exh99-2form8k10q2ndqtr102010.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 condensed consolidated financial statements included in "Item 1. Financial Statements." Any references to Notes in the following "Management's Discussion and Analysis of Financial Condition and Results of Operations" refer to the Notes to Condensed Consolidated Financial Statements included in "Item 1. Financial Statements" (attached as Exhibit 99.1 to this Report).

Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations

BUSINESS ENVIRONMENT

In May 2010, the U.S. Department of 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 in response to the BP Macondo well incident. The U.S. Department of Interior subsequently issued Notices to Lessees ("NTLs") implementing additional safety and certification requirements applicable to drilling activities in the U.S. Gulf of Mexico, imposed additional requirements for approval of 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 June 22, 2010, the U.S. District Court for the Eastern District of Louisiana granted a temporary injunction which immediately prohibited enforcement of the moratorium/suspension and an appeal to the Fifth Circuit Court of Appeals declined the government's petition to stay enforcement of the injunction. On July 12, 2010, the U.S. Department of Interior issued a revised moratorium/suspension on drilling in the U.S. Gulf of Mexico that generally applies to mobile offshore drilling units that utilize subsea blowout prevention equipment required for deepwater drilling operations.

Some U.S. Gulf of Mexico deepwater projects have been delayed as a result of the moratorium/suspension, which does not prohibit certain well operations. Although global deepwater drilling activity has remained stable during 2010, there is significant uncertainty as to the near-term and long-term impact the BP Macondo well incident may have on deepwater drilling in the U.S. Gulf of Mexico, in addition to its potential impact on the global deepwater market.

Semisubmersible rig supply also continues to increase as a result of newbuild construction programs. It has been reported that 29 newbuild semisubmersible rigs are currently under construction, approximately half of which are scheduled for delivery during the remainder of 2010. The majority of semisubmersible rigs scheduled for delivery during 2010 are contracted. Based on the current level of uncertainty regarding deepwater drilling in the U.S. Gulf of Mexico, we are unable to predict whether newbuild semisubmersible rigs will be absorbed into the global market without a significant effect on utilization and day rates.

The significant decline in oil and natural gas prices during the latter half of 2008 and the deterioration of the global economy led to an abrupt reduction in demand for jackup rigs during 2009. Although oil prices have stabilized, incremental drilling activity during 2010 has remained limited resulting in continued softness in jackup rig day rates. While we are encouraged by continued rig inquiries, it remains uncertain whether they will ultimately result in a measurable increase in jackup rig demand in the near-term. Furthermore, it is uncertain as to the impact the BP Macondo well incident may have on jackup rig demand in general, and in the U.S. Gulf of Mexico in particular.

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. It has been reported that 41 newbuild jackup rigs are currently under construction, over half of which are scheduled for delivery during the remainder of 2010. The majority of jackup rigs scheduled for delivery during 2010 are not contracted. 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 of jackup rigs.

For additional information concerning the potential impact the aforementioned events and circumstances may have on our business, our industry and global supply, see "Item 1A. Risk Factors" in Part I and "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" in Part II of our Annual Report on Form 10-K for the year ended December 31, 2009, as updated in the Current Reports on Form 8-K dated June 8, 2010, August 13, 2010, November 29, 2010 and in this Report.

Deepwater

During 2009, depressed oil and natural gas prices resulted in a modest decline in demand for ultra-deepwater semisubmersible rigs, however, global utilization and day rates generally were stable. Although utilization and day rates remained stable during the first six months of 2010, utilization and day rates may come under pressure if deepwater contracts in the U.S. Gulf of Mexico are terminated and/or those rigs are marketed in 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 potential long-term impact the BP Macondo well incident may have on the global deepwater market.

ENSCO 8502 was delivered in January 2010 and is scheduled to commence drilling operations under a two-year contract in August 2010. Although our customer has questioned whether the new requirements of the moratorium/suspension and related NTLs will delay contract commencement, we believe ENSCO 8502 is in compliance with contractual requirements and current applicable regulations and that the drilling contract should commence in accordance with its terms. We also 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 is committed under a long-term drilling contract in the Gulf of Mexico and is scheduled to commence drilling operations during the first quarter of 2011. The remaining ENSCO 8500 Series® rigs under construction are without contracts. Our ENSCO 7500 ultra-deepwater semisubmersible rig currently is operating under contract in Australia.

Asia Pacific

During 2009, Asia Pacific jackup rig utilization and day rates were significantly impacted by the 2008 decline in oil and natural gas prices. While the Asia Pacific jackup market began to show signs of stability during the first six months of 2010, competition for work remained intense due to the oversupply of jackup rigs and limited contract opportunities. With 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.

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 during the first six months of 2010. In July 2010, we acquired a KFELS Super B Class design jackup rig constructed in 2008. The rig was renamed ENSCO 109 and is currently operating in Australia.

Europe and Africa

Our Europe and Africa offshore drilling operations are mainly conducted in Northern Europe. The 2008 decline in oil and natural gas prices resulted in several cancelled tenders and unexercised contract extension options during the latter portion of 2009. Tender activity in the region during the first six months of 2010 was limited with some inquiries for work beginning in 2011, and we expect this trend to continue in the near-term. With limited tender activity and additional jackup rigs projected to complete their current contracts later this year, we anticipate this market will experience excess rig availability, and utilization and day rates will remain under pressure in the near-term.

North and South America

A significant portion of our North and South America offshore drilling operations are conducted in Mexico, where demand for rigs increased in recent years 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 and the first six months of 2010, demand for jackup rigs in Mexico remained high despite global economic conditions. PEMEX recently issued additional tenders for several jackup rigs to commence drilling operations in late 2010 in response to contracts expiring later this year. We expect future day rates in Mexico to face pressure as jackup rig contracts in the region expire and drilling contractors with idle rigs in the Gulf of Mexico and other geographic regions pursue the available contract opportunities.

We also conduct a portion of our North and South America jackup rig operations in the U.S. Gulf of Mexico. The U.S. Gulf of Mexico jackup rig market remained extremely weak during 2009, with drilling activity reaching historic lows as a result of the deterioration in the global economy. During early 2010, tender activity in the U.S. Gulf of Mexico improved as operators capitalized on cost-effective terms offered by drilling contractors. Due to the potential for delays from hurricane season, certain operators’ inability to timely obtain drilling permits and the uncertainty regarding the impact the BP Macondo well incident may have on jackup rig drilling operations in the region, we do not expect meaningful improvement in U.S. Gulf of Mexico jackup rig utilization and day rates in the near-term.

RESULTS OF OPERATIONS

The following table summarizes our condensed consolidated results of operations for the three-month and six-month periods ended June 30, 2010 and 2009 (in millions):

	Three Months Ended June 30,				Six Months Ended June 30,
	2010		2009		2010		2009

Revenues	$411.4		$497.4		$860.0		$982.2
Operating expenses
Contract drilling (exclusive of depreciation)	206.0		196.3		388.4		357.8
Depreciation	51.9		45.3		103.6		89.0
General and administrative	22.0		16.0		42.6		28.0
Operating income	131.5		239.8		325.4		507.4
Other income, net	12.8		6.9		15.9		2.6
Provision for income taxes	22.4		47.9		57.4		100.1
Income from continuing operations	121.9		198.8		283.9		409.9
Income from discontinued operations, net	6.0		2.6		35.6		13.6
Net income	127.9		201.4		319.5		423.5
Net income attributable to noncontrolling interests	(1.6	)	(1.1	)	(3.4	)	(2.5	)
Net income attributable to Ensco	$126.3		$200.3		$316.1		$421.0

For the quarter ended June 30, 2010, revenues declined by $86.0 million, or 17%, and operating income declined by $108.3 million, or 45%, as compared to the prior year quarter. For the six-month period ended June 30, 2010, revenues declined by $122.2 million, or 12%, and operating income declined by $182.0 million, or 36%, as compared to the prior year period. These declines were primarily due to a decline in average day rates and utilization for our Europe and Africa and Asia Pacific jackup rig fleets, partially offset by significant increases in revenues and operating income generated by our ultra-deepwater semisubmersible rig fleet.

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, which will continue to negatively impact our operating results during 2010. While we have substantial contract backlog for 2010, it is unlikely that revenue and operating income levels achieved during 2009 will be sustained during 2010.

Certain of our ultra-deepwater semisubmersible rigs currently contracted in the U.S. Gulf of Mexico are affected by the drilling moratorium/suspension imposed by the U.S. Department of Interior in response to the BP Macondo well incident. This moratorium/suspension and related NTLs are being challenged in litigation by Ensco and others. The operations of certain of our jackup rigs not expressly covered by the moratorium/suspension are being delayed due to the requirements of the NTLs and the drilling permit approval process. Current or future NTLs or other directives may impact our customers' ability to obtain drilling permits and commence or continue deepwater or shallow-water operations in the U.S. Gulf of Mexico.

Customers recently have submitted force majeure notices involving our ultra-deepwater semisubmersible (ENSCO 8500) and four of our jackup rigs (ENSCO 68, ENSCO 82, ENSCO 86 and ENSCO 87) in the U.S. Gulf of Mexico. We have rejected all of these force majeure notices as invalid under the applicable terms of the contract. All four jackup rigs (ENSCO 68, ENSCO 82, ENSCO 86 and ENSCO 87) currently are operating and earning full day rate. In the event of valid force majeure circumstances, the contracts for our ultra-deepwater semisubmersible rigs currently in the U.S. Gulf of Mexico generally provide that a reduced rate applies for a specified number of days (approximately ten weeks) after which our customers have a right to terminate, subject to payment of a significant portion of the day rate for the remainder of the contract term (which, in some cases, is to be offset by other drilling work obtained during said period). As respects our jackup rigs in the U.S. Gulf of Mexico, the contractual force majeure provisions generally provide for payment of full day rate for a specified number of days (approximately two weeks) after which our customers have a right to terminate without further payment.

We are working with our customers on mutually agreeable contingency plans for our rigs in the U.S. Gulf of Mexico that may involve day rate adjustments or rig relocations. As respects ENSCO 8502, our customer has questioned whether the new requirements of the moratorium/suspension and related NTLs will delay contract commencement. We believe ENSCO 8502 is in compliance with contractual requirements and current applicable regulations and that the drilling contract should commence in accordance with its terms.

Significant uncertainty remains as to the near-term and long-term impact the BP Macondo well incident may have on our operating results in general, and in the U.S. Gulf of Mexico in particular.

Rig Locations, Utilization and Average Day Rates

We manage our business through four operating segments. Our jackup rigs are mobile and occasionally move between operating segments in response to market conditions and contract opportunities. The following table summarizes our offshore drilling rigs by segment and rigs under construction as of June 30, 2010 and 2009:

	June 30, 2010	June 30, 2009

Deepwater(1)	4	3
Asia Pacific	17	17
Europe and Africa	10	10
North and South America	13	13
Under construction	4	5
Total(2)	48	48

(1)		In January 2010, we accepted delivery of ENSCO 8502, which is scheduled to commence drilling operations in the Gulf of Mexico under a two-year contract in August 2010.
(2)		The total number of rigs for each period excludes rigs reclassified as discontinued operations.

The following table summarizes our rig utilization and average day rates from continuing operations by operating segment for the three-month and six-month periods ended June 30, 2010 and 2009:

	Three Months Ended June 30,		Six Months Ended June 30,
	2010	2009	2010	2009
Rig utilization(1)
Deepwater	91%	96%	95%	98%
Asia Pacific(3)	68%	69%	72%	75%
Europe and Africa	63%	87%	66%	93%
North and South America(4)	94%	78%	94%	73%
Total	76%	77%	78%	80%

Average day rates(2)
Deepwater	$403,307	$490,865	$407,334	$490,865
Asia Pacific(3)	116,529	142,195	116,716	152,290
Europe and Africa	125,257	219,715	133,423	219,309
North and South America(4)	82,939	119,264	85,482	119,667
Total	$131,231	$171,451	$135,033	$170,621

(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 for the Asia Pacific operating segment include our jackup rigs only. The ENSCO I barge rig has been excluded.
(4)		ENSCO 69 has been excluded from rig utilization and average day rates for our North and South America 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 condensed 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 operating segment, are provided below.

Operating Income

Our business consists of four operating segments: (1) Deepwater, (2) Asia Pacific, (3) Europe and Africa (4) North and South America. Each of our four operating segments provides one service, contract drilling. Segment information for the three-month and six-month periods ended June 30, 2010 and 2009 is presented below (in millions). General and administrative expense is not allocated to our operating segments for purposes of measuring segment operating income and is included in "Reconciling Items."

Three Months Ended June 30, 2010	Deepwater	Asia Pacific	Europe and Africa	North and South America	Operating Segments Total	Reconciling Items	Consolidated Total

Revenues	$120.9	$121.3	$73.5	$95.7	$411.4	$ --	$411.4
Operating expenses Contract drilling (exclusive of depreciation)	46.5	65.8	51.0	42.7	206.0	--	206.0
Depreciation	9.7	18.2	11.9	11.8	51.6	.3	51.9
General and administrative	--	--	--	--	--	22.0	22.0
Operating income (loss)	$ 64.7	$ 37.3	$10.6	$41.2	$153.8	$(22.3)	$131.5

Three Months Ended June 30, 2009	Deepwater	Asia Pacific	Europe and Africa	North and South America	Operating Segments Total	Reconciling Items	Consolidated Total

Revenues	$ 67.7	$147.2	$176.0	$106.5	$497.4	$ --	$497.4
Operating expenses Contract drilling (exclusive of depreciation)	23.7	54.4	52.6	65.6	196.3	--	196.3
Depreciation	3.7	18.7	11.0	11.6	45.0	.3	45.3
General and administrative	--	--	--	--	--	16.0	16.0
Operating income (loss)	$ 40.3	$ 74.1	$112.4	$ 29.3	$256.1	$(16.3)	$239.8

Six Months Ended June 30, 2010	Deepwater	Asia Pacific	Europe and Africa	North and South America	Operating Segments Total	Reconciling Items	Consolidated Total

Revenues	$251.3	$253.3	$161.1	$194.3	$860.0	$ --	$860.0
Operating expenses Contract drilling (exclusive of depreciation)	91.5	117.6	98.1	81.2	388.4	--	388.4
Depreciation	19.5	36.5	23.7	23.3	103.0	.6	103.6
General and administrative	--	--	--	--	--	42.6	42.6
Operating income (loss)	$140.3	$ 99.2	$ 39.3	$ 89.8	$368.6	$(43.2)	$325.4

Six Months Ended June 30, 2009	Deepwater	Asia Pacific	Europe and Africa	North and South America	Operating Segments Total	Reconciling Items	Consolidated Total

Revenues	$67.7	$343.0	$372.4	$199.1	$982.2	$ --	$982.2
Operating expenses Contract drilling (exclusive of depreciation)	28.5	111.6	106.1	111.6	357.8	--	357.8
Depreciation	6.0	37.0	21.9	23.5	88.4	.6	89.0
General and administrative	--	--	--	--	--	28.0	28.0
Operating income (loss)	$33.2	$194.4	$244.4	$ 64.0	$536.0	$(28.6)	$507.4

Deepwater

Deepwater revenues for the quarter ended June 30, 2010 increased by $53.2 million as compared to the prior year quarter. The increase in revenues was due to revenues earned by ENSCO 8500 and ENSCO 8501 which commenced drilling operations under long-term contracts during the second and fourth quarters of 2009, respectively. Contract drilling expense increased by $22.8 million, due to the commencement of ENSCO 8500 and ENSCO 8501 drilling operations as previously noted. Depreciation expense increased by $6.0 million, due to the addition of ENSCO 8500 and ENSCO 8501 to our deepwater fleet in the second and fourth quarters of 2009, respectively.

Deepwater revenues for the six-month period ended June 30, 2010 increased by $183.6 million as compared to the prior year period. The increase in revenues was due to the deferral of ENSCO 7500 revenues during the first quarter of 2009 as the rig mobilized from the Gulf of Mexico to Australia and due to revenues earned by ENSCO 8500 and ENSCO 8501 which commenced drilling operations under long-term contracts during the second and fourth quarters of 2009, respectively. Contract drilling expense increased by $63.0 million, primarily due to the deferral of certain costs during the first quarter of 2009 associated with the ENSCO 7500 mobilization to Australia and the commencement of ENSCO 8500 and ENSCO 8501 drilling operations as previously noted. Depreciation expense increased by $13.5 million, due to the addition of ENSCO 8500 and ENSCO 8501 to our deepwater fleet in the second and fourth quarters of 2009, respectively.

Asia Pacific

Asia Pacific revenues for the quarter ended June 30, 2010 declined by $25.9 million, or 18%, as compared to the prior year quarter. The decline in revenues was primarily due to an 18% decline in average day rates as compared to the prior year quarter. The decline in average day rates occurred due to lower levels of spending by oil and gas companies in response to the current economic environment, coupled with excess rig availability in the region. Contract drilling expense increased by $11.4 million, or 21%, as compared to the prior year quarter, primarily due to a $12.2 million loss on impairment of ENSCO I, our only barge rig, partially offset by a modest decline in payroll expense. Depreciation expense was comparable to the prior year quarter.

Asia Pacific revenues for the six-month period ended June 30, 2010 declined by $89.7 million, or 26%, as compared to the prior year period. The decline in revenues was primarily due to a 23% decline in average day rates and, to a lesser extent, a decline in utilization to 72% from 75% in the comparable prior year period. The decline in average day rates and utilization occurred due to lower levels of spending by oil and gas companies as previously noted, coupled with excess rig availability in the region. Contract drilling expense increased by $6.0 million, or 5%, as compared to the prior year period, primarily due to a $12.2 million loss on impairment of ENSCO I, our only barge rig, partially offset by a decline in payroll expense. Depreciation expense was comparable to the prior year period.

Europe and Africa

Europe and Africa revenues for the quarter ended June 30, 2010 declined by $102.5 million, or 58%, as compared to the prior year quarter. The decline in revenues was primarily due to a 43% decline in average day rates and a decline in utilization to 63% from 87% in the prior year quarter, due to lower levels of spending by oil and gas companies in response to the current economic environment. Contract drilling expense declined by $1.6 million, or 3%, as compared to the prior year quarter, due to a decline in payroll and repair and maintenance expense. Depreciation expense increased by 8% due to the ENSCO 100 capital enhancement project completed during 2009 and depreciation on minor upgrades and improvements to our Europe and Africa fleet completed during 2009 and the first half of 2010.

Europe and Africa revenues for the six-month period ended June 30, 2010 declined by $211.3 million, or 57%, as compared to the prior year period. The decline was primarily due to a decline in utilization to 66% from 93% in the comparable prior year period and a 39% decline in average day rates, due to lower levels of spending by oil and gas companies as previously noted. Contract drilling expense declined by $8.0 million, or 8%, as compared to the prior year period, due to a decline in payroll and repair and maintenance expense. Depreciation expense increased by 8% due to the ENSCO 100 capital enhancement project completed during 2009 and depreciation on minor upgrades and improvements to our Europe and Africa fleet completed during 2009 and the first half of 2010.

North and South America

North and South America revenues for the quarter ended June 30, 2010 declined by $10.8 million, or 10%, as compared to the prior year quarter. The decline was primarily due to a 30% decline in average day rates, partially offset by an increase in utilization to 94% from 78% in the prior year quarter. The increase in utilization resulted primarily from the reduced supply of available jackup rigs in the 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 $22.9 million, or 35%, as compared to the prior year quarter, primarily due to a $17.3 million loss recorded on the disposal of ENSCO 69 during the second quarter of 2009 coupled with a decline in bad debt expense. Depreciation expense was comparable to the prior year quarter.

North and South America revenues for the six-month period ended June 30, 2010 declined by $4.8 million, or 2%, as compared to the prior year period. The decline was primarily due to a 29% decline in average day rates, partially offset by an increase in utilization to 94% from 73% in the comparable prior year period. The increase in utilization resulted from the reduced supply of available jackup rigs in the 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 decreased by $30.4 million, or 27%, as compared to the prior year period, primarily due to a $17.3 million loss recorded on the disposal of ENSCO 69 during the second quarter of 2009 coupled with a decline in bad debt and repair and maintenance expense. Depreciation expense was comparable to the prior year period.

Other

General and administrative expense for the three-month and six-month periods ended June 30, 2010 increased by $6.0 million, or 38%, and $14.6 million, or 52%, respectively, as compared to the respective prior year periods. These increases were primarily due to increased professional fees incurred in connection with various reorganization efforts undertaken as a result of our redomestication to the U.K. in December 2009, increased share-based compensation expense and costs related to operating our new London headquarters.

Other Income, Net

The following summarizes other income, net, for the three-month and six-month periods ended June 30, 2010 and 2009 (in millions):

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2010		2009		2010		2009

Interest income	$ .2		$ .4		$ .3		$ 1.1
Interest expense, net:
Interest expense	(5.4	)	(5.3	)	(10.4	)	(10.6	)
Capitalized interest	5.4		5.3		10.4		10.6
	--		--		--		--
Other, net	12.6		6.5		15.6		1.5
	$12.8		$ 6.9		$ 15.9		$ 2.6

Interest income for the three-month and six-month periods ended June 30, 2010 declined as compared to the respective prior year periods due to lower average interest rates, partially offset by an increase in amounts invested. Interest expense for the three-month and six-month periods ended June 30, 2010 was comparable with the respective prior year periods.

During the quarter ended June 30, 2010, we recognized a gain of $11.4 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 three-month and six-month periods ended June 30, 2010.

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. Net foreign currency exchange gains of $1.9 million and $4.0 million were included in other, net, for the three-month and six-month periods ended June 30, 2010, respectively. Net foreign currency exchange gains of $6.5 million and $500,000 were included in other, net, for the three-month and six-month periods ended June 30, 2009, respectively.

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 rig 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 $22.4 million and $47.9 million for the quarters ended June 30, 2010 and 2009, respectively. The $25.5 million decline in income tax expense as compared to the prior year quarter was primarily due to reduced profitability and a decline in our consolidated effective income tax rate to 15.5% from 19.4% in the prior year quarter. The decline in our 2010 consolidated effective income tax rate as compared to the prior year quarter 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.

Income tax expense was $57.4 million and $100.1 million for the six-month period ended June 30, 2010 and 2009, respectively. The $42.7 million decline in income tax expense as compared to the prior year period was primarily due to reduced profitability and a decline in our consolidated effective income tax rate to 16.8% from 19.6% in the comparable prior year period. The decline in our 2010 consolidated effective income tax rate as compared to the prior year period 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.

Discontinued Operations

ENSCO 60

In September 2010, we executed a Memorandum of Agreement (the “MOA”) to sell ENSCO 60 for $26.0 million. The MOA requires the sale to close in the near-term and the buyer to pay us a non-refundable deposit of $2.6 million.

Based on the facts and circumstances and our conclusion that it was probable the sale of the rig would occur within one year, we classified ENSCO 60 as held-for-sale as of September 30, 2010. The rig’s aggregate net book value and inventory totaled $20.9 million as of June 30, 2010. ENSCO 60 operating results were reclassified as discontinued operations in our condensed consolidated statements of income for the three-month and six-month periods ended June 30, 2010 and 2009 and previously were included within our North and South America operating segment.

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 57 in April 2010 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 condensed consolidated statements of income for three-month and six-month periods ended June 30, 2010. ENSCO 57 operating results were reclassified as discontinued operations in our condensed consolidated statements of income for the three-month and six-month periods ended June 30, 2010 and 2009. See Note 11 to our condensed consolidated financial statements for additional information on the sale of ENSCO 57.

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 condensed consolidated statement of income for the six-month period ended June 30, 2010. ENSCO 50 and ENSCO 51 operating results were reclassified as discontinued operations in our condensed consolidated statements of income for the three-month and six-month periods ended June 30, 2010 and 2009. See Note 11 to our condensed consolidated financial statements for additional information on the sale of ENSCO 50 and ENSCO 51.

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.

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 nationalization of 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 the second quarter of 2009 and reclassified its operating results as discontinued operations.

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"). The agreement also required Petrosucre to compensate us for its use of the rig, and we recognized $5.5 million and $12.4 million of pre-tax income for the three-month and six-month periods ended June 30, 2010 associated with collections under the agreement. Although the agreement obligates Petrosucre to make additional payments for its use of the rig through June 30, 2010, the associated income was not recognized in our condensed consolidated statements of income, as collectability was not reasonably assured.

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 as continuing operations for the three-month and six-month periods ended June 30, 2010 and 2009.

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 condensed consolidated financial statements for additional information on insurance and legal remedies related to ENSCO 69.

The following table summarizes our income from discontinued operations for the three-month and six-month periods ended June 30, 2010 and 2009 (in millions):

	Three Months Ended June 30,				Six Months Ended June 30,
	Three Months Ended June 30,				Six Months Ended June 30,
	2010		2009		2010		2009

Revenues	$ --		$14.2		$12.5		$43.5
Operating expenses	3.3		13.1		14.0		29.1
Operating income (loss) before income taxes	(3.3	)	1.1		(1.5	)	14.4
Income tax (benefit) expense	(3.6	)	(1.5	)	(2.2	)	.8
Gain on disposal of discontinued operations, net	5.7		--		34.9		--
Income from discontinued operations	$ 6.0		$ 2.6		$35.6		$13.6

Fair Value Measurements

Auction Rate Securities

Our auction rate securities were measured at fair value as of June 30, 2010 and December 31, 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 June 30, 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 June 30, 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 June 30, 2010 was appropriate.

Based on the results of our fair value measurements, we recognized net unrealized gains of $300,000 and $600,000 during the three-month and six-month periods ended June 30, 2010, included in other income, net, in our condensed consolidated statements of income. The carrying values of our auction rate securities, classified as long-term investments on our condensed consolidated balance sheets, were $45.2 million and $60.5 million as of June 30, 2010 and December 31, 2009, respectively. We anticipate realizing the $50.9 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 67% of our assets measured at fair value on a recurring basis and less than 1% of our total assets as of June 30, 2010. See Note 9 to our condensed consolidated financial statements for additional information on our fair value measurements.

ENSCO I Impairment

During the quarter ended June 30, 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 Asia Pacific operating segment. The loss on impairment was included in contract drilling expense in our condensed consolidated statements of income for the three-month and six-month periods ended June 30, 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 June 30, 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 June 30, 2010. See Note 9 to our condensed 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 flow from continuing operations to meet liquidity needs and fund the majority of our cash requirements. We have maintained a strong financial position through the disciplined and conservative use of debt. A substantial 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.

It is likely that the impact from the BP Macondo well incident and resulting legislative, regulatory or permit requirements could result in a decline in our cash flow from operations during the second half of 2010 and beyond. However, based on $1,237.1 million of cash and cash equivalents on hand as of June 30, 2010 and our current contractual backlog, we believe our future operations and remaining obligations associated with the construction of our ENSCO 8500 Series® rigs will be funded from existing cash and cash equivalents and future operating cash flow.

During the six-month period ended June 30, 2010, our primary source of cash was $375.4 million generated from continuing operations and $132.4 million of proceeds from the sale of three jackup rigs. Our primary uses of cash for the same period included $336.6 million for the construction, enhancement and other improvement of our drilling rigs, including $267.2 invested in the construction of our ENSCO 8500 Series® rigs, and $53.6 million for the payment of dividends.

During the six-month period ended June 30, 2009, our primary source of cash was $556.3 million generated from continuing operations. Our primary uses of cash for the same period included $468.6 million for the construction, enhancement and other improvement of our drilling rigs including $328.5 million invested in the construction of our ENSCO 8500 Series® rigs.

Cash Flow and Capital Expenditures

Our cash flow from continuing operations and capital expenditures on continuing operations for the six-month periods ended June 30, 2010 and 2009 were as follows (in millions):

	Six Months Ended June 30,
	2010	2009

Cash flow from continuing operations	$375.4	$556.3
Capital expenditures on continuing operations
New rig construction	$267.2	$328.5
Rig acquisition	18.6	--
Rig enhancements	5.1	88.3
Minor upgrades and improvements	45.7	51.8
	$336.6	$468.6

Cash flow from continuing operations decreased by $180.9 million, or 33%, for the six-month period ended June 30, 2010 as compared to the prior year period. The decline resulted primarily from a $196.9 million decline in cash receipts from contract drilling services partially offset by a $23.2 million decline in tax payments.

We continue to expand the size and quality of our drilling rig fleet. 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. In addition, ENSCO 8502 was delivered in January 2010 and is scheduled to commence drilling operations under a two-year contract in August 2010 although our customer has questioned whether the moratorium/suspension and related NTLs will delay contract commencement. We believe ENSCO 8502 is in compliance with contractual requirements and current applicable regulations and that the drilling contract should commence in accordance with its terms. ENSCO 8503 is committed under a long-term drilling contract in the Gulf of Mexico and is scheduled to commence drilling operations during the first quarter of 2011. The remaining ENSCO 8500 Series® rigs under construction currently are without contracts.

In conjunction with our long-established strategy of high-grading our fleet by investing in newer equipment, we acquired a KFELS Super B Class design jackup rig in July 2010 with available cash for $186.0 million. The rig, which was constructed in 2008, has been renamed ENSCO 109, and we will assume its drilling contract offshore Australia that extends through May 2011.

Based on our current projections, we expect capital expenditures during 2010 to include approximately $620.0 million for construction of our ENSCO 8500® Series rigs, approximately $186.0 million for the acquisition of ENSCO 109, approximately $40.0 million for rig enhancement projects and approximately $100.0 million for minor upgrades and improvements. Depending on market conditions and opportunities, we may make additional capital expenditures to upgrade rigs 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 June 30, 2010 and December 31, 2009 are summarized below (in millions, except percentages):

	June 30, 2010		December 31, 2009

Long-term debt	$ 248.6		$ 257.2
Total capital*	$6,016.2		$5,756.4
Long-term debt to total capital	4.1	%	4.5	%

*Total capital consists of long-term debt and Ensco shareholders' equity.

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 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 June 30, 2010 and December 31, 2009, respectively.

We filed a Form S-3 Registration Statement with the Securities and Exchange Commission (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 June 30, 2010, we had an aggregate $116.9 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.

The Board of Directors of ENSCO International Incorporated previously authorized the repurchase of up to $1,500.0 million of our American depositary shares ("ADSs" or "shares"), 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. No shares were repurchased under the share repurchase programs during the six-month period ended June 30, 2010. Although $562.4 million remained available for repurchase as of June 30, 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.

Liquidity

Our liquidity position as of June 30, 2010 and December 31, 2009 is summarized in the table below (in millions, except ratios):

	June 30, 2010	December 31, 2009

Cash and cash equivalents	$1,237.1	$1,141.4
Working capital	$1,271.2	$1,167.9
Current ratio	4.0	3.4

We expect to fund our short-term liquidity needs, including 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 $1,237.1 million of cash and cash equivalents as of June 30, 2010 and our current contractual backlog, we believe our remaining $909.7 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 flow. 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 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 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. 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 currencies. As of June 30, 2010, $207.6 million of the aggregate remaining contractual obligations associated with our ENSCO 8500 Series® construction projects was denominated in Singapore dollars, of which $155.1 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 June 30, 2010, we had derivatives outstanding to exchange an aggregate $257.0 million for various foreign currencies, including $161.5 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 June 30, 2010 would approximate $21.4 million, including $15.4 million related to our Singapore dollar exposures. All of our derivatives mature during the next 15 months. See Note 4 to our condensed 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 $50.9 million (par value) of auction rate securities with a carrying value of $45.2 million as of June 30, 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 June 30, 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 June 30, 2010 would approximate $1.5 million. See Note 9 to our condensed consolidated financial statements for additional information on our auction rate securities.

CRITICAL ACCOUNTING POLICIES

The preparation of our consolidated 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 the Consolidated Financial Statements for the year ended December 31, 2009 included in our Annual Report on Form 10-K filed with the SEC on February 25, 2010, as updated in the Current Reports on Form 8-K dated June 8, 2010, August 13, 2010 and November 29, 2010. 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 June 30, 2010, the carrying value of our property and equipment totaled $4,604.8 million, which represented 67% 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 carrying values of assets and operating results.

For additional information on the useful lives of our drilling rigs, including an analysis of the impact of various changes in useful life assumptions, see "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Critical Accounting Policies and Estimates" in Part II of our Annual Report on Form 10-K for the year ended December 31, 2009, as updated in the Current Reports on Form 8-K dated June 8, 2010, August 13, 2010 and November 29, 2010.

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 ultra-deepwater semisubmersible rigs and jackup rigs are suited for, and accessible to, broad and numerous markets throughout the world.

For property and equipment used in our operations, recoverability generally is 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 future utilization, day rates, expense levels and capital requirements for each of our drilling rigs, as well as cash flows generated upon disposition. 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 of our 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 would 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 future utilization, day rates, expense levels, capital requirements and terminal values for each of our drilling rigs. Due to the inherent uncertainties associated with these estimates, we 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 substantially declined, we may 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 future 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 and expected future 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 June 30, 2010, our condensed consolidated balance sheet included a $341.9 million net deferred income tax liability, a $60.1 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 International Incorporated ("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 Internal Revenue Service and/or Her Majesty's Revenue and Customs 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.