exh99-22011form8k10q1stqtr.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).

As further discussed in Note 13 to our condensed consolidated financial statements included in "Item 1. Financial Statements (attached as Exhibit 99.1 to this Report), our condensed 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 and Item 2 of the Form 10-Q 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-Q.

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

BUSINESS ENVIRONMENT

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. During the first quarter of 2011, several drilling permits were issued in the U.S. Gulf of Mexico related to deepwater programs that were interrupted by the Macondo well incident. In February 2011, the U.S. District Court for the Eastern District of Louisiana issued a preliminary injunction compelling the Bureau of Ocean Energy Management, Regulation and Enforcement (“BOEM”) to process five pending drilling permit applications related to Ensco rigs within 30 days, but the U.S. Court of Appeal for the Fifth Circuit issued a stay of the injunction pending appeal. Since then the BOEM has issued a permit to one of our customers, which was the first permit issued by the BOEM to drill a deepwater well since the moratoriums/suspensions were issued.

The issuance of deepwater drilling permits in the U.S. Gulf of Mexico continues to be protracted. However, demand for deepwater drilling in the region is expected to increase in the near-term as additional permits are issued. We also are encouraged by increases in tender activity outside the U.S. Gulf of Mexico that has resulted from strengthening demand for work in 2011 and beyond for deepwater drilling in various other regions as well as the recent increase in oil prices, both of which are expected to have a positive impact on future ultra-deepwater semisubmersible rig demand.

Semisubmersible rig supply continues to increase as a result of newbuild construction programs. It has been reported that over 20 newbuild semisubmersible rigs currently are 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.

Although oil prices increased, 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 an increase in both standard duty and heavy duty jackup rig demand for work in 2011 and beyond across various regions as well as the positive effect the recent increase in oil prices are expected to have on future jackup rig demand.

Jackup rig supply also continues to increase as a result of newbuild construction programs. It has been reported that over 35 newbuild jackup rigs currently are under construction, nearly half of which are scheduled for delivery during 2011. The majority of jackup rigs scheduled for delivery are not contracted. It is uncertain whether 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 standard duty 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, 2010, as updated in this Report.

Deepwater

Although utilization and day rates for ultra-deepwater semisubmersible rigs remained stable during the first half of 2010, a significant number of U.S. Gulf of Mexico deepwater projects were delayed or terminated later in the year as a result of delays in operators' ability to secure permits. During the first quarter of 2011, several drilling permits were issued in the U.S. Gulf of Mexico related to programs that were interrupted by the Macondo well incident as offshore drilling contractors continued to work with operators and government regulators to address new regulatory requirements and secure drilling permits. Although deepwater drilling activity remains limited in the U.S. Gulf of Mexico, demand in the region is expected to increase in the near-term as additional permits are issued. Ultra-deepwater semisubmersible rig utilization and day rates will, in large part, depend on expectations of future oil and gas prices, coupled with the continued near-term impact of the Macondo well incident and associated new regulatory, legislative or permitting requirements in the U.S. Gulf of Mexico.

Jackup

Demand for drilling rigs in the jackup segment was limited during the latter half of 2010, resulting in continued softness in day rates for standard duty jackup rigs. We are encouraged by improving tender activity due to an increase in both standard duty and heavy duty jackup rig demand for work in 2011 and beyond across various regions. In addition, the increase in oil prices over the past year is expected to have a positive effect on future jackup rig demand.

The Asia Pacific Rim, including Vietnam, Malaysia, Indonesia and Australia, began to stabilize during 2010 with incremental demand seen as multiple tenders were issued in the latter part of the year for work in 2011 and beyond. During the first quarter of 2011, tender activity in the region continued to improve as a result of strengthening demand. Although the supply of available jackup rigs is expected to further increase from newbuild deliveries, jackup rig utilization and day rates in the Asia Pacific Rim are expected to remain stable in the near-term.

In the North Sea, tender activity during the first half of 2010 was limited although an increase in inquiries was seen late in the year. During the first quarter of 2011, tender activity improved for work beginning in mid-2011 and beyond resulting from incremental demand for both standard duty and heavy duty jackup rigs in the region. Jackup rig utilization and day rates in the North Sea are expected to improve in the near-term.

A portion of our jackup rig operations are conducted in Mexico for Petróleos Mexicanos ("PEMEX"), the national oil company of Mexico. During 2010, the number of jackup rigs contracted in Mexico declined as contracts expired. During the first quarter of 2011, tender activity increased for work beginning in 2011 and is expected to continue in the near-term as PEMEX attempts to increase its jackup rig fleet. Future day rates in Mexico may 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. Although tender activity in the U.S. Gulf of Mexico improved as operators capitalized on cost-effective terms offered by drilling contractors during early 2010, certain operators experienced an inability to timely obtain drilling permits later in the year which negatively influenced utilization and day rates in the region. During 2011, tender activity in the U.S. Gulf of Mexico improved resulting in a modest increase in rig utilization in the region. U.S. Gulf of Mexico jackup rig utilization and day rates are expected to remain stable in the near-term.

RESULTS OF OPERATIONS

The following table summarizes our condensed consolidated operating results for the quarters ended March 31, 2011 and 2010 (in millions):

	2011	2010

Revenues	$361.5	$448.6
Operating expenses
Contract drilling (exclusive of depreciation)	191.6	182.4
Depreciation	59.5	51.7
General and administrative	30.1	20.6
Operating income	80.3	193.9
Other income, net	2.2	3.1
Provision for income taxes	17.0	35.0
Income from continuing operations	65.5	162.0
Income from discontinued operations, net	--	29.6
Net income	65.5	191.6
Net income attributable to noncontrolling interests	(.9)	(1.8)
Net income attributable to Ensco	$ 64.6	$189.8

During the quarter ended March 31, 2011, revenues declined by $87.1 million, or 19%, and operating income declined by $113.6 million, or 59%, as compared to the prior year quarter. These declines were primarily due to a decline in jackup rig average day rates in the Asia Pacific Rim market coupled with a decline in jackup rig utilization in the Europe and Mediterranean markets, in addition to a decline in utilization of our ultra-deepwater semisubmersible rig fleet due to downtime on the ENSCO 7500 as the rig was undergoing an enhancement project in a shipyard in Singapore.

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 continued to result in a decline in demand for contract drilling services during 2010, which may continue to negatively impact our operating results during 2011.

Certain of our drilling rigs 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 Notices to Lessees ("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.

While we have substantial contract backlog 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 March 31, 2011 and 2010:

	2011	2010

Deepwater(1)	5	4
Midwater(2)	--	--
Jackup(3)	40	39
Under construction(1)(4)	5	4
Total(5)	50	47

(1)		ENSCO 8503 was delivered in September 2010 and commenced drilling operations in French Guiana under a short-term sublet agreement during the first quarter of 2011. ENSCO 8503 is expected to commence drilling operations in the U.S. Gulf of Mexico under a two-year contract during 2011.
(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 March 31, 2011 and 2010.
(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)		In February 2011, we entered into agreements with Keppel FELS Limited ("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.
(5)		The total number of rigs for each period excludes rigs reclassified as discontinued operations.

The following table summarizes our rig utilization and average day rates from continuing operations by reportable segment for the quarters ended March 31, 2011 and 2010:

	2011	2010

Rig utilization(1)
Deepwater	77%	99%
Midwater(3)	N/A	N/A
Jackup(4)	72%	79%
Total	72%	80%

Average day rates(2)
Deepwater	$304,220	$ 411,090
Midwater(3)	N/A	N/A
Jackup(4)	96,766	111,706
Total	$118,447	$138,684

(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 the quarters ended March 31, 2011 and 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). For additional information on ENSCO 69, see Note 11 to our audited consolidated financial statements for the year ended December 31, 2010 included in our Annual Report on Form 10-K.

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. Segment information for the quarters ended March 31, 2011 and 2010 is present below (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."

Three Months Ended March 31, 2011


					Operating
					Segments	Reconciling	Consolidated
	Deepwater	Midwater	Jackup	Other	Total	Items	Total

Revenues	$98.2	$ --	$263.3	$ --	$361.5	$ --	$361.5
Operating expenses Contract drilling (exclusive of depreciation)	40.9	--	150.3	.4	191.6	--	191.6
Depreciation	16.3	--	42.4	.4	59.1	.4	59.5
General and administrative	--	--	--	--	--	30.1	30.1
Operating income (loss)	$41.0	$ --	$ 70.6	$(0.8)	$110.8	$(30.5)	$ 80.3

Three Months Ended March 31, 2010


					Operating
					Segments	Reconciling	Consolidated
	Deepwater	Midwater	Jackup	Other	Total	Items	Total

Revenues	$130.4	$ --	$318.2	$ --	$448.6	$ --	$448.6
Operating expenses Contract drilling (exclusive of depreciation)	45.0	--	137.0	.4	182.4	--	182.4
Depreciation	9.8	--	40.9	.7	51.4	.3	51.7
General and administrative	--	--	--	--	--	20.6	20.6
Operating income (loss)	$ 75.6	$ --	$140.3	$(1.1)	$214.8	$(20.9)	$193.9

Deepwater

Deepwater revenues for the quarter ended March 31, 2011 declined by $32.2 million, or 25%, as compared to the prior year quarter. The decline in revenues was primarily due to a decline in utilization to 77% from 99% in the prior year quarter. The decline in utilization occurred due to downtime on ENSCO 7500 as the rig was undergoing an enhancement project in a shipyard in Singapore, partially offset by ENSCO 8502 and ENSCO 8503 which were added to our Deepwater fleet and commenced drilling operations during the third quarter of 2010 and first quarter of 2011, respectively. Contract drilling expense declined by $4.1 million, or 9%, primarily due to downtime on ENSCO 7500, partially offset by the commencement of ENSCO 8502 and ENSCO 8503 drilling operations. Depreciation expense increased by $6.5 million, or 66%, due to the addition of ENSCO 8502 and ENSCO 8503 to our Deepwater fleet as previously noted.

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

Jackup revenues for the quarter ended March 31, 2011 declined by $54.9 million, or 17%, as compared to the prior year quarter. The decline in revenues was primarily due to a 13% decline in average day rates and a decline in utilization to 72% from 79% in the prior year quarter. These declines were due to lower levels of spending by oil and gas companies across all regions coupled with excess rig availability. Contract drilling expense increased by $13.3 million, or 10%, as compared to the prior year quarter primarily due to increased repair and maintenance expense and personnel costs. Depreciation expense increased by $1.5 million, or 4%, as compared to the prior year quarter primarily due to the addition of ENSCO 109 to our jackup fleet during the third quarter of 2010.

Other

Contract drilling expense and depreciation expense for the quarters ended March 31, 2011and 2010 were attributable to ENSCO I, our only barge rig.

Reconciling Items

General and administrative expense for the quarter ended March 31, 2011 increased by $9.5 million, or 46%, as compared to the prior year quarter primarily due to increased professional fees incurred in connection with our proposed merger with Pride International, Inc. ("Pride"), increased share-based compensation and costs related to operating our new London headquarters. These increases were partially offset by professional fees incurred during the quarter ended March 31, 2010 in connection with various reorganization efforts undertaken as a result of our redomestication to the U.K. in December 2009.

Other Income, Net

The following summarizes other income, net, for the quarters ended March 31, 2011 and 2010 (in millions):

	2011		2010

Interest income	$ .2		$ .1
Interest expense, net:
Interest expense	(18.5	)	(5.0	)
Capitalized interest	14.4		5.0
	(4.1	)	--
Other, net	6.1		3.0
	$ 2.2		$ 3.1

Interest income for the quarter ended March 31, 2011 increased as compared to the prior year quarter due to an increase in amounts invested. Interest expense increased over the same period due to $8.8 million of fees incurred with respect to a bridge term facility and an increase in outstanding debt resulting from our public offering on March 17, 2011 of $1,000.0 million aggregate principal amount of 3.25% senior notes due 2016 and $1,500.0 million aggregate principal amount of 4.70% senior notes due 2021. Interest expense of $14.4 million and $5.0 million was capitalized in connection with our newbuild construction during the quarters ended March 31, 2011 and 2010, respectively. See Note 6 to our condensed consolidated financial statements for additional information on the bridge term facility and our senior notes.

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 $300,000 and $2.1 million of net foreign currency exchange gains for the quarters ended March 31, 2011 and 2010, respectively.

Other, net, also included net gains of $4.8 million and $300,000 associated with our auction rate securities during the quarters ended March 31, 2011 and 2010, respectively. See Note 9 to our condensed consolidated financial statements for additional information on our auction rate securities.

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 others, the transfer of ownership of several of our drilling rigs among our subsidiaries in April 2010 and December 2010.

Income tax expense was $17.0 million and $35.0 million for the quarters ended March 31, 2011 and 2010, respectively. The $18.0 million decline in income tax expense as compared to the prior year quarter was primarily due to reduced profitability, partially offset by an increase in our consolidated effective income tax rate to 20.6% from 17.8% in the prior year quarter. Our consolidated effective income tax rate for the quarter ended March 31, 2011 of 20.6% reflects the impact of $4.7 million of net income tax expense attributable to prior years, $3.2 million of which resulted from the recognition of a liability for unrecognized tax benefits associated with a tax position taken in a prior year. Excluding the impact of the aforementioned items, our consolidated effective income tax rate for the quarter ended March 31, 2011 was 14.9%. The decrease compared to the prior year quarter was primarily attributable to the transfer of ownership of several of our drilling rigs among our subsidiaries in April 2010 and December 2010, which resulted in an increase in the relative components of our earnings generated in tax jurisdictions with lower tax rates.

LIQUIDITY AND CAPITAL RESOURCES

Although our business historically has 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 has been invested in the expansion and enhancement of our fleet of drilling rigs in general and construction of our ENSCO 8500 Series® rigs and two new jackup rigs in particular.

During the first quarter of 2011, our cash flows from operations were negatively influenced by the Macondo well incident and associated new regulatory, legislative or permitting requirements, which is expected to continue during 2011. However, based on $3,432.1 million of cash and cash equivalents on hand as of March 31, 2011 and our current contractual backlog, we believe our future operations and obligations associated with our newbuild construction and the cash portion of the consideration related to the proposed merger with Pride primarily will be funded from existing cash and cash equivalents, future operating cash flow and additional short-term debt financing.

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, including proceeds from our public offering on March 17, 2011 of $1,000.0 million aggregate principal amount of 3.25% senior notes due 2016 and $1,500.0 million aggregate principal amount of 4.70% senior notes due 2021, and additional short-term debt financing. 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 American depositary shares, each representing one Class A ordinary share ("ADS" or "share"). 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 primarily be dedicated to finance newbuild construction.

During the quarter ended March 31, 2011, our primary source of cash was $2,462.8 million in proceeds from the issuance of our senior notes and $125.2 million generated from operating activities of continuing operations. Our primary use of cash for the same period was $131.0 million for the construction, enhancement and other improvement of our drilling rigs, including $88.6 million invested in the construction of two ultra-high specification harsh environment jackup rigs, and $50.2 million for the payment of dividends.

During the quarter ended March 31, 2010, our primary source of cash was $159.7 million generated from operating activities of continuing operations and $90.0 million of proceeds from the sale of ENSCO 50 and ENSCO 51. Our primary use of cash for the same period was $167.5 million for the construction, enhancement and other improvement of our drilling rigs, including $151.5 million invested in the construction of our ENSCO 8500 Series® rigs.

Cash Flow and Capital Expenditures

Our cash flow from operating activities of continuing operations and capital expenditures on continuing operations for the quarters ended March 31, 2011 and 2010 were as follows (in millions):

	2011	2010

Cash flow from operating activities of continuing operations	$125.2	$159.7
Capital expenditures on continuing operations
New rig construction	$ 97.1	$151.5
Rig enhancements	22.7	1.9
Minor upgrades and improvements	11.2	14.1
	$131.0	$167.5

Cash flow from continuing operations declined by $34.5 million, or 22%, during the quarter ended March 31, 2011 as compared to the prior year quarter. The decline resulted primarily from a $119.0 million decline in cash receipts from drilling services, partially offset by a $51.4 million decline in tax payments and a $43.9 million increase in cash receipts from repurchases/redemptions of our auction rate securities.

We continue to expand the size and quality of our drilling rig fleet. ENSCO 8503 was delivered in September 2010 and commenced drilling operations in French Guiana under a short-term sublet agreement during the first quarter of 2011. ENSCO 8503 is expected to commence drilling operations in the U.S. Gulf of Mexico under a two-year contract during 2011.

We also have three 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. ENSCO 8504 is committed under a drilling contract in Brunei, while the other two ENSCO 8500 Series® rigs under construction currently are uncontracted. 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 entered into agreements with KFELS in February 2011 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, without taking into consideration the proposed merger with Pride, we expect capital expenditures during 2011 to include approximately $220.0 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 $190.0 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 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 March 31, 2011 and December 31, 2010 are summarized below (in millions, except percentages):

	March 31,	December 31,
	2011	2010

Long-term debt	$ 240.1	$ 240.1
Total capital(1)	6,226.8	6,199.6
Long-term debt to total capital(2)	3.9%	3.9%

(1)		Total capital includes long-term debt and Ensco shareholders' equity.

(2)		Due to the redemption features of our senior notes issued in March 2011, as described below, the senior notes were classified as short-term debt on our condensed consolidated balance sheet as of March 31, 2011 and will be reclassified as long-term debt in the event the merger is consummated within the proposed timeframe.

Senior Notes

On March 17, 2011, we issued $1,000.0 million aggregate principal amount of unsecured 3.25% senior notes due 2016 at a discount of $7.6 million and $1,500.0 million aggregate principal amount of unsecured 4.70% senior notes due 2021 at a discount of $29.6 million (collectively the “Notes”) in a public offering. Interest on the Notes is payable semiannually in March and September of each year. The Notes were issued pursuant to an Indenture between us and Deutsche Bank Trust Company Americas, as trustee (the “Trustee”), dated March 17, 2011 (the “Indenture”), and a Supplemental Indenture between us and the Trustee, dated March 17, 2011 (the “Supplemental Indenture”).

We intend to use the proceeds from the sale of the Notes to fund a portion of the cash consideration payable in connection with the proposed merger with Pride. However, in the event that, for any reason, (i) we do not consummate the merger prior to 5:00 p.m., New York City time, on February 3, 2012 or (ii) the merger agreement with Pride is terminated at any time before such time but after September 17, 2011, the Company must redeem all of the Notes at a redemption price equal to 102% of the aggregate principal amount of the Notes, plus accrued and unpaid interest to the special mandatory redemption date. If the merger agreement with Pride is terminated at any time on or before September 17, 2011, we must redeem the Notes at a redemption price equal to 101% of the aggregate principal amount of the Notes, plus accrued and unpaid interest to the special mandatory redemption date. “Special mandatory redemption date” means the earlier to occur of (1) March 9, 2012, if the merger has not been consummated prior to 5:00 p.m., New York City time, on February 3, 2012, or (2) the 35th day (or if such day is not a business day, the first business day thereafter) following the termination of the merger agreement with Pride for any reason.

Due to the aforementioned redemption features, the Notes were classified as short-term debt on our condensed consolidated balance sheet as of March 31, 2011 and will be reclassified as long-term debt in the event the merger is consummated within the above described timeframe. Moreover, interest payments on the Notes will total $82.7 million for the year ended 2011 and $103.0 million on an annual basis thereafter.

We may also redeem each series of the Notes, in whole or in part, at any time, at a price equal to 100% of their principal amount, plus accrued and unpaid interest and a “make-whole” premium. The Notes, the Indenture and the Supplemental Indenture also contain customary events of default, including failure to pay principal or interest on the Notes when due, among others. The Supplemental Indenture contains certain restrictions, including, among others, restrictions on our ability and the ability of our subsidiaries to create or incur secured indebtedness, enter into certain sale/leaseback transactions and enter into certain merger or consolidation transactions.

Revolving Credit Facility

We have a $700.0 million unsecured revolving credit facility (the “Credit Facility”) with a syndicate of banks. The Credit Facility has a four-year term, expiring in May 2014. Advances under the 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 Credit Facility. We have the right, subject to lender consent, to increase the commitments under the Credit Facility up to $850.0 million. We had no amounts outstanding under the Credit Facility as of March 31, 2011 and December 31, 2010.

Other Financing

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 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. Upon receipt of the proceeds from the issuance of the Notes, we determined that we had adequate cash resources to fund the cash component of the consideration payable in connection with the proposed merger with Pride, and accordingly the Bridge Term Facility was terminated.

We filed a Form S-3 Registration Statement with the Securities and Exchange Commission ("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 March 31, 2011, 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.

The Board of Directors of our U.S. subsidiary and predecessor, ENSCO International Incorporated ("Ensco Delaware"), previously authorized the repurchase of up to $1,500.0 million of our ADSs. 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 quarter ended March 31, 2011. Although $562.4 million remained available for repurchase as of March 31, 2011, 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 March 31, 2011 and December 31, 2010 is summarized in the table below (in millions, except ratios):

	March 31,	December 31,
	2011	2010

Cash and cash equivalents	$3,432.1	$1,050.7
Working capital	952.8	1,087.7
Current ratio*	1.3	4.1

Due to the redemption features of our senior notes issued in March 2011, as described above, the Notes were classified as short-term debt on our condensed consolidated balance sheet as of March 31, 2011 and will be reclassified as long-term debt in the event the merger is consummated within the proposed timeframe.

We expect to fund the cash component of the merger consideration payable in connection with the proposed merger with Pride from existing cash and cash equivalents, including proceeds from the issuance of our Notes, and additional short-term debt financing. 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 $83.0 million, ADS issuance costs of approximately $70.0 million, as well as change in control severance payments to certain Pride employees of approximately $44.0 million. Upon completion of the proposed merger, we will increase our indebtedness, which will include Pride’s debt obligations that 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.

Without taking into consideration the proposed merger with Pride, 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, operating cash flow and, if necessary, funds borrowed under our Credit Facility or other future financing arrangements. 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 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

We use foreign currency forward contracts ("derivatives") to reduce our exposure to 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 certain 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 foreign currencies. As of March 31, 2011, $176.6 million of the aggregate remaining contractual obligations associated with our ENSCO 8500 Series® construction projects was denominated in Singapore dollars, of which $118.4 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 March 31, 2011, we had derivatives outstanding to exchange an aggregate $275.5 million for various foreign currencies, including $135.4 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 March 31, 2011 would approximate $26.8 million, including $9.3 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 17 months. See Note 4 to our condensed consolidated financial statements for additional information on our derivative instruments.

CRITICAL ACCOUNTING POLICIES

The preparation of financial statements and related disclosures in conformity with accounting principles generally accepted in the United States of America 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 audited consolidated financial statements for the year ended December 31, 2010 included in our Annual Report on Form 10-K filed with the SEC on February 24, 2011. 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 March 31, 2011, the carrying value of our property and equipment totaled $5,259.1 million, which represented 54% 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.

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, 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 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 March 31, 2011, our condensed consolidated balance sheet included a $340.6 million net deferred income tax liability, a $13.7 million liability for income taxes currently payable and a $20.2 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 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 our redomestication to the U.K. in December 2009.
	•	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.