Valaris Limited 8K 2013 Other Events | VAL Filing

PART II

As further discussed in Note 11 to our consolidated financial statements herein, our consolidated financial statements have been updated to reclassify ENSCO 5000, ENSCO 5001, ENSCO 5002, ENSCO 6000, ENSCO 7500, ENSCO 69, ENSCO 85 and Pride Wisconsin as discontinued operations for all periods presented. This filing includes updates only to the portions of Item 6, Item 7 and Item 8 of our annual report on Form 10-K for the year ended December 31, 2013 that specifically relate to the reclassification of these eight rigs as discontinued operations and Note 17 of Item 8 regarding the loss on impairment recorded during the three-month period ended June 30, 2014, and does not otherwise modify or update any other disclosures set forth in our annual report on Form 10-K for the year ended December 31, 2013.

Item 6. Selected Financial Data

The financial data below should be read in conjunction with "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" and our consolidated financial statements and notes thereto included in "Item 8. Financial Statements and Supplementary Data."



	Year Ended December 31,
	2013			2012			2011⁽¹⁾			2010			2009
	(in millions, except per share amounts)
Consolidated Statement of Income Data
Revenues	$	4,519.9		$	3,869.2		$	2,599.2		$	1,427.8		$	1,635.8
Operating expenses
Contract drilling (exclusive of depreciation)	2,080.1			1,747.9			1,286.1			654.4			578.9
Depreciation	528.2			476.1			357.6			197.6			168.4
General and administrative	146.8			148.9			158.6			86.1			64.0
Operating income	1,764.8			1,496.3			796.9			489.7			824.5
Other (expense) income, net	(100.1		)	(98.6		)	(57.9		)	18.2			8.8
Provision for income taxes	212.7			238.1			111.6			88.3			176.0
Income from continuing operations	1,452.0			1,159.6			627.4			419.6			657.3
(Loss) income from discontinued operations, net⁽²⁾	(24.1		)	17.1			(21.8		)	166.3			127.2
Net income	1,427.9			1,176.7			605.6			585.9			784.5
Net income attributable to noncontrolling interests	(9.7		)	(7.0		)	(5.2		)	(6.4		)	(5.1		)
Net income attributable to Ensco	$	1,418.2		$	1,169.7		$	600.4		$	579.5		$	779.4
Earnings (loss) per share – basic
Continuing operations	$	6.19		$	4.97		$	3.20		$	2.89		$	4.59
Discontinued operations	(0.11		)	0.08			(0.11		)	1.17			0.89
	$	6.08		$	5.05		$	3.09		$	4.06		$	5.48
Earnings (loss) per share - diluted
Continuing operations	$	6.18		$	4.97		$	3.19		$	2.89		$	4.59
Discontinued operations	(0.11		)	0.07			(0.11		)	1.17			0.89
	$	6.07		$	5.04		$	3.08		$	4.06		$	5.48
Net income attributable to Ensco shares - Basic and Diluted	$	1,403.1		$	1,157.4		$	593.5		$	572.1		$	769.7
Weighted-average shares outstanding
Basic	230.9			229.4			192.2			141.0			140.4
Diluted	231.1			229.7			192.6			141.0			140.5
Cash dividends per share	$	2.25		$	1.50		$	1.40		$	1.08		$	0.10



	Year Ended December 31,
	2013		2012		2011⁽¹⁾		2010		2009
	(in millions)
Consolidated Balance Sheet (as of period end) and Cash Flow Statement Data
Working capital	$	487.9	$	734.2	$	348.7	$	1,087.7	$	1,167.9
Total assets	19,472.9		18,565.3		17,898.8		7,051.5		6,747.2
Long-term debt, net of current portion	4,718.9		4,798.4		4,877.6		240.1		257.2
Ensco shareholders' equity	12,791.6		11,846.4		10,879.3		5,959.5		5,499.2
Cash flows from operating activities of continuing operations	1,886.7		2,074.1		757.4		669.0		1,032.8


⁽¹⁾	Includes the results of Pride from the Merger Date.


⁽²⁾	See Note 11 to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" for information on discontinued operations.

Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations

INTRODUCTION

Our Business

We own the world's second largest offshore drilling rig fleet amongst competitive rigs, our ultra-deepwater fleet is the newest in the industry, and our premium jackup fleet is the largest of any offshore drilling company. We currently own and operate an offshore drilling rig fleet of 74 rigs, including six rigs under construction, spanning most of the strategic, high-growth markets around the globe. Our rig fleet includes ten drillships, 13 dynamically positioned semisubmersible rigs, six moored semisubmersible rigs and 45 jackup rigs.

Our customers include most of the leading national and international oil companies, in addition to many independent operators. We are among the most geographically diverse offshore drilling companies, with current operations and drilling contracts spanning approximately 20 countries on six continents in nearly every major offshore basin around the world. The markets in which we operate include Australia, Brazil, the Mediterranean, Mexico, the Middle East, the North Sea, Southeast Asia, the U.S. Gulf of Mexico and West Africa.

We provide drilling services on a "day rate" contract basis. Under day rate contracts, we provide a drilling rig and rig crews and receive a fixed amount per day for drilling a well. Our customers bear substantially all of the ancillary costs of constructing the well and supporting drilling operations, as well as the economic risk relative to the success of the well. In addition, our customers may pay all or a portion of the cost of moving our equipment and personnel to and from the well site. We do not provide "turnkey" or other risk-based drilling services.

Our Industry

Operating results in the offshore contract drilling industry are cyclical and directly related to the demand for drilling rigs and the available supply of drilling rigs. While the cost of moving a rig and the availability of rig-moving vessels may cause the balance of supply and demand to vary somewhat between regions, significant variations between regions are generally of a short-term nature due to rig mobility.

Drilling Rig Demand

Demand for drilling rigs is directly related to the regional and worldwide levels of offshore exploration and development spending by oil and gas companies, which is beyond our control. The markets for our contract drilling services are cyclical. Offshore exploration and development spending may fluctuate substantially from year-to-year and from region-to-region. Such spending fluctuations result from many factors, including:


•	demand for oil and natural gas,


•	regional and global economic conditions and changes therein,


•	political, social and legislative environments in major oil-producing countries,


•	production and inventory levels and related activities of the Organization of Petroleum Exporting Countries ("OPEC") and other oil and natural gas producers,


•	technological advancements that impact the methods or cost of oil and natural gas exploration and development,


•	disruption to exploration and development activities due to hurricanes and other severe weather conditions and the risk thereof, and


•	the impact that these and other events, whether caused by economic conditions, international or national climate change regulations or other factors, may have on the current and expected future prices of oil and natural gas.

Utilization and day rates stabilized during 2011 as deepwater permitting activity increased in the U.S. Gulf of Mexico and global demand for shallow-water and deepwater drilling improved. During 2012, the permitting process in the U.S. Gulf of Mexico continued to improve and demand growth for floater and jackup rigs resulted in increased utilization and day rates. Day rates strengthened further during 2013 as demand remained strong in most regions, due in part to favorable commodity prices and the announcement of new oil and gas discoveries in regions around the world.

Since factors that affect offshore exploration and development spending are beyond our control and because rig demand can change quickly, it is difficult for us to predict future industry conditions, demand trends or future operating results. Periods of low rig demand often result in excess rig supply, which generally results in reductions in utilization and day rates; conversely, periods of high rig demand often result in a shortage of rigs, which generally results in increased utilization and day rates.

Drilling Rig Supply

During the current newbuild cycle, various industry participants ordered the construction of 381 new drillships, semisubmersible rigs and jackup rigs, 149 of which were delivered during the last three years.

Worldwide rig supply in the Floaters segment continues to increase as a result of newbuild construction programs. Currently there are 99 newbuild drillships and semisubmersible rigs under construction, over 30 of which are scheduled for delivery during 2014. Approximately half of all newbuild floater rigs scheduled for delivery during 2014 are contracted. We expect these newbuild floaters to be absorbed into the market; however, utilization and day rates for less capable floaters will likely be negatively impacted.

Worldwide rig supply in the Jackups segment continues to increase as a result of newbuild construction programs. Currently there are 133 newbuild jackup rigs under construction, over 35 of which are scheduled for delivery during 2014. The majority of all newbuild jackup rigs scheduled for delivery during 2014 are not contracted. Although we expect these newbuild jackup rigs to be absorbed into the market, utilization and day rates in certain regions may come under pressure in the near to intermediate term depending upon the rate at which older jackups are retired.

Rig loss or damage due to hurricanes, blowouts, craterings, punchthroughs and other operational events, and the limited availability of insurance for certain perils in some geographic regions, may impact the supply of offshore drilling rigs in a particular market and cause fluctuations in utilization and day rates.

Drilling Rig Construction and Delivery

We previously contracted Keppel FELS Limited ("KFELS") to construct seven ENSCO 8500 Series^® ultra-deepwater semisubmersible rigs based on our proprietary design. The ENSCO 8500 Series^® rigs are enhanced versions of ENSCO 7500 and are capable of drilling in up to 8,500 feet of water. ENSCO 8506, the final rig in the ENSCO 8500 Series^®, was delivered during 2012 and commenced drilling operations in the U.S. Gulf of Mexico under a long-term contract during the first quarter of 2013.

In connection with the Merger, we acquired seven drillships, two of which were under construction at the time of the Merger. ENSCO DS-6 was delivered in January 2012, underwent customer specified upgrades and commenced drilling operations in Angola under a long-term contract during the first quarter of 2013. ENSCO DS-7 was delivered in September 2013 and commenced a long-term contract in Angola during the fourth quarter of 2013. These newbuild drillships are based on a Samsung Heavy Industries ("SHI") proprietary hull design capable of drilling in up to 10,000 feet of water.

During 2012, we entered into agreements with SHI to construct two additional ultra-deepwater drillships (ENSCO DS-8 and ENSCO DS-9). ENSCO DS-8 is currently uncontracted and scheduled for delivery during the third

quarter of 2014. ENSCO DS-9 is currently scheduled for delivery during the fourth quarter of 2014 and is committed under a long-term contract. During 2013, we entered into an agreement with SHI to construct our eighth ultra-deepwater drillship (ENSCO DS-10), which is uncontracted and scheduled for delivery during the third quarter of 2015.

We previously entered into agreements with KFELS to construct three ultra-premium harsh environment jackup rigs (ENSCO 120, ENSCO 121 and ENSCO 122). ENSCO 120 was delivered in September 2013 and is expected to commence drilling operations under a long-term contract in the North Sea during the first quarter of 2014. ENSCO 121 was delivered during the fourth quarter of 2013 and is expected to commence drilling operations under a long-term contract in the North Sea during the second quarter of 2014. ENSCO 122 is currently scheduled for delivery during the third quarter 2014 and is committed under a long-term drilling contract.

During 2013, we entered into agreements with KFELS to construct a premium jackup rig (ENSCO 110) and a fourth ultra-premium harsh environment jackup rig in the ENSCO 120 Series (ENSCO 123). These rigs are scheduled for delivery during the first quarter of 2015 and the second quarter of 2016, respectively. Both of these rigs are currently uncontracted.

A substantial portion of our projected cash flows will continue to be invested in the expansion and enhancement of our fleet of drilling rigs. We also intend to continue paying quarterly dividends for the foreseeable future. However, our Board of Directors may change the timing and payment amount depending on several factors including our profitability, liquidity, financial condition, reinvestment opportunities and capital requirements. We believe our strong balance sheet, $10.6 billion of contract backlog and borrowing capacity under our commercial paper program and revolving credit facility will provide flexibility to make additional investments in our fleet and sustain an adequate level of liquidity during 2014 and beyond.

Divestitures

Our business strategy has been to focus on ultra-deepwater floater and premium jackup operations and de-emphasize other assets and operations considered to be non-core or that do not meet our standards for financial performance. Consistent with this strategy, we sold five jackup rigs, one moored semisubmersible rig and our last remaining barge rig during the three-year period ended December 31, 2013. See Note 17 to our consolidated financial statements for information about two additional jackup rigs sold in January 2014.

Segment Highlights

Floaters

Operating results for our Floaters segment improved during 2013, primarily due to commencement of ENSCO 8506 and ENSCO DS-6 drilling operations as well as a full year of operations for ENSCO 8505. During the first quarter of 2013, ENSCO 8506 and ENSCO DS-6 commenced drilling operations under long-term contracts at day rates of approximately $530,000. ENSCO 8505 commenced drilling operations under a long-term contract during the second quarter of 2012 at a day rate of approximately $475,000.

ENSCO DS-7 was delivered in September 2013 and commenced a long-term contract in Angola during the fourth quarter of 2013. The day rate averages approximately $648,000 over the term of the contract. In January 2014, ENSCO DS-9 was contracted to ConocoPhillips and is expected to commence a long-term contract in the U.S. Gulf of Mexico during the third quarter of 2015 at an average day rate of approximately $550,000.

ENSCO 8501 received a one-year contract extension from Noble Energy in the U.S. Gulf of Mexico that commenced in August 2013 at a day rate of approximately $525,000. ENSCO 5004 was contracted to Mellitah during the third quarter of 2013 and is expected to commence drilling operations in the Mediterranean during the second quarter of 2014 at an average day rate of approximately $310,000 over the term of the contract.

ENSCO 6001 and ENSCO 6002 received five-year contract extensions from Petrobras in Brazil that commenced in June and July 2013, respectively, at day rates of approximately $370,000, significantly higher than the day rates earned under the expiring contracts.

During 2013, we entered into an agreement with SHI to construct our eighth ultra-deepwater drillship, ENSCO DS-10, which is currently uncontracted and scheduled for delivery during the third quarter of 2015.

Jackups

An increase in average day rates resulted in improved operating results for our Jackups segment during 2013. In particular, premium jackup rigs earned significantly higher day rates during 2013 due to increasing customer demand for more technically capable rigs. The jackup market remains tight, and as of December 31, 2013, all of our marketed jackup rigs were contracted.

In the U.S. Gulf of Mexico, multiple jackup rigs were contracted for longer terms and higher day rates than the expiring contracts. Energy XXI extended the ENSCO 82 contract for one year through September 2014 and the ENSCO 99 contract for nine months through July 2014. Both rigs will receive higher day rates under the contract extensions. Chevron contracted ENSCO 68 and ENSCO 81 for one year and 11 month terms, respectively, at day rates of approximately $145,000, significantly higher than the day rates earned under the expiring contracts. Additionally, Fieldwood extended the ENSCO 87 contract for one year through January 2015 at a day rate of approximately $147,000.

The jackup market was also strong in other regions. ENSCO 54 was contracted to Saudi Aramco in the Middle East through October 2017 at an average day rate of approximately $115,000. ENSCO 105 was contracted to Shell in Malaysia through November 2014 at a day rate of approximately $161,000.

Ultra-premium harsh environment jackup rigs ENSCO 120 and ENSCO 121 were delivered during 2013. ENSCO 120 is expected to commence drilling operations under a long-term contract in the North Sea at a day rate of approximately $230,000 during the first quarter of 2014. ENSCO 121 is expected to commence drilling operations under a long-term contract in the North Sea at a day rate of approximately $230,000 during the second quarter of 2014.

In response to strong demand, we recently entered into agreements with KFELS to construct a premium jackup rig (ENSCO 110) and an ultra-premium harsh environment jackup rig (ENSCO 123). These rigs are scheduled for delivery during the first quarter 2015 and second quarter 2016, respectively. Both of these rigs are currently uncontracted.

BUSINESS ENVIRONMENT

Floaters

Demand for high-specification floaters is expected to remain healthy during 2014. We believe commodity prices will remain at favorable levels making it economic for customers to continue to drill. Approximately two-thirds of wells in progress are focused on development, and recent discoveries are anticipated to prompt additional appraisal and development drilling. Increasing rig supply from newbuild floaters and rigs coming off contract is expected to temper utilization, day rates and contract duration, but retirements of older, less capable floaters should alleviate some of this pressure. Drilling contractors will likely be challenged to contract older, less capable floaters that are not retired.

Rig supply in the U.S. Gulf of Mexico is expected to increase as more than 12 rigs will mobilize to the region during 2014. Although the majority of these newbuild rigs are contracted, utilization for existing floaters in the region may be negatively impacted, and some of these rigs may mobilize to other regions. In Mexico, the government is taking steps to expand deepwater drilling that could lead to incremental demand in future years.

We believe there will be incremental demand in Brazil as customers come to the market for rigs to drill their new exploration acreage awarded in licensing rounds held during 2013. Petrobras has open tenders and inquiries to contract floaters and contract extension negotiations for multiple rigs with contracts expiring in 2015 are ongoing.

In West Africa, multiple newbuild drillships are projected to enter the region during 2014; however, these rigs are expected to be absorbed by incremental demand. We expect demand in the Asia Pacific market to remain stable, with incremental requirements in Australia, Indonesia, Myanmar and Vietnam.

Supply and demand in the North Sea market are balanced, and we believe there will be incremental demand for harsh environment floaters. The Mediterranean market is also expected to present additional drilling opportunities.

Jackups

Demand for jackups is robust, supporting current day rates and contract terms. Utilization for the worldwide jackup fleet continues to be strong. Utilization and day rates in certain regions may come under pressure as more newbuild rigs enter the market, however, retirements of older jackups should balance the market.

Demand is strong in the U.S. Gulf of Mexico, and we expect a balanced market during 2014. The national oil company of Mexico, Petróleos Mexicanos ("PEMEX"), continues to expand its rig fleet, and we believe there will be incremental demand in Mexico as PEMEX contracts additional jackups.

The Asia Pacific market remains balanced, and the majority of contracted newbuild rigs being built in the region will mobilize to other regions during 2014 to begin their initial contracts. Uncontracted newbuild rigs scheduled for delivery from Asian shipyards during 2014 may put pressure on utilization and day rates in the region depending upon the rate at which older jackups are retired.

The Middle East market is expected to remain strong, and we believe there will be incremental demand from operators in the region. Demand in West Africa increased during 2013, and there are currently open tenders for incremental rigs for multi-year terms.

We expect the North Sea market to remain tight. Significant contracted backlog exists for 2014, and operators are issuing tenders to secure rigs for work beginning in 2015 and beyond.

RESULTS OF OPERATIONS

The following table summarizes our consolidated results of operations for each of the years in the three-year period ended December 31, 2013 (in millions):



	2013			2012			2011
Revenues	$	4,519.9		$	3,869.2		$	2,599.2
Operating expenses
Contract drilling (exclusive of depreciation)	2,080.1			1,747.9			1,286.1
Depreciation	528.2			476.1			357.6
General and administrative	146.8			148.9			158.6
Operating income	1,764.8			1,496.3			796.9
Other expense, net	(100.1		)	(98.6		)	(57.9		)
Provision for income taxes	212.7			238.1			111.6
Income from continuing operations	1,452.0			1,159.6			627.4
(Loss) income from discontinued operations, net	(24.1		)	17.1			(21.8		)
Net income	1,427.9			1,176.7			605.6
Net income attributable to noncontrolling interests	(9.7		)	(7.0		)	(5.2		)
Net income attributable to Ensco	$	1,418.2		$	1,169.7		$	600.4

Revenues and operating income increased by $650.7 million, or 17%, and $268.5 million, or 18%, respectively, for the year ended December 31, 2013 as compared to the prior year. The increase in revenues and operating income was primarily due to the addition of newbuild rigs to our Floaters segment and an increase in average day rates across our fleet, partially offset by a decline in utilization for our Floaters segment. The increase in operating income was also partially offset by an increase in personnel costs and, to a lesser extent, the favorable settlement of third-party claims during the prior year which reduced contract drilling expense. See below for additional information on our results by segment.

The liquidity of OGX Petróleo e Gás Participações S.A. ("OGX") deteriorated during the second half of 2013, and on October 30, 2013, OGX filed for bankruptcy protection in Brazil. We did not recognize revenue for drilling services provided to OGX during the second half of 2013 as we concluded collectability of these amounts was not reasonably assured. Additionally, we recognized a $14.2 million provision for doubtful accounts during the year ended December 31, 2013 for receivables related to drilling services provided through June 30, 2013. Our receivables with OGX were fully reserved on our consolidated balance sheet as of December 31, 2013.

During 2012, excluding an increase of $692.6 million in revenues and $317.9 million in operating income attributable to the impact of the Merger, revenues and operating income increased by $577.4 million, or 33%, and $381.5 million, or 68%, respectively, as compared to the prior year. The increase in revenues and operating income was primarily due to newbuild additions to our Floaters segment, an increase in utilization for our Jackups segment and an increase in average day rates for our Floaters and Jackups segments. See below for additional information on our operating results by segment.

A significant number of our drilling contracts are of a long-term nature. Accordingly, an increase or decline in demand for contract drilling services generally affects our operating results and cash flows gradually over future periods as long-term contracts expire and new contracts and/or options are priced at current market rates.

Rig Counts, Utilization and Average Day Rates

The following table sets forth our offshore drilling rigs by reportable segment and rigs under construction as of December 31, 2013, 2012 and 2011:



	2013	2012	2011
Floaters⁽¹⁾⁽²⁾	26	25	22
Jackups⁽¹⁾⁽²⁾	44	42	42
Under construction⁽²⁾⁽³⁾	6	6	7
Total⁽⁴⁾	76	73	71


⁽¹⁾	The table above includes ENSCO 5000, ENSCO 5001, ENSCO 5002, ENSCO 6000 and ENSCO 7500, which were classified as "held for sale" as of June 30, 2014, as well as ENSCO 69, Pride Wisconsin and ENSCO 85 which were sold during 2014.

⁽²⁾

During 2013, we accepted delivery of one ultra-deepwater drillship (ENSCO DS-7) and two ultra-premium harsh environment jackup rigs (ENSCO 120 and ENSCO 121). ENSCO DS-7 commenced a long-term contract during the fourth quarter of 2013. ENSCO 120 is expected to commence drilling operations under a long-term contract during the first quarter of 2014, and ENSCO 121 is expected to commence drilling operations under a long-term contract during the second quarter of 2014.

During 2012, we accepted delivery of two ultra-deepwater semisubmersible rigs (ENSCO 8505 and ENSCO 8506) and one ultra-deepwater drillship (ENSCO DS-6). ENSCO 8505 commenced drilling operations under a long-term contract during the second quarter of 2012. ENSCO 8506 and ENSCO DS-6 commenced drilling operations under long-term contracts during the first quarter of 2013.

⁽³⁾

During 2013, we entered into an agreement with SHI to construct our eighth ultra-deepwater drillship (ENSCO DS-10), which is uncontracted and scheduled for delivery during the third quarter of 2015. During 2013, we also entered into agreements with KFELS to construct one premium jackup rig (ENSCO 110) and one ultra-premium harsh environment jackup rig (ENSCO 123). These rigs are scheduled for delivery during the first quarter 2015 and second quarter 2016, respectively. Both of these rigs are currently uncontracted.

During 2012, we entered into agreements with SHI to construct our sixth and seventh ultra-deepwater drillships (ENSCO DS-8 and ENSCO DS-9). ENSCO DS-8 is currently uncontracted and scheduled for delivery during third quarter of 2014. ENSCO DS-9 is committed under a long-term drilling contract and is scheduled for delivery during the fourth quarter of 2014.


⁽⁴⁾	The total number of rigs for each period excludes rigs sold prior to December 31, 2013.

The following table summarizes our rig utilization and average day rates from continuing operations by reportable segment for each of the years in the three-year period ended December 31, 2013:



	2013		2012		2011
Rig Utilization⁽¹⁾
Floaters	83%		89%		88%
Jackups	92%		94%		85%
Total	89%		92%		85%
Average Day Rates⁽²⁾
Floaters	$	437,393	$	385,528	$	354,907
Jackups	122,642		105,876		97,921
Total	$	222,086	$	189,149	$	157,374

⁽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 and recognized day rate revenue, including days associated with compensated downtime and mobilizations. When revenue is earned but is deferred and amortized over a future period, for example when a rig earns revenue while mobilizing to commence a new contract or while being upgraded in a shipyard, the related days are excluded from days under contract.

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, lump sum revenues and revenues attributable to amortization of drilling contract intangibles, by the aggregate number of contract days, adjusted to exclude contract days associated with certain mobilizations, demobilizations, shipyard contracts and standby contracts.

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

Operating Income

Our business consists of three operating segments: (1) Floaters, which includes our drillships and semisubmersible rigs, (2) Jackups and (3) Other, which consists of management services on rigs owned by third-parties. Our two reportable segments, Floaters and Jackups, provide one service, contract drilling.

Segment information for each of the years in the three-year period ended December 31, 2013 is presented 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."

Year Ended December 31, 2013



	Floaters		Jackups		Other		Operating Segments Total		Reconciling Items			Consolidated Total

Revenues	$	2,760.8	$	1,684.0	$	75.1	$	4,519.9	$	—		$	4,519.9
Operating expenses
Contract drilling (exclusive of depreciation)	1,209.7		811.9		58.5		2,080.1		—			2,080.1
Depreciation	364.8		156.9		—		521.7		6.5			528.2
General and administrative	—		—		—		—		146.8			146.8
Operating income (loss)	$	1,186.3	$	715.2	$	16.6	$	1,918.1	$	(153.3	)	$	1,764.8

Year Ended December 31, 2012



	Floaters		Jackups		Other		Operating Segments Total		Reconciling Items			Consolidated Total

Revenues	$	2,300.8	$	1,485.6	$	82.8	$	3,869.2	$	—		$	3,869.2
Operating expenses
Contract drilling (exclusive of depreciation)	956.0		730.8		61.1		1,747.9		—			1,747.9
Depreciation	305.7		161.5		—		467.2		8.9			476.1
General and administrative	—		—		—		—		148.9			148.9
Operating income (loss)	$	1,039.1	$	593.3	$	21.7	$	1,654.1	$	(157.8	)	$	1,496.3

Year Ended December 31, 2011



	Floaters		Jackups		Other		Operating Segments Total		Reconciling Items			Consolidated Total

Revenues	$	1,352.6	$	1,194.2	$	52.4	$	2,599.2	$	—		$	2,599.2
Operating expenses
Contract drilling (exclusive of depreciation)	630.2		613.0		42.9		1,286.1		—			1,286.1
Depreciation	189.1		164.1		—		353.2		4.4			357.6
General and administrative	—		—		—		—		158.6			158.6
Operating income (loss)	$	533.3	$	417.1	$	9.5	$	959.9	$	(163.0	)	$	796.9

Floaters

During 2013, Floater revenues increased by $460.0 million, or 20%, as compared to the prior year. The increase in revenues was primarily due to commencement of ENSCO 8506 and ENSCO DS-6 drilling operations during the first quarter of 2013 and commencement of ENSCO 8505 drilling operations during the second quarter of 2012. To a lesser extent, the increase in revenues was attributable to an increase in average day rates for various rigs in our Floater fleet. These increases were partially offset by a decline in utilization, primarily due to ENSCO 5005, which was in the shipyard for a capital enhancement project during 2013, shipyard related downtime incurred by ENSCO DS-2 and downtime prompted by a vendor notice regarding inspection and replacement of connector bolts on various rigs during the first quarter of 2013. ENSCO 5004 drilling services provided to OGX that were not recognized as revenue also adversely impacted utilization.

Contract drilling expense increased by $253.7 million, or 27%, during 2013 as compared to the prior year, primarily due to the additions to our Floater fleet and increased personnel costs. These increases were partially offset by lower contract drilling expense for ENSCO 5005, which was in the shipyard for a capital enhancement project during 2013. The prior year also included the favorable settlement of third-party claims which reduced contract drilling expense by $63.3 million. Depreciation expense increased by $59.1 million, or 19%, primarily due to the aforementioned additions to our Floater fleet.

During 2012, excluding an increase of $652.0 million attributable to the impact of the Merger, Floater revenues increased by $296.2 million, or 51%, as compared to the prior year. The increase in revenues was primarily due to commencement of ENSCO 8503, ENSCO 8504 and ENSCO 8505 drilling operations during the first and third quarters of 2011 and the second quarter of 2012, respectively. The increase in revenues was also due to an increase in average day rates primarily attributable to ENSCO 8502 and ENSCO 8503, which were sublet during 2011 before commencing original two-year contracts in the U.S. Gulf of Mexico in June 2011 and January 2012, respectively.

Excluding an increase of $251.6 million attributable to the impact of the Merger during 2012, contract drilling expense increased by $74.2 million, or 37%, during 2012 as compared to the prior year, primarily due to the additions to our Floater fleet. The increase in contract drilling expense attributable to the impact of the Merger is net of $63.3 million related to the favorable settlement of third-party claims during 2012. Depreciation expense increased by $23.8 million, or 35%, excluding an increase of $92.8 million in expense attributable to the impact of the Merger. The increase in depreciation expense was primarily due to the aforementioned additions to our Floater fleet.

Jackups

During 2013, Jackup revenues increased by $198.4 million, or 13%, as compared to the prior year. The increase in revenues was primarily due to an increase in average day rates, mostly attributable to the U.S. Gulf of Mexico, North Sea and Southeast Asia. Contract drilling expense increased by $81.1 million, or 11%, as compared to the prior year, primarily due to increased personnel costs.

During 2012, excluding $10.4 million of revenues attributable to the impact of the Merger, Jackup revenues increased by $281.0 million, or 24%, as compared to the prior year. The increase in revenues was primarily due to an increase in utilization to 94% from 85% in the prior year and an 8% increase in average day rates. Increased utilization and average day rates were primarily attributable to increased drilling activity in the Middle East, North Sea, Southeast Asia and Australia. As a result, certain previously cold stacked rigs were reactivated and commenced drilling operations under long-term contracts.

Excluding an increase of $11.1 million attributable to the impact of the Merger, contract drilling expense increased by $106.7 million, or 18%, as compared to the prior year, primarily due to increased utilization and personnel costs. Depreciation expense was comparable to the prior year, excluding an increase of $2.8 million attributable to the impact of the Merger.

Reconciling Items

During 2012, general and administrative expense declined $9.7 million, or 6%, as compared to the prior year, primarily due to professional fees incurred during 2011 in connection with the Merger, partially offset by a general increase in costs as a result of the Merger and lease termination costs associated with our former U.S. administrative office in Dallas, TX.

Other Income (Expense), Net

The following table summarizes other income (expense), net, for each of the years in the three-year period ended December 31, 2013 (in millions):



	2013			2012			2011
Interest income	$	16.6		$	22.8		$	17.2
Interest expense, net:
Interest expense	(226.5		)	(229.4		)	(176.1		)
Capitalized interest	67.7			105.8			80.2
	(158.8		)	(123.6		)	(95.9		)
Other, net	42.1			2.2			20.8
	$	(100.1	)	$	(98.6	)	$	(57.9	)

During 2013, interest income declined as compared to the prior year due to declining outstanding principal amounts due from customers for reimbursement of mobilization and upgrade costs on certain long-term drilling contracts. Interest income increased during 2012 as compared to the prior year due to the acquisition of the aforementioned amounts due from customers for reimbursement of mobilization and upgrade costs on certain long-term drilling contracts in connection with the Merger.

Interest expense during 2013 was comparable to the prior year as the outstanding principal balances associated with our long-term debt instruments remained consistent with the prior year. Interest expense increased during 2012 as compared to the prior year primarily due to an increase in average outstanding debt resulting from $1.9 billion aggregate principal amount of debt assumed in connection with the Merger and, to a lesser extent, our March 2011 public offering of $2.5 billion aggregate principal amount of senior notes.

Interest expense capitalized during 2013 declined $38.1 million, or 36%, as compared to the prior year, due to a decline in the average outstanding amount of capital invested in newbuild construction. ENSCO 8506 and ENSCO DS-6 were placed into service in the first quarter of 2013, and ENSCO 8505 was placed into service during the second quarter of 2012. Interest expense capitalized during 2012 increased $25.6 million, or 32%, as compared to the prior year, due to the aforementioned increase in average outstanding debt and an increase in the average outstanding amount of capital invested in drilling rigs that were acquired in connection with the Merger while under construction.

During 2013, we received a $30.6 million reimbursement from the Mexican tax authority with respect to the tax authority's draw on letters of credit issued by an Ensco subsidiary for the benefit of Seahawk Drilling Inc. ("Seahawk") under a credit support agreement executed in connection with the 2009 spin-off of Seahawk. The reimbursement was included in other, net in our consolidated statement of income for the year ended December 31, 2013.

Our functional currency is the U.S. dollar, and a portion of the revenues earned and expenses incurred by certain 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 $6.4 million, net foreign currency exchange losses of $3.5 million and net foreign currency exchange gains of $16.9 million were included in other, net, in our consolidated statements of income for the years ended December 31, 2013, 2012 and 2011, respectively.

Net unrealized gains of $6.2 million and $2.8 million and net unrealized losses of $300,000 from marketable securities held in our supplemental executive retirement plans ("SERP") were included in other, net, in our consolidated statements of income for the year ended December 31, 2013, 2012 and 2011, respectively. The fair value measurement of our marketable securities held in the SERP is discussed in Note 3 to our consolidated financial statements.

A net gain of $4.8 million associated with the sale of our auction rate securities was included in other, net, in our consolidated statement of income for the year ended December 31, 2011.

Provision for Income Taxes

Ensco plc, our parent company, is domiciled and resident in the U.K. Our subsidiaries conduct operations and earn income in numerous countries and are subject to the laws of taxing jurisdictions within those countries. The income of our non-U.K. subsidiaries is not subject to U.K. taxation. 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 frequent changes in the taxing jurisdictions in which our drilling rigs are operated and/or owned, changes in the overall level of our income and changes in tax laws, our consolidated effective income tax rate may vary substantially from one reporting period to another.

Income tax expense was $212.7 million, $238.1 million and $111.6 million, and our consolidated effective income tax rate was 12.8%, 17.0% and 15.1% during the years ended December 31, 2013, 2012 and 2011, respectively. Our consolidated effective income tax rate for 2013 includes the impact of various discrete tax items. The majority of discrete tax expense recognized during 2013 was attributable to the recognition of a $7.4 million liability for taxes associated with a $30.6 million reimbursement from the resolution of a dispute with the Mexican tax authority and a $7.0 million increase in the valuation allowance on U.S. foreign tax credits resulting from a restructuring transaction in December 2013. Our consolidated effective income tax rate for 2012 also includes the impact of various discrete tax items. The majority of discrete tax expense recognized during 2012 was attributable to $51.2 million of income tax expense associated with the restructuring of certain subsidiaries of the acquired company in December 2012 and net income tax expense associated with liabilities for unrecognized tax benefits and other adjustments relating to prior years. Excluding the impact of the aforementioned discrete tax items, our consolidated effective income tax rate for the years ended December 31, 2013 and 2012 was 12.5% and 12.3%, respectively. The increase in our consolidated effective income tax rate, excluding discrete tax items, was due to the change in taxing jurisdictions in which our drilling rigs are operated and/or owned that resulted in an increase in the relative components of our earnings generated in tax jurisdictions with higher tax rates.

Our consolidated effective income tax rate for 2011 includes the impact of various discrete tax items. The majority of discrete tax expense recognized during 2011 was attributable to 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 discrete tax items, our consolidated effective income tax rate for the year ended December 31, 2011 was 13.0%. The decrease in our 2012 consolidated effective income tax rate, excluding discrete tax items, to 12.3% from 13.0% in 2011 was due to unrecognized benefits related to net operating losses and foreign tax credits of certain acquired subsidiaries in 2011 and changes in taxing jurisdictions in which our drilling rigs are operated and/or owned that resulted in an increase in the relative components of our earnings generated in taxing jurisdictions with lower tax rates.

Discontinued Operations

Our business strategy has been to focus on ultra-deepwater floater and premium jackup operations, and de-emphasize other assets and operations considered to be non-core or that do not meet our standards for financial performance. Consistent with this strategy, we sold the following rigs during the three-year period ended December 31, 2013 (in millions):



Rig	Date of Rig Sale	Segment⁽¹⁾	Net Proceeds		Net Book Value⁽²⁾		Pre-tax (Loss)/Gain⁽³⁾
Pride Pennsylvania	March 2013	Jackups	$	15.5	$	15.7	$	(.2	)
ENSCO 5003	December 2012	Floaters	68.2		89.4		(21.2		)
Pride Hawaii	October 2012	Jackups	18.8		16.8		2.0
ENSCO I	September 2012	Other	4.5		12.3		(7.8		)
ENSCO 61	June 2012	Jackups	31.7		19.6		12.1
ENSCO 59	May 2012	Jackups	22.8		21.9		.9
ENSCO 95	June 2011	Jackups	41.5		28.8		12.7
			$	203.0	$	204.5	$	(1.5	)

⁽¹⁾ The rigs' operating results were reclassified to discontinued operations in our consolidated statements of income for each of the years in the three-year period ended December 31, 2013 and previously were included within the operating segment noted in the above table.

⁽²⁾Includes the rig's net book value as well as inventory and other assets on the date of the sale.

⁽³⁾ The pre-tax (loss)/gain was included in loss from discontinued operations, net in our consolidated statements of income in the year of sale. Income tax expense of $900,000 and $10.9 million was recognized in connection with the sale of assets during the years ended December 31, 2013 and December 31, 2011, respectively. There was no net income tax expense recognized in connection with the sale of assets during the year ended December 31, 2012.

During the quarter ended June 30, 2014, management committed to a plan to sell five floaters. The ENSCO 5000, ENSCO 5001, ENSCO 5002, ENSCO 6000 and ENSCO 7500 were removed from our portfolio of rigs marketed for contract drilling services and are being actively marketed for sale. The operating results from these rigs were included in (loss) income from discontinued operations, net in our consolidated statement of income for the three-year period ended December 31, 2013.

In connection with the sale of the ENSCO 7500, we will be required to pay the outstanding principal on the 6.36% MARAD bonds due 2015, which are collateralized by this rig. The outstanding principal balance on this bond is $25.3 million as of December 31, 2013, of which $12.7 million is included in current maturities of long-term debt on our consolidated balance sheet as of December 31, 2013.

During the quarter ended June 30, 2014, we sold ENSCO 85 for net proceeds of $64.4 million. ENSCO 85 operating results were included in (loss) income from discontinued operations, net in our consolidated statement of income for the three-year period ended December 31, 2013.

During the quarter ended March 31, 2014, we sold ENSCO 69 and Pride Wisconsin for net proceeds of $32.2 million. These rigs were classified as held for sale on our consolidated balance sheet as of December 31, 2013. The proceeds from the sale were received in December 2013 and included in net cash used in investing activities of discontinued operations in our consolidated statement of cash flows for the year ended December 31, 2013. ENSCO 69 and Pride Wisconsin operating results were included in (loss) income from discontinued operations, net in our consolidated statement of income for the three-year period ended December 31, 2013.

During 2012, we classified Pride Pennsylvania as held for sale and the rig was written down to fair value less estimated cost to sell. We recognized a $2.5 million loss, which was included in (loss) income from discontinued operations, net in our consolidated statement of income during the year ended December 31, 2012.

The following table summarizes (loss) income from discontinued operations for each of the years in the three-year period ended December 31, 2013 (in millions):



	2013			2012			2011
Revenues	$	399.9		$	438.2		$	243.5
Operating expenses	412.6			406.9			258.7
Operating (loss) income	(12.7		)	31.3			(15.2		)
Other income	.3			1.3			.2
Income tax (expense) benefit	(10.6		)	1.0			(8.6		)
(Loss) gain on disposal of discontinued operations, net	(1.1		)	(16.5		)	1.8
(Loss) income from discontinued operations	$	(24.1	)	$	17.1		$	(21.8	)

Debt and interest expense are not allocated to our discontinued operations.

During 2008, ENSCO 74 was lost as a result of Hurricane Ike in the U.S. Gulf of Mexico. The owner of a pipeline filed claims alleging that ENSCO 74 caused the pipeline to rupture during Hurricane Ike. We incurred $3.6 million in professional fees in connection with this matter, which we applied against our $10.0 million per occurrence deductible under our liability insurance policy.

In February 2014, we reached an agreement in principle to settle with the pipeline owner for $9.6 million. Accordingly, we recorded a $6.4 million charge for our remaining obligation under our liability insurance policy in loss from discontinued operations in our consolidated statement of income for the year ended December 31, 2013. The remaining $3.2 million was settled by our underwriters. See Note 12 to our consolidated financial statements for additional information on the ENSCO 74 loss.

LIQUIDITY AND CAPITAL RESOURCES

Although our business is cyclical, we have historically relied on our cash flows from continuing operations to meet liquidity needs and fund the majority of our cash requirements. We have maintained a strong financial position through the disciplined and conservative use of debt, which has provided us the ability to achieve future growth potential through acquisitions and newbuild rig construction. A substantial portion of our cash flows have been invested in the expansion and enhancement of our fleet of drilling rigs, through newbuild construction and upgrade projects, and the return of capital to shareholders through dividend payments.

We expect that our operating cash flows will be dedicated to finance newbuild construction and upgrade projects and service our long-term debt. We also intend to continue paying quarterly dividends for the foreseeable future. However, our Board of Directors may change the timing and payment amount depending on several factors including our profitability, liquidity, financial condition, reinvestment opportunities and capital requirements. Based on our balance sheet and current contractual backlog of $10.6 billion, we believe future capital project, debt service and dividend payment obligations will primarily be funded from future operating cash flows and borrowings under our commercial paper program and/or revolving credit facility. We may decide to access debt and/or equity markets to raise additional capital or increase liquidity as necessary.

During the three-year period ended December 31, 2013, our primary source of cash was an aggregate $4.7 billion generated from operating activities of continuing operations, $2.5 billion in proceeds from the issuance of our senior notes and $203.0 million in proceeds from rig sales. Our primary uses of cash during the same period included $4.1 billion for the construction, enhancement and other improvement of our drilling rigs, including $3.0 billion invested

in our newbuild construction, $2.8 billion paid for the cash consideration of the Merger, $1.2 billion for dividend payments and $308.3 million for long-term debt payments.

Detailed explanations of our liquidity and capital resources for each of the years in the three-year period ended December 31, 2013 are set forth below.

Cash Flows and Capital Expenditures

Our cash flows from operating activities of continuing operations and capital expenditures on continuing operations for each of the years in the three-year period ended December 31, 2013 were as follows (in millions):



	2013		2012		2011
Cash flows from operating activities of continuing operations	$	1,886.7	$	2,074.1	$	757.4
Capital expenditures on continuing operations:
New rig construction	$	1,282.5	$	1,298.3	$	394.0
Rig enhancements	238.9		216.5		104.0
Minor upgrades and improvements	247.1		200.2		147.7
	$	1,768.5	$	1,715.0	$	645.7

During 2013, cash flows from continuing operations declined by $187.4 million, or 9%, as compared to the prior year. The decrease primarily resulted from a $381.6 million increase in cash payments related to contract drilling expenses, a $115.8 million increase in cash payments for income taxes, a $40.2 million increase in cash payments for interest and a $28.8 million increase in cash payments related to general and administrative expenses, partially offset by a $365.3 million increase in cash receipts from contract drilling services.

Cash payments during 2013 related to contract drilling and general and administrative expenses were generally higher than the prior year due in part to the full year impact of the Pride acquisition on certain annual payments made during 2013. Annual payments made during the year ended December 31, 2012 were based on seven months of acquired company operating activity.

Cash receipts from contract drilling services associated with customer reimbursed capital upgrades and mobilizations which are amortized to revenue over the term of the related contract totaled $260.0 million for the year ended December 31, 2012 as compared to $70.0 million for the year ended December 31, 2013.

During 2012, cash flows from continuing operations increased by $1.3 billion, or 174%, as compared to the prior year. The increase primarily resulted from a $1.5 billion increase in cash receipts from contract drilling services and a $112.1 million decrease in cash payments related to general and administrative costs, which was primarily attributable to the Merger. The aforementioned items were partially offset by a $161.5 million increase in cash payments related to contract drilling expenses, a $71.2 million increase in cash payments for interest and a $49.2 million decrease in cash receipts from the sale of our auction rate securities during 2011.

We remain focused on our long-established strategy of high-grading and expanding the size of our fleet. During the three-year period ended December 31, 2013, we invested $3.0 billion in the construction of new drilling rigs and an additional $559.4 million enhancing the capability and extending the useful lives of our fleet.

Based on our current projections, we expect capital expenditures during 2014 to include approximately $1.4 billion for newbuild construction, approximately $570.0 million for rig enhancement projects and approximately $300.0 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 total debt, total capital and total debt to total capital ratios as of December 31, 2013, 2012 and 2011 are summarized below (in millions, except percentages):



	2013			2012			2011
Total debt	$	4,766.4		$	4,845.9		$	5,050.1
Total capital^*	17,558.0			16,692.3			15,929.4
Total debt to total capital	27.1		%	29.0		%	31.7		%

^*Total capital includes total debt plus Ensco shareholders' equity.

Senior Notes

In March 2011, we issued $1.0 billion aggregate principal amount of unsecured 3.25% senior notes due 2016 at a discount of $7.6 million and $1.5 billion 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, and a supplemental indenture between us and the Trustee, dated March 17, 2011. The proceeds from the sale of the Notes were used to fund a portion of the cash consideration payable in connection with the Merger.

Upon consummation of the Merger, we assumed the acquired company's outstanding debt comprised of $900.0 million aggregate principal amount of 6.875% senior notes due 2020, $500.0 million aggregate principal amount of 8.5% senior notes due 2019 and $300.0 million aggregate principal amount of 7.875% senior notes due 2040 (the "Acquired Notes"). Under a supplemental indenture, Ensco plc has fully and unconditionally guaranteed the performance of all obligations of Pride with respect to the Acquired Notes. See Note 15 to our consolidated financial statements for additional information on the guarantee of the Acquired Notes.

We may redeem each series of the Notes and Acquired 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 indentures governing both the Notes and Acquired Notes contain customary events of default, including failure to pay principal or interest on the Notes and Acquired Notes when due, among others. The indentures governing both the Notes and Acquired Notes also contain 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.

Commercial Paper

We participate in a commercial paper program with four commercial paper dealers pursuant to which we may issue, on a private placement basis, unsecured commercial paper notes up to a maximum aggregate amount outstanding at any time of $1.0 billion. Amounts issued under the commercial paper program are supported by the available and unused committed capacity under our Five-Year Credit Facility. As a result, amounts issued under the commercial paper program will be limited by the amount of our available and unused committed capacity under our Five-Year Credit Facility. The proceeds of such financings may be used for capital expenditures and other general corporate purposes. The commercial paper will bear interest at rates that will vary based on market conditions and the ratings assigned by credit rating agencies at the time of issuance. The weighted-average interest rate on our commercial paper borrowings was 0.35% and 0.44% during 2013 and 2012, respectively. The maturities of the commercial paper will vary, but may not exceed 364 days from the date of issue. The commercial paper is not redeemable or subject to voluntary prepayment by us prior to maturity. We had no amounts outstanding under our commercial paper program as of December 31, 2013 and 2012.

Revolving Credit

On May 7, 2013, we entered into the Fourth Amended and Restated Credit Agreement (the "Five-Year Credit Facility"), among Ensco, a subsidiary of Ensco, Citibank, N.A., as Administrative Agent, DNB Bank ASA, as Syndication Agent, and a syndicate of banks party thereto. The Five-Year Credit Facility provides for a $2.0 billion senior unsecured revolving credit facility to be used for general corporate purposes with a five-year term expiring on May 7, 2018. The Five-Year Credit Facility amends and restates our $1.45 billion credit agreement which was scheduled to mature on May 12, 2016. Advances under the Five-Year Credit Facility bear interest at Base Rate or LIBOR plus an applicable margin rate (currently 0.125% per annum for Base Rate advances and 1.125% per annum for LIBOR advances) depending on our credit rating. Amounts repaid may be re-borrowed during the term. We are required to pay a quarterly undrawn facility fee (currently 0.125% per annum) on the total $2.0 billion commitment, which is also based on our credit rating. In addition to other customary restrictive covenants, the Five-Year Credit Facility requires us to maintain a total debt to total capitalization ratio less than or equal to 50%. We have the right, subject to lender consent, to increase the commitments under the Five-Year Credit Facility to an aggregate amount of up to $2.5 billion. We had no amounts outstanding under the Five-Year Credit Facility as of December 31, 2013 and 2012.

In connection with the amendment of our Five-Year Credit Facility, we terminated our $450.0 million 364-day revolving unsecured credit facility dated as of May 12, 2011. We had no amounts outstanding under the 364-Day Credit Facility as of December 31, 2012.

Other Financing

As of December 31, 2013, we had $150.0 million of 7.2% debentures outstanding that require semiannual interest payments due in 2027. We also make semiannual principal and interest payments on an aggregate $135.7 million outstanding under our Maritime Administration bond issues due in 2015, 2016 and 2020 with fixed interest rates ranging from 4.24% to 6.36%. In connection with the sale of the ENSCO 7500, we will be required to pay the outstanding principal on the 6.36% MARAD bonds due 2015, which are collateralized by this rig. The outstanding principal balance on this bond is $25.3 million as of December 31, 2013, of which $12.7 million is included in current maturities of long-term debt on our consolidated balance sheet as of December 31, 2013.

We filed an automatically effective shelf registration statement on Form S-3 with the U.S. Securities and Exchange Commission ("SEC") on January 13, 2012, which provides us the ability to issue debt securities, equity securities, guarantees and/or units of securities in one or more offerings. The registration statement, as amended, expires in January 2015.

a maximum of $2.0 billion in the aggregate under the program, but in no case more than 35.0 million shares. The program terminates in May 2018.

Contractual Obligations

We have various contractual commitments related to our new rig construction and rig enhancement agreements, long-term debt and operating leases. We expect to fund these commitments from future operating cash flows and borrowings under our commercial paper program and/or revolving credit facility. The actual timing of our new rig construction and rig enhancement payments may vary based on the completion of various milestones, which are beyond our control. The following table summarizes our significant contractual obligations as of December 31, 2013 and the periods in which such obligations are due (in millions):



	Payments due by period
	2014		2015 and 2016		2017 and 2018		Thereafter		Total
New rig construction agreements	$	1,061.4	$	687.3	$	—	$	—	$	1,748.7
Principal payments on long-term debt	47.5		1,067.2		9.0		3,359.0		4,482.7
Interest payments on long-term debt	247.6		472.2		420.0		938.7		2,078.5
Operating leases	36.9		30.4		19.1		63.7		150.1
Rig enhancement agreements	94.2		—		—		—		94.2
Total contractual obligations⁽¹⁾	$	1,487.6	$	2,257.1	$	448.1	$	4,361.4	$	8,554.2


⁽¹⁾	Contractual obligations do not include $169.0 million of unrecognized tax benefits, inclusive of interest and penalties, included on our consolidated balance sheet as of December 31, 2013. We are unable to specify with certainty the future periods in which we may be obligated to settle such amounts.

Contractual obligations do not include foreign currency forward contracts ("derivatives"). As of December 31, 2013, we had derivatives outstanding to exchange an aggregate $585.0 million U.S. dollars for various foreign currencies. As of December 31, 2013, our consolidated balance sheet included a net derivative asset of $1.8 million. All of our outstanding derivatives mature during the next 18 months.

Other Commitments

We have other commitments that we are contractually obligated to fulfill with cash under certain circumstances. These commitments include letters of credit and surety bonds to guarantee our performance as it relates to our drilling contracts, contract bidding, customs duties, tax appeals and other obligations in various jurisdictions. Obligations under these letters of credit and surety bonds are not normally called, as we typically comply with the underlying performance requirement. As of December 31, 2013, we had not been required to make collateral deposits with respect to these agreements. The following table summarizes our other commitments as of December 31, 2013 (in millions):



	Commitment expiration by period
	2014		2015 and 2016		2017 and 2018		Thereafter		Total
Letters of Credit	$	28.2	$	62.6	$	140.9	$	—	$	231.7
Surety bonds	.4		.2		—		—		.6
Total commitments	$	28.6	$	62.8	$	140.9	$	—	$	232.3

Liquidity

Our liquidity position as of December 31, 2013, 2012 and 2011 is summarized below (in millions, except ratios):



	2013		2012		2011
Cash and cash equivalents	$	165.6	$	487.1	$	430.7
Short-term investments	50.0		50.0		4.5
Working capital	487.9		734.2		348.7
Current ratio	1.5		1.7		1.3

We expect to fund our short-term liquidity needs, including contractual obligations and anticipated capital expenditures, as well as dividends or working capital requirements, from our cash and cash equivalents, short-term investments, operating cash flows, funds borrowed under our commercial paper program and, if necessary, funds borrowed under our revolving credit facility. We may decide to access debt and/or equity markets to raise additional capital or increase liquidity as necessary.

We expect to fund our long-term liquidity needs, including contractual obligations, anticipated capital expenditures and dividends, from our operating cash flows and, if necessary, funds borrowed under our revolving credit facility or other future financing arrangements. We may decide to access debt and/or equity markets to raise additional capital or increase liquidity as necessary.

Effects of Climate Change and Climate Change Regulation

Greenhouse gas ("GHG") emissions have increasingly become the subject of international, national, regional, state and local attention. During 2009, the United States Environmental Protection Agency (the "EPA") officially published its findings that emissions of carbon dioxide, methane and other GHGs present an endangerment to human health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth's atmosphere and other climatic changes. These EPA findings allowed the agency to proceed with the adoption and implementation of regulations to restrict GHG emissions under existing provisions of the Clean Air Act that establish Prevention of Significant Deterioration ("PSD") construction and Title V operating permit reviews for certain large stationary sources that are potential major sources of GHG emissions. Facilities required to obtain PSD permits for their GHG emissions also will be required to meet "best available control technology" standards to be established by the states or, in some cases, the EPA, on a case-by-case basis. The EPA has also adopted rules requiring annual monitoring and reporting of GHG emissions from specified sources in the United States, including, among others, certain onshore and offshore oil and natural gas production facilities.

Beginning this year, the Companies Act 2006 (Strategic and Directors' Reports) Regulations 2013 now requires all quoted U.K. companies to report their annual GHG emissions in the company's directors' report. Additionally, in recent years, cap and trade initiatives to limit GHG emissions have been introduced in the European Union. Similarly, a number of bills related to climate change have been introduced in the U.S. Congress. If these or similar bills were to be adopted, such legislation could adversely impact many industries. However, it appears unlikely that comprehensive federal climate legislation will be passed by Congress in the foreseeable future. In the absence of federal legislation, almost half of the states have begun to address GHG emissions, primarily through the development or planned development of emission inventories or regional GHG cap and trade programs. Future regulation of GHG emissions could occur pursuant to future treaty obligations, statutory or regulatory changes or new climate change legislation in the jurisdictions in which we operate. If Congress undertakes comprehensive tax reform in the future, it is possible that such reform may include a carbon tax, which could impose additional direct costs on operations and reduce demand for refined products. Depending on the particular program, we, or our customers, could be required to control GHG emissions or to purchase and surrender allowances for GHG emissions resulting from our operations. It is uncertain whether any of these initiatives will be implemented. If such initiatives are implemented, we do not believe that such initiatives would have a direct, material adverse effect on our financial condition, operating results or cash flows in a manner different than our competitors.

Restrictions on GHG 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 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 and expenses are denominated in U.S. dollars; however, a portion of the revenues earned and 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 utilize cash flow hedges to hedge forecasted foreign currency denominated transactions, primarily to reduce our exposure to foreign currency exchange rate risk on future expected contract drilling expenses and capital expenditures denominated in various foreign currencies. 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. As of December 31, 2013, we had cash flow hedges outstanding to exchange an aggregate $376.1 million for various foreign currencies.

We have net assets and liabilities denominated in numerous foreign currencies and use various strategies to manage our exposure to changes in foreign currency exchange rates. We occasionally enter into derivatives that hedge the fair value of recognized foreign currency denominated assets or liabilities, thereby reducing exposure to earnings fluctuations caused by changes in foreign currency exchange rates. We do not designate such derivatives as hedging instruments. In these situations, a natural hedging relationship generally exists whereby changes in the fair value of the derivatives offset changes in the fair value of the underlying hedged items. As of December 31, 2013, we held derivatives not designated as hedging instruments to exchange an aggregate $208.9 million for various foreign currencies.

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 as of December 31, 2013 would

approximate $24.2 million. Approximately $18.1 million of these unrealized losses would be offset by corresponding gains on the derivatives utilized to offset changes in the fair value of net assets and liabilities denominated in foreign currencies.

We utilize derivatives and undertake foreign currency exchange rate hedging activities in accordance with our established policies for the management of market risk. We mitigate our credit risk relating to counterparties of our derivatives through a variety of techniques, including transacting with multiple, high-quality financial institutions, thereby limiting our exposure to individual counterparties and by entering into International Swaps and Derivatives Association, Inc. (“ISDA”) Master Agreements, which include provisions for a legally enforceable master netting agreement, with almost all of our derivative counterparties. The terms of the ISDA agreements may also include credit support requirements, cross default provisions, termination events, or set-off provisions. Legally enforceable master netting agreements reduce credit risk by providing protection in bankruptcy in certain circumstances and generally permitting the closeout and netting of transactions with the same counterparty upon the occurrence of certain events.

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 does not expose us to material credit risk or any other material market risk. All of our derivatives mature during the next 18 months. See Note 6 to our consolidated financial statements for additional information on our derivative instruments.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

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 consolidated financial statements. These policies, along with our underlying judgments and assumptions made in their application, have a significant impact on our consolidated financial statements. We identify our critical accounting policies as those that are the most pervasive and important to the portrayal of our financial position and operating results and that require the most difficult, subjective and/or complex judgments by management regarding estimates in matters that are inherently uncertain. Our critical accounting policies are those related to property and equipment, impairment of long-lived assets and goodwill and income taxes.

Property and Equipment

As of December 31, 2013, the carrying value of our property and equipment totaled $14.3 billion, which represented 73% of total assets. This carrying value reflects the application of our property and equipment accounting policies, which incorporate management's estimates, judgments and assumptions relative to the capitalized costs, useful lives and salvage values of our rigs.

We develop and apply property and equipment accounting policies that are designed to appropriately and consistently capitalize those costs incurred to enhance, improve and extend the useful lives of our assets and expense those costs incurred to repair or maintain the existing condition or useful lives of our assets. The development and application of such policies requires estimates, judgments and assumptions by management relative to the nature of, and benefits from, expenditures on our assets. We establish property and equipment accounting policies that are designed to depreciate our assets over their estimated useful lives. The judgments and assumptions used by management in determining the useful lives of our property and equipment reflect both historical experience and expectations regarding future operations, utilization and performance of our assets. The use of different estimates, judgments and assumptions in the establishment of our property and equipment accounting policies, especially those involving the useful lives of our rigs, would likely result in materially different asset carrying values and operating results.

The useful lives of our drilling rigs are difficult to estimate due to a variety of factors, including technological advances that impact the methods or cost of oil and natural gas exploration and development, changes in market or economic conditions and changes in laws or regulations affecting the drilling industry. We evaluate the remaining useful lives of our rigs on a periodic basis, considering operating condition, functional capability and market and economic factors. Our most recent change in estimated useful lives occurred during 1998, when we extended the useful lives of our drilling rigs by an average of five to six years.

Our fleet of 26 floater rigs, exclusive of three rigs under construction, represented 67% of the gross cost and 73% of the net carrying amount of our depreciable property and equipment as of December 31, 2013. Our floater rigs are depreciated over useful lives ranging from 15 to 35 years. Our fleet of 44 jackup rigs, exclusive of three rigs under construction, represented 23% of the gross cost and 15% of the net carrying amount of our depreciable property and equipment as of December 31, 2013. Our jackup rigs are depreciated over useful lives ranging from 10 to 30 years. The following table provides an analysis of estimated increases and decreases in depreciation expense that would have been recognized for the year ended December 31, 2013 for various assumed changes in the useful lives of our drilling rigs effective January 1, 2013:



Increase (decrease) in useful lives of our drilling rigs		Estimated (decrease) increase in depreciation expense that would have been recognized (in millions)
10%		$(47.2)
20%		(81.2)
(10%)		47.7
(20%)		107.6

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 historically has been highly cyclical, and it is not unusual for rigs to be unutilized or underutilized for significant periods of time and subsequently resume full or near full utilization when business cycles change. Likewise, during periods of supply and demand imbalance, rigs frequently are 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 generally may be moved from markets with excess supply, if economically feasible. Our drilling rigs are suited for, and accessible to, 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 utilization levels, 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 may 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. When testing goodwill for impairment, we perform a qualitative assessment to determine whether it is more-likely-than-not that the fair value of a reporting unit is less than its carrying amount. Our two reportable segments represent our reporting units. If we determine it is more-likely-than-not that the fair value of a reporting unit exceeds its carrying value after qualitatively assessing all facts and circumstances, its goodwill is considered not impaired.

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 both of our reporting units has more-likely-than-not declined below its carrying amount and perform a quantitative assessment whereby we estimate the fair value of each reporting unit. 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 both of our reporting units has been impaired. In most instances, our calculation of the fair values 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 levels, 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. It is reasonably possible that the judgments and assumptions inherent in our goodwill impairment test may change in response to future market conditions.

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 or other assumptions 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 a qualitative assessment performed as of December 31, 2013 for our annual goodwill impairment test, we concluded it was more-likely-than-not that the fair value of our reporting units exceeded their carrying amount and there was no impairment of goodwill. However, if the market value of our shares declines for a prolonged period, and if management's judgments and assumptions regarding future industry conditions and operations diminish, it is reasonably possible that our expectations of future cash flows may decline and ultimately result in goodwill impairment for our Floaters reporting unit.

Asset impairment evaluations are 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 levels, day rates, expense levels and capital requirements. The estimates, judgments and assumptions used by management in the application of our asset impairment policies reflect both historical experience and an assessment of current operational, industry, market, economic and political environments. The use of different estimates, judgments, assumptions and expectations regarding future industry conditions and operations would likely result in materially different asset carrying values and operating results.

Income Taxes

We conduct operations and earn income in numerous countries and are subject to the laws of numerous tax jurisdictions. As of December 31, 2013, our consolidated balance sheet included a $295.0 million net deferred income tax liability, a $63.1 million liability for income taxes currently payable and a $169.0 million liability for unrecognized tax benefits, inclusive of interest and penalties.

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 offset deferred tax assets and deferred tax liabilities attributable to different tax paying jurisdictions.

We do not provide deferred taxes on the undistributed earnings of certain subsidiaries because our policy and intention is to reinvest such earnings indefinitely. Should we make a distribution from these subsidiaries in the form of dividends or otherwise, we would be subject to additional income taxes.

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 several 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 occasionally are finalized through a negotiation process. In some jurisdictions, income tax payments may be required before a final income tax obligation is determined in order to avoid significant penalties and/or interest. While we historically have not 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:


•	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 and challenged 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, treaties and the administrative practices and precedents of tax authorities change frequently, requiring us to modify existing tax strategies to conform to such changes.

NEW ACCOUNTING PRONOUNCEMENTS

In July 2013, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update 2013-11, Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists ("Update 2013-11"), an amendment to FASB ASC Topic 740. The new guidance requires an unrecognized tax benefit be presented in the financial statements as a reduction to a deferred tax asset for a net operating loss carryforward, similar tax loss or a tax credit carryforward. To the extent the tax benefit is not available at the reporting date under the governing tax law or if the entity does not intend to use the deferred tax asset for such purpose, the unrecognized tax benefit should be presented as a liability and not combined with deferred tax assets. Update 2013-11 is effective for annual and interim periods for fiscal years beginning after December 15, 2013. We will adopt the accounting standard on a prospective basis effective January 1, 2014. We do not expect the adoption to have a material effect on our consolidated financial statements.

Item 8. Financial Statements and Supplementary Data

MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f) or 15d-15(f). Our internal control over financial reporting system is designed to provide reasonable assurance to our management and Board of Directors regarding the preparation and fair presentation of published financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Under the supervision and with the participation of management, including the Chief Executive Officer and Chief Financial Officer, we have conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control - Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, we have concluded that our internal control over financial reporting is effective as of December 31, 2013 to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.

KPMG LLP, the independent registered public accounting firm who audited our consolidated financial statements, has issued an audit report on our internal control over financial reporting. KPMG LLP's audit report on our internal control over financial reporting is included herein.

February 26, 2014

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Shareholders

Ensco plc:

We have audited the accompanying consolidated balance sheets of Ensco plc and subsidiaries (the Company) as of December 31, 2013 and 2012, and the related consolidated statements of income, comprehensive income, and cash flows for each of the years in the three-year period ended December 31, 2013. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Ensco plc and subsidiaries as of December 31, 2013 and 2012, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2013, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Ensco plc’s internal control over financial reporting as of December 31, 2013, based on criteria established in Internal Control - Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO)”), and our report dated February 26, 2014, expressed an unqualified opinion on the effectiveness of Ensco plc’s internal control over financial reporting.

/s/ KPMG LLP

Houston, Texas

February 26, 2014, except for Notes 1, 2, 10, 11, 13, 14, 15, 16, and 17, as to which the date is September 22, 2014.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Shareholders

Ensco plc:

We have audited Ensco plc's (the Company) internal control over financial reporting as of December 31, 2013, based on criteria established in Internal Control - Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company's internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, Ensco plc maintained, in all material respects, effective internal control over financial reporting as of December 31, 2013, based on criteria established in Internal Control - Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Ensco plc and subsidiaries as of December 31, 2013 and 2012, and the related consolidated statements of income, comprehensive income, and cash flows for each of the years in the three-year period ended December 31, 2013, and our report dated February 26, 2014 expressed an unqualified opinion on those consolidated financial statements.

/s/ KPMG LLP

Houston, Texas

February 26, 2014

ENSCO PLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

(in millions, except per share amounts)



	Year Ended December 31,
	2013			2012			2011
OPERATING REVENUES	$	4,519.9		$	3,869.2		$	2,599.2
OPERATING EXPENSES
Contract drilling (exclusive of depreciation)	2,080.1			1,747.9			1,286.1
Depreciation	528.2			476.1			357.6
General and administrative	146.8			148.9			158.6
	2,755.1			2,372.9			1,802.3
OPERATING INCOME	1,764.8			1,496.3			796.9
OTHER INCOME (EXPENSE)
Interest income	16.6			22.8			17.2
Interest expense, net	(158.8		)	(123.6		)	(95.9		)
Other, net	42.1			2.2			20.8
	(100.1		)	(98.6		)	(57.9		)
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	1,664.7			1,397.7			739.0
PROVISION FOR INCOME TAXES
Current income tax expense	201.5			211.0			124.7
Deferred income tax expense (benefit)	11.2			27.1			(13.1		)
	212.7			238.1			111.6
INCOME FROM CONTINUING OPERATIONS	1,452.0			1,159.6			627.4
(LOSS) INCOME FROM DISCONTINUED OPERATIONS, NET	(24.1		)	17.1			(21.8		)
NET INCOME	1,427.9			1,176.7			605.6
NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS	(9.7		)	(7.0		)	(5.2		)
NET INCOME ATTRIBUTABLE TO ENSCO	$	1,418.2		$	1,169.7		$	600.4
EARNINGS (LOSS) PER SHARE - BASIC
Continuing operations	$	6.19		$	4.97		$	3.20
Discontinued operations	(0.11		)	0.08			(0.11		)
	$	6.08		$	5.05		$	3.09
EARNINGS (LOSS) PER SHARE - DILUTED
Continuing operations	$	6.18		$	4.97		$	3.19
Discontinued operations	(0.11		)	0.07			(0.11		)
	$	6.07		$	5.04		$	3.08

NET INCOME ATTRIBUTABLE TO ENSCO SHARES - BASIC AND DILUTED	$	1,403.1		$	1,157.4		$	593.5

WEIGHTED-AVERAGE SHARES OUTSTANDING
Basic	230.9			229.4			192.2
Diluted	231.1			229.7			192.6

CASH DIVIDENDS PER SHARE	$	2.25		$	1.50		$	1.40

The accompanying notes are an integral part of these consolidated financial statements.

ENSCO PLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(in millions)



	Year Ended December 31,
	2013			2012			2011

NET INCOME	$	1,427.9		$	1,176.7		$	605.6
OTHER COMPREHENSIVE (LOSS) INCOME, NET
Net change in fair value of derivatives	(5.8		)	8.7			.1
Reclassification of net losses (gains) on derivative instruments from other comprehensive income into net income	2.0			—			(5.5		)
Other	1.9			2.8			2.9
NET OTHER COMPREHENSIVE (LOSS) INCOME	(1.9		)	11.5			(2.5		)

COMPREHENSIVE INCOME	1,426.0			1,188.2			603.1
COMPREHENSIVE INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS	(9.7		)	(7.0		)	(5.2		)
COMPREHENSIVE INCOME ATTRIBUTABLE TO ENSCO	$	1,416.3		$	1,181.2		$	597.9

The accompanying notes are an integral part of these consolidated financial statements.

ENSCO PLC AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in millions, except share and par value amounts)



	December 31,
ASSETS	2013			2012
CURRENT ASSETS
Cash and cash equivalents	$	165.6		$	487.1
Accounts receivable, net	855.7			811.4
Other	513.9			425.4
Total current assets	1,535.2			1,723.9
PROPERTY AND EQUIPMENT, AT COST	17,498.5			15,737.1
Less accumulated depreciation	3,187.5			2,591.5
Property and equipment, net	14,311.0			13,145.6
GOODWILL	3,274.0			3,274.0
OTHER ASSETS, NET	352.7			421.8
	$	19,472.9		$	18,565.3
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable - trade	$	341.1		$	357.8
Accrued liabilities and other	658.7			584.4
Current maturities of long-term debt	47.5			47.5
Total current liabilities	1,047.3			989.7
LONG-TERM DEBT	4,718.9			4,798.4
DEFERRED INCOME TAXES	362.1			351.7
OTHER LIABILITIES	545.7			573.4
COMMITMENTS AND CONTINGENCIES
ENSCO SHAREHOLDERS' EQUITY
Class A ordinary shares, U.S. $.10 par value, 450.0 million shares authorized, 239.5 million and 237.7 million shares issued as of December 31, 2013 and 2012	24.0			23.8
Class B ordinary shares, £1 par value, 50,000 shares authorized and issued as of December 31, 2013 and 2012	.1			.1
Additional paid-in capital	5,467.2			5,398.7
Retained earnings	7,327.3			6,434.7
Accumulated other comprehensive income	18.2			20.1
Treasury shares, at cost, 6.0 million shares and 5.3 million shares	(45.2		)	(31.0		)
Total Ensco shareholders' equity	12,791.6			11,846.4
NONCONTROLLING INTERESTS	7.3			5.7
Total equity	12,798.9			11,852.1
	$	19,472.9		$	18,565.3

The accompanying notes are an integral part of these consolidated financial statements.

ENSCO PLC AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (in millions)

	Year Ended December 31,
	2013			2012			2011
OPERATING ACTIVITIES
Net income	$	1,427.9		$	1,176.7		$	605.6
Adjustments to reconcile net income to net cash provided by operating activities of continuing operations:
Discontinued operations, net	24.1			(17.1		)	21.8
Depreciation expense	528.2			476.1			357.6
Share-based compensation expense	50.3			53.2			47.7
Amortization of intangibles and other, net	(20.7		)	(16.4		)	(18.2		)
Deferred income tax expense (benefit)	11.2			27.1			(13.1		)
Settlement of warranty and other claims	(11.0		)	(57.9		)	—
Other	15.0			6.0			(.9		)
Changes in operating assets and liabilities	(138.3		)	426.4			(243.1		)
Net cash provided by operating activities of continuing operations	1,886.7			2,074.1			757.4
INVESTING ACTIVITIES
Additions to property and equipment	(1,768.5		)	(1,715.0		)	(645.7		)
Purchases of short-term investments	(50.0		)	(90.0		)	(4.5		)
Maturities of short-term investments	50.0			44.5			—
Acquisition of Pride International Inc., net of cash acquired	—			—			(2,656.0		)
Other	6.0			3.2			5.3
Net cash used in investing activities of continuing operations	(1,762.5		)	(1,757.3		)	(3,300.9		)
FINANCING ACTIVITIES
Cash dividends paid	(525.6		)	(348.1		)	(292.3		)
Reduction of long-term borrowings	(47.5		)	(47.5		)	(213.3		)
Proceeds from exercise of share options	22.3			35.8			39.9
Debt financing costs	(4.6		)	—			(31.8		)
Commercial paper borrowings, net	—			(125.0		)	125.0
Equity issuance reimbursement (cost)	—			66.7			(70.5		)
Proceeds from issuance of senior notes	—			—			2,462.8
Other	(21.7		)	(17.4		)	(15.7		)
Net cash (used in) provided by financing activities	(577.1		)	(435.5		)	2,004.1
DISCONTINUED OPERATIONS
Operating activities	93.8			113.0			(25.2		)
Investing activities	37.8			60.1			(54.6		)
Net cash provided by (used in) discontinued operations	131.6			173.1			(79.8		)
Effect of exchange rate changes on cash and cash equivalents	(.2		)	2.0			(.8		)
(DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS	(321.5		)	56.4			(620.0		)
CASH AND CASH EQUIVALENTS, BEGINNING OF YEAR	487.1			430.7			1,050.7
CASH AND CASH EQUIVALENTS, END OF YEAR	$	165.6		$	487.1		$	430.7

The accompanying notes are an integral part of these consolidated financial statements.

ENSCO PLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. DESCRIPTION OF THE BUSINESS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Business

We are one of the leading providers of offshore contract drilling services to the international oil and gas industry. We own an offshore drilling rig fleet of 74 rigs, including six rigs under construction, spanning most of the strategic, high-growth markets around the globe. Our rig fleet includes ten drillships, 13 dynamically positioned semisubmersible rigs, six moored semisubmersible rigs and 45 jackup rigs. Our fleet is the world's second largest amongst competitive rigs, our ultra-deepwater fleet is the newest in the industry, and our premium jackup fleet is the largest of any offshore drilling company.

Our customers include most of the leading national and international oil companies, in addition to many independent operators. We are among the most geographically diverse offshore drilling companies, with current operations and drilling contracts spanning approximately 20 countries on six continents in nearly every major offshore basin around the world. The markets in which we operate include the U.S. Gulf of Mexico, Mexico, Brazil, the Mediterranean, the North Sea, the Middle East, West Africa, Australia and Southeast Asia.

Redomestication

During 2009, we completed a reorganization of the corporate structure of the group of companies controlled by our predecessor, ENSCO International Incorporated ("Ensco Delaware"), pursuant to which an indirect, wholly-owned subsidiary merged with Ensco Delaware, and Ensco plc became our publicly-held parent company incorporated under English law (the "redomestication").

The redomestication was accounted for as an internal reorganization of entities under common control and, therefore, Ensco Delaware's assets and liabilities were accounted for at their historical cost basis and not revalued in the transaction. We remain subject to the U.S. Securities and Exchange Commission (the "SEC") reporting requirements, the mandates of the Sarbanes-Oxley Act of 2002, as amended, and the applicable corporate governance rules of the New York Stock Exchange ("NYSE"), and we will continue to report our consolidated financial results in U.S. dollars and in accordance with U.S. generally accepted accounting principles ("GAAP"). We also must comply with additional reporting requirements of English law.

Basis of Presentation—U.K. Companies Act 2006 Section 435 Statement

The accompanying consolidated financial statements have been prepared in accordance with GAAP, which the directors consider to be the most meaningful presentation of our results of operations and financial position. The accompanying consolidated financial statements do not constitute statutory accounts required by the U.K. Companies Act 2006, which for the year ended December 31, 2013 will be prepared in accordance with generally accepted accounting principles in the U.K. and delivered to the Registrar of Companies in the U.K. following the annual general meeting of shareholders. The U.K. statutory accounts are expected to include an unqualified auditor’s report, which is not expected to contain any references to matters on which the auditors drew attention by way of emphasis without qualifying the report or any statements under Sections 498(2) or 498(3) of the U.K. Companies Act 2006.

Principles of Consolidation

The accompanying consolidated financial statements include the accounts of Ensco plc and its majority-owned subsidiaries. All significant intercompany accounts and transactions have been eliminated. Certain previously reported amounts have been reclassified to conform to the current year presentation.

Pervasiveness of Estimates

The preparation of financial statements in conformity with GAAP requires management to make certain estimates, judgments and assumptions that affect the reported amounts of assets and liabilities, the related revenues and expenses and disclosures of gain and loss contingencies as of the date of the financial statements. Actual results could differ from those estimates.

Foreign Currency Remeasurement and Translation

Our functional currency is the U.S. dollar. As is customary in the oil and gas industry, a majority of our revenues and expenses are denominated in U.S. dollars; however, a portion of the revenues earned and expenses incurred by certain 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. Most transaction gains and losses, including certain gains and losses on our derivative instruments, are included in other, net, in our consolidated statement of income. Certain gains and losses from the translation of foreign currency balances of our non-U.S. dollar functional currency subsidiaries are included in accumulated other comprehensive income on our consolidated balance sheet. We incurred net foreign currency exchange gains of $6.4 million, net foreign currency exchange losses of $3.5 million and net foreign currency exchange gains of $16.9 million for the years ended December 31, 2013, 2012 and 2011, respectively.

Cash Equivalents and Short-Term Investments

Highly liquid investments with maturities of three months or less at the date of purchase are considered cash equivalents. Highly liquid investments with maturities of greater than three months but less than one year at the date of purchase are classified as short-term investments.

Short-term investments, consisting of time deposits with initial maturities in excess of three months but less than one year, were included in other current assets on our consolidated balance sheets and totaled $50.0 million as of December 31, 2013 and 2012. Cash flows from purchases and maturities of short-term investments were classified as investing activities in our consolidated statements of cash flows for the years ended December 31, 2013, 2012 and 2011.

Property and Equipment

All costs incurred in connection with the acquisition, construction, major enhancement and improvement of assets are capitalized, including allocations of interest incurred during periods that our drilling rigs are under construction or undergoing major enhancements and improvements. Repair and maintenance costs are charged to contract drilling expense in the period in which they occur. Upon sale or retirement of assets, the related cost and accumulated depreciation are removed from the balance sheet, and the resulting gain or loss is included in contract drilling expense, unless reclassified to discontinued operations.

Our property and equipment is depreciated on a straight-line basis, after allowing for salvage values, over the estimated useful lives of our assets. Drilling rigs and related equipment are depreciated over estimated useful lives ranging from four to 35 years. Buildings and improvements are depreciated over estimated useful lives ranging from two to 30 years. Other equipment, including computer and communications hardware and software costs, is depreciated over estimated useful lives ranging from two to six years.

We evaluate the carrying value of our property and equipment for impairment when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. For property and equipment used in our operations, recoverability 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. Property and equipment held for sale is recorded at the lower of net book value or net realizable value.

If the global economy were to deteriorate and/or the offshore drilling industry were to incur a significant prolonged downturn, it is reasonably possible that impairment charges may occur with respect to specific individual rigs, groups of rigs, such as a specific type of drilling rig, or rigs in a certain geographic location.

Goodwill

We test goodwill for impairment on an annual basis as of December 31 of each year or when events or changes in circumstances indicate that a potential impairment exists. When testing goodwill for impairment, we perform a qualitative assessment to determine whether it is more-likely-than-not that the fair value of a reporting unit is less than its carrying amount.

If we conclude that the fair value of one or both of our reporting units has more-likely-than-not declined below its carrying amount after qualitatively assessing existing facts and circumstances, we perform a quantitative assessment whereby we estimate the fair value of each reporting unit. 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 in the reporting unit.

Based on a qualitative assessment performed as of December 31, 2013, we concluded it was more-likely-than-not that the fair value of our reporting units exceeded their carrying amount, and there was no impairment of goodwill. However, if the market value of our shares declines for a prolonged period, and if management's judgments and assumptions regarding future industry conditions and operations diminish, it is reasonably possible that our expectations of future cash flows may decline and ultimately result in goodwill impairment for our Floaters reporting unit. See "Note 9 - Goodwill and Other Intangible Assets and Liabilities" for additional information on our goodwill.

Operating Revenues and Expenses

Substantially all of our drilling contracts ("contracts") are performed on a day rate basis, and the terms of such contracts are typically for a specific period of time or the period of time required to complete a specific task, such as drill a well. Contract revenues and expenses are recognized on a per day basis, as the work is performed. Day rate revenues are typically earned, and contract drilling expense is typically incurred, on a uniform basis over the terms of our contracts.

In connection with some contracts, we receive lump-sum fees or similar compensation for the mobilization of equipment and personnel prior to the commencement of drilling services or the demobilization of equipment and personnel upon contract completion. Fees received for the mobilization or demobilization of equipment and personnel are included in operating revenues. The costs incurred in connection with the mobilization and demobilization of equipment and personnel are included in contract drilling expense.

Mobilization fees received and costs incurred prior to commencement of drilling operations are deferred and recognized on a straight-line basis over the period that the related drilling services are performed. Demobilization fees and related costs are recognized as incurred upon contract completion. Costs associated with the mobilization of equipment and personnel to more promising market areas without contracts are expensed as incurred.

Deferred mobilization costs were included in other current assets and other assets, net, on our consolidated balance sheets and totaled $66.6 million and $54.5 million as of December 31, 2013 and 2012, respectively. Deferred mobilization revenue was included in accrued liabilities and other, and other liabilities on our consolidated balance sheets and totaled $76.8 million and $52.6 million as of December 31, 2013 and 2012, respectively.

In connection with some contracts, we receive up-front lump-sum fees or similar compensation for capital improvements to our drilling rigs. Such compensation is deferred and recognized as revenue over the period that the related drilling services are performed. The cost of such capital improvements is capitalized and depreciated over the useful life of the asset. Deferred revenue associated with capital improvements was included in accrued liabilities and other, and other liabilities on our consolidated balance sheets and totaled $273.6 million and $301.9 million as of December 31, 2013 and 2012, respectively.

We must obtain certifications from various regulatory bodies in order to operate our drilling rigs and must maintain such certifications through periodic inspections and surveys. The costs incurred in connection with maintaining such certifications, including inspections, tests, surveys and drydock, as well as remedial structural work and other compliance costs, are deferred and amortized over the corresponding certification periods. Deferred regulatory certification and compliance costs were included in other current assets and other assets, net, on our consolidated balance sheets and totaled $18.3 million and $14.4 million as of December 31, 2013 and 2012, respectively.

In certain countries in which we operate, taxes such as sales, use, value-added, gross receipts and excise may be assessed by the local government on our revenues. We generally record our tax-assessed revenue transactions on a net basis in our consolidated statement of income.

Derivative Instruments

We use derivatives to reduce our exposure to various market risks, primarily foreign currency exchange rate risk. See "Note 6 - Derivative Instruments" for additional information on how and why we use derivatives.

All derivatives are recorded on our consolidated balance sheet at fair value. Derivatives subject to legally enforceable master netting agreements are not offset on our consolidated balance sheet. Accounting for the gains and losses resulting from changes in the fair value of derivatives depends on the use of the derivative and whether it qualifies for hedge accounting. Derivatives qualify for hedge accounting when they are formally designated as hedges and are effective in reducing the risk exposure that they are designated to hedge. Our assessment of hedge effectiveness is formally documented at hedge inception, and we review hedge effectiveness and measure any ineffectiveness throughout the designated hedge period on at least a quarterly basis.

Changes in the fair value of derivatives that are designated as hedges of the variability in expected future cash flows associated with existing recognized assets or liabilities or forecasted transactions ("cash flow hedges") are recorded in accumulated other comprehensive income ("AOCI"). Amounts recorded in AOCI associated with cash flow hedges are subsequently reclassified into contract drilling, depreciation or interest expense as earnings are affected by the underlying hedged forecasted transactions.

Gains and losses on a cash flow hedge, or a portion of a cash flow hedge, that no longer qualifies as effective due to an unanticipated change in the forecasted transaction are recognized currently in earnings and included in other, net, in our consolidated statement of income based on the change in the fair value of the derivative. When a forecasted transaction is no longer probable of occurring, gains and losses on the derivative previously recorded in AOCI are reclassified currently into earnings and included in other, net, in our consolidated statement of income.

We occasionally enter into derivatives that hedge the fair value of recognized assets or liabilities, but do not designate such derivatives as hedges or the derivatives otherwise do not qualify for hedge accounting. In these situations, there generally is a natural hedging relationship where changes in the fair value of the derivatives offset changes in the fair value of the underlying hedged items. Changes in the fair value of these derivatives are recognized currently in earnings in other, net, in our consolidated statement of income.

Derivatives with asset fair values are reported in other current assets or other assets, net, on our consolidated balance sheet depending on maturity date. Derivatives with liability fair values are reported in accrued liabilities and other or other liabilities on our consolidated balance sheet depending on maturity date.

Income Taxes

We conduct operations and earn income in numerous countries. Current income taxes are recognized for the amount of taxes payable or refundable based on the laws and income tax rates in the taxing jurisdictions in which operations are conducted and income is earned.

Deferred tax assets and liabilities are recognized for the anticipated future tax effects of temporary differences between the financial statement basis and the tax basis of our assets and liabilities using the enacted tax rates in effect at year-end. A valuation allowance for deferred tax assets is recorded when it is more-likely-than-not that the benefit from the deferred tax asset will not be realized. We do not offset deferred tax assets and deferred tax liabilities attributable to different tax paying jurisdictions.

We operate in certain jurisdictions where tax laws relating to the offshore drilling industry are not well developed and change frequently. Furthermore, we may enter into transactions with affiliates or employ other tax planning strategies that generally are subject to complex tax regulations. As a result of the foregoing, the tax liabilities and assets we recognize in our financial statements may differ from the tax positions taken, or expected to be taken, in our tax returns. Our tax positions are evaluated for recognition using a more-likely-than-not threshold, and those tax positions requiring recognition are measured as the largest amount of tax benefit that is greater than 50% likely of being realized upon effective settlement with a taxing authority that has full knowledge of all relevant information. Interest and penalties relating to income taxes are included in current income tax expense in our consolidated statement of income.

Our drilling rigs frequently move from one taxing jurisdiction to another based on where they are contracted to perform drilling services. The movement of drilling rigs among taxing jurisdictions may involve a transfer of drilling rig ownership among our subsidiaries (“intercompany rig sale”). The pre-tax profit resulting from an intercompany rig sale is eliminated from our consolidated financial statements and the carrying value of a rig sold in an intercompany transaction remains at historical net depreciated cost prior to the transaction. Our consolidated financial statements do not reflect the asset disposition transaction of the selling subsidiary or the asset acquisition transaction of the acquiring subsidiary. Income taxes resulting from an intercompany rig sale, as well as the tax effect of any reversing temporary differences resulting from the sale, are deferred and amortized on a straight-line basis over the remaining useful life of the rig.

In some instances, we may determine that certain temporary differences will not result in a taxable or deductible amount in future years; as it is more-likely-than-not we will commence operations and depart from a given taxing jurisdiction without such temporary differences being recovered or settled. Under these circumstances, no future tax consequences are expected and no deferred taxes are recognized in connection with such operations. We evaluate these determinations on a periodic basis and, in the event our expectations relative to future tax consequences change, the applicable deferred taxes are recognized or derecognized.

We do not provide deferred taxes on the undistributed earnings of certain subsidiaries because our policy and intention is to reinvest such earnings indefinitely. See "Note 10 - Income Taxes" for additional information on our deferred taxes, unrecognized tax benefits, intercompany transfers of drilling rigs and undistributed earnings.

Share-Based Compensation

We sponsor share-based compensation plans that provide equity compensation to our key employees, officers and non-employee directors. Share-based compensation cost is measured at fair value on the date of grant and recognized on a straight-line basis over the requisite service period (usually the vesting period). The amount of compensation cost recognized in our consolidated statement of income is based on the awards ultimately expected to vest and, therefore, reduced for estimated forfeitures. All changes in estimated forfeitures are based on historical

experience and are recognized as a cumulative adjustment to compensation cost in the period in which they occur. See "Note 8 - Benefit Plans" for additional information on our share-based compensation.

Fair Value Measurements

We measure certain of our assets and liabilities based on a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy assigns the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities ("Level 1") and the lowest priority to unobservable inputs ("Level 3"). Level 2 measurements represent inputs that are observable for similar assets or liabilities, either directly or indirectly, other than quoted prices included within Level 1. See "Note 3 - Fair Value Measurements" for additional information on the fair value measurement of certain of our assets and liabilities.

Earnings Per Share

We compute basic and diluted earnings per share ("EPS") in accordance with the two-class method. Net income attributable to Ensco used in our computations of basic and diluted EPS is adjusted to exclude net income allocated to non-vested shares granted to our employees and non-employee directors. Weighted-average shares outstanding used in our computation of diluted EPS is calculated using the treasury stock method and excludes non-vested shares.

The following table is a reconciliation of net income attributable to Ensco shares used in our basic and diluted EPS computations for each of the years in the three-year period ended December 31, 2013 (in millions):



	2013			2012			2011
Net income attributable to Ensco		$1,418.2			$1,169.7			$600.4
Net income allocated to non-vested share awards	(15.1		)	(12.3		)	(6.9		)
Net income attributable to Ensco shares		$1,403.1			$1,157.4			$593.5

The following table is a reconciliation of the weighted-average shares used in our basic and diluted earnings per share computations for each of the years in the three-year period ended December 31, 2013 (in millions):



	2013	2012	2011
Weighted-average shares - basic	230.9	229.4	192.2
Potentially dilutive shares	.2	.3	.4
Weighted-average shares - diluted	231.1	229.7	192.6

Antidilutive share options totaling 300,000 for the year ended December 31, 2013 and 400,000 for the years ended December 31, 2012 and 2011 were excluded from the computation of diluted EPS.

Noncontrolling Interests

Third parties hold a noncontrolling ownership interest in certain of our non-U.S. subsidiaries. Noncontrolling interests are classified as equity on our consolidated balance sheet and net income attributable to noncontrolling interests is presented separately in our consolidated statement of income.

Income from continuing operations attributable to Ensco for each of the years in the three-year period ended December 31, 2013 was as follows (in millions):



	2013			2012			2011
Income from continuing operations	$	1,452.0		$	1,159.6		$	627.4
Income from continuing operations attributable to noncontrolling interests	(8.9		)	(7.0		)	(5.2		)
Income from continuing operations attributable to Ensco	$	1,443.1		$	1,152.6		$	622.2

(Loss) income from discontinued operations attributable to Ensco for each of the years in the three-year period ended December 31, 2013 was as follows (in millions):



	2013			2012		2011
(Loss) income from discontinued operations	$	(24.1	)	$	17.1	$	(21.8	)
Income from discontinued operations attributable to noncontrolling interests	(.8		)	—		—
(Loss) income from discontinued operations attributable to Ensco	$	(24.9	)	$	17.1	$	(21.8	)

2. ACQUISITION OF PRIDE INTERNATIONAL, INC.

On May 31, 2011 (the "Merger Date"), Ensco plc completed a merger transaction (the "Merger") with Pride International, Inc., a Delaware corporation ("Pride"), pursuant to which Pride became an indirect, wholly-owned subsidiary of Ensco plc.

The Merger added drillships to our asset base, increased our presence in Angola and Brazil as well as various other major offshore drilling markets and established our fleet as the world's second largest competitive offshore drilling rig fleet.

Pro Forma Impact of the Merger

The following unaudited supplemental pro forma results for the year ended December 31, 2011 includes pro forma results for the period prior to the closing date of May 31, 2011 and actual results for the period from May 31, 2011 through December 31, 2011. The pro forma results include, among others, (i) the amortization associated with the acquired intangible assets and liabilities; (ii) interest expense associated with debt used to fund a portion of the Merger; and (iii) the impact of certain fair value adjustments such as additional depreciation expense for adjustments to property and equipment and reductions to interest expense for adjustments to debt. The pro forma results do not include any potential synergies, non-recurring charges resulting directly from the Merger, cost savings or other expected benefits of the Merger. The pro forma results should not be considered indicative of future results.



(In millions, except per share amounts)
	2011^*
Revenues	$	3,094.6
Net income	604.8
Earnings per share - basic	2.61
Earnings per share - diluted	2.60


^*	Supplemental pro forma earnings were adjusted to exclude an aggregate $157.6 million of merger-related costs incurred by Ensco and Pride during 2011.

3. FAIR VALUE MEASUREMENTS

The following fair value hierarchy table categorizes information regarding our net financial assets measured at fair value on a recurring basis as of December 31, 2013 and 2012 (in millions):



	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
As of December 31, 2013
Supplemental executive retirement plan assets	$	37.7	$	—	$	—	$	37.7
Derivatives, net	—		1.8		—		1.8
Total financial assets	$	37.7	$	1.8	$	—	$	39.5
As of December 31, 2012
Supplemental executive retirement plan assets	$	29.8	$	—	$	—	$	29.8
Derivatives, net	—		5.2		—		5.2
Total financial assets	$	29.8	$	5.2	$	—	$	35.0

Supplemental Executive Retirement Plans

Our Ensco supplemental executive retirement plans (the "SERP") are non-qualified plans that provide for eligible employees to defer a portion of their compensation for use after retirement. Assets held in the SERP were marketable securities measured at fair value on a recurring basis using Level 1 inputs and were included in other assets, net, on our consolidated balance sheets as of December 31, 2013 and 2012. The fair value measurements of assets held in the SERP were based on quoted market prices. Net unrealized gains of $6.2 million and $2.8 million and net unrealized losses of $300,000 from marketable securities held in our SERP were included in other, net, in our consolidated statements of income for the years ended December 31, 2013, 2012 and 2011, respectively.

Derivatives

Our derivatives were measured at fair value on a recurring basis using Level 2 inputs as of December 31, 2013 and 2012. See "Note 6 - Derivative Instruments" for additional information on our derivatives, including a description of our foreign currency hedging activities and related methodologies used to manage foreign currency exchange rate risk. The fair value measurements of our derivatives were based on market prices that are generally observable for similar assets or liabilities at commonly quoted intervals.

Other Financial Instruments

The carrying values and estimated fair values of our debt instruments as of December 31, 2013 and 2012 were as follows (in millions):



	December 31, 2013				December 31, 2012
	Carrying Value		Estimated Fair Value		Carrying Value		Estimated Fair Value

4.70% Senior notes due 2021	$	1,477.2	$	1,596.9	$	1,474.7	$	1,715.6
6.875% Senior notes due 2020	1,024.8		1,086.7		1,040.6		1,138.3
3.25% Senior notes due 2016	996.5		1,045.8		995.1		1,068.9
8.50% Senior notes due 2019	600.5		635.8		616.4		661.7
7.875% Senior notes due 2040	382.6		410.5		383.8		423.9
7.20% Debentures due 2027	149.1		178.6		149.0		193.2
4.33% MARAD bonds, including current maturities, due 2016	78.9		79.7		112.3		121.6
6.36% MARAD bonds, including current maturities, due 2015	25.3		27.1		38.0		48.7
4.65% MARAD bonds, including current maturities, due 2020	31.5		35.2		36.0		43.9
Total	$	4,766.4	$	5,096.3	$	4,845.9	$	5,415.8

The estimated fair values of our senior notes and debentures were determined using quoted market prices. The estimated fair values of our U.S. Maritime Administration ("MARAD") bonds were determined using an income approach valuation model. The estimated fair values of our cash and cash equivalents, short-term investments, receivables, trade payables and other liabilities approximated their carrying values as of December 31, 2013 and 2012.

4. PROPERTY AND EQUIPMENT

Property and equipment as of December 31, 2013 and 2012 consisted of the following (in millions):



	2013		2012
Drilling rigs and equipment	$	15,839.0	$	13,499.4
Other	101.0		89.1
Work in progress	1,558.5		2,148.6
	$	17,498.5	$	15,737.1

Drilling rigs and equipment increased $2.3 billion primarily due to ENSCO 8506, ENSCO DS-6 and ENSCO DS-7, which were placed into service during 2013, and capital upgrades to the rig fleet.

Work in progress decreased $590.1 million during 2013 primarily due to the aforementioned rigs that were placed into service, partially offset by the construction of four ultra-premium harsh environment jackup rigs, three ultra-deepwater drillships and one premium jackup rig. Work in progress as of December 31, 2013 primarily consisted of $627.2 million related to the construction of the ENSCO 120 Series ultra-premium harsh environment jackup rigs, $513.4 million related to the construction of ENSCO DS-8, ENSCO DS-9 and ENSCO DS-10 ultra-deepwater drillships, $43.7 million related to the construction of ENSCO 110 premium jackup rig and costs associated with various modification and enhancement projects.

Work in progress as of December 31, 2012 primarily consisted of $1.1 billion related to the construction of ENSCO DS-6, ENSCO DS-7, ENSCO DS-8 and ENSCO DS-9 ultra-deepwater drillships, $603.9 million related to

the construction of ENSCO 8506 ultra-deepwater semisubmersible rig, $157.4 million related to the construction of the ENSCO 120 Series ultra-premium harsh environment jackup rigs and costs associated with various modification and enhancement projects.

5. DEBT

The carrying value of long-term debt as of December 31, 2013 and 2012 consisted of the following (in millions):



	2013			2012
4.70% Senior notes due 2021	$	1,477.2		$	1,474.7
6.875% Senior notes due 2020	1,024.8			1,040.6
3.25% Senior notes due 2016	996.5			995.1
8.50% Senior notes due 2019	600.5			616.4
7.875% Senior notes due 2040	382.6			383.8
7.20% Debentures due 2027	149.1			149.0
4.33% MARAD bonds due 2016	78.9			112.3
6.36% MARAD bonds due 2015	25.3			38.0
4.65% MARAD bonds due 2020	31.5			36.0
Total debt	4,766.4			4,845.9
Less current maturities	(47.5		)	(47.5		)
Total long-term debt	$	4,718.9		$	4,798.4

Senior Notes

During 2011, we issued $1.0 billion aggregate principal amount of unsecured 3.25% senior notes due 2016 at a discount of $7.6 million and $1.5 billion 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, and a supplemental indenture between us and the Trustee, dated March 17, 2011. The proceeds from the sale of the Notes were used to fund a portion of the cash consideration payable in connection with the Merger.

Upon consummation of the Merger, we assumed the acquired company's outstanding debt comprised of $900.0 million aggregate principal amount of 6.875% senior notes due 2020, $500.0 million aggregate principal amount of 8.5% senior notes due 2019 and $300.0 million aggregate principal amount of 7.875% senior notes due 2040 (the "Acquired Notes"). Under a supplemental indenture, Ensco plc has fully and unconditionally guaranteed the performance of all obligations of Pride with respect to the Acquired Notes. See "Note 15 - Guarantee of Registered Securities" for additional information on the guarantee of the Acquired Notes.

Debentures Due 2027

During 1997, Ensco Delaware issued $150.0 million of unsecured 7.20% Debentures due November 15, 2027 (the "Debentures") in a public offering. Interest on the Debentures is payable semiannually in May and November. We may redeem the Debentures, in whole or in part, at any time prior to maturity, at a price equal to 100% of their principal amount, plus accrued and unpaid interest and a "make-whole" premium. The indenture under which the Debentures were issued contains limitations on the incurrence of indebtedness secured by certain liens and limitations on engaging in certain sale/leaseback transactions and certain merger, consolidation or reorganization transactions. The Debentures are not subject to any sinking fund requirements. During 2009, in connection with the redomestication, Ensco plc entered into a supplemental indenture to unconditionally guarantee the principal and interest payments on the Debentures.

The Debentures, the indenture and the supplemental indenture also contain customary events of default, including failure to pay principal or interest on the Debentures 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.

MARAD Bonds Due 2015, 2016 and 2020

During 2001, a subsidiary of Ensco Delaware issued $190.0 million of 15-year bonds which are guaranteed by MARAD to provide long-term financing for ENSCO 7500. The bonds will be repaid in 30 equal semiannual principal installments of $6.3 million ending in December 2015. Interest on the bonds is payable semiannually, in June and December, at a fixed rate of 6.36%.

During 2003, a subsidiary of Ensco Delaware issued $76.5 million of 17-year bonds which are guaranteed by MARAD to provide long-term financing for ENSCO 105. The bonds will be repaid in 34 equal semiannual principal installments of $2.3 million ending in October 2020. Interest on the bonds is payable semiannually, in April and October, at a fixed rate of 4.65%.

Ensco Delaware issued separate guaranties to MARAD, guaranteeing the performance of obligations under the bonds. In February 2010, the documents governing MARAD's guarantee commitments were amended to address certain changes arising from the redomestication and to include Ensco plc as an additional guarantor of the debt obligations of Ensco Delaware and its subsidiaries.

Upon consummation of the Merger, we assumed $151.5 million of MARAD bonds issued to provide long-term financing for ENSCO 6003 and ENSCO 6004. The bonds are guaranteed by MARAD and will be repaid in semiannual principal installments ending in 2016. Interest on the bonds is payable semiannually at a weighted average fixed rate of 4.33%.

Commercial Paper

Revolving Credit Facility

Maturities

The aggregate maturities of our debt, excluding net unamortized premiums of $283.7 million, as of December 31, 2013 were as follows (in millions):



2014	$	47.5
2015	47.5
2016	1,019.7
2017	4.5
2018	4.5
Thereafter	3,359.0
Total	$	4,482.7

Interest expense totaled $158.8 million, $123.6 million and $95.9 million for the years ended December 31, 2013, 2012 and 2011, respectively, which was net of interest amounts capitalized of $67.7 million, $105.8 million and $80.2 million in connection with our newbuild rig construction and other capital projects.

6. DERIVATIVE INSTRUMENTS

We use derivatives to reduce our exposure to various market risks, primarily foreign currency exchange rate risk. 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 mitigate 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 entering into International Swaps and Derivatives Association, Inc. (“ISDA”) Master Agreements, which include provisions for a legally enforceable master netting agreement, with almost all of our derivative counterparties. See "Note 14 - Supplemental Financial Information" for additional information on the mitigation of credit risk relating to counterparties of our derivatives. We do not enter into derivatives for trading or other speculative purposes.

All derivatives were recorded on our consolidated balance sheets at fair value. Derivatives subject to legally enforceable master netting agreements were not offset on our consolidated balance sheets. Accounting for the gains and losses resulting from changes in the fair value of derivatives depends on the use of the derivative and whether it qualifies for hedge accounting. See "Note 1 - Description of the Business and Summary of Significant Accounting Policies" for additional information on our accounting policy for derivatives and "Note 3 - Fair Value Measurements" for additional information on the fair value measurement of our derivatives.

As of December 31, 2013 and 2012, our consolidated balance sheets included net foreign currency derivative assets of $1.8 million and $5.2 million, respectively. All of our derivatives mature during the next 18 months. Derivatives recorded at fair value on our consolidated balance sheets as of December 31, 2013 and 2012 consisted of the following (in millions):



	Derivative Assets				Derivative Liabilities
	2013		2012		2013		2012
Derivatives Designated as Hedging Instruments
Foreign currency forward contracts - current⁽¹⁾	$	9.1	$	5.0	$	9.8	$	.3
Foreign currency forward contracts - non-current⁽²⁾	1.2		.5		.6		—
	10.3		5.5		10.4		.3
Derivatives not Designated as Hedging Instruments
Foreign currency forward contracts - current⁽¹⁾	2.5		.2		.6		.2
	2.5		.2		.6		.2
Total	$	12.8	$	5.7	$	11.0	$	.5


⁽¹⁾	Derivative assets and liabilities that have maturity dates equal to or less than 12 months from the respective balance sheet dates were included in other current assets and accrued liabilities and other, respectively, on our consolidated balance sheets.


⁽²⁾	Derivative assets and liabilities that have maturity dates greater than 12 months from the respective balance sheet dates were included in other assets, net, and other liabilities, respectively, on our consolidated balance sheets.

We utilize cash flow hedges to hedge forecasted foreign currency denominated transactions, primarily to reduce our exposure to foreign currency exchange rate risk associated with contract drilling expenses and capital expenditures denominated in various currencies. As of December 31, 2013, we had cash flow hedges outstanding to exchange an aggregate $376.1 million for various foreign currencies, including $175.1 million for British pounds, $110.8 million for Brazilian reais, $35.3 million for Singapore dollars, $23.6 million for Australian dollars, $22.3 million for Euros and $9.0 million for other currencies.

Gains and losses, net of tax, on derivatives designated as cash flow hedges included in our consolidated statements of income and comprehensive income for each of the years in the three-year period ended December 31, 2013 were as follows (in millions):



	(Loss) Gain Recognized in Other Comprehensive Income ("OCI") on Derivatives (Effective Portion)							(Loss) Gain Reclassified from AOCI into Income (Effective Portion)⁽¹⁾									(Loss) Gain Recognized in Income on Derivatives (Ineffective Portion and Amount Excluded from Effectiveness Testing)⁽²⁾
	2013			2012		2011		2013			2012			2011			2013			2012			2011
Interest rate lock contracts⁽³⁾	$	—		$	—	$	—	$	(.4	)	$	(.5	)	$	(.5	)	$	—		$	—		$	—
Foreign currency forward contracts⁽⁴⁾	(5.8		)	8.7		.1		(1.6		)	.5			6.0			(.3		)	(.3		)	.3
Total	$	(5.8	)	$	8.7	$	.1	$	(2.0	)	$	—		$	5.5		$	(.3	)	$	(.3	)	$	.3


⁽¹⁾	Changes in the fair value of cash flow hedges are recorded in AOCI. Amounts recorded in AOCI associated with cash flow hedges are subsequently reclassified into contract drilling, depreciation or interest expense as earnings are affected by the underlying hedged forecasted transaction.


⁽²⁾	Gains and losses recognized in income for ineffectiveness and amounts excluded from effectiveness testing were included in other, net, in our consolidated statements of income.


⁽³⁾	Losses on interest rate lock derivatives reclassified from AOCI into income (effective portion) were included in interest expense, net in our consolidated statements of income.


⁽⁴⁾	During the year ended December 31, 2013, $2.5 million of losses were reclassified from AOCI into contract drilling expense and $900,000 of gains were reclassified from AOCI into depreciation expense in our consolidated statement of income.

We have net assets and liabilities denominated in numerous foreign currencies and use various methods to manage our exposure to foreign currency exchange rate risk. We predominantly structure our drilling contracts in U.S. dollars, which significantly reduces the portion of our cash flows and assets denominated in foreign currencies. We occasionally enter into derivatives that hedge the fair value of recognized foreign currency denominated assets or liabilities but do not designate such derivatives as hedging instruments. In these situations, a natural hedging relationship generally exists whereby changes in the fair value of the derivatives offset changes in the fair value of the underlying hedged items. As of December 31, 2013, we held derivatives not designated as hedging instruments to exchange an aggregate $208.9 million for various foreign currencies, including $97.9 million for Euros, $25.8 million for British pounds, $21.4 million for Swiss francs, $20.8 million for Brazilian reais, $16.5 million for Australian dollars, $13.9 million for Indonesian Rupiah and $12.6 million for other currencies.

Net gains of $3.6 million, $1.5 million and $500,000 associated with our derivatives not designated as hedging instruments were included in other, net, in our consolidated statements of income for the years ended December 31, 2013, 2012 and 2011, respectively.

As of December 31, 2013, the estimated amount of net losses associated with derivatives, net of tax, that will be reclassified to earnings during the next 12 months was as follows (in millions):



Net unrealized (losses) to be reclassified to contract drilling expense	$	(1.7	)
Net realized gains to be reclassified to depreciation expense	.9
Net realized (losses) to be reclassified to interest expense	(.4		)
Net (losses) to be reclassified to earnings	$	(1.2	)

7. SHAREHOLDERS' EQUITY

Activity in our various shareholders' equity accounts for each of the years in the three-year period ended December 31, 2013 was as follows (in millions):



	Shares	Par Value		Additional Paid-in Capital			Retained Earnings			AOCI			Treasury Shares			Noncontrolling Interest
BALANCE, December 31, 2010	150.1	$	15.1	$	637.1		$	5,305.0		$	11.1		$	(8.8	)	$	5.5
Net income	—	—		—			600.4			—			—			5.2
Cash dividends paid	—	—		—			(292.3		)	—			—			—
Distributions to noncontrolling interests	—	—		—			—			—			—			(5.5		)
Shares issued under share-based compensation plans, net	—	—		39.7			—			—			.2			—
Shares issued in connection with the Merger	85.8	8.6		4,568.9			—			—			—			—
Fair value of share options assumed in connection with the Merger	—	—		35.4			—			—			—			—
Equity issuance costs	—	—		(70.5		)	—			—			—			—
Tax benefit from share-based compensation	—	—		.5			—			—			—			—
Repurchase of shares	—	—		—			—			—			(10.5		)	—
Share-based compensation cost	—	—		41.9			—			—			—			—
Net other comprehensive loss	—	—		—			—			(2.5		)	—			—
BALANCE, December 31, 2011	235.9	23.7		5,253.0			5,613.1			8.6			(19.1		)	5.2
Net income	—	—		—			1,169.7			—			—			7.0
Cash dividends paid	—	—		—			(348.1		)	—			—			—
Distributions to noncontrolling interests	—	—		—			—			—			—			(6.5		)
Shares issued in connection with share-based compensation plans, net	1.8	.2		35.3			—			—			(.1		)	—
Equity issuance cost refunds	—	—		66.7			—			—			—			—
Tax deficiency from share-based compensation	—	—		(1.0		)	—			—			—			—
Repurchase of shares	—	—		—			—			—			(11.8		)	—
Share-based compensation cost	—	—		44.7			—			—			—			—
Net other comprehensive income	—	—		—			—			11.5			—			—
BALANCE, December 31, 2012	237.7	23.9		5,398.7			6,434.7			20.1			(31.0		)	5.7
Net income	—	—		—			1,418.2			—			—			9.7
Cash dividends paid	—	—		—			(525.6		)	—			—			—
Distributions to noncontrolling interests	—	—		—			—			—			—			(8.1		)
Shares issued in connection with share-based compensation plans, net	1.9	.2		21.8			—			—			(.1		)	—
Tax benefit from share-based compensation	—	—		.1			—			—			—			—
Repurchase of shares	—	—		—			—			—			(14.1		)	—
Share-based compensation cost	—	—		46.6			—			—			—			—
Net other comprehensive loss	—	—		—			—			(1.9		)	—			—
BALANCE, December 31, 2013	239.6	$	24.1	$	5,467.2		$	7,327.3		$	18.2		$	(45.2	)	$	7.3

In May 2013, our shareholders approved a new share repurchase program. Subject to certain provisions under English law, including the requirement of Ensco plc to have sufficient distributable reserves, we may purchase up to a maximum of $2.0 billion in the aggregate under the program, but in no case more than 35.0 million shares. The program terminates in May 2018. As of December 31, 2013, there had been no share repurchases under this program.

8. BENEFIT PLANS

During 2012, our shareholders approved the 2012 Long-Term Incentive Plan (the “2012 LTIP”) effective January 1, 2012, to provide for the issuance of non-vested share awards, share option awards and performance awards (collectively "awards"). The 2012 LTIP is similar to and replaces the Company's previously adopted 2005 Long-Term Incentive Plan. Under the 2012 LTIP, 14.0 million shares were reserved for issuance as awards to officers, non-employee directors and key employees who are in a position to contribute materially to our growth, development and long-term success. As of December 31, 2013, there were 9.8 million shares available for issuance as awards under the 2012 LTIP. Awards may be satisfied by newly issued shares, including shares held by a subsidiary or affiliated entity, or by delivery of shares held in an affiliated employee benefit trust at the Company's discretion.

Non-Vested Share Awards

Grants of non-vested share awards generally vest at rates of 20% or 33% per year, as determined by a committee or subcommittee of the Board of Directors at the time of grant. Our non-vested share awards have voting and dividend rights effective on the date of grant. Compensation expense is measured using the market value of our shares on the date of grant and is recognized on a straight-line basis over the requisite service period (usually the vesting period).

The following table summarizes non-vested share award related compensation expense recognized during each of the years in the three-year period ended December 31, 2013 (in millions):



	2013			2012			2011
Contract drilling	$	21.3		$	17.1		$	17.0
General and administrative	21.6			24.8			21.5
Non-vested share award related compensation expense included in operating expenses	42.9			41.9			38.5
Tax benefit	(5.4		)	(7.0		)	(6.9		)
Total non-vested share award related compensation expense included in net income	$	37.5		$	34.9		$	31.6

The following table summarizes the value of non-vested share awards granted and vested during each of the years in the three-year period ended December 31, 2013:



	2013		2012		2011
Weighted-average grant-date fair value of non-vested share awards granted (per share)	$	59.79	$	48.32	$	52.50
Total fair value of non-vested share awards vested during the period (in millions)	$	49.6	$	42.5	$	41.0

The following table summarizes non-vested share award activity for the year ended December 31, 2013 (shares in thousands):



	Shares		Weighted-Average Grant-Date Fair Value
Non-vested share awards as of December 31, 2012	2,491		$	46.52
Granted	1,018		59.79
Vested	(829	)	49.96
Forfeited	(184	)	49.16
Non-vested share awards as of December 31, 2013	2,496		$	52.95

As of December 31, 2013, there was $100.5 million of total unrecognized compensation cost related to non-vested share awards, which is expected to be recognized over a weighted-average period of 2.2 years.

Share Option Awards

Share option awards ("options") granted to officers and employees generally become exercisable in 25% increments over a four-year period or 33% increments over a three-year period and, to the extent not exercised, expire on the seventh anniversary of the date of grant. Options granted to non-employee directors are immediately exercisable and, to the extent not exercised, expire on the seventh anniversary of the date of grant. The exercise price of options granted under the 2012 LTIP equals the market value of the underlying shares on the date of grant. As of December 31, 2013, options granted under predecessor or acquired plans to purchase 814,000 shares were outstanding under the 2012 LTIP.

The following table summarizes option related compensation expense recognized during each of the years in the three-year period ended December 31, 2013 (in millions):



	2013			2012			2011
General and administrative	$	.8		$	1.6		$	2.5
Option related compensation expense included in operating expenses	.8			1.6			2.5
Tax benefit	(.1		)	(.3		)	(.5		)
Total option related compensation expense included in net income	$	.7		$	1.3		$	2.0

The fair value of each option is estimated on the date of grant using the Black-Scholes option valuation model. We did not grant share option awards during the years ended December 31, 2013 and 2012. The following weighted-average assumptions were utilized in the Black-Scholes model for options granted during the year ended December 31, 2011:



	2011
Risk-free interest rate	1.4	%
Expected term (in years)	3.7
Expected volatility	50.2	%
Dividend yield	2.6	%

Expected volatility is based on the historical volatility in the market price of our shares over the period of time equivalent to the expected term of the options granted. The expected term of options granted is derived from historical exercise patterns over a period of time equivalent to the contractual term of the options granted. We have not experienced significant differences in the historical exercise patterns among officers, employees and non-employee directors for them to be considered separately for valuation purposes. The risk-free interest rate is based on the implied yield of

U.S. Treasury zero-coupon issues on the date of grant with a remaining term approximating the expected term of the options granted.

The following table summarizes option activity for the year ended December 31, 2013 (shares and intrinsic value in thousands, term in years):



	Shares		Weighted-Average Exercise Price		Weighted-Average Contractual Term	Intrinsic Value
Outstanding as of December 31, 2012	1,346		$	46.05
Granted	—		—
Exercised	(506	)	43.96
Forfeited	—		—
Expired	(26	)	51.24
Outstanding as of December 31, 2013	814		$	47.18	2.5	$	9,065
Exercisable as of December 31, 2013	780		$	46.85	2.4	$	8,986

The following table summarizes the value of options granted and exercised during each of the years in the three-year period ended December 31, 2013:



	2013		2012		2011
Weighted-average grant-date fair value of options granted (per share)	$	—	$	—	$	19.05
Intrinsic value of options exercised during the year (in millions)	$	8.7	$	17.8	$	17.2

The following table summarizes information about options outstanding as of December 31, 2013 (shares in thousands):



	Options Outstanding			Options Exercisable
	Number	Weighted-Average Remaining	Weighted-Average	Number	Weighted-Average
Exercise Prices	Outstanding	Contractual Life	Exercise Price	Exercisable	Exercise Price
$21.54 - $40.99	247	3.1 years	$33.51	247	$33.51
41.18 - 54.30	229	3.5 years	43.77	217	43.22
55.34 - 60.74	338	1.3 years	59.50	316	59.79
	814	2.5 years	$47.18	780	$46.85

As of December 31, 2013, there was $200,000 of total unrecognized compensation cost related to options, which is expected to be recognized over a weighted-average period of 0.3 years.

Performance Awards

Under the 2012 LTIP, performance awards may be issued to our senior executive officers. Performance awards granted prior to 2013 are payable in Ensco shares, cash or a combination thereof upon attainment of specified performance goals based on relative total shareholder return ("TSR") and absolute and relative return on capital employed ("ROCE"). Performance awards granted during 2013 are payable in Ensco shares upon attainment of specified performance goals based on relative TSR and relative ROCE. The performance goals are determined by a committee or subcommittee of the Board of Directors.

Performance awards generally vest at the end of a three-year measurement period based on attainment of performance goals. Our performance awards granted prior to 2013 are classified as liability awards with compensation expense measured based on the estimated probability of attainment of the specified performance goals and recognized on a straight-line basis over the requisite service period. The estimated probable outcome of attainment of the specified performance goals is based on historical experience, and any subsequent changes in this estimate are recognized as a cumulative adjustment to compensation cost in the period in which the change in estimate occurs. Our performance awards granted during 2013 are classified as equity awards with compensation expense recognized on a straight-line basis over the requisite service period. The estimated probable outcome of attainment of the specified performance goals is based on historical experience, and any subsequent changes in this estimate for the relative ROCE performance goal are recognized as a cumulative adjustment to compensation cost in the period in which the change in estimate occurs. The aggregate grant-date fair value of performance awards granted during 2013, 2012 and 2011 totaled $8.2 million, $7.2 million and $3.1 million, respectively. The aggregate fair value of performance awards vested during 2013, 2012 and 2011 totaled $7.4 million, $5.3 million and $5.6 million, respectively, all of which was paid in cash.

During the years ended December 31, 2013, 2012 and 2011, we recognized $6.6 million, $9.7 million and $6.7 million of compensation expense for performance awards, respectively, which was included in general and administrative expense in our consolidated statements of income. As of December 31, 2013, there was $8.7 million of total unrecognized compensation cost related to unvested performance awards, which is expected to be recognized over a weighted-average period of 1.8 years.

Savings Plans

We have profit sharing plans (the "Ensco Savings Plan," the "Ensco Multinational Savings Plan" and the "Ensco Limited Retirement Plan"), which cover eligible employees, as defined within each plan. The Ensco Savings Plan includes a 401(k) savings plan feature which allows eligible employees to make tax deferred contributions to the plan. The Ensco Limited Retirement Plan also allows eligible employees to make tax deferred contributions to the plan. Contributions made to the Ensco Multinational Savings Plan may or may not qualify for tax deferral based on each plan participant's local tax requirements.

We generally make matching cash contributions to the plans. We match 100% of the amount contributed by the employee up to a maximum of 5% of eligible salary. Matching contributions totaled $21.1 million, $16.5 million and $12.8 million for the years ended December 31, 2013, 2012 and 2011, respectively. Profit sharing contributions made into the plans require approval of the Board of Directors and are generally paid in cash. We recorded profit sharing contribution provisions of $55.3 million, $45.1 million and $21.1 million for the years ended December 31, 2013, 2012 and 2011, respectively. Matching contributions and profit sharing contributions become vested in 33% increments upon completion of each initial year of service with all contributions becoming fully vested subsequent to achievement of three or more years of service. We have 1.0 million shares reserved for issuance as matching contributions under the Ensco Savings Plan.

9. GOODWILL AND OTHER INTANGIBLE ASSETS AND LIABILITIES

Goodwill

The carrying amount of goodwill as of December 31, 2013 is detailed below by reporting unit (in millions):



Floaters		$3,081.4
Jackups	192.6
Total		$3,274.0

Drilling Contract Intangibles

In connection with the Merger, we recorded intangible assets and liabilities representing the estimated fair values of the acquired company's firm drilling contracts in place at the Merger Date with favorable or unfavorable contract terms as compared to then-current market day rates for comparable drilling rigs. The gross carrying amounts of our drilling contract intangibles, which we consider to be definite-lived intangibles assets and intangible liabilities, and accumulated amortization as of December 31, 2013 and 2012 were as follows (in millions):



	December 31, 2013								December 31, 2012
	Gross Carrying Amount		Accumulated Amortization			Net Carrying Amount			Gross Carrying Amount		Accumulated Amortization			Net Carrying Amount
Drilling contract intangible assets
Balance, beginning of period	$	209.0	$	(88.3	)	$	120.7		$	209.0	$	(36.4	)	$	172.6
Amortization	—		(42.3		)	(42.3		)	—		(51.9		)	(51.9		)
Balance, end of period	$	209.0	$	(130.6	)	$	78.4		$	209.0	$	(88.3	)	$	120.7

Drilling contract intangible liabilities
Balance, beginning of period	$	278.0	$	(160.0	)	$	118.0		$	278.0	$	(92.8	)	$	185.2
Amortization	—		(48.9		)	(48.9		)	—		(67.2		)	(67.2		)
Balance, end of period	$	278.0	$	(208.9	)	$	69.1		$	278.0	$	(160.0	)	$	118.0

The various factors considered in the determination of the fair values of our drilling contract intangibles were (1) the contracted day rate for each contract, (2) the remaining term of each contract, (3) the rig class and (4) the market conditions for each respective rig class at the Merger Date. The intangible assets and liabilities were calculated based on the present value of the difference in cash inflows over the remaining contract term as compared to a hypothetical contract with the same remaining term at an estimated then-current market day rate using a risk-adjusted discount rate and an estimated effective income tax rate.

We amortize the drilling contract intangibles to operating revenues over the respective remaining drilling contract terms on a straight-line basis. The estimated net (reduction) increase to future operating revenues related to the amortization of these intangible assets and liabilities as of December 31, 2013, is as follows (in millions):



2014	$	(4.3	)
2015	(4.5		)
2016	(.8		)
2017	.3
Total	$	(9.3	)

10. INCOME TAXES

We generated income of $173.4 million, $101.1 million and loss of $24.2 million from continuing operations before income taxes in the U.S. and $1.5 billion, $1.3 billion and $763.2 million of income from continuing operations before income taxes in non-U.S. countries for the years ended December 31, 2013, 2012 and 2011, respectively.

The following table summarizes components of the provision for income taxes from continuing operations for each of the years in the three-year period ended December 31, 2013 (in millions):



	2013			2012			2011
Current income tax expense:
U.S.	$	94.2		$	45.0		$	36.4
Non-U.S.	107.3			166.0			88.3
	201.5			211.0			124.7
Deferred income tax expense (benefit):
U.S.	19.8			29.6			(9.7		)
Non-U.S.	(8.6		)	(2.5		)	(3.4		)
	11.2			27.1			(13.1		)
Total income tax expense	$	212.7		$	238.1		$	111.6

Deferred Taxes

The following table summarizes significant components of deferred income tax assets (liabilities) as of December 31, 2013 and 2012 (in millions):



	2013			2012
Deferred tax assets:
Foreign tax credits	$	159.0		$	173.4
Premium on long-term debt	111.9			124.0
Net operating loss carryforwards	104.0			87.8
Employee benefits, including share-based compensation	41.7			33.4
Deferred revenue	19.4			22.7
Other	19.8			24.5
Total deferred tax assets	455.8			465.8
Valuation allowance	(232.6		)	(227.1		)
Net deferred tax assets	223.2			238.7
Deferred tax liabilities:
Property and equipment	(453.6		)	(472.9		)
Intercompany transfers of property	(29.2		)	(32.2		)
Deferred costs	(11.4		)	(20.9		)
Other	(24.0		)	(31.3		)
Total deferred tax liabilities	(518.2		)	(557.3		)
Net deferred tax liability	$	(295.0	)	$	(318.6	)
Net current deferred tax asset	$	20.9		$	13.8
Net noncurrent deferred tax liability	(315.9		)	(332.4		)
Net deferred tax liability	$	(295.0	)	$	(318.6	)

Unrecognized tax benefits of $21.0 million associated with a tax position taken in tax years with NOL carryforwards were presented as a reduction of deferred tax assets in accordance with Financial Accounting Standards Board ("FASB") ASC Topic 740 Income Taxes.

The realization of substantially all of our deferred tax assets is dependent on generating sufficient taxable income during future periods in various jurisdictions in which we operate. Realization of certain of our deferred tax

assets is not assured. We recognize a valuation allowance for deferred tax assets when it is more-likely-than-not that the benefit from the deferred tax asset will not be realized. The amount of deferred tax assets considered realizable could increase or decrease in the near-term if our estimates of future taxable income change.

As of December 31, 2013, we had deferred tax assets of $159.0 million for U.S. foreign tax credits (“FTC”) and $104.0 million related to $375.6 million of net operating loss (“NOL”) carryforwards, which can be used to reduce our income taxes payable in future years. The FTC expires between 2017 and 2023. NOL carryforwards, which were generated in various jurisdictions worldwide, include $231.4 million that do not expire and $144.2 million that will expire, if not utilized, beginning in 2014 through 2020. Due to the uncertainty of realization, we have a $228.8 million valuation allowance on FTC and NOL carryforwards, primarily relating to countries where we no longer operate or do not expect to generate future taxable income.

Effective Tax Rate



	2013		2012		2011
U.K. statutory income tax rate	23.3	%	24.5	%	26.5	%
Non-U.K. taxes	(13.7	)	(17.3	)	(18.1	)
Valuation allowance	1.9		4.8		4.7
Net expense associated with uncertain tax positions and other adjustments relating to prior years	.6		1.0		.8
Amortization of net deferred charges associated with intercompany rig sales	.1		.4		.8
Income taxes associated with restructuring transactions	—		3.7		—
Other	.6		(.1	)	.4
Effective income tax rate	12.8	%	17.0	%	15.1	%

In December 2012, we completed the restructuring of certain subsidiaries of the acquired company and recognized $51.2 million of income tax expense in connection therewith.

Our consolidated effective income tax rate for 2013 includes various discrete tax items. The majority of discrete tax expense recognized during 2013 was attributable to the recognition of a $7.4 million liability for taxes associated with a $30.6 million reimbursement from the resolution of a dispute with the Mexican tax authority and a $7.0 million increase in the valuation allowance on U.S. FTC resulting from a restructuring transaction in December 2013. Our consolidated effective income tax rate for 2012 also includes the impact of various discrete tax items. The majority of discrete tax expense recognized during 2012 was attributable to income tax expense associated with certain restructuring transactions in December 2012 and net income tax expense associated with liabilities for unrecognized tax benefits and other adjustments relating to prior years. Excluding the impact of the aforementioned discrete tax items, our consolidated effective income tax rate for the years ended December 31, 2013 and 2012 was 12.5% and 12.3%, respectively. The increase in our consolidated effective income tax rate, excluding discrete tax items, was due to the change in taxing jurisdictions in which our drilling rigs are operated and/or owned that resulted in an increase in the relative components of our earnings generated in taxing jurisdictions with higher tax rates.

tax benefits associated with a tax position taken in a prior year. Excluding the impact of the aforementioned discrete tax items, our consolidated effective income tax rate for the year ended December 31, 2011 was 13.0%. The decrease in our 2012 consolidated effective income tax rate, excluding discrete tax items, to 12.3% from 13.0% in 2011 was due to unrecognized benefits related to net operating losses and foreign tax credits of certain acquired subsidiaries in 2011 and changes in taxing jurisdictions in which our drilling rigs are operated and/or owned that resulted in an increase in the relative components of our earnings generated in taxing jurisdictions with lower tax rates.

Unrecognized Tax Benefits

Our tax positions are evaluated for recognition using a more-likely-than-not threshold, and those tax positions requiring recognition are measured as the largest amount of tax benefit that is greater than 50% likely of being realized upon effective settlement with a taxing authority that has full knowledge of all relevant information. As of December 31, 2013, we had $151.7 million of unrecognized tax benefits, of which $130.7 million was included in other liabilities on our consolidated balance sheet. Unrecognized tax benefits of $21.0 million associated with a tax position taken in tax years with NOL carryforwards were presented as a reduction of deferred tax assets in accordance with FASB ASC Topic 740 Income Taxes. If recognized, $127.4 million of our unrecognized tax benefits would impact our consolidated effective income tax rate. A reconciliation of the beginning and ending amount of unrecognized tax benefits for the years ended December 31, 2013 and 2012 is as follows (in millions):



	2013			2012
Balance, beginning of year	$	110.7		$	53.6
Increases in unrecognized tax benefits as a result of tax positions taken during prior years	35.8			21.3
Increases in unrecognized tax benefits as a result of tax positions taken during the current year	10.0			60.7
Decreases in unrecognized tax benefits as a result of tax positions taken during prior years	(3.7		)	(.4		)
Settlements with taxing authorities	—			(4.1		)
Lapse of applicable statutes of limitations	(1.1		)	(20.8		)
Impact of foreign currency exchange rates	—			.4
Balance, end of year	$	151.7		$	110.7

Accrued interest and penalties totaled $17.3 million and $18.9 million as of December 31, 2013 and 2012, respectively, and were included in other liabilities on our consolidated balance sheets. We recognized net benefits of $1.6 million, $2.8 million and $400,000 associated with interest and penalties during the years ended December 31, 2013, 2012 and 2011, respectively. Interest and penalties are included in current income tax expense in our consolidated statements of income.

Tax years as early as 2003 remain subject to examination in the major tax jurisdictions in which we operated. Ensco Delaware and Ensco United Incorporated, an indirect wholly-owned subsidiary of Ensco, participate in the U.S. Internal Revenue Service’s Compliance Assurance Process ("IRS CAP") which, among other things, provides for the resolution of tax issues in a timely manner and generally eliminates the need for lengthy post-filing examinations. The 2010, 2011 and 2012 U.S. federal tax returns of Ensco Delaware remain subject to examination under the IRS CAP.

Statutes of limitations applicable to certain of our tax positions lapsed during 2013, 2012 and 2011, resulting in net income tax benefits, inclusive of interest and penalties, of $3.1 million, $28.6 million and $4.2 million, respectively.

Statutes of limitations applicable to certain of our tax positions will lapse during 2014. Therefore, it is reasonably possible that our unrecognized tax benefits will decline during the next 12 months by $2.3 million, inclusive of $900,000 of accrued interest and penalties, all of which would impact our consolidated effective income tax rate if recognized.

Intercompany Transfer of Drilling Rigs

Subsequent to the Merger, we transferred ownership of several acquired drilling rigs among our subsidiaries, including five drillships during 2011, one jackup rig during 2012 and two semisubmersible rigs during 2013. The income tax liability associated with gains on the intercompany transfers of drilling rigs totaled $3.3 million and $10.3 million in 2012 and 2011, respectively. There was no income tax liability associated with the intercompany transfers of drilling rigs during 2013. The related income tax expense was deferred and is being amortized on a straight-line basis over the remaining useful lives of the associated rigs, which range from 15 to 35 years for the rigs transferred during 2012 and 2011. Similarly, the tax effects of $29.6 million of reversing temporary differences of the selling subsidiaries during 2011 also were deferred and are being amortized on the same basis and over the same periods as described above.

As of December 31, 2013 and 2012, the unamortized balance associated with deferred charges for income taxes incurred in connection with intercompany transfers of drilling rigs totaled $50.2 million and $58.3 million, respectively, and was included in other assets, net, on our consolidated balance sheets. Current income tax expense from continuing operations for the years ended December 31, 2013, 2012 and 2011 included $4.1 million, $9.1 million and $9.7 million, respectively, of amortization of income taxes incurred in connection with intercompany transfers of drilling rigs.

As of December 31, 2013 and 2012, the deferred tax liability associated with temporary differences of transferred drilling rigs totaled $29.2 million and $32.2 million, respectively, and was included in deferred income taxes on our consolidated balance sheets. Deferred income tax expense from continuing operations for the years ended December 31, 2013, 2012 and 2011 included benefits of $2.4 million, $3.4 million and $3.8 million, respectively, of amortization of deferred reversing temporary differences associated with intercompany transfers of drilling rigs.

Undistributed Earnings

Dividend income received by Ensco plc from its subsidiaries is exempt from U.K. taxation. We do not provide deferred taxes on undistributed earnings of certain subsidiaries because our policy and intention is to reinvest such earnings indefinitely. Each of the subsidiaries for which we maintain such policy has significant net assets, liquidity, contract backlog and/or other financial resources available to meet operational and capital investment requirements and otherwise allow us to continue to maintain our policy of reinvesting the undistributed earnings indefinitely.

In December 2012, a U.S. subsidiary received $530.0 million in earnings distributions from two non-U.S. subsidiaries. There was no net U.S. tax liability on the earnings repatriation, as we utilized net operating loss carryforwards to offset the previously untaxed portion of the earnings distribution. The earnings distribution was made in consideration of unique circumstances, and our U.S. subsidiaries continue to have significant net assets, liquidity, contract backlog and other financial resources available to meet operational and capital investment requirements. Accordingly, this distribution does not change, and we continue to maintain, our policy and intention to reinvest the undistributed earnings of the two aforementioned subsidiaries indefinitely.

As of December 31, 2013, the aggregate undistributed earnings of the subsidiaries for which we maintain a policy and intention to reinvest earnings indefinitely totaled $2.1 billion. Should we make a distribution from these subsidiaries in the form of dividends or otherwise, we would be subject to additional income taxes. The unrecognized deferred tax liability related to these undistributed earnings was not practicable to estimate as of December 31, 2013.

11. DISCONTINUED OPERATIONS

We sold the following rigs during the three-year period ended December 31, 2013 (in millions):



Rig	Date of Rig Sale	Segment⁽¹⁾	Net Proceeds		Net Book Value⁽²⁾		Pre-tax (Loss)/Gain⁽³⁾
Pride Pennsylvania	March 2013	Jackups	$	15.5	$	15.7	$	(.2	)
ENSCO 5003	December 2012	Floaters	68.2		89.4		(21.2		)
Pride Hawaii	October 2012	Jackups	18.8		16.8		2.0
ENSCO I	September 2012	Other	4.5		12.3		(7.8		)
ENSCO 61	June 2012	Jackups	31.7		19.6		12.1
ENSCO 59	May 2012	Jackups	22.8		21.9		.9
ENSCO 95	June 2011	Jackups	41.5		28.8		12.7
			$	203.0	$	204.5	$	(1.5	)

⁽¹⁾ The rigs' operating results were reclassified to discontinued operations in our consolidated statements of income for each of the years in the three-year period ended December 31, 2013 and were previously included within the operating segment noted in the above table.

⁽²⁾Includes the rig's net book value as well as inventory and other assets on the date of the sale.

⁽³⁾ The pre-tax (loss)/gain was included in loss from discontinued operations, net in our consolidated statement of income in the year of sale. Income tax expense of $900,000 and $10.9 million was recognized in connection with the sale of assets during the years ended December 31, 2013 and December 31, 2011, respectively. There was no net income tax expense recognized in connection with the sale of assets during the year ended December 31, 2012.

The following table summarizes (loss) income from discontinued operations for each of the years in the three-year period ended December 31, 2013 (in millions):



	2013			2012			2011
Revenues	$	399.9		$	438.2		$	243.5
Operating expenses	412.6			406.9			258.7
Operating (loss) income	(12.7		)	31.3			(15.2		)
Other income	.3			1.3			.2
Income tax (expense) benefit	(10.6		)	1.0			(8.6		)
(Loss) gain on disposal of discontinued operations, net	(1.1		)	(16.5		)	1.8
(Loss) income from discontinued operations	$	(24.1	)	$	17.1		$	(21.8	)

Debt and interest expense are not allocated to our discontinued operations.

In February 2014, we reached an agreement in principle to settle with the pipeline owner for $9.6 million. Accordingly, we recorded a $6.4 million charge for our remaining obligation under our liability insurance policy in loss from discontinued operations in our consolidated statement of income for the year ended December 31, 2013. The remaining $3.2 million was settled by our underwriters. See "Note 12 - Commitments and Contingencies" for additional information on the ENSCO 74 loss.

12. COMMITMENTS AND CONTINGENCIES

Leases

We are obligated under leases for certain of our offices and equipment. Rental expense relating to operating leases was $53.6 million, $47.5 million and $31.5 million during the years ended December 31, 2013, 2012 and 2011, respectively. Future minimum rental payments under our noncancellable operating lease obligations are as follows: $36.9 million during 2014; $20.1 million during 2015; $10.3 million during 2016; $9.5 million during 2017; $9.6 million during 2018 and $63.7 million thereafter.

Capital Commitments

The following table summarizes the cumulative amount of contractual payments made as of December 31, 2013 for our rigs under construction and estimated timing of our remaining contractual payments (in millions):



	Cumulative Paid⁽¹⁾		2014		2015		2016		Total⁽²⁾
ENSCO DS-8	161.4		383.2		—		—		544.6
ENSCO DS-9	157.4		373.2		—		—		530.6
ENSCO DS-10	103.0		103.0		307.4		—		513.4
ENSCO 110	41.0		—		166.1		—		207.1
ENSCO 122	49.0		202.0		—		—		251.0
ENSCO 123	53.5		—		—		213.8		267.3
	$	565.3	$	1,061.4	$	473.5	$	213.8	$	2,314.0


⁽¹⁾	Cumulative paid represents the aggregate amount of contractual payments made from commencement of the construction agreement through December 31, 2013.


⁽²⁾	Total commitments are based on fixed-price shipyard construction contracts, exclusive of costs associated with commissioning, systems integration testing, project management and capitalized interest.

Future contractual payments for rig enhancement projects, which are not reflected in the table above, are $94.2 million. We currently estimate these payments will be made during 2014.

The actual timing of these expenditures may vary based on the completion of various construction milestones, which are, to a large extent, beyond our control.

ENSCO 74 Loss

During 2008, ENSCO 74 was lost as a result of Hurricane Ike in the U.S. Gulf of Mexico. Portions of its legs remained underwater adjacent to the customer's platform, and the sunken rig hull of ENSCO 74 was located approximately 95 miles from the original drilling location when it was struck by an oil tanker during 2009. Wreck removal operations on the sunken rig hull of ENSCO 74 were completed during 2010.

During 2012, we entered into an agreement with the customer pursuant to which, among other matters, the customer agreed to remove the legs. Regardless of the actual removal costs incurred by the customer, we agreed to pay $19.0 million in nine installments upon the completion of certain milestones during the removal. We have insurance coverage for the actual removal costs incurred by the customer.

We have paid $19.0 million to the customer and received $18.5 million in insurance reimbursements through December 31, 2013. Our consolidated balance sheet as of December 31, 2013 included a $500,000 receivable for recovery of related costs under our insurance policy in other assets, net.

We filed a petition for exoneration or limitation of liability under U.S. admiralty and maritime law during 2009. A number of claimants presented claims in the exoneration/limitation proceedings. Currently, only three claimants remain. We have liability insurance policies that provide coverage for such claims as well as removal of wreckage and debris in excess of the property insurance policy sublimit, subject to a $10.0 million per occurrence deductible for third-party claims and an annual aggregate limit of $490.0 million.

The owner of the oil tanker that struck the hull of ENSCO 74 filed claims seeking monetary damages currently in excess of $5.0 million for losses incurred when the tanker struck the sunken hull of ENSCO 74. The owner of a pipeline filed claims alleging that ENSCO 74 caused the pipeline to rupture during Hurricane Ike and sought damages

for the cost of repairs and business interruption in an amount in excess of $26.0 million. We have reached an agreement in principle with the owner of the pipeline to settle the claims for $9.6 million. Prior to the settlement we incurred legal fees of $3.6 million for this matter. Accordingly, we accrued a $6.4 million liability as of December 31, 2013 for the remainder of our deductible under our liability insurance policy, which was included in accrued liabilities and other on our consolidated balance sheet. The remaining $3.2 million was paid by underwriters. Based on information currently available, primarily the adequacy of available defenses, we have not concluded that it is probable a liability exists with respect to the claim by the owner of the oil tanker.

We believe all liabilities associated with the ENSCO 74 loss during Hurricane Ike resulted from a single occurrence under the terms of the applicable insurance policies. However, legal counsel for certain liability underwriters have asserted that the liability claims arise from separate occurrences. In the event of multiple occurrences, the deductible is $15.0 million for two occurrences and $1.0 million for each occurrence thereafter.

Although we do not expect final disposition of the claims associated with the ENSCO 74 loss to have a material adverse effect upon our financial position, operating results or cash flows, there can be no assurances as to the ultimate outcome.

Asbestos Litigation

We and certain subsidiaries have been named as defendants, along with numerous third-party companies as co-defendants, in multi-party lawsuits filed in Mississippi and Louisiana by approximately 100 plaintiffs. The lawsuits seek an unspecified amount of monetary damages on behalf of individuals alleging personal injury or death, primarily under the Jones Act, purportedly resulting from exposure to asbestos on drilling rigs and associated facilities during the 1960s through the 1980s.

In December 2013, we reached an agreement in principle with 58 of the plaintiffs to settle lawsuits filed in Mississippi for a nominal amount. While we believe the special master's recommendations will be accepted by the plaintiffs and approved by the Court, there can be no assurances as to the ultimate outcome.

We intend to vigorously defend against the remaining claims and have filed responsive pleadings preserving all defenses and challenges to jurisdiction and venue. However, discovery is still ongoing and, therefore, available information regarding the nature of all pending claims is limited. At present, we cannot reasonably determine how many of the claimants may have valid claims under the Jones Act or estimate a range of potential liability exposure, if any.

In addition to the pending cases in Mississippi and Louisiana, we have other asbestos or lung injury claims pending against us in litigation in other jurisdictions. Although we do not expect final disposition of these asbestos or lung injury lawsuits to have a material adverse effect upon our financial position, operating results or cash flows, there can be no assurances as to the ultimate outcome of the lawsuits.

Other Matters

In addition to the foregoing, we are named defendants or parties in certain other lawsuits, claims or proceedings incidental to our business and are involved from time to time as parties to governmental investigations or proceedings, including matters related to taxation, arising in the ordinary course of business. Although the outcome of such lawsuits or other proceedings cannot be predicted with certainty and the amount of any liability that could arise with respect to such lawsuits or other proceedings cannot be predicted accurately, we do not expect these matters to have a material adverse effect on our financial position, operating results or cash flows.

In the ordinary course of business with customers and others, we have entered into letters of credit and surety bonds to guarantee our performance as it relates to our drilling contracts, contract bidding, customs duties, tax appeals and other obligations in various jurisdictions. Letters of credit and surety bonds outstanding as of December 31, 2013 totaled $232.3 million and are issued under facilities provided by various banks and other financial institutions. Obligations under these letters of credit and surety bonds are not normally called, as we typically comply with the

underlying performance requirement. As of December 31, 2013, we had not been required to make collateral deposits with respect to these agreements.

13. SEGMENT INFORMATION

Year Ended December 31, 2013



	Floaters		Jackups		Other		Operating Segments Total		Reconciling Items			Consolidated Total
Revenues	$	2,760.8	$	1,684.0	$	75.1	$	4,519.9	$	—		$	4,519.9
Operating expenses
Contract drilling (exclusive of depreciation)	1,209.7		811.9		58.5		2,080.1		—			2,080.1
Depreciation	364.8		156.9		—		521.7		6.5			528.2
General and administrative	—		—		—		—		146.8			146.8
Operating income (loss)	$	1,186.3	$	715.2	$	16.6	$	1,918.1	$	(153.3	)	$	1,764.8
Property and equipment, net	$	11,303.4	$	2,961.6	$	—	$	14,265.0	$	46.0		$	14,311.0
Capital expenditures	$	1,031.3	$	710.6	$	—	$	1,741.9	$	26.6		$	1,768.5

Year Ended December 31, 2012



	Floaters		Jackups		Other		Operating Segments Total		Reconciling Items			Consolidated Total
Revenues	$	2,300.8	$	1,485.6	$	82.8	$	3,869.2	$	—		$	3,869.2
Operating expenses
Contract drilling (exclusive of depreciation)	956.0		730.8		61.1		1,747.9		—			1,747.9
Depreciation	305.7		161.5		—		467.2		8.9			476.1
General and administrative	—		—		—		—		148.9			148.9
Operating income (loss)	$	1,039.1	$	593.3	$	21.7	$	1,654.1	$	(157.8	)	$	1,496.3
Property and equipment, net	$	10,727.6	$	2,389.8	$	—	$	13,117.4	$	28.2		$	13,145.6
Capital expenditures	$	1,520.1	$	192.2	$	—	$	1,712.3	$	2.7		$	1,715.0

Year Ended December 31, 2011



	Floaters		Jackups		Other		Operating Segments Total		Reconciling Items			Consolidated Total
Revenues	$	1,352.6	$	1,194.2	$	52.4	$	2,599.2	$	—		$	2,599.2
Operating expenses
Contract drilling (exclusive of depreciation)	630.2		613.0		42.9		1,286.1		—			1,286.1
Depreciation	189.1		164.1		—		353.2		4.4			357.6
General and administrative	—		—		—		—		158.6			158.6
Operating income (loss)	$	533.3	$	417.1	$	9.5	$	959.9	$	(163.0	)	$	796.9
Property and equipment, net	$	9,923.6	$	2,462.4	$	12.8	$	12,398.8	$	23.1		$	12,421.9
Capital expenditures	$	355.4	$	276.3	$	—	$	631.7	$	14.0		$	645.7

Information about Geographic Areas

As of December 31, 2013, our Floaters segment consisted of seven drillships, 13 dynamically positioned semisubmersible rigs and six moored semisubmersible rigs deployed in various locations throughout North and South America, Middle East and Africa, Asia Pacific, Europe and Mediterranean and Brazil. Additionally, our Floaters segment consisted of three ultra-deepwater drillships under construction in South Korea. Our Jackups segment consisted of 47 jackup rigs, of which 44 were deployed in various locations throughout North and South America, Middle East and Africa, Asia Pacific and Europe and Mediterranean, and three were under construction in Singapore.

As of December 31, 2013, the geographic distribution of our drilling rigs by operating segment was as follows:



	Floaters⁽¹⁾	Jackups⁽¹⁾	Total⁽¹⁾⁽²⁾
North & South America (excluding Brazil)	8	14	22
Middle East & Africa	6	10	16
Asia & Pacific Rim	3	10	13
Europe & Mediterranean	2	10	12
Brazil	7	—	7
Asia & Pacific Rim (under construction)	3	3	6
Total	29	47	76


⁽¹⁾	The table above includes the five floaters classified as "held for sale" as of June 30, 2014, as well as ENSCO 69, Pride Wisconsin and ENSCO 85 which were sold during 2014.


⁽²⁾	We provide management services on two rigs owned by third-parties not included in the table above.

For purposes of our geographic disclosure, we attribute revenues to the geographic location where such revenues are earned and assets to the geographic location of the drilling rig as of the end of the applicable year. For new construction projects, assets are attributed to the location of future operation if known or to the location of construction if the ultimate location of operation is undetermined. Information by country for those countries that account for more than 10% of total revenues or 10% of our long-lived assets was as follows (in millions):



	Revenues						Long-lived Assets
	2013		2012		2011		2013		2012		2011
United States	$	1,724.9	$	1,291.3	$	753.8	$	4,617.8	$	4,525.9	$	3,450.6
Brazil	683.7		776.3		430.9		2,447.5		2,911.3		3,101.8
Angola	467.1		341.6		209.5		2,543.7		2,147.2		1,347.9
Other countries	1,644.2		1,460.0		1,205.0		4,702.0		3,561.2		4,521.6
Total	$	4,519.9	$	3,869.2	$	2,599.2	$	14,311.0	$	13,145.6	$	12,421.9

14. SUPPLEMENTAL FINANCIAL INFORMATION

Consolidated Balance Sheet Information

Accounts receivable, net, as of December 31, 2013 and 2012 consisted of the following (in millions):



	2013			2012
Trade	$	869.8		$	812.4
Other	14.3			18.2
	884.1			830.6
Allowance for doubtful accounts	(28.4		)	(19.2		)
	$	855.7		$	811.4

The liquidity of OGX Petróleo e Gás Participações S.A. ("OGX") deteriorated during the second half of 2013, and on October 30, 2013, OGX filed for bankruptcy protection in Brazil. We did not recognize revenue for drilling services provided to OGX during the second half of 2013 as we concluded collectability of these amounts was not reasonably assured. Additionally, we recorded a $14.2 million provision for doubtful accounts during the year ended December 31, 2013 for receivables related to drilling services provided through June 30, 2013. Our receivables with OGX were fully reserved on our consolidated balance sheet as of December 31, 2013.

Other current assets as of December 31, 2013 and 2012 consisted of the following (in millions):



	2013		2012
Inventory	$	256.4	$	207.8
Prepaid taxes	88.1		62.2
Short-term investments	50.0		50.0
Deferred costs	47.4		46.9
Deferred tax assets	23.1		14.6
Prepaid expenses	18.5		20.3
Derivative assets	11.6		5.2
Assets held for sale	8.6		14.2
Other	10.2		4.2
	$	513.9	$	425.4

Other assets, net, as of December 31, 2013 and 2012 consisted of the following (in millions):



	2013		2012
Intangible assets	$	83.8	$	143.3
Deferred costs	59.1		45.2
Unbilled receivables	51.9		77.1
Prepaid taxes on intercompany transfers of property	50.2		58.3
Supplemental executive retirement plan assets	37.7		29.8
Warranty and other claim receivables	30.6		30.6
Deferred tax assets	25.2		19.3
Wreckage and debris removal receivables	.5		13.2
Other	13.7		5.0
	$	352.7	$	421.8

Accrued liabilities and other as of December 31, 2013 and 2012 consisted of the following (in millions):



	2013		2012
Personnel costs	$	242.0	$	231.1
Deferred revenue	169.8		146.9
Taxes	84.2		86.9
Accrued interest	68.0		67.9
Advance payment received on sale of assets	33.0		—
Customer pre-payments	20.0		—
Wreckage and debris removal	—		9.0
Other	41.7		42.6
	$	658.7	$	584.4

Other liabilities as of December 31, 2013 and 2012 consisted of the following (in millions):



	2013		2012
Deferred revenue	$	217.6	$	224.5
Unrecognized tax benefits (inclusive of interest and penalties)	148.0		129.6
Intangible liabilities	69.1		118.0
Supplemental executive retirement plan liabilities	40.5		33.3
Personnel costs	37.2		31.6
Other	33.3		36.4
	$	545.7	$	573.4

Accumulated other comprehensive income as of December 31, 2013 and 2012 consisted of the following (in millions):



	2013			2012
Derivative Instruments	$	20.6		$	24.4
Other	(2.4		)	(4.3		)
	$	18.2		$	20.1

Consolidated Statement of Income Information

Repair and maintenance expense related to continuing operations for each of the years in the three-year period ended December 31, 2013 was as follows (in millions):



	2013		2012		2011
Repair and maintenance expense	$	311.7	$	294.7	$	223.6

Consolidated Statement of Cash Flows Information

Net cash provided by operating activities of continuing operations attributable to the net change in operating assets and liabilities for each of the years in the three-year period ended December 31, 2013 was as follows (in millions):



	2013			2012		2011
(Increase) decrease in other assets	$	(98.4	)	$	68.3	$	6.7
(Decrease) increase in liabilities	(10.6		)	312.0		(33.9		)
(Increase) decrease in accounts receivable	(29.3		)	46.1		(215.9		)
	$	(138.3	)	$	426.4	$	(243.1	)

Cash paid for interest and income taxes of continuing operations for each of the years in the three-year period ended December 31, 2013 was as follows (in millions):



	2013		2012		2011
Interest, net of amounts capitalized	$	182.2	$	150.7	$	28.6
Income taxes	203.9		88.1		113.7

Capitalized interest totaled $67.7 million, $105.8 million and $80.2 million during the years ended December 31, 2013, 2012 and 2011, respectively. Capital expenditure accruals totaling $113.9 million, $111.1 million and $303.7 million for the years ended December 31, 2013, 2012 and 2011, respectively, were excluded from investing activities in our consolidated statements of cash flows.

Amortization of intangibles and other, net, included amortization of intangible assets and liabilities related to the estimated fair values of acquired Company firm drilling contracts in place at the Merger Date, debt premiums related to the fair value adjustment of acquired Company debt instruments, deferred charges for income taxes incurred on intercompany transfers of drilling rigs and certain other deferred costs.

Concentration of Risk

We are exposed to credit risk relating to our receivables from customers, our cash and cash equivalents and investments and our use of derivatives in connection with the management of foreign currency exchange rate risk. We mitigate our credit risk relating to receivables from customers, which consist primarily of major international, government-owned and independent oil and gas companies, by performing ongoing credit evaluations. We also maintain reserves for potential credit losses, which generally have been within management's expectations. We mitigate our credit risk relating to cash and investments by focusing on diversification and quality of instruments. Cash equivalents and short-term investments consist of a portfolio of high-grade instruments. Custody of cash and cash equivalents and short-term investments is maintained at several well-capitalized financial institutions, and we monitor the financial condition of those financial institutions.

We mitigate our credit risk relating to counterparties of our derivatives through a variety of techniques, including transacting with multiple, high-quality financial institutions, thereby limiting our exposure to individual counterparties and by entering into ISDA Master Agreements, which include provisions for a legally enforceable master netting agreement, with almost all of our derivative counterparties. The terms of the ISDA agreements may also include credit support requirements, cross default provisions, termination events, or set-off provisions. Legally enforceable master netting agreements reduce credit risk by providing protection in bankruptcy in certain circumstances and generally permitting the closeout and netting of transactions with the same counterparty upon the occurrence of certain events.

During the years ended December 31, 2013, 2012 and 2011, Petrobras, our largest customer, accounted for $604.8 million, $788.2 million and $364.5 million, or 13%, 20% and 14%, of consolidated revenues, respectively, all of which were attributable to our Floaters segment.

During the year ended December 31, 2013, revenues provided by our drilling operations in the U. S. Gulf of Mexico totaled $1.7 billion, or 38%, of consolidated revenues, of which 75% were attributable to our Floaters segment. Revenues provided by our drilling operations in Brazil and Angola during the year ended December 31, 2013 totaled $683.7 million and 467.1 million, or 15% and 10%, respectively, of consolidated revenues, all of which were attributable to our Floaters segment.

15. GUARANTEE OF REGISTERED SECURITIES

In connection with the Merger, Ensco plc and Pride entered into a supplemental indenture to the indenture dated as of July 1, 2004 between Pride and the Bank of New York Mellon, as indenture trustee, providing for, among other matters, the full and unconditional guarantee by Ensco plc of Pride’s 8.5% senior notes due 2019, 6.875% senior notes due 2020 and 7.875% senior notes due 2040, which had an aggregate outstanding principal balance of $1.7 billion as of December 31, 2013. The Ensco plc guarantee provides for the unconditional and irrevocable guarantee of the prompt payment, when due, of any amount owed to the holders of the notes.

Ensco plc is also a full and unconditional guarantor of the 7.2% Debentures due 2027 issued by Ensco Delaware in November 1997, which had an aggregate outstanding principal balance of $150.0 million as of December 31, 2013.

All guarantees are unsecured obligations of Ensco plc ranking equal in right of payment with all of its existing and future unsecured and unsubordinated indebtedness.

The following tables present our condensed consolidating statements of income for each of the years in the three-year period ended December 31, 2013; our condensed consolidating statements of comprehensive income for each of the years in the three-year period ended December 31, 2013; our condensed consolidating balance sheets as of December 31, 2013 and 2012; and our condensed consolidating statements of cash flows for each of the years in the three-year period ended December 31, 2013, in accordance with Rule 3-10 of Regulation S-X.



ENSCO PLC AND SUBSIDIARIES CONDENSED CONSOLIDATING STATEMENTS OF INCOME Year Ended December 31, 2013 (in millions)
	Ensco plc			ENSCO International Incorporated			Pride International, Inc.			Other Non-guarantor Subsidiaries of Ensco			Consolidating Adjustments			Total
OPERATING REVENUES	$	35.0		$	149.4		$	—		$	4,642.9		$	(307.4	)	$	4,519.9
OPERATING EXPENSES
Contract drilling (exclusive of depreciation)	27.5			149.4			—			2,210.6			(307.4		)	2,080.1
Depreciation	.3			4.0			—			523.9			—			528.2
General and administrative	63.5			.5			—			82.8			—			146.8
OPERATING (LOSS) INCOME	(56.3		)	(4.5		)	—			1,825.6			—			1,764.8
OTHER (EXPENSE) INCOME, NET	(65.6		)	(9.4		)	(27.9		)	2.8			—			(100.1		)
(LOSS) INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	(121.9		)	(13.9		)	(27.9		)	1,828.4			—			1,664.7
INCOME TAX PROVISION	—			92.5			—			120.2			—			212.7
DISCONTINUED OPERATIONS, NET	—			—			—			(24.1		)	—			(24.1		)
EQUITY EARNINGS IN AFFILIATES, NET OF TAX	1,540.1			366.2			111.6			—			(2,017.9		)	—
NET INCOME	1,418.2			259.8			83.7			1,684.1			(2,017.9		)	1,427.9
NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS	—			—			—			(9.7		)	—			(9.7		)
NET INCOME ATTRIBUTABLE TO ENSCO	$	1,418.2		$	259.8		$	83.7		$	1,674.4		$	(2,017.9	)	$	1,418.2



ENSCO PLC AND SUBSIDIARIES CONDENSED CONSOLIDATING STATEMENTS OF INCOME Year Ended December 31, 2012 (in millions)
	Ensco plc			ENSCO International Incorporated			Pride International, Inc.			Other Non-guarantor Subsidiaries of Ensco			Consolidating Adjustments			Total
OPERATING REVENUES	$	44.0		$	147.6		$	—		$	3,997.7		$	(320.1	)	$	3,869.2
OPERATING EXPENSES
Contract drilling (exclusive of depreciation)	51.2			147.6			—			1,869.2			(320.1		)	1,747.9
Depreciation	.4			3.5			—			472.2			—			476.1
General and administrative	63.8			.4			—			84.7			—			148.9
OPERATING (LOSS) INCOME	(71.4		)	(3.9		)	—			1,571.6			—			1,496.3
OTHER (EXPENSE) INCOME, NET	(41.8		)	(7.0		)	(50.0		)	.2			—			(98.6		)
(LOSS) INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	(113.2		)	(10.9		)	(50.0		)	1,571.8			—			1,397.7
INCOME TAX PROVISION	—			68.8			—			169.3			—			238.1
DISCONTINUED OPERATIONS, NET	—			—			—			17.1			—			17.1
EQUITY EARNINGS IN AFFILIATES, NET OF TAX	1,282.9			335.9			239.2			—			(1,858.0		)	—
NET INCOME	1,169.7			256.2			189.2			1,419.6			(1,858.0		)	1,176.7
NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS	—			—			—			(7.0		)	—			(7.0		)
NET INCOME ATTRIBUTABLE TO ENSCO	$	1,169.7		$	256.2		$	189.2		$	1,412.6		$	(1,858.0	)	$	1,169.7



ENSCO PLC AND SUBSIDIARIES CONDENSED CONSOLIDATING STATEMENTS OF INCOME Year Ended December 31, 2011 (in millions)
	Ensco plc			ENSCO International Incorporated			Pride International, Inc.			Other Non-guarantor Subsidiaries of Ensco			Consolidating Adjustments			Total
OPERATING REVENUES	$	—		$	70.0		$	—		$	2,671.0		$	(141.8	)	$	2,599.2
OPERATING EXPENSES
Contract drilling (exclusive of depreciation)	46.9			70.0			—			1,311.0			(141.8		)	1,286.1
Depreciation	.4			1.8			—			355.4			—			357.6
General and administrative	52.2			—			—			106.4			—			158.6
OPERATING (LOSS) INCOME	(99.5		)	(1.8		)	—			898.2			—			796.9
OTHER INCOME (EXPENSE), NET	32.1			.4			(22.7		)	(67.7		)	—			(57.9		)
(LOSS) INCOME BEFORE INCOME TAXES	(67.4		)	(1.4		)	(22.7		)	830.5			—			739.0
INCOME TAX PROVISION	—			38.5			1.5			71.6			—			111.6
DISCONTINUED OPERATIONS, NET	—			(11.1		)	—			(10.7		)				(21.8		)
EQUITY EARNINGS IN AFFILIATES, NET OF TAX	667.8			271.5			143.9			—			(1,083.2		)	—
NET INCOME	600.4			220.5			119.7			748.2			(1,083.2		)	605.6
NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS	—			—			—			(5.2		)	—			(5.2		)
NET INCOME ATTRIBUTABLE TO ENSCO	$	600.4		$	220.5		$	119.7		$	743.0		$	(1,083.2	)	$	600.4

ENSCO PLC AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME

Year Ended December 31, 2013

(in millions)



	Ensco plc		ENSCO International Incorporated			Pride International, Inc.		Other Non-Guarantor Subsidiaries of Ensco			Consolidating Adjustments			Total

NET INCOME	$	1,418.2	$	259.8		$	83.7	$	1,684.1		$	(2,017.9	)	$	1,427.9
OTHER COMPREHENSIVE (LOSS) INCOME, NET
Net change in fair value of derivatives	—		(5.8		)	—		—			—			(5.8		)
Reclassification of net losses on derivative instruments from other comprehensive income into net income	—		2.0			—		—			—			2.0
Other	—		—			—		1.9			—			1.9
NET OTHER COMPREHENSIVE (LOSS) INCOME	—		(3.8		)	—		1.9			—			(1.9		)

COMPREHENSIVE INCOME	1,418.2		256.0			83.7		1,686.0			(2,017.9		)	1,426.0
COMPREHENSIVE INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS	—		—			—		(9.7		)	—			(9.7		)
COMPREHENSIVE INCOME ATTRIBUTABLE TO ENSCO	$	1,418.2	$	256.0		$	83.7	$	1,676.3		$	(2,017.9	)	$	1,416.3

ENSCO PLC AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME

Year Ended December 31, 2012

(in millions)



	Ensco plc		ENSCO International Incorporated		Pride International, Inc.		Other Non-Guarantor Subsidiaries of Ensco			Consolidating Adjustments			Total

NET INCOME	$	1,169.7	$	256.2	$	189.2	$	1,419.6		$	(1,858.0	)	$	1,176.7
OTHER COMPREHENSIVE INCOME (LOSS), NET
Net change in fair value of derivatives	—		6.3		—		2.4			—			8.7
Reclassification of net losses (gains) on derivative instruments from other comprehensive income into net income	—		.2		—		(.2		)	—			—
Other	—		—		—		2.8			—			2.8
NET OTHER COMPREHENSIVE INCOME	—		6.5		—		5.0			—			11.5

COMPREHENSIVE INCOME	1,169.7		262.7		189.2		1,424.6			(1,858.0		)	1,188.2
COMPREHENSIVE INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS	—		—		—		(7.0		)	—			(7.0		)
COMPREHENSIVE INCOME ATTRIBUTABLE TO ENSCO	$	1,169.7	$	262.7	$	189.2	$	1,417.6		$	(1,858.0	)	$	1,181.2

ENSCO PLC AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME

Year Ended December 31, 2011

(in millions)



	Ensco plc		ENSCO International Incorporated			Pride International, Inc.		Other Non-Guarantor Subsidiaries of Ensco			Consolidating Adjustments			Total

NET INCOME	$	600.4	$	220.5		$	119.7	$	748.2		$	(1,083.2	)	$	605.6
OTHER COMPREHENSIVE (LOSS) INCOME, NET
Net change in fair value of derivatives	—		(4.2		)	—		4.3			—			.1
Reclassification of net losses (gains) on derivative instruments from other comprehensive income into net income	—		.2			—		(5.7		)	—			(5.5		)
Other	—		—			—		2.9			—			2.9
NET OTHER COMPREHENSIVE (LOSS) INCOME	—		(4.0		)	—		1.5			—			(2.5		)

COMPREHENSIVE INCOME	600.4		216.5			119.7		749.7			(1,083.2		)	603.1
COMPREHENSIVE INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS	—		—			—		(5.2		)	—			(5.2		)
COMPREHENSIVE INCOME ATTRIBUTABLE TO ENSCO	$	600.4	$	216.5		$	119.7	$	744.5		$	(1,083.2	)	$	597.9



ENSCO PLC AND SUBSIDIARIES CONDENSED CONSOLIDATING BALANCE SHEETS December 31, 2013 (in millions)
	Ensco plc		ENSCO International Incorporated		Pride International, Inc.		Other Non-guarantor Subsidiaries of Ensco		Consolidating Adjustments			Total
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	46.5	$	.5	$	4.9	$	113.7	$	—		$	165.6
Accounts receivable, net	—		—		—		855.7		—			855.7
Accounts receivable from affiliates	1,235.0		213.8		5.5		4,169.2		(5,623.5		)	—
Other	3.2		61.3		—		449.4		—			513.9
Total current assets	1,284.7		275.6		10.4		5,588.0		(5,623.5		)	1,535.2
PROPERTY AND EQUIPMENT, AT COST	2.1		34.3		—		17,462.1		—			17,498.5
Less accumulated depreciation	1.5		26.5		—		3,159.5		—			3,187.5
Property and equipment, net	.6		7.8		—		14,302.6		—			14,311.0
GOODWILL	—		—		—		3,274.0		—			3,274.0
DUE FROM AFFILIATES	4,876.8		4,236.0		1,898.0		5,069.7		(16,080.5		)	—
INVESTMENTS IN AFFILIATES	13,830.1		4,868.6		4,092.2		—		(22,790.9		)	—
OTHER ASSETS, NET	8.8		60.1		—		283.8		—			352.7
	$	20,001.0	$	9,448.1	$	6,000.6	$	28,518.1	$	(44,494.9	)	$	19,472.9
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable and accrued liabilities	$	31.5	$	9.1	$	34.2	$	925.0	$	—		$	999.8
Accounts payable to affiliates	3,666.1		549.7		—		1,407.7		(5,623.5		)	—
Current maturities of long-term debt	—		—		—		47.5		—			47.5
Total current liabilities	3,697.6		558.8		34.2		2,380.2		(5,623.5		)	1,047.3
DUE TO AFFILIATES	1,030.8		2,760.4		1,331.1		10,958.2		(16,080.5		)	—
LONG-TERM DEBT	2,473.7		149.1		2,007.8		88.3		—			4,718.9
DEFERRED INCOME TAXES	—		358.3		—		3.8		—			362.1
OTHER LIABILITIES	—		2.3		8.7		534.7		—			545.7
ENSCO SHAREHOLDERS' EQUITY	12,798.9		5,619.2		2,618.8		14,545.6		(22,790.9		)	12,791.6
NONCONTROLLING INTERESTS	—		—		—		7.3		—			7.3
Total equity	12,798.9		5,619.2		2,618.8		14,552.9		(22,790.9		)	12,798.9
	$	20,001.0	$	9,448.1	$	6,000.6	$	28,518.1	$	(44,494.9	)	$	19,472.9



ENSCO PLC AND SUBSIDIARIES CONDENSED CONSOLIDATING BALANCE SHEETS December 31, 2012 (in millions)
	Ensco plc		ENSCO International Incorporated		Pride International, Inc.		Other Non-guarantor Subsidiaries of Ensco		Consolidating Adjustments			Total
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	271.8	$	1.7	$	85.0	$	128.6	$	—		$	487.1
Accounts receivable, net	—		.2		—		811.2		—			811.4
Accounts receivable from affiliates	1,294.5		226.5		—		2,375.1		(3,896.1		)	—
Other	2.8		24.9		—		397.7		—			425.4
Total current assets	1,569.1		253.3		85.0		3,712.6		(3,896.1		)	1,723.9
PROPERTY AND EQUIPMENT, AT COST	2.1		30.2		—		15,704.8		—			15,737.1
Less accumulated depreciation	1.1		23.5		—		2,566.9		—			2,591.5
Property and equipment, net	1.0		6.7		—		13,137.9		—			13,145.6
GOODWILL	—		—		—		3,274.0		—			3,274.0
DUE FROM AFFILIATES	3,483.5		3,594.7		1,628.4		4,748.9		(13,455.5		)	—
INVESTMENTS IN AFFILIATES	13,469.3		2,693.8		3,824.8		—		(19,987.9		)	—
OTHER ASSETS, NET	11.3		67.4		—		343.1		—			421.8
	$	18,534.2	$	6,615.9	$	5,538.2	$	25,216.5	$	(37,339.5	)	$	18,565.3
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable and accrued liabilities	$	31.0	$	28.1	$	34.1	$	849.0	$	—		$	942.2
Accounts payable to affiliates	2,364.8		136.9		—		1,394.4		(3,896.1		)	—
Current maturities of long-term debt	—		—		—		47.5		—			47.5
Total current liabilities	2,395.8		165.0		34.1		2,290.9		(3,896.1		)	989.7
DUE TO AFFILIATES	1,816.7		2,054.7		877.5		8,706.6		(13,455.5		)	—
LONG-TERM DEBT	2,469.6		149.0		2,040.8		139.0		—			4,798.4
DEFERRED INCOME TAXES	—		335.1		—		16.6		—			351.7
OTHER LIABILITIES	—		—		10.8		562.6		—			573.4
ENSCO SHAREHOLDERS' EQUITY	11,852.1		3,912.1		2,575.0		13,495.1		(19,987.9		)	11,846.4
NONCONTROLLING INTERESTS	—		—		—		5.7		—			5.7
Total equity	11,852.1		3,912.1		2,575.0		13,500.8		(19,987.9		)	11,852.1
	$	18,534.2	$	6,615.9	$	5,538.2	$	25,216.5	$	(37,339.5	)	$	18,565.3



ENSCO PLC AND SUBSIDIARIES CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS Year Ended December 31, 2013 (in millions)
	Ensco plc			ENSCO International Incorporated			Pride International, Inc.			Other Non-guarantor Subsidiaries of Ensco			Consolidating Adjustments		Total
OPERATING ACTIVITIES
Net cash (used in) provided by operating activities of continuing operations	$	(114.8	)	$	(128.7	)	$	(62.9	)	$	2,193.1		$	—	$	1,886.7
INVESTING ACTIVITIES
Additions to property and equipment	—			—			—			(1,768.5		)	—		(1,768.5		)
Purchases of short-term investments	—			—			—			(50.0		)	—		(50.0		)
Maturities of short-term investments	—			—			—			50.0			—		50.0
Other	—			(4.1		)	—			10.1			—		6.0
Net cash used in investing activities of continuing operations	—			(4.1		)	—			(1,758.4		)	—		(1,762.5		)
FINANCING ACTIVITIES
Cash dividends paid	(525.6		)	—			—			—			—		(525.6		)
Reduction of long-term borrowings	—			—			—			(47.5		)	—		(47.5		)
Proceeds from exercise of share options	22.3			—			—			—			—		22.3
Debt financing costs	—			(4.6		)	—			—			—		(4.6		)
Advances from (to) affiliates	407.2			136.2			(17.2		)	(526.2		)	—		—
Other	(14.4		)	—			—			(7.3		)	—		(21.7		)
Net cash (used in) provided by financing activities	(110.5		)	131.6			(17.2		)	(581.0		)	—		(577.1		)
DISCONTINUED OPERATIONS
Operating activities	—			—			—			93.8			—		93.8
Investing activities	—			—			—			37.8			—		37.8
Net cash provided by discontinued operations	—			—			—			131.6			—		131.6
Effect of exchange rate changes on cash and cash equivalents	—			—			—			(.2		)	—		(.2		)
DECREASE IN CASH AND CASH EQUIVALENTS	(225.3		)	(1.2		)	(80.1		)	(14.9		)	—		(321.5		)
CASH AND CASH EQUIVALENTS, BEGINNING OF YEAR	271.8			1.7			85.0			128.6			—		487.1
CASH AND CASH EQUIVALENTS, END OF YEAR	$	46.5		$	.5		$	4.9		$	113.7		$	—	$	165.6



ENSCO PLC AND SUBSIDIARIES CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS Year Ended December 31, 2012 (in millions)
	Ensco plc			ENSCO International Incorporated			Pride International, Inc.			Other Non-guarantor Subsidiaries of Ensco			Consolidating Adjustments		Total
OPERATING ACTIVITIES
Net cash (used in) provided by operating activities of continuing operations	$	(71.6	)	$	(38.2	)	$	(21.6	)	$	2,205.5		$	—	$	2,074.1
INVESTING ACTIVITIES
Additions to property and equipment	—			—			—			(1,715.0		)	—		(1,715.0		)
Purchases of short-term investments	—			—			—			(90.0		)	—		(90.0		)
Maturities of short-term investments	—			—			—			44.5			—		44.5
Other	(.3		)	.4			—			3.1			—		3.2
Net cash (used in) provided by investing activities of continuing operations	(.3		)	.4			—			(1,757.4		)	—		(1,757.3		)
FINANCING ACTIVITIES
Cash dividends paid	(348.1		)	—			—			—			—		(348.1		)
Commercial paper borrowings, net	(125.0		)	—			—			—			—		(125.0		)
Equity issuance reimbursement	66.7			—			—			—			—		66.7
Reduction of long-term borrowings	—			—			—			(47.5		)	—		(47.5		)
Proceeds from exercise of share options	23.9			11.9			—			—			—		35.8
Advances from (to) affiliates	501.2			27.6			84.0			(612.8		)	—		—
Other	(11.6		)	—			—			(5.8		)	—		(17.4		)
Net cash provided by (used in) financing activities	107.1			39.5			84.0			(666.1		)	—		(435.5		)
DISCONTINUED OPERATIONS
Operating activities	—			—			—			113.0			—		113.0
Investing activities	—			—			—			60.1			—		60.1
Net cash provided by discontinued operations	—			—			—			173.1			—		173.1
Effect of exchange rate changes on cash and cash equivalents	—			—			—			2.0			—		2.0
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	35.2			1.7			62.4			(42.9		)	—		56.4
CASH AND CASH EQUIVALENTS, BEGINNING OF YEAR	236.6			—			22.6			171.5			—		430.7
CASH AND CASH EQUIVALENTS, END OF YEAR	$	271.8		$	1.7		$	85.0		$	128.6		$	—	$	487.1



ENSCO PLC AND SUBSIDIARIES CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS Year Ended December 31, 2011 (in millions)
	Ensco plc			ENSCO International Incorporated			Pride International, Inc.			Other Non-guarantor Subsidiaries of Ensco			Consolidating Adjustments		Total
OPERATING ACTIVITIES
Net cash provided by (used in) operating activities of continuing operations	$	2.0		$	(2.6	)	$	(59.9	)	$	817.9		$	—	$	757.4
INVESTING ACTIVITIES
Acquisition of Pride International, Inc., net of cash acquired	—			—			92.9			(2,748.9		)	—		(2,656.0		)
Additions to property and equipment	—			—			—			(645.7		)	—		(645.7		)
Purchases of short-term investments	—			—			—			(4.5		)	—		(4.5		)
Other	—			(6.1		)	—			11.4			—		5.3
Net cash (used in) provided by investing activities of continuing operations	—			(6.1		)	92.9			(3,387.7		)	—		(3,300.9		)
FINANCING ACTIVITIES
Proceeds from issuance of senior notes	2,462.8			—			—			—			—		2,462.8
Cash dividends paid	(292.3		)	—			—			—			—		(292.3		)
Reduction of long-term borrowings	—			—			(181.0		)	(32.3		)	—		(213.3		)
Commercial paper borrowings, net	125.0			—			—			—			—		125.0
Equity issuance cost	(70.5		)	—			—			—			—		(70.5		)
Proceeds from exercise of share options	—			39.9											39.9
Debt financing costs	(27.1		)	(4.7		)	—			—			—		(31.8		)
Advances (to) from affiliates	(1,956.1		)	(34.5		)	170.6			1,820.0			—		—
Other	(10.6		)	—			—			(5.1		)	—		(15.7		)
Net cash provided by (used in) financing activities	231.2			.7			(10.4		)	1,782.6			—		2,004.1
DISCONTINUED OPERATIONS
Operating activities	—			(11.1		)	—			(14.1		)	—		(25.2		)
Investing activities	—			—			—			(54.6		)	—		(54.6		)
Net cash used in discontinued operations	—			(11.1		)	—			(68.7		)	—		(79.8		)
Effect of exchange rate changes on cash and cash equivalents	—			—			—			(.8		)	—		(.8		)
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	233.2			(19.1		)	22.6			(856.7		)	—		(620.0		)
CASH AND CASH EQUIVALENTS, BEGINNING OF YEAR	3.4			19.1			—			1,028.2			—		1,050.7
CASH AND CASH EQUIVALENTS, END OF YEAR	$	236.6		$	—		$	22.6		$	171.5		$	—	$	430.7

16. UNAUDITED QUARTERLY FINANCIAL DATA

The following tables summarize our unaudited quarterly consolidated income statement data for the years ended December 31, 2013 and 2012 (in millions, except per share amounts):



2013	First Quarter			Second Quarter			Third Quarter			Fourth Quarter			Year
Operating revenues	$	1,040.3		$	1,130.3		$	1,162.2		$	1,187.1		$	4,519.9
Operating expenses
Contract drilling (exclusive of depreciation)	479.8			527.2			534.3			538.8			2,080.1
Depreciation	127.9			132.0			132.6			135.7			528.2
General and administrative	37.8			36.4			37.4			35.2			146.8
Operating income	394.8			434.7			457.9			477.4			1,764.8
Other expense, net	(29.8		)	(39.8		)	(1.6		)	(28.9		)	(100.1		)
Income from continuing operations before income taxes	365.0			394.9			456.3			448.5			1,664.7
Provision for income taxes	50.8			48.5			65.4			48.0			212.7
Income from continuing operations	314.2			346.4			390.9			400.5			1,452.0
Loss from discontinued operations, net	5.7			16.2			(9.5		)	(36.5		)	(24.1		)
Net income	319.9			362.6			381.4			364.0			1,427.9
Net income attributable to noncontrolling interests	(2.8		)	(1.7		)	(2.6		)	(2.6		)	(9.7		)
Net income attributable to Ensco	$	317.1		$	360.9		$	378.8		$	361.4		$	1,418.2
Earnings (loss) per share – basic
Continuing operations	$	1.34		$	1.48		$	1.66		$	1.71		$	6.19
Discontinued operations	0.02			0.07			(0.04		)	(0.16		)	(0.11		)
	$	1.36		$	1.55		$	1.62		$	1.55		$	6.08
Earnings (loss) per share – diluted
Continuing operations	$	1.34		$	1.48		$	1.66		$	1.70		$	6.18
Discontinued operations	0.02			0.07			(0.04		)	(0.16		)	(0.11		)
	$	1.36		$	1.55		$	1.62		$	1.54		$	6.07



2012	First Quarter			Second Quarter			Third Quarter			Fourth Quarter			Year
Operating revenues	$	916.5		$	965.7		$	1,013.9		$	973.1		$	3,869.2
Operating expenses
Contract drilling (exclusive of depreciation)	439.9			423.4			434.1			450.5			1,747.9
Depreciation	116.4			115.5			121.2			123.0			476.1
General and administrative	38.2			35.5			40.2			35.0			148.9
Operating income	322.0			391.3			418.4			364.6			1,496.3
Other expense, net	(26.7		)	(24.7		)	(25.5		)	(21.7		)	(98.6		)
Income from continuing operations before income taxes	295.3			366.6			392.9			342.9			1,397.7
Provision for income taxes	32.8			40.4			44.3			120.6			238.1
Income from continuing operations	262.5			326.2			348.6			222.3			1,159.6
(Loss) income from discontinued operations, net	4.9			16.5			(3.2		)	(1.1		)	17.1
Net income	267.4			342.7			345.4			221.2			1,176.7
Net income attributable to noncontrolling interests	(2.0		)	(1.4		)	(1.9		)	(1.7		)	(7.0		)
Net income attributable to Ensco	$	265.4		$	341.3		$	343.5		$	219.5		$	1,169.7
Earnings (loss) per share – basic
Continuing operations	$	1.13		$	1.40		$	1.49		$	0.95		$	4.97
Discontinued operations	0.02			0.07			(0.01		)	(0.01		)	0.08
	$	1.15		$	1.47		$	1.48		$	0.94		$	5.05
Earnings (loss) per share – diluted
Continuing operations	$	1.13		$	1.40		$	1.49		$	0.95		$	4.97
Discontinued operations	0.02			0.07			(0.01		)	(0.01		)	0.07
	$	1.15		$	1.47		$	1.48		$	0.94		$	5.04

17. SUBSEQUENT EVENTS

In January 2014, we closed on the sale of ENSCO 69 and Pride Wisconsin for $32.2 million. The proceeds were received in December 2013 and included in net cash used in investing activities of discontinued operations in our consolidated statement of cash flows for the year ended December 31, 2013 and accrued liabilities and other on our consolidated balance sheet as of December 31, 2013. We classified the rigs as held for sale during the fourth quarter of 2013 and included the $8.6 million aggregate net book value in other current assets on our consolidated balance sheet as of December 31, 2013. The gain on sale was recognized during the first quarter of 2014.

In April 2014, we sold ENSCO 85 for net proceeds of $64.4 million. The gain on sale was recognized during the second quarter of 2014.

During recent periods, a reduction in demand by operators combined with an oversupply of rigs has negatively impacted the floater market. The supply and demand imbalance has significantly challenged drilling contractors to contract older, less capable floaters.

During the second quarter of 2014, demand for floaters deteriorated further as a result of the continued reduction in capital spending by operators and recently announced delays in operators’ drilling programs. The further reduction in demand, when combined with the increasing supply from newbuild floater deliveries, has led to a very competitive market. In response to the adverse change in the current and anticipated floaters business climate, management evaluated

our older, less capable floaters during the three-month period ended June 30, 2014 and committed to a plan to sell five rigs. These rigs were written down to fair value, less costs to sell, and classified as "held for sale" on our June 30, 2014 condensed consolidated balance sheet. We recorded a pre-tax, non-cash loss on impairment totaling $546.4 million during the three-month period ended June 30, 2014.

As a result of the adverse change in the floater business climate observed during the second quarter of 2014, management's commitment to a plan to sell five floaters during the second quarter of 2014 and the impairment charge incurred on the "held for sale" floaters, management concluded that a triggering event had occurred during the second quarter of 2014 and performed an asset impairment analysis on our remaining older, less capable floaters. Based on the analysis performed, we recorded an additional non-cash loss on impairment with respect to four other floaters totaling $991.5 million during the three-month period ended June 30, 2014.

Valaris Limited (VAL) 8-K2013 FY Other Events