worldwide effective income tax rate, among other anticipated benefits. We expect that the reorganization will also result in operational and administrative efficiencies over the long-term and enhance our ability to expand in the U.K., Europe and beyond.
The redomestication was accounted for as an internal reorganization of entities under common control and, therefore, Ensco Delaware's assets and liabilities were accounted for at their historical cost basis and not revalued in the transaction. We remain subject to SEC reporting requirements, the mandates of the Sarbanes-Oxley Act and the applicable corporate governance rules of the NYSE, and we will continue to report our consolidated financial results in U.S. dollars and in accordance with GAAP. We also must comply with additional reporting requirements of English law.
Our Industry
Historically, 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 major oil-producing countries, |
| | • | production and inventory levels and related activities of 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 risk thereof, and |
| | • | the impact that these and other events, whether caused by economic conditions, international or national climate change regulations or other factors, may have on the current and expected future prices of oil and natural gas. |
The significant decline in oil and natural gas prices during the latter half of 2008 and the general deterioration in the global economy led to an abrupt reduction in demand for jackup rigs during 2009. Although oil prices gradually improved throughout 2009, incremental drilling activity was limited. Day rates softened as contractors attempted to lock-in drilling programs and maintain their existing contract backlog amid growing concerns over oil and natural gas prices and pressure from operators to reduce day rates. While we are encouraged by the number of recent rig inquiries in certain markets, it remains unclear whether they will result in incremental jackup rig demand.
Demand for ultra-deepwater semisubmersible rigs remained stable during 2009 despite the decline in oil and natural gas prices from record highs and global economic concerns. Deepwater projects are typically more expensive and longer in duration than shallow-water jackup projects. Accordingly, deepwater operators tend to adopt a longer-term view of commodity prices and the global economy.
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 recent periods of high demand for drilling rigs, various industry participants ordered the construction of over 175 new jackup and semisubmersible rigs, over 80 of which were delivered during the last three years.
Jackup rig supply continues to increase as a result of newbuild construction programs which were initiated prior to the 2008 decline in oil and natural gas prices and global economic crisis. It has been reported that 58 newbuild jackup rigs are currently under construction, half of which are scheduled for delivery during 2010. The majority of jackup rigs scheduled for delivery are not contracted.
Newbuild jackup rigs will likely reduce utilization and day rates as rigs are absorbed into the fleet, especially in light of current levels of jackup rig demand. We expect the Asia Pacific region to be impacted most by the delivery of newbuild jackup rigs, as a significant portion of rig construction is occurring in the Asia Pacific region. It is time consuming and expensive to move drilling rigs between markets in response to changes in supply and demand and, accordingly, the supply of rigs in the Asia Pacific region, or other regions where newbuild rigs are delivered, may not adjust quickly and could lead to sudden changes in utilization and day rates. It is unclear whether, or to what extent, other markets will be adversely affected by newbuild rigs.
Semisubmersible rig supply also continues to increase as a result of newbuild construction programs. It has been reported that 37 newbuild semisubmersible rigs are currently under construction, over half of which are scheduled for delivery during 2010. The majority of semisubmersible rigs scheduled for delivery are contracted. Based on the current level of demand for semisubmersible rigs, especially ultra-deepwater semisubmersible rigs, we anticipate that newbuild semisubmersible rigs will be absorbed into the market without a 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 utilization and day rates.
Deepwater
Demand for ultra-deepwater semisubmersible rigs on a worldwide basis exceeded supply resulting in high utilization levels and day rates during 2007 and 2008. Although lower oil and natural gas prices resulted in a modest decline in demand for ultra-deepwater semisubmersible rigs during 2009, utilization and day rates were generally stable.
The deepwater market is becoming increasingly bifurcated between the high-specification, ultra-deepwater rig market and the market for other deepwater rigs. We anticipate continued high utilization of the worldwide ultra-deepwater semisubmersible rig fleet for the foreseeable future. We expect operators to continue to upgrade their fleets to ultra-deepwater semisubmersible rigs during periods of moderating day rates and as new discoveries occur at deeper water depths. Future ultra-deepwater semisubmersible rig day rates will depend in large part on projected oil and natural gas prices and the global economy.
In addition to ENSCO 8500, which commenced a four-year drilling contract in June 2009, ENSCO 8501, which commenced a three-and-a-half-year drilling contract in October 2009, and ENSCO 8502, which was delivered in January 2010 and is expect to commence drilling under a two-year contract during the third quarter of 2010, we have four ENSCO 8500 Series® rigs under construction with scheduled delivery dates during the fourth quarter of 2010, the second half of 2011 and the first and second half of 2012. ENSCO 8503 has secured a long-term drilling contract in the Gulf of Mexico. The remaining ENSCO 8500 Series® rigs under construction are without contracts. Our ENSCO 7500 ultra-deepwater semisubmersible rig is currently operating under contract in Australia.
Asia Pacific
During 2007, demand for Asia Pacific jackup rigs exceeded the supply of available rigs resulting in high utilization levels and increasing day rates. During the first half of 2008, Asia Pacific jackup rig utilization remained high and day rates stabilized as strong rig demand was offset by new rig deliveries. During the latter half of 2008, jackup rig demand was significantly impacted by the decline in oil and natural gas prices and global economic crisis, resulting in a significant reduction in utilization and day rates during 2009. With limited contract opportunities currently available and an expected increase in the supply of available jackup rigs from newbuild deliveries and expiring drilling contracts, we anticipate that Asia Pacific jackup rig utilization and day rates will remain under pressure in the near-term.
Europe and Africa
Our Europe and Africa offshore drilling operations are mainly conducted in northern Europe. During 2007, 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 2008, shortfalls in rig availability in this region led to sustained high utilization levels and day rates. Although utilization and day rates remained high during early 2009, the decline in oil and natural gas prices during the latter half of 2008 resulted in several cancelled tenders and unexercised contract extension options. Tender activity in the region during 2009 was minimal, and we expect this trend to continue in the near-term. We anticipate this market will experience excess rig availability and utilization and day rates will remain under pressure as a significant portion of the North Sea jackup fleet is scheduled to roll-off existing contracts in the coming months.
North and South America
The majority of our North and South America offshore drilling operations are conducted in Mexico, where demand for rigs increased during 2007 and 2008 as Petróleos Mexicanos ("PEMEX"), the national oil company of Mexico, accelerated drilling activities in an attempt to offset continued depletion of its major oil and natural gas fields. During 2009, demand for jackup rigs in Mexico remained high despite global economic conditions. A significant number of PEMEX jackup rig contracts expire during 2010, and PEMEX may extend these contracts and/or tender for incremental rigs. We expect future day rates in Mexico to face pressure as drilling contractors with idle rigs in other geographic regions pursue the available contract opportunities.
We also conduct a portion of our North and South America jackup operations in the Gulf of Mexico. During 2007, 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 resulting in a decline in utilization and day rates. During 2008, damage caused by Hurricanes Gustav and Ike reduced the supply of available jackup rigs, however, the reduction was more than offset by a decrease in demand resulting from the decline in oil and natural gas prices and global economic crisis. The region's jackup market remained extremely weak during 2009 with drilling activity reaching historic lows during later portions of the year. Although it is likely that drilling activity in this region will increase during 2010, we do not expect meaningful improvement in da y rates in the near-term.
RESULTS OF OPERATIONS
The following table summarizes our consolidated operating results for each of the years in the three-year period ended December 31, 2009 (in millions):
| | 2009 | 2008 | 2007 |
| | | | | | | | | | |
| Revenues | | $1,927.8 | | | $2,267.0 | | | $1,953.3 | |
| Operating expenses | | | | | | | | | |
Contract drilling (exclusive of depreciation) | | 707.8 | | | 720.8 | | | 617.4 | |
Depreciation | | 197.1 | | | 178.0 | | | 170.7 | |
General and administrative | | 64.0 | | | 53.8 | | | 59.5 | |
| Operating income | | 958.9 | | | 1,314.4 | | | 1,105.7 | |
| Other income (expense), net | | 8.8 | | | (4.2 | ) | | 37.8 | |
| Provision for income taxes | | 178.4 | | | 220.4 | | | 234.8 | |
| Income from continuing operations | | 789.3 | | | 1,089.8 | | | 908.7 | |
| (Loss) income from discontinued operations, net | | (4.8 | ) | | 66.9 | | | 90.2 | |
| Net income | | 784.5 | | | 1,156.7 | | | 998.9 | |
| Net income attributable to noncontrolling interests | | (5.1 | ) | | (5.9 | ) | | (6.9 | ) |
| Net income attributable to Ensco | | $ 779.4 | | | $1,150.8 | | | $ 992.0 | |
During 2009, revenues declined by $339.2 million, or 15%, and operating income declined by $355.5 million, or 27%, as compared to the prior year. The revenue and operating income declines were primarily due to a decline in jackup rig utilization in all geographic regions, partially offset by the commencement of ENSCO 8500 and ENSCO 8501 drilling operations and an increase in average day rates earned by our jackup rigs contracted in Mexico and ENSCO 7500.
During 2008, revenues increased by $313.7 million, or 16%, and operating income increased by $208.7 million, or 19%, as compared to the prior year. The increases were primarily due to improved average day rates earned by our Asia Pacific and Europe and Africa jackup rigs and ENSCO 7500 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.
A significant number of our drilling contracts are of a long-term nature. Accordingly, the effects of a decline in demand for contract drilling services on our operating results and cash flows typically occurs gradually over several quarters as long-term contracts expire. The significant decline in oil and natural gas prices and the deterioration of the global economy resulted in a dramatic decline in demand for contract drilling services during the later portions of 2008 and 2009, which will negatively impact our operating results and cash flows during 2010. While we have contract backlog of over $1,300.0 million for 2010, it is unlikely that revenue, operating income and cash flow levels achieved during 2009 will be sustained during 2010.
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 occasionally move between our geographic region segments. The following table summarizes our offshore drilling rigs by segment as of December 31, 2009, 2008 and 2007:
| | 2009 | 2008 | 2007 |
| | | | |
Deepwater(1) | 3 | 2 | 1 |
| Asia Pacific | 18 | 18 | 18 |
| Europe and Africa | 10 | 10 | 10 |
| North and South America | 13 | 13 | 13 |
Under construction(1)(2) | 5 | 6 | 4 |
Total(3) | 49 | 49 | 46 |
(1) | | In June 2009, we accepted delivery of ENSCO 8501, which commenced drilling operations in the Gulf of Mexico under a three-and-a-half year contract in October 2009. In September 2008, we accepted delivery of ENSCO 8500, which commenced drilling operations in the Gulf of Mexico under a four-year contract in June 2009. |
(2) | | 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. |
(3) | | The total number of rigs for each period excludes rigs reclassified as discontinued operations. ENSCO 50 and ENSCO 51 have been reclassified as discontinued operations and, therefore, excluded from the table. |
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, 2009:
| | 2009 | 2008 | 2007 |
| | | | | | | |
Rig utilization(1) | | | | | | |
| Deepwater | 85% | | 95% | | 97% | |
Asia Pacific(3) | 76% | | 95% | | 99% | |
| Europe and Africa | 77% | | 96% | | 93% | |
| North and South America | 67% | | 97% | | 77% | |
| Total | 74% | | 96% | | 91% | |
| | | | | | | |
Average day rates(2) | | | | | | |
| Deepwater | $425,190 | | $334,688 | | $199,432 | |
Asia Pacific(3) | 144,903 | | 149,459 | | 129,642 | |
| Europe and Africa | 198,595 | | 221,164 | | 198,551 | |
| North and South America | 119,951 | | 98,166 | | 107,147 | |
| Total | $163,239 | | $154,122 | | $142,538 | |
| (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 and established a separate business unit to manage our deepwater operations during 2008. Our jackup rigs and barge rig are managed by major geographic region. Accordingly, our business consists of four operating segments: (1) Deepwater, (2) Asia Pacific, (3) Europe and 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, 2009. 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, 2009
(in millions)
| | Deepwater | Asia Pacific | Europe and Africa | North and South America | Operating Segments Total | Reconciling Items | Consolidated Total |
| | | | | | | | |
| Revenues | $254.1 | | | $705.9 | | | $569.1 | | | $398.7 | | | $1,927.8 | | | $ -- | | | $1,927.8 | | |
Operating expenses Contract drilling (exclusive of depreciation) | 108.1 | | | 231.3 | | | 208.8 | | | 159.6 | | | 707.8 | | | -- | | | 707.8 | | |
Depreciation | 22.2 | | | 79.2 | | | 44.5 | | | 49.9 | | | 195.8 | | | 1.3 | | | 197.1 | | |
General and administrative | -- | | | -- | | | -- | | | -- | | | -- | | | 64.0 | | | 64.0 | | |
| Operating income | $123.8 | | | $395.4 | | | $315.8 | | | $189.2 | | | $1,024.2 | | | $(65.3) | | | $ 958.9 | | |
Year Ended December 31, 2008
(in millions)
| | Deepwater | Asia Pacific | Europe and Africa | North and South America | Operating Segments Total | Reconciling Items | Consolidated Total |
| | | | | | | | |
| Revenues | $ 84.4 | | | $926.3 | | | $804.1 | | | $452.2 | | | $2,267.0 | | | $ -- | | | $2,267.0 | | |
Operating expenses Contract drilling (exclusive of depreciation) | 31.2 | | | 284.8 | | | 246.7 | | | 158.1 | | | 720.8 | | | -- | | | 720.8 | | |
Depreciation | 9.1 | | | 76.7 | | | 43.0 | | | 47.3 | | | 176.1 | | | 1.9 | | | 178.0 | | |
General and administrative | -- | | | -- | | | -- | | | -- | | | -- | | | 53.8 | | | 53.8 | | |
| Operating income | $ 44.1 | | | $564.8 | | | $514.4 | | | $246.8 | | | $1,370.1 | | | $(55.7) | | | $1,314.4 | | |
Year Ended December 31, 2007
(in millions)
| | Deepwater | Asia Pacific | Europe and Africa | North and South America | Operating Segments Total | Reconciling Items | Consolidated Total |
| | | | | | | | |
| Revenues | $ 72.8 | | | $807.8 | | | $670.8 | | | $401.9 | | | $1,953.3 | | | $ -- | | | $1,953.3 | | |
Operating expenses Contract drilling (exclusive of depreciation) | 28.8 | | | 238.3 | | | 208.4 | | | 141.9 | | | 617.4 | | | -- | | | 617.4 | | |
Depreciation | 9.3 | | | 74.3 | | | 40.4 | | | 42.6 | | | 166.6 | | | 4.1 | | | 170.7 | | |
General and administrative | -- | | | -- | | | -- | | | -- | | | -- | | | 59.5 | | | 59.5 | | |
| Operating income | $ 34.7 | | | $495.2 | | | $422.0 | | | $217.4 | | | $1,169.3 | | | $(63.6) | | | $1,105.7 | | |
Deepwater
During 2009, Deepwater revenues increased by $169.7 million as compared to the prior year. The increase in revenues was due to the commencement of ENSCO 8500 and ENSCO 8501 drilling operations, an increase in the day rate earned by ENSCO 7500 and the recognition of ENSCO 7500 mobilization revenues deferred during the rig's mobilization to Australia. In October 2008, we amended the existing ENSCO 7500 drilling contract and agreed to relocate the rig to Australia where we commenced drilling operations in April 2009 at a day rate of approximately $550,000. Revenues earned during the mobilization period were deferred and are being recognized ratably over the firm commitment period of the contract. The aforementioned revenue increases were partially offset by the deferral of ENSCO 7500 revenues during the rig's mobilization to Australia du ring the first quarter of 2009. Contract drilling expense increased by $76.9 million as compared to the prior year due to the commencement of ENSCO 8500 and ENSCO 8501 drilling operations, ENSCO 7500 mobilization expense and incremental expenses associated with operating ENSCO 7500 in Australia as compared to the Gulf of Mexico. Depreciation expense increased by $13.1 million primarily due to ENSCO 8500 and ENSCO 8501 as noted above.
During 2008, Deepwater revenues increased by $11.6 million, or 16%, as compared to the prior year. 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 revenues during the fourth quarter of 2008 when the rig commenced mobilization to Australia as noted above. Contract drilling expense increased by $2.4 million, or 8%, as compared to the prior year, primarily due to increased personnel costs and repair and maintenance expense, partially offset by the deferral of costs during the ENSCO 7500 mobilization. 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.
Asia Pacific
During 2009, Asia Pacific revenues declined by $220.4 million, or 24%, as compared to the prior year. The decline in revenues was primarily due to a decline in utilization to 76% from 95% during the prior year. The decline in utilization occurred due to lower levels of spending by oil and gas companies, coupled with excess rig availability in the region. Contract drilling expense declined by $53.5 million, or 19%, as compared to the prior year, primarily due to the impact of lower utilization and a decline in repair and maintenance expense. Depreciation expense increased by 3% as compared to the prior year, primarily due to the ENSCO 53 capital enhancement project completed during the second quarter of 2009 and depreciation on minor upgrades and improvements to our Asia Pacific fleet completed during 2008 and 2009.
During 2008, Asia Pacific revenues increased by $118.5 million, or 15%, as compared to the prior year. The increase in revenues was primarily due to a 15% 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 during 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 $46.5 million, or 20%, as compared to the prior year, 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 3% as compared to the prior year. 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.
Europe and Africa
During 2009, Europe and Africa revenues declined by $235.0 million, or 29%, as compared to the prior year. The decline in revenues was primarily due to a decline in utilization to 77% from 96% during the prior year. The decline in utilization occurred due to lower levels of spending by oil and gas companies. Contract drilling expense declined by $37.9 million, or 15%, as compared to the prior year, due to a decline in mobilization expense and the impact of lower utilization. Depreciation expense increased by 3% as compared to the prior year due to depreciation on minor upgrades and improvements to our Europe and Africa fleet completed during 2008 and 2009.
During 2008, Europe and Africa revenues increased by $133.3 million, or 20%, as compared to the prior year. 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. 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 2007. The relocation of ENSCO 105 to the Europe and 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. Contra ct drilling expense increased by $38.3 million, or 18%, as compared to the prior year, 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 6% as compared to the prior year. 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 and Africa fleet completed during 2007 and 2008.
North and South America
During 2009, North and South America revenues declined by $53.5 million, or 12%, as compared to the prior year. The decline in revenues was primarily due to a decline in utilization to 67% from 97% during the prior year, partially offset by a 22% increase in average day rates. The decline in utilization occurred due to lower levels of spending by oil and gas companies in the Gulf of Mexico. The increase in average day rates was largely due to the relocation of ENSCO 83, ENSCO 89, ENSCO 93 and ENSCO 98 to Mexico and ENSCO 68 to Venezuela, where day rates are generally higher than the Gulf of Mexico. Contract drilling expense increased by 1% as compared to the prior year, due to incremental expenses associated with operating in Mexico and Venezuela as compared to the Gulf of Mexico and an increase in mobilization and repair and maintena nce expense, partially offset by the impact of lower utilization. Depreciation expense increased by 5% as compared to the prior year, primarily due to ENSCO 89 and ENSCO 93 capital enhancement projects completed during the second quarter of 2009, the ENSCO 98 capital enhancement project completed during the third quarter of 2009 and depreciation on minor upgrades and improvements to our North and South America fleet completed during 2008 and 2009.
During 2008, North and South America revenues increased by $50.3 million, or 13%, as compared to the prior year. The increase in revenues was primarily due to an increase in utilization to 97% from 77% during the prior year, partially offset by an 8% decline in average day rates. The increase in utilization was attributable to reduced rig supply in the Gulf of Mexico, as drilling contractors mobilized rigs to other regions, and an increase in customer demand. Although we realized day rate increases on new contracts during the majority of 2008, day rates earned during 2008 were generally lower than day rates earned during early 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 $16.2 million, or 11%, as compared to the prior year, primarily due to increased personnel costs and the impact of increased utilization, partially offset by a decline in mobilization expense and the relocation of ENSCO 105 during 2007. Depreciation expense increased by 11% as compared to the prior year. 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.
Other
During 2009, general and administrative expense increased by $10.2 million, or 19%, as compared to the prior year. The increase was primarily attributable to $7.6 million of professional fees incurred in connection with our redomestication during the fourth quarter of 2009 and a $1.9 million expense incurred in connection with a separation agreement with our former Senior Vice President of Operations.
During 2008, general and administrative expense declined by $5.7 million, or 10%, as compared to the prior year. The decline was primarily attributable to an $11.3 million expense incurred during the prior year in connection with a retirement agreement with our former Chairman and Chief Executive Officer, partially offset by increased professional fees and personnel costs and costs associated with our branding initiative.
Other Income (Expense), Net
The following table summarizes other income (expense), net, for each of the years in the three-year period ended December 31, 2009 (in millions):
| | 2009 | 2008 | 2007 |
| | | | | | | | | | |
| Interest income | | $ 2.2 | | | $ 14.0 | | | $ 26.3 | |
| Interest expense, net: | | | | | | | | | |
Interest expense | | (20.9 | ) | | (21.6 | ) | | (32.3 | ) |
Capitalized interest | | 20.9 | | | 21.6 | | | 30.4 | |
| | | -- | | | -- | | | (1.9 | ) |
| Other, net | | 6.6 | | | (18.2 | ) | | 13.4 | |
| | | $ 8.8 | | | $ (4.2 | ) | | $ 37.8 | |
During 2009 and 2008, interest income declined as compared to their respective prior years due to lower average interest rates, partially offset by an increase in cash balances invested. Interest expense declined during 2009 and 2008 as compared to their respective prior years due to a decline in outstanding debt. All interest expense incurred during 2009 and 2008 was capitalized in connection with the construction of our ENSCO 8500 Series® rigs.
A portion of the revenues earned and expenses incurred by our non-U.S. subsidiaries are denominated in currencies other than the U.S. dollar ("foreign currencies"). These transactions are remeasured in U.S. dollars based on a combination of both current and historical exchange rates. Other, net, included $2.6 million of net foreign currency exchange gains, $10.4 million of net foreign currency exchange losses and $9.2 million of net foreign currency exchange gains during 2009, 2008 and 2007, respectively.
Other, net, also included net unrealized gains of $1.8 million and unrealized losses of $8.1 million associated with the valuation of our auction rate securities during 2009 and 2008, respectively. The fair value measurement of our auction rate securities is discussed in Note 8 to our consolidated financial statements. During 2007, other, net, 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 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 revenues, 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 $178.4 million, $220.4 million and $234.8 million and our effective tax rate was 18.4%, 16.8% and 20.5% during the years ended December 31, 2009, 2008 and 2007, respectively. The increase in our 2009 effective tax rate as compared to the prior year was primarily related to an $8.8 million non-recurring current income tax expense incurred in connection with certain restructuring activities undertaken immediately following our redomestication in December 2009. Excluding the impact from this non-recurring item, our 2009 effective tax rate was 17.5%, generally consistent with the prior year. The decline in our 2008 effective tax rate as compared to the prior year was primarily due to an increase in earnings generated by our non-U.S. subsidiaries whose earnings are being indefinitely reinvested and taxed at lower rat es.
Discontinued Operations
ENSCO 50 and ENSCO 51
In recent years we have focused on the expansion of our ultra-deepwater semisubmersible rig fleet and high-grading our premium jackup rig fleet. Accordingly, we sold ENSCO 50 and ENSCO 51 in March 2010 for an aggregate $94.7 million, of which $4.7 million was received in December 2009. ENSCO 50 and ENSCO 51 operating results were reclassified as discontinued operations in our consolidated statements of income for each of the years in the three-year period ended December 31, 2009. See Note 11 to our consolidated financial statements for a dditional information on the sale of ENSCO 50 and ENSCO 51.
ENSCO 69
From May 2007 to June 2009, ENSCO 69 was contracted to Petrosucre, a subsidiary of Petróleos de Venezuela S.A., the national oil company of Venezuela ("PDVSA"). During portions of 2008 and 2009, PDVSA subsidiaries reportedly lacked funds and generally were not paying their contractors and service providers. In January 2009, we suspended drilling operations on ENSCO 69 after Petrosucre failed to satisfy its contractual obligations and meet commitments relative to the payment of past due invoices. Petrosucre then took over complete control of ENSCO 69 drilling operations utilizing Petrosucre employees and a portion of the Venezuelan rig crews we had utilized. Petrosucre initially advised us that it was temporarily taking over operations on the rig, and our supervisory rig personnel remained onboard to observe Petrosucre's operation s.
On June 4, 2009, after Petrosucre's failure to satisfy its contractual payment obligations, failure to reach a mutually acceptable agreement with us and denial of our request to demobilize ENSCO 69 from Venezuela, Petrosucre advised that it would not return the rig and would continue to operate it without our consent. Petrosucre further advised that it would release ENSCO 69 after a six-month period, subject to a mutually agreed accord addressing the resolution of all remaining obligations under the ENSCO 69 drilling contract. On June 6, 2009, we terminated our contract with Petrosucre and removed all remaining Ensco employees from the rig.
Due to Petrosucre's failure to satisfy its contractual obligations and meet payment commitments, and in consideration of the Venezuelan government's recent nationalization of assets owned by international oil and gas companies and oilfield service companies, we concluded it was remote that ENSCO 69 would be returned to us by Petrosucre and operated again by Ensco. Therefore, we recorded the disposal of ENSCO 69 during the second quarter of 2009 and recognized a pre-tax loss of $18.1 million representing the rig's net book value of $17.3 million and inventory and other assets totaling $800,000. The disposal was classified as loss on disposal of discontinued operations, net, in our consolidated statement of income for the year ended December 31, 2009. ENSCO 69 operating results were reclassified as discontinued operations in our consoli dated statements of income for each of the years in the three-year period ended December 31, 2009.
In November 2009, we executed an agreement with Petrosucre to mitigate our losses and resolve issues relative to outstanding amounts owed by Petrosucre for drilling operations performed by Ensco through the date of termination of the drilling contract in June 2009 (the "agreement"). Although ENSCO 69 will continue to be fully controlled and operated by Petrosucre, the agreement also requires Petrosucre to compensate us for its ongoing use of the rig. We recognized $33.1 million of pre-tax income from discontinued operations for the year ended December 31, 2009 associated with collections under the agreement, consisting of $21.2 million of revenues from Petrosucre's use of the rig during 2009 and $11.9 million from the release of bad debt provisions recorded during 2008.
Although the agreement obligates Petrosucre to make additional payments during 2010 for its use of the rig during 2009, the associated income was not recognized in our consolidated statement of income for the year ended December 31, 2009, as collectability was not reasonably assured. There can be no assurances relative to the recovery of outstanding contract entitlements, insurance recovery, the return of ENSCO 69 to us by Petrosucre or the imposition of customs duties in relation to the rig's ongoing presence in Venezuela. See Note 12 to our consolidated financial statements for additional information on insurance recovery and legal remedies related to ENSCO 69.
ENSCO 74
In September 2008, ENSCO 74 was lost as a result of Hurricane Ike. Portions of its legs remained underwater adjacent to the customer's platform, and we conducted extensive aerial and sonar reconnaissance but did not locate the rig hull. In March 2009, the sunken hull of ENSCO 74 was located approximately 95 miles from the original drilling location when it was struck by an oil tanker. The rig was a total loss, as defined under the terms of our insurance policies. The operating results of ENSCO 74 were reclassified as discontinued operations in our consolidated statements of income for the years ended December 31, 2008 and 2007. See Note 11 and Note 12 to our consolidated financial statements for additional information on the loss of ENSCO 74 and associated contingencies.
The following table summarizes income (loss) from discontinued operations for each of the years in the three-year period ended December 31, 2009 (in millions):
| | 2009 | 2008 | 2007 |
| | | | |
| Revenues | | $ 44.1 | | $219.6 | | $190.5 | |
| Operating expenses | | 29.6 | | 99.4 | | 73.4 | |
| Operating income before income taxes | | 14.5 | | 120.2 | | 117.1 | |
| Income tax expense | | 7.5 | | 29.8 | | 26.9 | |
| Loss on disposal of discontinued operations, net | | (11.8) | | (23.5) | | -- | |
| (Loss) income from discontinued operations | | $ (4.8) | | $ 66.9 | | $ 90.2 | |
Fair Value Measurements
Our auction rate securities were measured at fair value as of December 31, 2009 and 2008 using significant Level 3 inputs.
As a result of continued auction failures, quoted prices for our auction rate securities did not exist as of December 31, 2009 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, 2009. The exit price was derived as the weighted-average present value of expected cash flows 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 Level 3 inputs were significant to the overall fair value measurement, particularly the estimates of risk-adjusted discount rates and ranges of expected periods of illiquidity. 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, 2009 was appropriate.
Based on the results of our fair value measurements, we recognized net unrealized gains of $1.8 million and unrealized losses of $8.1 million for the years ended December 31, 2009 and 2008, respectively. Unrealized gains and losses on our auction rate securities were included in other income (expense), net, in our consolidated statements of income. The carrying values of our auction rate securities, classified as long-term investments on our consolidated balance sheets, were $60.5 million and $64.2 million as of December 31, 2009 and 2008, respectively. We anticipate realizing the $66.8 million (par value) of our auction rate securities on the basis that we intend to hold them until they are redeemed, repurchased or sold in a market that facilitates orderly transactions.
Auction rate securities measured at fair value using significant Level 3 inputs constituted 65% of our assets measured at fair value and less than 1% of our total assets as of December 31, 2009. See Note 8 to our consolidated financial statements for additional information on our fair value measurements.
LIQUIDITY AND CAPITAL RESOURCES
Although our business has historically been very cyclical, we have relied on our cash flows 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 portion 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.
During the three-year period ended December 31, 2009, our primary source of cash was an aggregate $3,407.3 million generated from continuing operations. Our primary uses of cash during the same period included an aggregate $2,143.9 million for the construction, enhancement and other improvement of our drilling rigs, including $1,614.6 million invested in the construction of our ENSCO 8500 Series® rigs, and $793.8 million for the repurchase of our shares.
Detailed explanations of our liquidity and capital resources for each of the years in the three-year period ended December 31, 2009 are set forth below.
Cash Flows and Capital Expenditures
Our cash flows from continuing operations and capital expenditures on continuing operations for each of the years in the three-year period ended December 31, 2009 were as follows (in millions):
| | 2009 | 2008 | 2007 |
| | | | | | | |
| Cash flows from continuing operations | $1,217.0 | | $1,047.4 | | $1,142.9 | |
| | | | | | | |
| Capital expenditures on continuing operations: | | | | | | |
| New rig construction | $ 623.4 | | $ 651.5 | | $ 367.7 | |
| Rig enhancements | 153.0 | | 33.7 | | 65.0 | |
| Minor upgrades and improvements | 82.7 | | 82.0 | | 84.9 | |
| | | $ 859.1 | | $ 767.2 | | $ 517.6 | |
During 2009, cash flows from continuing operations increased by $169.6 million, or 16%, as compared to the prior year. The increase resulted primarily from a $187.6 million decline in tax payments and a $77.8 million decline in our investment in trading securities, offset by a $75.7 million decline in cash receipts from contract drilling services and $11.0 million decline in cash received from interest income.
During 2008, cash flows from continuing operations declined by $95.5 million, or 8%, as compared to the prior year. The decline resulted primarily from a $72.3 million net investment in trading securities, a $148.4 million increase in cash payments related to contract drilling expenses and a $135.4 million increase in cash payments related to income taxes, partially offset by a $265.7 million increase in cash receipts from contract drilling services.
We continue to expand the size and quality of our drilling rig fleet. During the three-year period ended December 31, 2009, we invested $1,642.6 million in the construction of new drilling rigs and an additional $251.7 million upgrading the capability and extending the useful lives of our existing fleet. In addition to ENSCO 8500, which was delivered in September 2008 and commenced a four-year drilling contract in June 2009, and ENSCO 8501, which was delivered in June 2009 and commenced a three-and-a-half-year drilling contract in October 2009, ENSCO 8502 was delivered in January 2010 and is expect to commence drilling operations under a two-year contract during the third quarter of 2010. We also added ENSCO 108, a new high-specification jackup rig, to our fleet during 2007.
We have four ENSCO 8500 Series® ultra-deepwater semisubmersible rigs under construction with scheduled delivery dates during the fourth quarter of 2010, the second half of 2011 and the first and second half of 2012. ENSCO 8503 has secured a long-term drilling contract in the Gulf of Mexico, while the other three ENSCO 8500 Series® rigs under construction are currently without contracts.
Based on our current projections, we expect capital expenditures during 2010 to include approximately $610.0 million for construction of our ENSCO 8500 Series® rigs, approximately $30.0 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, 2009, 2008 and 2007 are summarized below (in millions, except percentages):
| | 2009 | 2008 | 2007 |
| | | | | | | |
| Long-term debt | $ 257.2 | | $ 274.3 | | $ 291.4 | |
Total capital* | 5,756.4 | | 4,951.2 | | 4,043.4 | |
| Long-term debt to total capital | 4.5% | | 5.5% | | 7.2% | |
* | | Total capital includes long-term debt plus Ensco shareholders' equity. |
We have a $350.0 million unsecured revolving credit facility (the "Credit Facility") with a syndicate of banks. We had no amounts outstanding under the Credit Facility as of December 31, 2009, 2008 and 2007. We are currently in discussions with multiple banks regarding a new line of credit to replace the Credit Facility upon expiration in June 2010. In addition, we filed a Form S-3 Registration Statement with the SEC on January 13, 2009, which provides us 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 Investor's Service and BBB+ from Standard & Poor's Ratings Service.
As of December 31, 2009, we had an aggregate $125.5 million outstanding under two separate bond issues guaranteed by the United States of America, acting by and through the United States Department of Transportation, 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. See Note 4 to our consolidated financial statements for more information on our long-term debt.
The Board of Directors previously authorized the repurchase of up to $1,500.0 million of our shares. From inception of our share repurchase programs during 2006 through December 31, 2008, we repurchased an aggregate 16.5 million shares at a cost of $937.6 million (an average cost of $56.79 per share). No shares were repurchased under the share repurchase programs during 2009. In December 2009, in conjunction with the redomestication, the remaining repurchase authorization was extended authorizing management to repurchase up to $562.4 million of ADSs from time to time pursuant to share repurchase agreements with two investment banks. Although such amount remained available for repurchase as of December 31, 2009, the Company will not repurchase any shares without further consultation with and approval by the Board of Directors of Ensco& #160;plc.
Contractual Obligations
We have various contractual commitments related to our new rig construction agreements, long-term debt and operating leases. We expect to fund these commitments from our existing cash and cash equivalents and future operating cash flows. 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, 2009 and the periods in which such obligations are due (in millions):
| | Payments due by period | |
| | 2010 | 2011 and 2012 | 2013 and 2014 | After 2014 | Total |
| | | | | | | | | | | |
| New rig construction agreements | $482.4 | | $644.5 | | $ -- | | $ -- | | $1,126.9 | |
| Principal payments on long-term debt | 17.2 | | 34.4 | | 34.4 | | 189.5 | | 275.5 | |
| Interest payments on long-term debt | 17.7 | | 32.3 | | 28.3 | | 144.6 | | 222.9 | |
| Operating leases | 7.5 | | 5.6 | | 3.5 | | 5.7 | | 22.3 | |
| Total contractual obligations | $524.8 | | $716.8 | | $66.2 | | $339.8 | | $1,647.6 | |
Our contractual obligations table does not include $17.6 million of unrecognized tax benefits included on our consolidated balance sheet as of December 31, 2009. Substantially all of our unrecognized tax benefits relate 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 foreign currency forward contracts ("derivatives"). As of December 31, 2009, we had derivatives outstanding to exchange an aggregate $350.0 million U.S. dollars for various other currencies, including $216.6 million for Singapore dollars. As of December 31, 2009, our consolidated balance sheet included net derivative assets of $13.2 million. All of our outstanding derivatives mature during the next two years.
Liquidity
Our liquidity position as of December 31, 2009, 2008 and 2007 is summarized below (in millions, except ratios):
| | 2009 | 2008 | 2007 |
| | | | | | | |
| Cash and cash equivalents | $1,141.4 | | $789.6 | | $629.5 | |
| Working capital | 1,167.9 | | 973.0 | | 625.8 | |
| Current ratio | 3.4 | | 3.3 | | 2.2 | |
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, share repurchases or working capital requirements, from our cash and cash equivalents and operating cash flows. 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 flows and, if necessary, funds borrowed under our $350.0 million unsecured revolving credit facility or other future financing arrangements.
Based on our $1,141.4 million of cash and cash equivalents as of December 31, 2009 and our current contractual backlog of over $2,900.0 million, we believe our remaining $1,126.9 million of contractual obligations associated with the construction of our ENSCO 8500 Series® rigs will be funded from existing cash and cash equivalents and future operating cash flows. We may decide to access debt markets to raise additional capital or increase liquidity as necessary.
Effects of Climate Change and Climate Change Regulation
Greenhouse gas emissions have increasingly become the subject of international, national, regional, state and local attention. Cap and trade initiatives to limit greenhouse gas emissions have been introduced in the European Union. Similarly, numerous bills related to climate change have been introduced in the U.S. Congress, which could adversely impact all industries. In addition, future regulation of greenhouse gas could occur pursuant to future treaty obligations, statutory or regulatory changes or new climate change legislation in the jurisdictions in which we operate. It is uncertain whether any of these initiatives will be implemented, although, based on published media reports, we believe that it is not reasonably likely that the current proposed initiatives in the U.S. will be implemented without substantial modification. If su ch initiatives are implemented, because we typically operate offshore with relatively minimal greenhouse gas emissions, we do not believe that such initiatives would have a direct, material adverse effect on our operating costs.
Restrictions on greenhouse gas emissions could have an indirect effect in those industries that use significant amounts of petroleum products, which could potentially result in a reduction in demand for petroleum products and, consequently, our offshore contract drilling services. We are currently unable to predict the manner or extent of any such effect. Further, one of the long-term physical effects of climate change may be an increase in the severity and frequency of adverse weather conditions, such as hurricanes, which may increase our insurance costs or limit insurance availability or reduce the areas in which, or the number of days during which, our customers would contract for our drilling rigs. We are currently unable to predict the manner or extent of any such effect.
MARKET RISK
Derivative Instruments
We use derivatives to reduce our exposure to various market risks, primarily foreign currency exchange rate risk. Our functional currency is the U.S. dollar. As is customary in the oil and gas industry, a majority of our revenues are denominated in U.S. dollars, however, a portion of the expenses incurred by our non-U.S. subsidiaries are denominated in currencies other than the U.S. dollar ("foreign currencies"). We maintain a foreign currency exchange rate 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 derivative instruments to minimize or eliminate unanticipated fluctuations in earnings and cash flows arising from chang es in, and volatility of, interest rates.
We utilize derivatives to hedge forecasted foreign currency denominated transactions, primarily to reduce our exposure to foreign currency exchange rate risk associated with the portion of our remaining ENSCO 8500 Series® construction obligations denominated in Singapore dollars and contract drilling expenses denominated in various other currencies. As of December 31, 2009, $264.8 million of the aggregate remaining contractual obligations associated with our ENSCO 8500 Series® construction projects was denominated in Singapore dollars, of which $212.5 million was hedged through derivatives.
We have net assets and liabilities denominated in numerous foreign currencies and use various methods to manage our exposure to changes in foreign currency exchange rates. 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 derivatives, 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 utilize derivatives and undertake foreign currency exchange rate hedging activities in accordance with our established policies for the management of market risk. We minimize our credit risk relating to the counterparties of our derivatives by transacting with multiple, high-quality financial institutions, thereby limiting exposure to individual counterparties, and by monitoring the financial condition of our counterparties. We do not enter into derivatives for trading or other speculative purposes. We believe that our use of derivatives and related hedging activities reduces our exposure to foreign currency exchange rate risk and interest rate risk and does not expose us to material credit risk or any other material market risk.
As of December 31, 2009, we had derivatives outstanding to exchange an aggregate $350.0 million for various other currencies, including $216.6 million for Singapore dollars. 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 derivatives as of December 31, 2009 would approximate $27.9 million, including $20.9 million related to our Singapore dollar exposures. All of our derivatives mature during the next two years. See Note 5 to our consolidated financial statements for additional information on our derivative instruments.
Auction Rate Securities
We have generated a substantial cash balance, portions of which are invested in securities that meet our requirements for quality and return. Investment of our cash exposes us to market risk. We held $66.8 million (par value) of auction rate securities with a carrying value of $60.5 million as of December 31, 2009. 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. 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, 2009, 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 flows 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 unrealized losses on our auction rate securities as of December 31, 2009 would approximate $2.0 million. See Note 3 to our consolidated financial statements for additional information on our auction rate securities.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
The preparation of financial statements and related disclosures in conformity with GAAP requires our management to make estimates, judgments and assumptions that affect the amounts reported in our 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 acc ounting 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, 2009, the carrying value of our property and equipment totaled $4,477.3 million, which represented 66% 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 estimates, 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 useful lives of our property and equipment reflect both historical experience and expectations regarding future operations, utilization and pe rformance 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 asset carrying values 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 during 1998, when we extended the useful lives of our drilling rigs by an average of five to six years.
Our fleet of 42 jackup rigs represented 74% of the gross cost and 67% of the net carrying amount of our depreciable property and equipment as of December 31, 2009. Our jackup rigs are depreciated over useful lives ranging from 15 to 30 years. Our fleet of three ultra-deepwater semisubmersible rigs, exclusive of the ENSCO 8500 Series® rigs under construction, represented 21% of the gross cost and 30% of the net carrying amount of our depreciable property and equipment as of December 31, 2009. 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, 2009 for various assumed changes in the useful lives of our drilling rigs effective January 1 , 2009:
Increase (decrease) in useful lives of our drilling rigs | Estimated increase (decrease) in depreciation expense that would have been recognized (in millions) |
| | |
| 10% | $(21.7) |
| 20% | (36.7) |
| (10%) | 15.9 |
| (20%) | 41.9 |
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 day rates increase when 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 and ultra-deepwater semisubmersible rigs are suited for, and accessible to, broad and numerous markets throughout the world.
For property and equipment used in our operations, recoverability is generally determined by comparing the net carrying value of an asset to the expected undiscounted future cash flows of the asset. If the carrying value of an asset is not recoverable, the amount of impairment loss is measured as the difference between the net book value of the asset and its estimated fair value. The determination of expected undiscounted cash flow amounts requires significant estimates, judgments and assumptions, including utilization, day rates, expense levels and capital requirements, as well as cash flows generated upon disposition, for each of our drilling rigs. Due to the inherent uncertainties associated with these estimates, we perform sensitivity analysis on key assumptions as part of our recoverability test.
If the global economy deteriorates and/or other events or changes in circumstances indicate that the carrying value of one or more drilling rigs may not be recoverable, we will conclude that a triggering event has occurred and perform a recoverability test. If, at the time of the recoverability test, management's judgments and assumptions regarding future industry conditions and operations have diminished, it is reasonably possible that we could conclude that one or more of our drilling rigs are impaired.
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 each unit's fair value as of the testing date. Our four operating segments represent our reporting units. 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 the appropriate risk-adjusted discount rate, as well as future industry conditions and operations, including expected utilization, day rates, expense levels, capital requirements and terminal values for each of our rigs. Due to the inherent uncertainties associated with these estimates, we perform sensitivity analysis on key assumptions as part of our goodwill impairment test.
If the aggregate fair value of our reporting units exceeds our market capitalization, we evaluate the reasonableness of the implied control premium which includes a comparison to implied control premiums from recent market transactions within our industry or other relevant benchmark data. 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 and reduce the estimated fair values of our reporting units.
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 disposal. Based on our annual goodwill impairment test performed as of December 31, 2009, there was no impairment of goodwill.
If the global economy deteriorates and/or our expectations relative to future offshore drilling industry conditions decline, we may conclude that the fair value of one or more of our reporting units has more-likely-than-not declined below its carrying amount and perform an interim period goodwill impairment test. If, at the time of the goodwill impairment test, management's judgments and assumptions regarding future industry conditions and operations have diminished, or if the market value of our shares has declined, we could conclude that the goodwill of one or more of our reporting units has been impaired. It is reasonably possible that the judgments and assumptions inherent in our goodwill impairment test may change in response to future market conditions.
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 asset carrying values and operating results.
Income Taxes
We conduct operations and earn income in numerous countries and are subject to the laws of numerous tax jurisdictions. As of December 31, 2009, our consolidated balance sheet included a $347.6 million net deferred income tax liability, a $78.5 million liability for income taxes currently payable and a $17.6 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 and are based on management's estimates, judgments and assumptions regarding future operating results and levels of taxable income. Carryforwards and tax credits are assessed for realization as a reduction of future taxable income by using a more-likely-than-not determination.
We do not provide U.S. deferred income taxes on the undistributed earnings of Ensco Delaware's non-U.S. subsidiaries because it is our policy and intention to reinvest such earnings indefinitely.
The carrying values of liabilities for income taxes currently payable and unrecognized tax benefits are based on management's interpretation of applicable tax laws and incorporate management's 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.
We operate in many 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 occasionally 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 liabilities to increase, including the following:
| | • | The IRS and HMRC may disagree with our interpretation of tax laws, treaties, or regulations with respect to the redomestication. |
| | • | During recent years, the portion of our overall operations conducted in non-U.S. tax jurisdictions has increased, and we currently anticipate that this trend will continue. |
| | • | In order to utilize tax planning strategies and conduct 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 January 2010, the FASB issued Accounting Standards Update 2010-06, "Fair Value Measurements and Disclosures (Topic 820): Improving Disclosures about Fair Value Measurements" ("Update 2010-06"). Update 2010-06 provides amendments to Subtopic 820-10 that require new disclosures about recurring and non-recurring fair value measurements including significant transfers into and out of Level 1 and Level 2 and information on purchases, sales, issuances and settlements on a gross basis in the reconciliation of Level 3 fair value measurements. Furthermore, this update provides amendments to Subtopic 820-10 that clarify existing disclosures with respect to levels of disaggregation of assets and liabilities measured at fair value, in addition to disclosures of inputs and valuation techniques used to measure fair value. Update 2010-06 is effec tive for interim and annual reporting periods beginning after December 15, 2009, except for certain disclosures related to Level 3 inputs which become effective for interim and annual reporting periods beginning after December 15, 2010. We do not expect the adoption of Update 2010-06 to have a material effect on fair value measurement disclosures.
