exh99-2form8k10k2010.htm

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 13 to our consolidated financial statements, our consolidated financial statements for all periods presented herein have been updated to retrospectively reflect the reorganization of our reportable segments resulting from the merger transaction with Pride International, Inc. (the "Merger") completed on May 31, 2011, pursuant to which Pride International became an indirect, wholly-owned subsidiary of Ensco plc. This filing includes updates only to the portions of Item 1, Item 7 and Item 8 of the Form 10-K that specifically relate to the updated segment disclosures resulting from the Merger and reorganization 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 46 drilling rigs, including 40 jackup rigs, five ultra-deepwater semisubmersible rigs and one barge rig. Additionally, we have three ultra-deepwater semisubmersible rigs and two ultra-high specification harsh environment jackup rigs under construction. We are concentrated in premium jackup rigs, but are currently in the process of developing a fleet of ultra-deepwater semisubmersible rigs. 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 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.

In May 2010, the U.S. Department of the Interior implemented a six-month moratorium/suspension on certain drilling activities in water depths greater than 500 feet in the U.S. Gulf of Mexico. The U.S. Department of the Interior subsequently issued NTLs implementing additional safety and certification requirements applicable to drilling activities in the U.S. Gulf of Mexico, imposed additional requirements with respect to development and production activities in the U.S. Gulf of Mexico and has delayed the approval of applications to drill in both deepwater and shallow-water areas. On July 12, 2010, the U.S. Department of the Interior issued a revised moratorium/suspension on drilling in the U.S. Gulf of Mexico, which was lifted on October 12, 2010 after the adoption on September 30, 2010 of new regulations relating to the design of wells and testing of the integrity of wellbores, the use of drilling fluids, the functionality and testing of well control equipment, including third-party inspections, minimum requirements for personnel, blowout preventers and other safety regulations. It is uncertain what impact these new regulations may have upon our operations and our customers' ability to obtain new drilling permits.

As a condition to lifting of the moratorium/suspension, the Bureau of Ocean Energy Management, Regulation and Enforcement (the “BOEM”) was directed to require that each operator demonstrate that it has in place written and enforceable commitments that ensure that containment resources are available promptly in the event of a blowout and that the Chief Executive Officer of each operator certify to the BOEM that the operator has complied with applicable regulations. Before deepwater drilling is resumed, the BOEM intends to conduct inspections of each deepwater drilling operation for compliance with regulations, including but not limited to the testing of blowout preventers. It is unclear when these requirements will be satisfied, due in part to the limited staffing of the BOEM.

Certain of our drilling rigs currently in the U.S. Gulf of Mexico have been or may be further affected by the regulatory developments and other actions that have or may be imposed by the U.S. Department of the Interior, including the regulations issued on September 30, 2010. The moratoriums/suspensions (which have been lifted), related NTLs, delays in processing drilling permits and other actions are being challenged in litigation by Ensco and others. Utilization and day rates for certain of our drilling rigs have been negatively influenced due to regulatory requirements and delays in our customers’ ability to secure permits. Current or future NTLs or other directives and regulations may further impact our customers' ability to obtain permits and commence or continue deepwater or shallow-water operations in the U.S. Gulf of Mexico.

Operating results in our Deepwater segment improved during 2010, partially offset by lower utilization and day rates incurred as a result of the aforementioned regulatory developments and other actions imposed by the U.S. Department of the Interior. ENSCO 7500 operated in Australia at a day rate of approximately $550,000 for the majority of the year and currently is undergoing an enhancement project in order to commence drilling operations in Brazil under a two-and-a-half year contract during the third quarter of 2011. ENSCO 8500 and ENSCO 8501 continued to operate under their long-term contracts in the U.S. Gulf of Mexico. ENSCO 8502 was delivered in January 2010 and commenced drilling operations in the U.S. Gulf of Mexico under a short-term sublet agreement during the fourth quarter of 2010. ENSCO 8503 was delivered in September 2010 and is expected to commence drilling operations in French Guiana under a short-term sublet agreement during the first quarter of 2011. ENSCO 8502 and ENSCO 8503 are expected to commence drilling operations in the U.S. Gulf of Mexico under two-year contracts during 2011.

During 2010, we continued construction of ENSCO 8504, ENSCO 8505 and ENSCO 8506. These rigs currently are uncontracted and scheduled for delivery during the third quarter 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 $1,050.7 million of cash and cash equivalents as of December 31, 2010, and over $3,000.0 million of contract backlog will enable us to sustain an adequate level of liquidity during 2011 and beyond.

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. Although oil prices have stabilized and recently improved, incremental drilling activity during 2010 was limited resulting in continued softness in day rates for standard duty jackup rigs. Accordingly, our jackup rig operating results continued to decline from their 2009 levels due to a decline in day rates for our jackup rigs in all geographic regions.

In conjunction with our long-established strategy of high-grading our jackup rig fleet by investing in newer equipment, we sold three jackup rigs located in the Asia Pacific region and one jackup rig located in the U.S. Gulf of Mexico during 2010. In addition, we acquired an ultra-high specification jackup rig constructed in 2008. The rig was renamed ENSCO 109 and is currently operating in Australia.

In February 2011, we entered into agreements with KFELS to construct two ultra-high specification harsh environment jackup rigs. These rigs currently are uncontracted and scheduled for delivery during the first and second half of 2013, respectively.

Pending Merger with Pride

On February 6, 2011, Ensco plc entered into an Agreement and Plan of Merger with Pride International, Inc., a Delaware corporation (“Pride”), Ensco Delaware, and ENSCO Ventures LLC, a Delaware limited liability company and an indirect, wholly-owned subsidiary of Ensco (“Merger Sub”). Pursuant to the merger agreement and subject to the conditions set forth therein, Merger Sub will merge with and into Pride, with Pride as the surviving entity and an indirect, wholly-owned subsidiary of Ensco. As a result of the merger, each outstanding share of Pride’s common stock (other than shares of common stock held directly or indirectly by Ensco, Pride or any wholly-owned subsidiary of Ensco or Pride (which will be cancelled as a result of the merger), those shares with respect to which appraisal rights under Delaware law are properly exercised and not withdrawn and other shares held by certain U.K. residents if determined by Ensco) will be converted into the right to receive $15.60 in cash and 0.4778 Ensco ADSs. Under certain circumstances, U.K. residents may receive all cash consideration as a result of compliance with legal requirements.

We estimate that the total consideration to be delivered in the merger to be approximately $7,400.0 million, consisting of $2,800.0 million of cash, the delivery of approximately 86.0 million Ensco ADSs (assuming that no Pride employee stock options are exercised before the closing of the merger) with an aggregate value of $4,550.0 million based on the closing price of Ensco ADSs of $52.88 on February 15, 2011 and the estimated fair value of $45.0 million of Pride employee stock options assumed by Ensco. The value of the merger consideration will fluctuate based upon changes in the price of Ensco ADSs and the number of shares of Pride common stock and employee options outstanding on the closing date. The merger agreement and the merger were approved by the respective Boards of Directors of Ensco and Pride. Consummation of the merger is subject to the approval of the shareholders of Ensco and the stockholders of Pride, regulatory approvals and the satisfaction or waiver of various other conditions as more fully described in the merger agreement. Subject to receipt of required approvals, it is anticipated that the closing of the merger will occur during the second quarter of 2011.

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.

Depressed oil and natural gas prices and the deterioration of the global economy resulted in a modest decline in demand for ultra-deepwater semisubmersible rigs during 2009, however, global utilization and day rates generally were stable due to the long-term nature of deepwater projects. Demand for ultra-deepwater semisubmersible rigs in the U.S. Gulf of Mexico remained stable during the first half of 2010 but came under pressure as a result of delays in operators’ ability to secure permits due to regulatory developments and other actions imposed by the U.S. Department of the Interior. There is significant uncertainty as to the near-term impact the BP Macondo well incident and associated new regulatory, legislative or permitting requirements may have on deepwater drilling in the U.S. Gulf of Mexico, in addition to the potential impact on the global deepwater market.

Depressed oil and natural gas prices and the deterioration of the global economy led to an abrupt reduction in demand for jackup rigs during 2009. Although oil prices have stabilized and recently improved, incremental drilling activity during 2010 was limited resulting in continued softness in day rates for standard duty jackup rigs. We are encouraged by improving tender activity due to a modest increase in jackup rig demand for work in 2011 across various regions. However, it is uncertain as to the impact the BP Macondo well incident and associated new regulatory, legislative or permitting requirements may have on jackup rig demand in general, and in the U.S. Gulf of Mexico in particular.

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 170 new jackup and semisubmersible rigs, over 100 of which were delivered during the last three years.

Semisubmersible rig supply continues to increase as a result of newbuild construction programs. It has been reported that over 20 newbuild semisubmersible rigs are currently under construction, over half of which are scheduled for delivery during 2011. The majority of semisubmersible rigs scheduled for delivery are contracted. We expect newbuild semisubmersible rigs will be absorbed into the global market without a significant effect on utilization and day rates.

Jackup rig supply also continues to increase as a result of newbuild construction programs, the majority of which were initiated prior to the 2008 decline in oil and natural gas prices and the deterioration of the global economy. It has been reported that over 30 newbuild jackup rigs are currently under construction, over half of which are scheduled for delivery during 2011. The majority of jackup rigs scheduled for delivery are not contracted.

Newbuild jackup rigs may reduce utilization and day rates as rigs are absorbed into the fleet, especially in light of current levels of standard duty jackup rig demand. A significant portion of rig construction is occurring in the Asia Pacific region and it is time consuming and expensive to move drilling rigs between markets in response to changes in supply and demand. Accordingly, the supply of rigs in the Asia Pacific region, or other regions where newbuild rigs are delivered, may not adjust quickly which could lead to sudden changes in utilization and day rates. It is unlikely that the market in general or any geographic region in particular will be able to fully absorb newbuild jackup rig deliveries in the near-term, especially in consideration of the existing oversupply.

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.

BUSINESS ENVIRONMENT

Deepwater

During 2008, global demand for ultra-deepwater semisubmersible rigs exceeded supply resulting in high utilization levels and day rates. During 2009, lower oil and natural gas prices resulted in a modest decline in demand for ultra-deepwater semisubmersible rigs with utilization and day rates generally remaining stable due to the long-term nature of deepwater projects. Although utilization and day rates remained stable during the first half of 2010, a significant number of U.S. Gulf of Mexico deepwater projects have been delayed as a result of delays in operators' ability to secure permits. Certain well operations were permitted to continue under the moratorium/suspension, such as workovers and completions, forcing operators and contractors to pursue non-conventional, short-term programs. Most contractors have hesitated to abandon the substantial deepwater reservoir potential in the region, while continuing to monitor developments regarding permitting delays. Although a limited number of rigs have mobilized from the U.S. Gulf of Mexico to other regions, additional rigs are expected to exit the U.S. Gulf of Mexico in the near-term. Utilization and day rates could come under pressure if additional deepwater contracts in the U.S. Gulf of Mexico are terminated and/or those rigs are marketed in, or relocated to, other regions. Future ultra-deepwater semisubmersible rig utilization and day rates will depend, in large part, on projected oil and natural gas prices, the global economy and the near-term impact the BP Macondo well incident and associated new regulatory, legislative or permitting requirements may have on the U.S. Gulf of Mexico and global deepwater markets.

Jackup

There was substantial volatility in jackup rig demand during 2008. During the first half of the year, jackup rig demand remained strong due to record high oil and natural gas prices, resulting in high utilization levels and day rates. However, during the latter half of 2008, oil and natural gas prices declined substantially due primarily to a decrease in demand for oil and natural gas resulting from the deteriorating global economy. 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 have stabilized and recently improved, incremental drilling activity during 2010 was limited resulting in continued softness in day rates for standard duty jackup rigs. Given the deterioration of the global economy and tightening of credit markets, the jackup industry continues to face the challenge of excess rig supply. Therefore, we expect that jackup rig utilization and day rates may remain under pressure in the near-term.

During the first half of 2008, jackup rig utilization in the Asia Pacific Rim, including Vietnam, Malaysia, Indonesia and Australia, 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 in the region was significantly impacted by the decline in oil and natural gas prices and the deterioration of the global economy, resulting in a significant reduction in utilization and day rates during 2009. The Asia Pacific Rim jackup market began to stabilize during 2010 with incremental demand seen as multiple tenders were recently issued for work in 2011 and beyond. In consideration of an expected increase in the supply of available jackup rigs from newbuild deliveries, jackup rig utilization and day rates in the region may remain under pressure in the near-term.

During 2008, shortfalls in rig availability in the North Sea led to high utilization levels and day rates. Depressed oil and natural gas prices and the deterioration of the global economy resulted in several cancelled tenders and unexercised contract extension options in the region during the latter portion of 2009. Tender activity during 2010 was limited but with a recent increase seen in inquiries for work beginning in mid-2011 resulting from incremental demand. However, with limited tender activity for work beginning in early 2011 and an excess supply of standard duty jackup rigs, jackup rig utilization and day rates in the North Sea may remain under pressure in the near-term.

A significant portion of our jackup rig operations are conducted in Mexico, where demand for rigs increased during 2008 and 2009 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 2010, the number of jackup rigs contracted in Mexico declined as contracts expired. However, additional tender activity for work beginning in 2011 is expected in the near-term as PEMEX attempts to replenish its jackup rig fleet. We expect future day rates in Mexico to face pressure as jackup rig contracts in the region continue to expire and drilling contractors with idle rigs in the U.S. Gulf of Mexico and other geographic regions pursue the available contract opportunities.

We also conduct a portion of our jackup rig operations in the U.S. Gulf of Mexico. 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 the deterioration of the global economy. The U.S. Gulf of Mexico jackup rig market remained extremely weak during 2009, with drilling activity reaching historic lows. During early 2010, tender activity in the U.S. Gulf of Mexico improved as operators capitalized on cost-effective terms offered by drilling contractors. During the latter portion of 2010, certain operators experienced an inability to timely obtain drilling permits which negatively influenced utilization and day rates in the region. Due to the uncertainty regarding the impact the BP Macondo well incident and associated new regulatory, legislative or permitting requirements may have on jackup rig drilling operations in the region, U.S. Gulf of Mexico jackup rig utilization and day rates may remain under pressure 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, 2010 (in millions):

	2010			2009			2008

Revenues		$1,696.8			$1,888.9			$2,242.6
Operating expenses
Contract drilling (exclusive of depreciation)		768.1			709.0			736.3
Depreciation		216.3			189.5			172.6
General and administrative		86.1			64.0			53.8
Operating income		626.3			926.4			1,279.9
Other income (expense), net		18.2			8.8			(4.2	)
Provision for income taxes		96.0			180.0			222.4
Income from continuing operations		548.5			755.2			1,053.3
Income from discontinued operations, net		37.4			29.3			103.4
Net income		585.9			784.5			1,156.7
Net income attributable to noncontrolling interests		(6.4	)		(5.1	)		(5.9	)
Net income attributable to Ensco		$ 579.5			$ 779.4			$1,150.8

During 2010, revenues declined by $192.1 million, or 10%, and operating income declined by $300.1 million, or 32%, as compared to the prior year. These declines were primarily due to a decline in jackup rig utilization and average day rates in the Europe, Mediterranean and Asia Pacific Rim markets coupled with a decline in jackup rig average day rates in the North America market, partially offset by a significant increase in revenues and operating income generated by our deepwater rigs.

During 2009, revenues declined by $353.7 million, or 16%, and operating income declined by $353.5 million, or 28%, as compared to the prior year. These 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.

A significant number of our drilling contracts are of a long-term nature. Accordingly, a decline in demand for contract drilling services typically affects our operating results and cash flows gradually over many quarters as long-term contracts expire. The significant decline in oil and natural gas prices during the latter half of 2008 and the deterioration of the global economy resulted in a dramatic decline in demand for contract drilling services during 2009 and 2010, which is expected to continue to negatively impact our operating results during 2011.

Furthermore, the BP Macondo well incident and associated new regulatory, legislative or permitting requirements negatively influenced demand for contract drilling services in the U.S. Gulf of Mexico during 2010, which is expected to continue during 2011.

While we have contract backlog of over $1,300.0 million for 2011, it is uncertain whether revenue, operating income and cash flow levels achieved during 2010 will be sustained during 2011.

Rig Locations, Utilization and Average Day Rates

The following table summarizes our offshore drilling rigs by reportable segment and rigs under construction as of December 31, 2010, 2009 and 2008:

	2010	2009	2008

Deepwater(1)	5	3	2
Midwater(2)	--	--	--
Jackup(3)	40	39	39
Under construction(1)	3	5	6
Total(4)	48	47	47

(1)		ENSCO 8502 was delivered in January 2010 and commenced drilling operations in the U.S. Gulf of Mexico under a short-term sublet agreement during the fourth quarter of 2010. ENSCO 8503 was delivered in September 2010 and is expected to commence drilling operations in French Guiana under a short-term sublet agreement during the first quarter of 2011. ENSCO 8502 and ENSCO 8503 are expected to commence drilling operations in the U.S. Gulf of Mexico under two-year contracts during 2011. During 2009, we accepted delivery of ENSCO 8501, which commenced drilling operations in the U.S. Gulf of Mexico under a three-and-a-half year contract in October 2009.
(2)		In May 2011, midwater rigs were acquired in connection with the Merger. Therefore, our rig fleet did not consist of midwater rigs as of December 31, 2010, 2009 and 2008.

(3)		In July 2010, we acquired an ultra-high specification jackup rig. The rig was renamed ENSCO 109 and is currently operating offshore Australia.
(4)		The total number of rigs for each period excludes rigs reclassified to discontinued operations.

The following table summarizes our rig utilization and average day rates from continuing operations by reportable segment for each of the years in the three-year period ended December 31, 2010:

	2010	2009	2008

Rig utilization(1)
Deepwater	81%	85%	95%
Midwater(3)	N/A	N/A	N/A
Jackup(4)	77%	74%	96%
Total	77%	75%	96%
Average day rates(2)
Deepwater	$375,098	$425,190	$334,688
Midwater(3)	N/A	N/A	N/A
Jackup(4)	106,007	151,636	152,418
Total	$128,784	$163,568	$155,767

(1)		Rig utilization is derived by dividing the number of days under contract by the number of days in the period. Days under contract equals the total number of days that rigs have earned a day rate, including days associated with compensated downtime and mobilizations. For newly constructed or acquired rigs, the number of days in the period begins upon commencement of drilling operations for rigs with a contract or when the rig becomes available for drilling operations for rigs without a contract.
(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 were not applicable for the Midwater segment as our rig fleet did not consist of midwater rigs during each of the years in the three-year period ended December 31, 2010.
(4)		ENSCO 69 has been excluded from rig utilization and average day rates for our Jackup operating segment during the period the rig was controlled and operated by Petrosucre, a subsidiary of Petróleos de Venezuela S.A., the national oil company of Venezuela (January 2009 - August 2010). See Note 11 to our consolidated financial statements for additional information on ENSCO 69.

Detailed explanations of our operating results, including discussions of revenues, contract drilling expense and depreciation expense by segment, are provided below.

Operating Income

In connection with the Merger and resulting management reorganization, we evaluated our then-current core assets and operations and organized them into three segments based on water depth operating capabilities. Accordingly, we now consider our business to consist of three reportable segments: (1) Deepwater, which consists of our rigs capable of drilling in water depths of 4,500 feet or greater, (2) Midwater, which consists of our semisubmersible rigs capable of drilling in water depths of 4,499 feet or less and (3) Jackup, which consists of our jackup rigs capable of operating in water depths up to 400 feet. Each of our three reportable segments provides one service, contract drilling. We also own one barge rig, which is included in “Other.”

As a result of our reorganization to three reportable segments, we retrospectively reclassified the segment information included herein to conform to the post-Merger presentation. The following tables summarize our operating income for each of the years in the three-year period ended December 31, 2010 (in millions). 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, 2010


					Operating
					Segments	Reconciling	Consolidated
	Deepwater	Midwater	Jackup	Other	Total	Items	Total

Revenues	$475.2	$ --	$1,221.6	$ --	$1,696.8	$ --	$1,696.8
Operating expenses Contract drilling (exclusive of depreciation)	176.1	--	578.2	13.8	768.1	--	768.1
Depreciation	44.8	--	167.8	2.4	215.0	1.3	216.3
General and administrative	--	--	--	--	--	86.1	86.1
Operating income (loss)	$254.3	$ --	$ 475.6	$(16.2)	$ 713.7	$(87.4)	$ 626.3

Year Ended December 31, 2009


					Operating
					Segments	Reconciling	Consolidated
	Deepwater	Midwater	Jackup	Other	Total	Items	Total

Revenues	$254.1	$ --	$1,634.8	$ --	$1,888.9	$ --	$1,888.9
Operating expenses Contract drilling (exclusive of depreciation)	108.1	--	599.0	1.9	709.0	--	709.0
Depreciation	22.2	--	162.9	3.1	188.2	1.3	189.5
General and administrative	--	--	--	--	--	64.0	64.0
Operating income (loss)	$123.8	$ --	$ 872.9	$ (5.0)	$ 991.7	$(65.3)	$ 926.4

Year Ended December 31, 2008


					Operating
					Segments	Reconciling	Consolidated
	Deepwater	Midwater	Jackup	Other	Total	Items	Total

Revenues	$ 84.4	$ --	$2,144.0	$ 14.2	$2,242.6	$ --	$2,242.6
Operating expenses Contract drilling (exclusive of depreciation)	31.2	--	696.5	8.6	736.3	--	736.3
Depreciation	9.1	--	158.3	3.3	170.7	1.9	172.6
General and administrative	--	--	--	--	--	53.8	53.8
Operating income (loss)	$ 44.1	$ --	$1,289.2	$ 2.3	$1,335.6	$(55.7)	$1,279.9

Deepwater

During 2010, Deepwater revenues increased by $221.1 million, or 87%, as compared to the prior year. The increase in revenues was due to revenues earned by ENSCO 8500, ENSCO 8501 and ENSCO 8502 which were added to our Deepwater fleet and commenced drilling operations during the second and fourth quarters of 2009 and the third quarter of 2010, respectively, and due to additional revenues earned by ENSCO 7500 associated with the demobilization of the rig to Singapore. The increase in revenues was partially offset by lower utilization and day rates incurred by ENSCO 8500, ENSCO 8501 and ENSCO 8502 as a result of the aforementioned regulatory developments and other actions imposed by the U.S. Department of the Interior in the U.S. Gulf of Mexico. Contract drilling expense increased by $68.0 million, or 63%, and depreciation expense increased by $22.6 million due to the commencement of ENSCO 8500, ENSCO 8501 and ENSCO 8502 drilling operations as previously noted.

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 recognized ratably over the firm commitment period of the contract. The increase in revenues was partially offset by the deferral of ENSCO 7500 revenues during the rig's mobilization to Australia during 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 U.S. Gulf of Mexico. Depreciation expense increased by $13.1 million, primarily due to the addition of ENSCO 8500 and ENSCO 8501 to our Deepwater fleet as noted above.

Midwater

In connection with the Merger, we acquired six midwater rigs. Prior to the Merger Date, our rig fleet did not consist of midwater rigs.

Jackup

During 2010, Jackup revenues declined by $413.2 million, or 25%, as compared to the prior year. The decline in revenues was primarily due to a 30% decline in average day rates due to lower levels of spending by oil and gas companies across all regions, partially offset by an increase in utilization to 77% from 74% during the prior year. The increase in utilization primarily resulted from the reduced supply of available jackup rigs in the U.S. Gulf of Mexico, including the mobilization of four of our jackup rigs to Mexico during 2009, and lower market day rates in the region. Contract drilling expense declined by $20.8 million, or 3%, as compared to the prior year, primarily due to a $17.3 million loss recorded on the disposal of ENSCO 69 during 2009 and a current year decline in repair and maintenance expense and personnel costs, partially offset by an $11.9 million reduction of our allowance for doubtful accounts during 2009 which was recorded during 2008 and related to ENSCO 69 drilling operations. Depreciation expense increased by 3% as compared to the prior year, primarily due to additions to our jackup fleet and depreciation on minor upgrades and improvements to our jackup fleet during 2010.

During 2009, Jackup revenues declined by $509.2 million, or 24%, as compared to the prior year. The decline in revenues was primarily due to a decline in utilization to 74% from 96% during the prior year. The decline in utilization occurred due to lower levels of spending by oil and gas companies and excess rig availability across all regions. Contract drilling expense declined by $97.5 million, or 62%, as compared to the prior year, primarily due to the impact of lower utilization across all regions and a decline in repair and maintenance expense and an $11.9 million reduction of our allowance for doubtful accounts as noted above, partially offset by a $17.3 million loss recorded on the disposal of ENSCO 69. Depreciation expense increased by 3% as compared to the prior year, primarily due to capital enhancement projects completed during 2009 and depreciation on minor upgrades and improvements to our jackup fleet completed during 2008 and 2009.

Other

Revenues, contract drilling expense and depreciation expense for each of the years in the three-year period ended December 31, 2010 were attributable to ENSCO I, our only barge rig. ENSCO I completed its then-current drilling contract in 2008 and subsequently cold-stacked in Singapore. During 2010, contract drilling expense included a $12.2 million loss on impairment of ENSCO I.

Reconciling Items

During 2010, general and administrative expense increased by $22.1 million, or 35%, as compared to the prior year. This increase was primarily due to increased share-based compensation expense, costs related to operating our new London headquarters and professional fees incurred in connection with various reorganization efforts undertaken as a result of our redomestication to the U.K. in December 2009.

During 2009, general and administrative expense increased by $10.2 million, or 19%, as compared to the prior year. The increase was primarily due to $7.6 million of professional fees incurred in connection with our redomestication to the U.K. in December 2009 and a $1.9 million expense incurred in connection with a separation agreement with our former Senior Vice President of Operations.

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, 2010 (in millions):

	2010			2009			2008

Interest income		$ .7			$ 2.2			$ 14.0
Interest expense, net:
Interest expense		(21.3	)		(20.9	)		(21.6	)
Capitalized interest		21.3			20.9			21.6
		--			--			--
Other, net		17.5			6.6			(18.2	)
		$ 18.2			$ 8.8			$ (4.2	)

During 2010 and 2009, interest income declined as compared to the respective prior years due to lower average interest rates. Interest expense increased during 2010 as compared to the prior year due to an increase in the amortization of deferred financing fees associated with the renewal of our revolving credit facility, partially offset by a decline in outstanding debt. Interest expense declined during 2009 as compared to the prior year due to a decline in outstanding debt. All interest expense incurred during each of the years in three-year period ended December 31, 2010 was capitalized in connection with the construction of our ENSCO 8500 Series® rigs.

Our functional currency is the U.S. dollar, and a portion of the revenues earned and expenses incurred by some of our 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 net foreign currency exchange gains of $3.5 million and $2.6 million and net foreign currency exchange losses of $10.4 million during 2010, 2009 and 2008, respectively.

During 2010, we recognized a gain of $10.1 million, net of related expenses, for a break-up fee resulting from our unsuccessful tender offer for Scorpion Offshore Ltd. The net gain was included in other, net, for the year ended December 31, 2010.

Other, net, also included net unrealized gains of $700,000 and $1.8 million and net unrealized losses of $8.1 million associated with the fair value measurement of our auction rate securities during 2010, 2009 and 2008, respectively. The fair value measurement of our auction rate securities is discussed in Note 8 to our consolidated financial statements.

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. Our drilling rigs frequently move from one taxing jurisdiction to another to perform contract drilling services. In some instances, the movement of drilling rigs among taxing jurisdictions will involve the transfer of ownership of the drilling rigs among our subsidiaries. As a result of the frequent changes in taxing jurisdictions in which our drilling rigs are operated and/or owned, 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.

Subsequent to our redomestication to the U.K. in December 2009, we reorganized our worldwide operations, which included, among other things, the transfer of ownership of several of our drilling rigs among our subsidiaries.

Income tax expense was $96.0 million, $180.0 million and $222.4 million and our consolidated effective income tax rate was 14.9%, 19.2% and 17.4% during the years ended December 31, 2010, 2009 and 2008, respectively. The decline in our 2010 consolidated effective income tax rate to 14.9% from 19.2% in the prior year was primarily due to the aforementioned transfer of drilling rig ownership in connection with the reorganization of our worldwide operations, which resulted in an increase in the relative components of our earnings generated in tax jurisdictions with lower tax rates, and an $8.8 million non-recurring current income tax expense incurred during 2009 in connection with certain restructuring activities undertaken immediately following our redomestication to the U.K. The increase in our 2009 consolidated effective income tax rate to 19.2% from 17.4% in the prior year was primarily related to the aforementioned non-recurring current income tax expense incurred during 2009. Excluding the impact from this non-recurring item, our 2009 consolidated effective income tax rate was 18.3%.

Discontinued Operations

Rig Sales

In recent years, we have focused on the expansion of our ultra-deepwater semisubmersible rig fleet and high-grading our premium jackup fleet. Accordingly, we sold jackup rig ENSCO 60 in November 2010 for $25.7 million and recognized a pre-tax gain of $5.7 million, which was included in gain on disposal of discontinued operations, net, in our consolidated statement of income for the year ended December 31, 2010. The rig’s net book value and inventory and other assets on the date of sale totaled $20.0 million. ENSCO 60 operating results were reclassified to discontinued operations in our consolidated statements of income for each of the years in the three-year period ended December 31, 2010 and previously were included within our Jackup operating segment.

In April 2010, we sold jackup rig ENSCO 57 for $47.1 million, of which a deposit of $4.7 million was received in December 2009. We recognized a pre-tax gain of $17.9 million in connection with the disposal of ENSCO 57, which was included in gain on disposal of discontinued operations, net, in our consolidated statement of income for the year ended December 31, 2010. The rig’s net book value and inventory and other assets on the date of sale totaled $29.2 million. ENSCO 57 operating results were reclassified to discontinued operations in our consolidated statements of income for each of the years in the three-year period ended December 31, 2010 and previously were included within our Jackup operating segment.

In March 2010, we sold jackup rigs ENSCO 50 and ENSCO 51 for an aggregate $94.7 million, of which a deposit of $4.7 million was received in December 2009. We recognized an aggregate pre-tax gain of $33.9 million in connection with the disposals of ENSCO 50 and ENSCO 51, which was included in gain on disposal of discontinued operations, net, in our consolidated statement of income for the year ended December 31, 2010. The two rigs' aggregate net book value and inventory and other assets on the date of sale totaled $60.8 million. ENSCO 50 and ENSCO 51 operating results were reclassified to discontinued operations in our consolidated statements of income for each of the years in the three-year period ended December 31, 2010 and previously were included within our Jackup operating segment.

ENSCO 69

From May 2007 to June 2009, ENSCO 69 was contracted to Petrosucre. 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. In June 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 nationalization of certain assets owned by other 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 2009 and reclassified its operating results to discontinued operations.

On August 24, 2010, possession of ENSCO 69 was returned to Ensco. Due to the return of ENSCO 69 from Petrosucre and our ability to significantly influence the future operations of the rig and to incur significant future cash flows related to those operations until the pending insurance claim is resolved and possibly thereafter, ENSCO 69 operating results were reclassified to continuing operations for each of the years in the three-year period ended December 31, 2010.

There can be no assurances relative to the recovery of outstanding contract entitlements, insurance recovery and related pending litigation or the imposition of customs duties in relation to the rig's recent presence in Venezuela. See Note 12 to our consolidated financial statements for additional information on contractual matters, insurance and legal proceedings related to ENSCO 69.

ENSCO 74

In September 2008, ENSCO 74 was destroyed as a result of Hurricane Ike and the rig was a total loss, as defined under the terms of our insurance policies. The operating results of ENSCO 74 were reclassified to discontinued operations in our consolidated statement of income for the year ended December 31, 2008. See Note 12 to our consolidated financial statements for additional information on the loss of ENSCO 74 and associated contingencies.

The following table summarizes income from discontinued operations for each of the years in the three-year period ended December 31, 2010 (in millions):

	2010		2009		2008

Revenues	$12.5		$83.0		$244.0
Operating expenses	17.1		54.2		89.3
Operating (loss) income before income taxes	(4.6	)	28.8		154.7
Income tax (benefit) expense	(3.4	)	(.5	)	27.8
Gain (loss) on disposal of discontinued operations, net	38.6		--		(23.5	)
Income from discontinued operations	$37.4		$29.3		$103.4

Fair Value Measurements

Auction Rate Securities

Our auction rate securities were measured at fair value as of December 31, 2010 and 2009 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, 2010 and, accordingly, we concluded that Level 1 inputs were not available. 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, 2010. 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, 2010 was appropriate.

Based on the results of our fair value measurements, we recognized net unrealized gains of $700,000 and $1.8 million and net unrealized losses of $8.1 million for the years ended December 31, 2010, 2009 and 2008, respectively, 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 $44.5 million and $60.5 million as of December 31, 2010 and 2009, respectively. We anticipate realizing the $50.1 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 53% of our assets measured at fair value on a recurring basis and less than 1% of our total assets as of December 31, 2010. See Note 8 to our consolidated financial statements for additional information on our fair value measurements.

ENSCO I Impairment

In June 2010, we recorded a $12.2 million loss from the impairment of ENSCO I, the only barge rig in our fleet, which is currently cold-stacked in Singapore and is included in our "Other" operating segment. The loss on impairment was included in contract drilling expense in our consolidated statement of income for the year ended December 31, 2010. The impairment resulted from the adjustment of the rig’s carrying value to its estimated fair value based on a change in our expectation that it is more-likely-than-not that the rig will be disposed of significantly before the end of its estimated useful life. ENSCO I was not classified as held-for-sale as of December 31, 2010, as a sale was not deemed probable of occurring within the next twelve months.

We utilized an income approach valuation model to estimate the price that would be received in exchange for the rig in an orderly transaction between market participants as of June 30, 2010. The resulting exit price was derived as the present value of expected cash flows from the use and eventual disposition of the rig, using a risk-adjusted discount rate. Level 3 inputs were significant to the overall fair value measurement of ENSCO I, due to the limited availability of observable market data for similar assets. We reviewed those inputs, evaluated the results and performed sensitivity analysis on key assumptions. Based on our review, we concluded that the fair value measurement of ENSCO I as of June 30, 2010 was appropriate.

The estimated fair value of ENSCO I using significant Level 3 inputs constituted less than 1% of our total assets as of December 31, 2010. 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 2010, our cash flows from operations were negatively influenced by the BP Macondo well incident and associated new regulatory, legislative or permitting requirements, which is expected to continue during 2011. However, based on $1,050.7 million of cash and cash equivalents on hand as of December 31, 2010 and our current contractual backlog of over $3,000.0 million, we believe our future operations and obligations associated with our newbuild construction will be funded from existing cash and cash equivalents and future operating cash flow.

On February 6, 2011, we entered into a definitive merger agreement with Pride. The merger is expected to close during the second quarter of 2011 and will be financed through a combination of existing cash and cash equivalents, an unsecured bridge term loan facility, potential issuances of debt securities, funds borrowed under our credit facility or other future financing arrangements. Total consideration to be paid to Pride shareholders will be approximately $2,800.0 million of cash and the delivery of approximately 86.0 million Ensco ADSs. Given the number of rigs under construction by both Ensco and Pride, it is contemplated that subsequent to closing of the merger, our cash flows initially will be dedicated to finance newbuild rigs.

During the three-year period ended December 31, 2010, our primary source of cash was an aggregate $3,017.0 million generated from operating activities of continuing operations and $167.5 million of proceeds from the sale of four jackup rigs. Our primary uses of cash during the same period included an aggregate $2,496.7 million for the construction, enhancement and other improvement of our drilling rigs, including $1,842.4 million invested in the construction of our ENSCO 8500 Series® rigs, $272.2 million for the repurchase of our shares, $186.0 million for the acquisition of an ultra-high specification jackup rig and accompanying inventory and $182.2 million for the payment of dividends.

Detailed explanations of our liquidity and capital resources for each of the years in the three-year period ended December 31, 2010 are set forth below.

Cash Flows and Capital Expenditures

Our cash flows from operating activities of continuing operations and capital expenditures on continuing operations for each of the years in the three-year period ended December 31, 2010 were as follows (in millions):

	2010	2009	2008

Cash flows from operating activities of continuing operations	$816.7	$1,185.6	$1,014.7

Capital expenditures on continuing operations:
New rig construction	$567.5	$ 623.4	$ 651.5
Rig acquisition	184.2	--	--
Minor upgrades and improvements	87.3	80.8	79.0
Rig enhancements	36.3	153.0	33.7
	$875.3	$ 857.2	$ 764.2

During 2010, cash flows from continuing operations decreased by $368.9 million, or 31%, as compared to the prior year. The decrease resulted primarily from a $329.0 million decline in cash receipts from contract drilling services and a $44.4 million increase in cash payments related to contract drilling expenses.

During 2009, cash flows from continuing operations increased by $170.9 million, or 17%, as compared to the prior year. The increase resulted primarily from a $186.4 million decline in tax payments and a $77.8 million decline in our investment in trading securities offset by a $90.2 million decline in cash receipts from contract drilling services and an $11.0 million decline in cash received from interest income.

We continue to expand the size and quality of our drilling rig fleet. During the three-year period ended December 31, 2010, we invested $1,842.4 million in the construction of new drilling rigs and an additional $223.0 million upgrading the capability and extending the useful lives of our existing fleet. ENSCO 8500 and ENSCO 8501 were delivered in 2008 and 2009, respectively, and commenced drilling operations in the U.S. Gulf of Mexico under long-term contracts during 2009. ENSCO 8502 was delivered in January 2010 and commenced drilling operations in the U.S. Gulf of Mexico under a short-term sublet agreement during the fourth quarter of 2010. ENSCO 8503 was delivered in September 2010 and is expected to commence drilling operations in French Guiana under a short-term sublet agreement during the first quarter of 2011. ENSCO 8502 and ENSCO 8503 are expected to commence drilling operations in the U.S. Gulf of Mexico under two-year contracts during 2011.

We also have three uncontracted ENSCO 8500 Series® ultra-deepwater semisubmersible rigs under construction with scheduled delivery dates during the third quarter of 2011 and the first and second half of 2012. Our ENSCO 7500 ultra-deepwater semisubmersible rig currently is undergoing an enhancement project in a shipyard in Singapore and is expected to commence drilling operations in Brazil under a two-and-a-half year contract during the third quarter of 2011.

In conjunction with our long-established strategy of high-grading our jackup rig fleet by investing in newer equipment, we sold three jackup rigs located in the Asia Pacific region and one jackup rig located in the North and South America region during 2010 for an aggregate $167.5 million in cash. In addition, we acquired an ultra-high specification jackup rig and accompanying inventory during 2010 with available cash for $186.0 million. The rig, renamed ENSCO 109, was constructed in 2008 and is currently operating in Australia.

In February 2011, we entered into agreements with KFELS to construct two ultra-high specification harsh environment jackup rigs for estimated total construction costs of approximately $230.0 million per rig. These rigs currently are uncontracted and scheduled for delivery during the first and second half of 2013, respectively.

Based on our current projections, notwithstanding the proposed merger with Pride, we expect capital expenditures during 2011 to include approximately $190.0 million for construction of our ENSCO 8500 Series® rigs, approximately $95.0 million for construction of two ultra-high specification harsh environment jackup 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, 2010, 2009 and 2008 are summarized below (in millions, except percentages):

	2010	2009	2008

Long-term debt	$ 240.1	$ 257.2	$ 274.3
Total capital*	6,199.6	5,756.4	4,951.2
Long-term debt to total capital	3.9%	4.5%	5.5%

Total capital includes long-term debt plus Ensco shareholders' equity.

On February 6, 2011, we entered into a bridge commitment letter (the “Commitment Letter”) with Deutsche Bank AG Cayman Islands Branch (“DBCI”), Deutsche Bank Securities Inc. and Citigroup Global Markets Inc. (“Citi”). Pursuant to the Commitment Letter, DBCI and Citi have committed to provide a $2,750.0 million unsecured bridge term loan facility (the “Bridge Term Facility”) to fund a portion of the cash consideration in the merger with Pride. The Bridge Term Facility would mature 364 days after closing. The commitment is subject to various conditions, including the absence of a material adverse effect on Pride or Ensco having occurred, the maintenance by us of investment grade credit ratings, the execution of satisfactory documentation and other customary closing conditions.

On May 28, 2010, we entered into an amended and restated agreement (the "2010 Credit Facility") with a syndicate of banks that provides for a $700.0 million unsecured revolving credit facility for general corporate purposes. The 2010 Credit Facility has a four-year term, expiring in May 2014, and replaces our $350.0 million five-year credit agreement which was scheduled to mature in June 2010. Advances under the 2010 Credit Facility generally bear interest at LIBOR plus an applicable margin rate (currently 2.0% per annum), depending on our credit rating. We are required to pay an annual undrawn facility fee (currently .25% per annum) on the total $700.0 million commitment, which is also based on our credit rating. We also are required to maintain a debt to total capitalization ratio less than or equal to 50% under the 2010 Credit Facility. We have the right, subject to lender consent, to increase the commitments under the 2010 Credit Facility up to $850.0 million. We had no amounts outstanding under the 2010 Credit Facility or the prior credit agreement as of December 31, 2010, 2009 and 2008.

We filed a Form S-3 Registration Statement with the SEC in January 2009, which provides us the ability to issue debt and/or equity securities in one or more offerings. The registration statement was immediately effective and expires in January 2012.

As of December 31, 2010, we had an aggregate $108.4 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, 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 of Ensco Delaware previously authorized the repurchase of up to $1,500.0 million of our ADSs, representing our Class A ordinary shares. In December 2009, the then-Board of Directors of Ensco International Limited, a predecessor of Ensco plc, continued the prior authorization and, subject to shareholder approval, authorized management to repurchase up to $562.4 million of ADSs from time to time pursuant to share repurchase agreements with two investment banks. The then-sole shareholder of Ensco International Limited approved such share repurchase agreements for a five-year term. 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 the years ended December 31, 2010 and 2009. Although $562.4 million remained available for repurchase as of December 31, 2010, we will not repurchase any shares under our share repurchase program without further consultation with and approval by the Board of Directors of Ensco 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. Notwithstanding the proposed merger with Pride, the table below summarizes our significant contractual obligations as of December 31, 2010 and the periods in which such obligations are due (in millions):

	Payments due by period
		2012	2014
		and	and	After
	2011	2013	2015	2015	Total

New rig construction agreements(1)	$ 435.6	$223.9	$ --	$ --	$ 659.5
Principal payments on long-term debt	17.2	34.4	34.4	172.4	258.4
Interest payments on long-term debt	16.7	30.3	26.2	131.5	204.7
Operating leases	8.2	6.3	4.2	5.3	24.0
Total contractual obligations(2)(3)	$477.7	$294.9	$64.8	$309.2	$1,146.6

(1)

In February 2011, we entered into agreements to construct two ultra-high specification harsh environment jackup rigs. The amounts disclosed above exclude construction obligations of $87.6 million for 2011 and $350.2 million for 2013 related to these rigs.

In connection with the aforementioned agreements to construct two new jackup rigs, we agreed with the shipyard contractor to defer $340.0 million of contractual commitments due during 2011 related to the construction of ENSCO 8505 and ENSCO 8506 until the rigs are delivered during the first and second half of 2012, respectively. The amounts disclosed above exclude the aforementioned deferral of contractual commitments.

(2)

Contractual obligations do not include $13.7 million of unrecognized tax benefits included on our consolidated balance sheet as of December 31, 2010. 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.

(3)

Contractual obligations do not include foreign currency forward contracts ("derivatives"). As of December 31, 2010, we had derivatives outstanding to exchange an aggregate $239.9 million U.S. dollars for various foreign currencies, including $121.0 million for Singapore dollars. As of December 31, 2010, our consolidated balance sheet included net derivative assets of $16.4 million. All of our outstanding derivatives mature during the next 18 months.

Liquidity

Our liquidity position as of December 31, 2010, 2009 and 2008 is summarized below (in millions, except ratios):

	2010	2009	2008

Cash and cash equivalents	$1,050.7	$1,141.4	$789.6
Working capital	1,087.7	1,167.9	973.0
Current ratio	4.1	3.4	3.3

We expect to fund our short-term liquidity needs, including approximately $555.0 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 credit facility or other future financing arrangements.

Based on our $1,050.7 million of cash and cash equivalents as of December 31, 2010 and our current contractual backlog of over $3,000.0 million, we believe our $1,097.3 million of contractual obligations associated with the construction of our ENSCO 8500 Series® rigs and two ultra-high specification harsh environment jackup rigs will be funded from existing cash and cash equivalents and future operating cash flow. We may decide to access debt markets to raise additional capital or increase liquidity as necessary.

We expect to fund the proposed merger with Pride from cash and cash equivalents, the Bridge Term Facility and potentially funds borrowed under our credit facility or other future financing arrangements. In addition, we intend to use such internal cash resources and financing as well as cash and cash equivalents of Pride following the merger to pay advisory, legal, valuation and other professional fees incurred by both Ensco and Pride of approximately $69.0 million, ADS issuance costs of approximately $70.0 million, debt issuance costs of approximately $20.0 million, as well as change in control severance for certain Pride employees of approximately $33.0 million. Upon completion of the proposed merger, we will increase our indebtedness, which will include acquisition debt financing of approximately $2,800.0 million and approximately $1,860.0 million of Pride’s debt obligations will remain outstanding after the merger. In addition, various commitments and contractual obligations in connection with Pride’s normal course of business will remain outstanding after the merger, including obligations associated with Pride’s newbuild program of approximately $1,320.0 million.

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 most 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. However, 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 such initiatives are implemented, we do not believe that such initiatives would have a direct, material adverse effect on our operating results.

Restrictions on greenhouse gas emissions or other related legislative or regulatory enactments 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. Furthermore, 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 risk retention, limit insurance availability or reduce the areas in which, or the number of days during which, our customers would contract for our drilling rigs in general and in the Gulf of Mexico in particular. We are currently unable to predict the manner or extent of any such effect.

MARKET RISK

Derivatives

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 some of our subsidiaries are denominated in currencies other than the U.S. dollar. 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 changes 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 foreign currencies. As of December 31, 2010, $172.7 million of the aggregate remaining contractual obligations associated with our ENSCO 8500 Series® construction projects was denominated in Singapore dollars, of which $115.8 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, 2010, we had derivatives outstanding to exchange an aggregate $239.9 million for various foreign currencies, including $121.0 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, 2010 would approximate $21.8 million, including $11.8 million related to our Singapore dollar exposures. A portion of these unrealized losses generally would be offset by corresponding gains on certain underlying expected future transactions being hedged. All of our derivatives mature during the next 18 months. 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 $50.1 million (par value) of auction rate securities with a carrying value of $44.5 million as of December 31, 2010. 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, 2010, 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. The resulting 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 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 risk-adjusted discount rate and a 10% adverse change in the periods of illiquidity, the additional net unrealized losses on our auction rate securities as of December 31, 2010 would approximate $1.2 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 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, 2010, the carrying value of our property and equipment totaled $5,049.9 million, which represented 72% 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 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 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 40 jackup rigs represented 68% of the gross cost and 59% of the net carrying amount of our depreciable property and equipment as of December 31, 2010. Our jackup rigs are depreciated over useful lives ranging from 15 to 30 years. Our fleet of five ultra-deepwater semisubmersible rigs, exclusive of the ENSCO 8500 Series® rigs under construction, represented 28% of the gross cost and 38% of the net carrying amount of our depreciable property and equipment as of December 31, 2010. 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, 2010 for various assumed changes in the useful lives of our drilling rigs effective January 1, 2010:

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

10%		$(29.3)
20%		(46.2)
(10%)		13.1
(20%)		42.5

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 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 carrying 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 three reportable 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, 2010, there was no impairment of goodwill, and none of our reporting units were determined to be at risk of a goodwill impairment in the near-term under the current circumstances.

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, 2010, our consolidated balance sheet included a $348.7 million net deferred income tax liability, an $11.9 million liability for income taxes currently payable and a $13.7 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 deferred taxes on the undistributed earnings of our U.S. subsidiary and predecessor, Ensco Delaware, because our policy and intention is to reinvest such earnings indefinitely or until such time that they can be distributed in a tax-free manner. We do not provide deferred taxes on the undistributed earnings of Ensco Delaware's non-U.S. subsidiaries because our policy and intention is 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 number of tax jurisdictions in which we conduct operations 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 December 2010, the FASB issued Accounting Standards Update 2010-28, "Intangibles – Goodwill and Other (Topic 350): When to Perform Step 2 of the Goodwill Impairment Test for Reporting Units with Zero or Negative Carrying Amounts" ("Update 2010-28"). Update 2010-28 provides amendments to Topic 350 that modify Step 1 of the goodwill impairment test for reporting units with zero or negative carrying amounts by establishing a requirement that Step 2 of the goodwill impairment test be performed for those reporting units if it is more-likely-than-not that a goodwill impairment exists. Update 2010-28 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2010. We do not expect the adoption of Update 2010-28 to have a material effect on our future goodwill impairment tests.

In December 2010, the FASB issued Accounting Standards Update 2010-29, "Business Combinations (Topic 805): Disclosure of Supplementary Pro Forma Information for Business Combinations" ("Update 2010-29"). Update 2010-29 provides amendments to Topic 805 that specify that if a public entity presents comparative financial statements, the entity should disclose revenue and earnings of the combined entity as though the business combination(s) that occurred during the current year had occurred as of the beginning of the comparable prior annual reporting period only. Furthermore, this update provides amendments to Topic 805 that expand the supplemental pro forma disclosures to include a description of the nature and amount of material, nonrecurring pro forma adjustments directly attributable to the business combination included in the reported pro forma revenue and earnings. Update 2010-29 is effective prospectively for business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2010. We expect the effect of adoption of Update 2010-29 to be limited to pro forma disclosures of any future acquisitions.