UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

  Washington, D.C. 20549  

FORM 10-K

(Mark One)

ý ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE  SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 2015

OR

o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from to  

Commission File Number 1-8097

 Ensco plc

(Exact name of registrant as specified in its charter)

England and Wales (State or other jurisdiction of incorporation or organization) 6 Chesterfield Gardens London, England (Address of principal executive offices) 98-0635229 (I.R.S. Employer Identification No.) W1J5BQ (Zip Code)

Registrant's telephone number, including area code: +44 (0) 20 7659 4660

Securities registered pursuant to Section 12(b) of the Act:

Title of each class Class A Ordinary Shares, U.S. $0.10 par value 4.50% Senior Notes due 2024 5.75% Senior Notes due 2044 5.20% Senior Notes due 2025 4.70% Senior Notes due 2021 Name of each exchange on which registered New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer as defined in Rule 405 of the Securities Act.        Yes ý       No  o

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.   Yes  o       No ý

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15 (d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  Yes ý       No  o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (S232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).   Yes  ý       No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (S229.405) is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act (Check one):

Large accelerated filer	x	Accelerated filer	o
Non-Accelerated filer	o  (Do not check if a smaller reporting company)	Smaller reporting company	o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).

Yes o        No ý

The aggregate market value of the Class A ordinary shares (based upon the closing price on the New York Stock Exchange on June 30, 2015 of $22.27) of Ensco plc held by non-affiliates of Ensco plc at that date was approximately $5,225,851,000.

As of February 19, 2016, there were 235,274,198 Class A ordinary shares of Ensco plc issued and outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Company's Proxy Statement for the 2016 General Meeting of Shareholders are incorporated by reference into Part III of this report.

TABLE OF CONTENTS
PART I	ITEM 1.	BUSINESS	4
	ITEM 1A.	RISK FACTORS	16
	ITEM 1B.	UNRESOLVED STAFF COMMENTS	37
	ITEM 2.	PROPERTIES	38
	ITEM 3.	LEGAL PROCEEDINGS	40
	ITEM 4.	MINE SAFETY DISCLOSURES	43
PART II	ITEM 5.	MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED SHAREHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES	44
	ITEM 6.	SELECTED FINANCIAL DATA	51
	ITEM 7.	MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	53
	ITEM 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	84
	ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	84
	ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	148
	ITEM 9A.	CONTROLS AND PROCEDURES	148
	ITEM 9B.	OTHER INFORMATION	148
PART III	ITEM 10.	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE	149
	ITEM 11.	EXECUTIVE COMPENSATION	149
	ITEM 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED SHAREHOLDER MATTERS	150
	ITEM 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE	150
	ITEM 14.	PRINCIPAL ACCOUNTING FEES AND SERVICES	150
PART IV	ITEM 15.	EXHIBITS, FINANCIAL STATEMENT SCHEDULES	151
		SIGNATURES	158

FORWARD-LOOKING STATEMENTS

Statements contained in this report that are not historical facts are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended (the "Exchange Act").  Forward-looking statements include words or phrases such as "anticipate," "believe," "estimate," "expect," "intend," "plan," "project," "could," "may," "might," "should," "will" and similar words and specifically include statements regarding expected financial performance; dividends; expected utilization, day rates, revenues, operating expenses, contract terms, contract backlog, capital expenditures, insurance, financing and funding; the timing of availability, delivery, mobilization, contract commencement or relocation or other movement of rigs and the timing thereof; future rig construction (including construction in progress and completion thereof), enhancement, upgrade or repair and timing and cost thereof; the suitability of rigs for future contracts; the offshore drilling market, including supply and demand, customer drilling programs, stacking of rigs, effects of new rigs on the market and effects of declines in commodity prices; general market, business and industry conditions, trends and outlook; future operations; the impact of increasing regulatory complexity; expected contributions from our rig fleet expansion program and our program to high-grade the rig fleet by investing in new equipment and divesting selected assets and underutilized rigs; expense management; and the likely outcome of litigation, legal proceedings, investigations or insurance or other claims or contract disputes and the timing thereof.

Such statements are subject to numerous risks, uncertainties and assumptions that may cause actual results to vary materially from those indicated, including:

• downtime and other risks associated with offshore rig operations, including rig or equipment failure, damage and other unplanned repairs, the limited availability of transport vessels, hazards, self-imposed drilling limitations and other delays due to severe storms and hurricanes and the limited availability or high cost of insurance coverage for certain offshore perils, such as hurricanes in the Gulf of Mexico or associated removal of wreckage or debris;

• changes in worldwide rig supply and demand, competition or technology, including as a result of delivery of newbuild drilling rigs;

• changes in future levels of drilling activity and expenditures by our customers, whether as a result of global capital markets and liquidity, prices of oil and natural gas or otherwise, which may cause us to idle or stack additional rigs;

• governmental action, terrorism, piracy, military action and political and economic uncertainties, including uncertainty or instability resulting from civil unrest, political demonstrations, mass strikes, or an escalation or additional outbreak of armed hostilities or other crises in oil or natural gas producing areas of the Middle East, North Africa, West Africa or other geographic areas, which may result in expropriation, nationalization, confiscation or deprivation of our assets or suspension and/or termination of contracts based on force majeure events;

• risks inherent to shipyard rig construction, repair, modification or upgrades, including risks associated with concentration of our construction contracts with three shipyards, unexpected delays in equipment delivery, engineering, design or commissioning issues following delivery, or changes in the commencement, completion or service dates;

• possible cancellation, suspension, renegotiation or termination (with or without cause) of drilling contracts as a result of general and industry-specific economic conditions, mechanical difficulties, performance or other reasons;

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• our ability to enter into, and the terms of, future drilling contracts, including contracts for our newbuild units, for rigs currently idled and for rigs whose contracts are expiring;

• the outcome of litigation, legal proceedings, investigations or other claims or contract disputes, including any inability to collect receivables or resolve significant contractual or day rate disputes, any renegotiation, nullification, cancellation or breach of contracts with customers or other parties and any failure to execute definitive contracts following announcements of letters of intent;

• governmental regulatory, legislative and permitting requirements affecting drilling operations, including limitations on drilling locations (such as the Gulf of Mexico during hurricane season);

• new and future regulatory, legislative or permitting requirements, future lease sales, changes in laws, rules and regulations that have or may impose increased financial responsibility, additional oil spill abatement contingency plan capability requirements and other governmental actions that may result in claims of force majeure or otherwise adversely affect our existing drilling contracts;

• our ability to attract and retain skilled personnel on commercially reasonable terms, whether due to labor regulations, unionization or otherwise;

• environmental or other liabilities, risks, damages or losses, whether related to storms or hurricanes (including wreckage or debris removal), collisions, groundings, blowouts, fires, explosions, other accidents, terrorism or otherwise, for which insurance coverage and contractual indemnities may be insufficient, unenforceable or otherwise unavailable;

• our ability to obtain financing and pursue other business opportunities may be limited by our debt levels, debt agreement restrictions and the credit ratings assigned to our debt by independent credit rating agencies;

• tax matters, including our effective tax rates, tax positions, results of audits, changes in tax laws, treaties and regulations, tax assessments and liabilities for taxes;

• delays in contract commencement dates or the cancellation of drilling programs by operators;

• adverse changes in foreign currency exchange rates, including their effect on the fair value measurement of our derivative instruments; and

• potential long-lived asset impairments.

In addition to the numerous risks, uncertainties and assumptions described above, you should also carefully read and consider "Item 1A. Risk Factors" in Part I and "Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations" in Part II of this Form 10-K.  Each forward-looking statement speaks only as of the date of the particular statement, and we undertake no obligation to publicly update or revise any forward looking statements, except as required by law.

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PART I

Item 1.  Business

General

Ensco plc is a global offshore contract drilling company. Unless the context requires otherwise, the terms "Ensco," "Company," "we," "us" and "our" refer to Ensco plc together with all its subsidiaries and predecessors.

We are one of the leading providers of offshore contract drilling services to the international oil and gas industry.

We own and operate an offshore drilling rig fleet of 64 rigs spanning most of the strategic markets around the globe. Our rig fleet includes ten drillships, 13 dynamically positioned semisubmersible rigs, three moored semisubmersible rigs and 42 jackup rigs, including four rigs under construction. Our fleet is the world's second largest amongst competitive rigs, our ultra-deepwater fleet is one of the newest in the industry, and our premium jackup fleet is the largest of any offshore drilling company.

Our customers include many 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 spanning approximately 15 countries on six continents. 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.

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 each day we are performing drilling or related services. Our customers bear substantially all of the 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.

Ensco plc is a public limited company incorporated under the laws of England and Wales. Our principal executive office is located at 6 Chesterfield Gardens, London W1J5BQ, England, United Kingdom, and our telephone number is +44 (0) 20 7659 4660.  Our website is www.enscoplc.com.  Information contained on our website is not included as part of, or incorporated by reference into, this report.

Acquisitions

We have grown our rig fleet through corporate acquisitions and new rig construction. A total of seven drillships, eight semisubmersible rigs and 25 jackup rigs in our current fleet were obtained through the acquisitions of Penrod Holding Corporation during 1993, Dual Drilling Company during 1996, Chiles Offshore Inc. during 2002 and Pride International, Inc. ("Pride") during 2011.  

Drilling Rig Construction and Delivery

We remain focused on our long-established strategy of high-grading our fleet. We will continue to invest in the expansion of our fleet where we believe strategic opportunities exist.  During the three-year period ended December 31, 2015, we invested approximately $3.2 billion in the construction of new drilling rigs.

During 2014, we entered into an agreement with Lamprell Energy Limited to construct two premium jackup rigs. ENSCO 140 and ENSCO 141 are significantly enhanced versions of the LeTorneau Super 116E jackup design and will incorporate Ensco's patented Canti-Leverage Advantage^SM technology. These rigs are scheduled for delivery during the second quarter and the third quarter of 2016, respectively. Both of these rigs are currently uncontracted.

During 2013, we entered into agreements with Keppel FELS ("KFELS") to construct a premium jackup rig (ENSCO 110) and an ultra-premium harsh environment jackup rig (ENSCO 123). ENSCO 110 was delivered during the second quarter of 2015 and commenced drilling operations under a long-term contract in the UAE. We recently

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agreed with the shipyard to delay delivery of ENSCO 123 until the first quarter of 2018. ENSCO 123 is currently uncontracted.

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

We previously entered into agreements with Samsung Heavy Industries to construct three ultra-deepwater drillships (ENSCO DS-8, ENSCO DS-9 and ENSCO DS-10). ENSCO DS-10 is currently uncontracted and we agreed with the shipyard to delay the delivery until the first quarter of 2017. During 2015, we accepted delivery of ENSCO DS-8 and ENSCO DS-9. ENSCO DS-8 was delivered during the third quarter and commenced drilling operations under a long-term contract in Angola. ENSCO DS-9 was delivered in the second quarter and is uncontracted following receipt of a notice of termination for convenience from our customer. Under the terms of the contract, our customer is obligated to pay us termination fees, which are payable monthly, of two years of operating day rate (approximately $550,000), which will be reduced pursuant to our obligation to mitigate idle rig costs, such as manning and maintenance activity, while the rig is idle and without a contract. We are in discussions with our customer on the amount of this reduction.  This day rate may also be adjusted if we recontract the rig.

Based on our balance sheet and contractual backlog of $5.8 billion, we believe our remaining capital commitments will primarily be funded from cash and cash equivalents, short term investments, operating cash flows 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.

Divestitures

Our business strategy has been to focus on ultra-deepwater floater and premium jackup operations and de-emphasize other assets and operations that are not part of our long-term strategic plan or that no longer meet our standards for economic returns. Consistent with this strategy, we sold eight jackup rigs and three moored semisubmersible rigs during the three-year period ended December 31, 2015. We are marketing for sale six rigs, which were classified as held-for-sale in our financial statements as of December 31, 2015. In February 2016, we determined that an additional six rigs - ENSCO 56, ENSCO 81, ENSCO 82, ENSCO 86, ENSCO 99 and ENSCO DS-1 - would likely be scrapped or otherwise retired.

Redomestication

Our predecessor, ENSCO International Incorporated ("Ensco Delaware"), was formed as a Texas corporation during 1975 and reincorporated in Delaware during 1987.  During 2009, we completed a reorganization of the corporate structure of the group of companies controlled by 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 the Laws of England and Wales (the "redomestication").

We remain subject to the U.S. Securities and Exchange Commission ("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"). We continue to report our consolidated financial results in U.S. dollars and in accordance with U.S. generally accepted accounting principles ("U.S. GAAP"), but also comply with reporting requirements under English law.

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Contract Drilling Operations

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.

We currently own and operate an offshore drilling rig fleet of 64 rigs. We also have four rigs under construction. Our rig fleet includes ten drillships (including one drillship under construction), 13 dynamically positioned semisubmersible rigs, three moored semisubmersible rigs and 42 jackup rigs (including three rigs under construction).  Of our 68 rigs, 30 are located in the Middle East, Africa and Asia Pacific (including four rigs under construction), 21 are currently located in North and South America (including Brazil) and 17 are located in Europe and the Mediterranean.

Our drilling rigs drill and complete oil and natural gas wells. From time to time, our drilling rigs may be utilized as accommodation units or for non-drilling services, such as workovers and interventions. Demand for our drilling services is based upon many factors beyond our control. See “Item 1A. Risk Factors - The success of our business largely depends on the level of activities in the oil and gas industry, which can be significantly affected by volatile oil and natural gas prices.”

Our drilling contracts are the result of negotiations with our customers, and most contracts are awarded upon competitive bidding. The terms of our drilling contracts can vary significantly, but generally contain the following commercial terms:

• contract duration or term for a specific period of time or a period necessary to drill one or more wells,

• term extension options in favor of our customer, exercisable upon advance notice to us, at mutually agreed, indexed, fixed rates or current rate at the date of extension,

• provisions permitting early termination of the contract (i) if the rig is lost or destroyed, (ii) by the customer if operations are suspended for a specified period of time due to breakdown of major rig equipment, unsatisfactory performance, or "force majeure" events beyond the control of either party or (iii) at the convenience (without cause) of the customer (in most cases obligating the customer to pay us an early termination fee providing some level of compensation to us for the remaining term),

• payment of compensation to us (generally in U.S. dollars although some contracts require a portion of the compensation to be paid in local currency) on a "day work" basis such that we receive a fixed amount for each day ("day rate") that the drilling unit is operating under contract (lower rates, shorter periods that a rate is payable or no payments ("zero rate") generally apply during periods of equipment breakdown and repair, during re-drilling lost or damaged portions of wells or suspension of operations due to negligence or in the event operations are suspended or interrupted due to unsatisfactory performance or other specified conditions), 

• payment by us of the operating expenses of the drilling unit, including crew labor and incidental rig supply and maintenance costs,

• mobilization and demobilization requirements of us to move the drilling unit to and from the planned drilling site, and such terms may include reimbursement of these costs by the customer by in the form of up-front payment, additional day rate over the contract term, or direct reimbursement, and

• provisions allowing us to recover certain labor and other operating cost increases, and certain cost increases due to changes in applicable law, from our customers through day rate adjustment or direct reimbursement.    

Due to the current depressed market conditions, we are seeing intense pressure on negotiation of operating day rates, which may result in rates that approximate direct operating expenses. In addition, we are seeing increased

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pressure to accept other less favorable contractual and commercial terms, including reduced or no mobilization and demobilization fees, reduced day rates during downtime, reduced standby, redrill and moving rates, caps on reimbursements for downhole tools, reduced periods to remediate equipment breakdowns or other deviations from contractual standards of performance, certain limitations on our ability to be indemnified and reduced early termination fees and notice periods.

Financial information regarding our operating segments and geographic regions is presented in Note 13 to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data." Additional financial information regarding our operating segments is presented in "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations."

Backlog Information

Our contract drilling backlog reflects commitments, represented by signed drilling contracts, and was calculated by multiplying the contracted day rate by the contract period. The contracted day rate excludes certain types of lump sum fees for rig mobilization, demobilization, contract preparation, as well as customer reimbursables and bonus opportunities. Contract backlog was adjusted for drilling contracts signed or terminated after each respective balance sheet date but prior to filing each of our annual reports on Form 10-K on February 24, 2016 and March 2, 2015, respectively.

The following table summarizes our contract backlog of business as of December 31, 2015 and 2014 (in millions):

	2015		2014
Floaters(1)	$	3,919.5	$	6,756.1
Jackups	1,751.7		2,743.8
Other	86.2		190.0
Total	$	5,757.4	$	9,689.9

⁽¹⁾  Contract drilling backlog as of December 31, 2015 for our floaters excludes $79 million in backlog attributable to contracted work for ENSCO DS-5. Petrobras has asserted that the ENSCO DS-5 drilling services contract is void. We disagree with Petrobras' assertion and plan to pursue our legal rights in connection with this dispute. See "Item 3. Legal Proceedings - DSA Dispute" for further information.

As of December 31, 2015, our backlog was $5.8 billion as compared to $9.7 billion as of December 31, 2014. Our floater backlog declined $2.8 billion primarily due to revenues realized during 2015, contract day rate concessions on certain rigs and ENSCO DS-4 and ENSCO DS-9 contract terminations. The remaining $1.1 billion decline primarily related to our Jackups segment and was mostly due to revenues realized during 2015 and contract day rate concessions on certain rigs, partially offset by contract extensions in the North Sea and new contracts in the Middle East.

The following table summarizes our contract backlog of business as of December 31, 2015 and the periods in which such revenues are expected to be realized (in millions):

	2016		2017		2018		2019 and Beyond		Total
Floaters(1)	$	1,765.6	$	1,239.7	$	453.8	$	460.4	$	3,919.5
Jackups	906.6		544.4		292.3		8.4		1,751.7
Other	83.7		2.5		—		—		86.2
Total	$	2,755.9	$	1,786.6	$	746.1	$	468.8	$	5,757.4

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⁽¹⁾  Floater backlog for 2016 excludes $79 million attributable to the ENSCO DS-5 drilling services contract with Petrobras. Petrobras has asserted that the ENSCO DS-5 drilling services contract is void. We disagree with Petrobras' assertion and plan to pursue our legal rights in connection with this dispute. See "Item 3. Legal Proceedings - DSA Dispute" for further information.

Our drilling contracts generally contain provisions permitting early termination of the contract (i) if the rig is lost or destroyed or (ii) by the customer if operations are suspended for a specified period of time due to breakdown of major rig equipment, unsatisfactory performance, "force majeure" events beyond the control of either party or other specified conditions.  In addition, our drilling contracts generally permit early termination of the contract by the customer for convenience (without cause), exercisable upon advance notice to us, and in some cases without making an early termination payment to us.  There can be no assurances that our customers will be able to or willing to fulfill their contractual commitments to us.  

The recent decline in oil prices and the perceived risk of a further decline in oil prices has caused and may continue to cause some customers to consider early termination or repudiation of contracts, despite having to pay onerous early termination fees in some cases. Customers may also request to re-negotiate the terms of existing contracts. The amount of actual revenues earned and the actual periods during which revenues are earned will be different from amounts disclosed in our backlog calculations due to a lack of predictability of various factors, including newbuild rig delivery dates, unscheduled repairs, maintenance requirements, weather delays, contract terminations or renegotiations and other factors.

See "Item 1A. Risk Factors - Our current backlog of contract drilling revenue may not be fully realized and may reduce significantly in the future, which may have a material adverse effect on our financial position, results of operations or cash flows” and “Item 1A. Risk Factors - We may suffer losses if our customers terminate or seek to renegotiate our contracts, if operations are suspended or interrupted or if a rig becomes a total loss.”

Drilling Contracts and Insurance Program

Our drilling contracts provide for varying levels of allocation of responsibility for liability between our customer and us for loss or damage to each party's property and third party property, personal injuries and other claims arising out of our drilling operations. We also maintain insurance for personal injuries, damage to or loss of property and certain business risks.

Our insurance policies typically consist of twelve-month policy periods, and the next renewal date for a substantial portion of our insurance program is scheduled for May 31, 2016. Our insurance program provides coverage, subject to the policies' terms and conditions, to the extent not otherwise assumed by the customer under the indemnification provisions of the drilling contract, for third-party claims arising from our operations, including third-party claims arising from well control events, named windstorms, sudden and accidental pollution originating from our rigs, wrongful death and personal injury. Third-party pollution claims could also arise from damage to adjacent pipelines and from spills of fluids maintained on the drilling unit. Generally, our program provides liability coverage up to $750.0 million, with a per occurrence deductible of $10.0 million or less. We retain the risk for liability not indemnified by the customer in excess of our insurance coverage.

Well control events generally include an unintended flow from the well that cannot be contained by using equipment on site (e.g., a blowout preventer), by increasing the weight of drilling fluid or by diverting the fluids safely into production facilities. In addition to the third-party coverage described above, for claims relating to a well control event, we also have $150.0 million of coverage available to pay costs of controlling and re-drilling of the well and third-party pollution claims.

Our insurance program also provides first party coverage to us for physical damage to, including total loss or constructive total loss of, our rigs, generally excluding damage arising from a named windstorm in the U.S. Gulf of Mexico. This coverage is based on an agreed amount for each rig, and has a per occurrence deductible for losses ranging from $15.0 million to $25.0 million. Due to the significant premium, high deductible and limited coverage,

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we decided not to purchase first party windstorm insurance for our jackup and floating rigs in the U.S. Gulf of Mexico. Accordingly, we have retained the risk for windstorm damage to our eight jackup and nine floating rigs in the U.S. Gulf of Mexico.

Our drilling contracts customarily provide that each party is responsible for injuries or death to their respective personnel and loss or damage to their respective property (including the personnel and property of each parties’ contractors and subcontractors). However, in certain drilling contracts we assume liability for damage to our customers' property and the property of other contractors of our customers resulting from our negligence, which is usually subject to negotiated caps on a per occurrence basis.  In other contracts, we are not indemnified by our customers for damage to their property and the property of their other contractors. In addition, our drilling contracts typically provide for our customers to indemnify us, generally based on replacement cost minus some level of depreciation, for damage to our down-hole equipment, and in some cases for a limited amount of the replacement cost of our subsea equipment, unless the damage is caused by our negligence, normal wear and tear, or defects in the equipment.

Subject to the exceptions noted below, our customers typically assume most of the responsibility for and indemnify us from any loss, damage or other liability resulting from pollution or contamination arising from operations, including as a result of blowouts and cratering, when the source of the pollution originates from the well or reservoir, including costs for clean-up and removal of pollution and third-party damages. In some drilling contracts, we assume liability for third-party damages resulting from such pollution and contamination caused by our negligence, usually subject to negotiated caps on a per occurrence or per event basis. In addition, in substantially all of our contracts, the customer assumes responsibility and indemnifies us for loss or damage to the reservoir, for loss of hydrocarbons escaping from the reservoir and for the costs of bringing the well under control.  Further, subject to the exceptions noted below, most of our contracts provide that the customer assumes responsibility and indemnifies us for loss or damage to the well, except when the loss or damage to the well is due to our negligence, in which case most of our contracts provide that the customer's sole remedy is to require us to redrill the lost or damaged portion of the well at a substantially reduced rate.

Most of our drilling contracts incorporate a broad exclusion that limits the operator's indemnity for damages and losses resulting from our gross negligence and willful misconduct and for fines and penalties and punitive damages levied or assessed directly against us. This exclusion overrides other provisions in the contract that limit our liability for ordinary negligence. In most of these cases we are still able to negotiate a liability cap (although these caps are significantly higher than the caps for ordinary negligence) on our exposure for losses or damages resulting from our gross negligence. In certain cases, the broad exclusion only applies to losses or damages resulting from the gross negligence of our senior supervisory personnel. However, in some cases we have contractually assumed significantly increased exposure or unlimited exposure for losses and damages due to the gross negligence of our rig personnel and in most cases we are not able to contractually limit our exposure for our willful misconduct.

Notwithstanding our negotiation of express limitations in our drilling contracts for losses or damages resulting from our ordinary negligence and any express limitations (albeit usually much higher) for losses or damages in the event of our gross negligence, under the applicable laws that govern certain of our drilling contracts, the courts will not enforce any indemnity for losses and damages that result from our gross negligence or willful misconduct. As a result, under the laws of such jurisdictions the indemnification provisions of our drilling contracts that would otherwise limit our liability in the event of our gross negligence or willful misconduct are deemed to be void as being contrary to public policy and we will be exposed to unlimited liability for losses and damages that result from our gross negligence or willful misconduct, regardless of the express limitation of our liability in the relevant drilling contracts. Under the laws of certain jurisdictions, an indemnity from an operator for losses or damages of third parties resulting from our gross negligence is enforceable but an indemnity for losses or damages of the operator is not enforceable. In such cases, the contractual indemnity obligation of the operator to us would be enforceable with respect to third party claims for losses of damages, such as may arise in pollution claims, but the contractual indemnity obligation of the operator to us with respect to the operator’s damages to the well, to the reservoir and for the costs of well control would not be enforceable. Furthermore, although there is a lack of precedential authority for these types of claims in countries where the civil law is applied, in those situations where a codified civil law system is applicable to our drilling contracts, as opposed to the common law system, the courts generally will not enforce a contractual indemnity clause that totally

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indemnifies us from losses or damages due to our gross negligence, but generally will enforce the contractual indemnity over and above a cap on our liability for gross negligence, assuming the cap requires us to accept a significant amount of liability.

Similar to gross negligence, regardless of any express limitations in a drilling contract regarding our liability for fines and penalties and punitive damages, the laws of most jurisdictions will not enforce an indemnity that indemnifies a party for a fine or penalty that is levied or punitive damages that are assessed directly against such party on the ground that it is against public policy to indemnify a party from a fine and penalty or punitive damages that were levied or assessed, where the purpose of such levy or assessment is to deter the behavior that resulted in the fine or penalty or punish such party for the behavior that warranted the assessment of punitive damages.

The above description of our insurance program and the indemnification provisions of our drilling contracts is only a summary as of the date hereof and is general in nature. In addition, our drilling contracts are individually negotiated, and the degree of indemnification we receive from operators against the liabilities discussed above can vary from contract to contract, based on market conditions and customer requirements existing when the contract was negotiated and the interpretation and enforcement of applicable law when the claim is adjudicated. Notwithstanding a contractual indemnity from a customer, there can be no assurance that our customers will be financially able to indemnify us or will otherwise honor a contractual indemnity obligation that is enforceable under applicable law. Our insurance program and the terms of our drilling contracts may change in the future.

In certain cases, vendors who provide equipment or services to us limit their pollution liability to a specific monetary cap, and we assume the liability above that cap. Typically, in the case of original equipment manufacturers, the cap is a negotiated amount based on mutual agreement of the parties considering the risk profiles and thresholds of each party. However, for smaller vendors, the liability is usually limited to the value, or double the value, of the contract.

We generally indemnify the customer for legal and financial consequences of spills of waste oil, fuels, lubricants, motor oils, pipe dope, paint, solvents, ballast, bilge, garbage, debris, sewage, hazardous waste and other liquids, the discharge of which originates from our rigs or equipment above the surface of the water and in some cases from our subsea equipment. Our contracts generally provide that, in the event of any such spill from our rigs, we are responsible for fines and penalties.

Major Customers

We provide our contract drilling services to major international, government-owned and independent oil and gas companies. During 2015, our five largest customers accounted for 52% of consolidated revenues. BP and Petrobras, our largest customers, accounted for 18% and 14% of consolidated revenues, respectively.

Competition

The offshore contract drilling industry is highly competitive. Drilling contracts are, for the most part, awarded on a competitive bid basis. Price competition is often the primary factor in determining which contractor is awarded a contract, although quality of service, operational and safety performance, equipment suitability and availability, location of equipment, reputation and technical expertise also are factors.  We have numerous competitors in the offshore contract drilling industry with significant resources.

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Governmental Regulation

Our operations are affected by political developments and by laws and regulations that relate directly to the oil and gas industry, including laws and regulations that have or may impose increased financial responsibility and oil spill abatement contingency plan capability requirements. Accordingly, we will be directly affected by the approval and adoption of laws and regulations curtailing exploration and development drilling for oil and natural gas for economic, environmental, safety or other policy reasons. It is also possible that these laws and regulations could adversely affect our operations in the future by significantly increasing our operating costs.  See "Item 1A. Risk Factors- Increasing regulatory complexity could adversely impact the costs associated with our offshore drilling operations."

Environmental Matters

Our operations are subject to laws and regulations controlling the discharge of materials into the environment, pollution, contamination and hazardous waste disposal or otherwise relating to the protection of the environment. Environmental laws and regulations specifically applicable to our business activities could impose significant liability on us for damages, clean-up costs, fines and penalties in the event of oil spills or similar discharges of pollutants or contaminants into the environment or improper disposal of hazardous waste generated in the course of our operations, which may not be covered by contractual indemnification or insurance and could have a material adverse effect on our financial position, operating results and cash flows.  To date, such laws and regulations have not had a material adverse effect on our operating results, and we have not experienced an accident that has exposed us to material liability arising out of or relating to discharges of pollutants into the environment.  However, the legislative, judicial and regulatory response to any well incidents could substantially increase our customers' liabilities in respect of oil spills and also could increase our liabilities. In addition to potential increased liabilities, such legislative, judicial or regulatory action could impose increased financial, insurance or other requirements that may adversely impact the entire offshore drilling industry.

The International Convention on Oil Pollution Preparedness, Response and Cooperation, the U.K. Merchant Shipping Act 1995, Marpol 73/78, the U.K. Merchant Shipping (Oil Pollution Preparedness, Response and Cooperation Convention) Regulations 1998 and other related legislation and regulations and the Oil Pollution Act of 1990 ("OPA 90"), as amended, The Clean Water Act, and other U.S. federal statutes applicable to us and our operations, as well as similar statutes in Texas, Louisiana, other coastal states and other non-U.S. jurisdictions, address oil spill prevention, reporting and control and significantly expand liability, fine and penalty exposure across many segments of the oil and gas industry. Such statutes and related regulations impose a variety of obligations on us related to the prevention of oil spills, disposal of waste and liability for resulting damages. For instance, OPA 90 imposes strict and, with limited exceptions, joint and several liability upon each responsible party for oil removal costs as well as a variety of fines, penalties and damages. Similar environmental laws apply in our other areas of operation. Failure to comply with these statutes and regulations, including OPA 90, may subject us to civil or criminal enforcement action, which may not be covered by contractual indemnification or insurance and could have a material adverse effect on our financial position, operating results and cash flows.

Events in recent years, including the Macondo well incident, have heightened governmental and environmental concerns about the oil and gas industry. From time to time, legislative proposals have been introduced that would materially limit or prohibit offshore drilling in certain areas.  We are adversely affected by restrictions on drilling in certain areas of the U.S. Gulf of Mexico and elsewhere, including the adoption of additional safety requirements and policies regarding the approval of drilling permits, restrictions on development and production activities in the U.S. Gulf of Mexico that have and may further impact our operations. 

As a result of Macondo, the Bureau of Safety and Environmental Enforcement ("BSEE") issued a drilling safety rule in 2012 that included requirements for the cementing of wells, well control barriers, blowout preventers, well-control fluids, well completions, workovers and de-commissioning operations. BSEE has also issued regulations requiring operators to have safety and environmental management systems ("SEMS") prior to conducting operations. In addition, in August 2012, BSEE issued Interim Policy Document stating that it would begin issuing Incidents of Non-Compliance ("INC's") to operators for serious violations of BSEE regulations. Although we have not yet incurred

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any material exposure from such regulations/decisions, the issuance of INC's could potentially make it easier for a successful assertion of third party claims against us.

Since 2014, the United States Coast Guard ("USCG") has proposed new regulations that would impose GPS equipment and positioning requirements for mobile offshore drilling units and jackup rigs operating in the U.S. Gulf of Mexico and issued notices regarding the development of regulations for cybersecurity measures used in the marine and offshore energy sectors for all vessels and facilities that are subject to the Maritime Transportation Security Act of 2002, including our rigs. In April 2015, BSEE proposed new rules that, if and when enacted, would include more stringent design requirements for well control equipment used in offshore drilling operations. Based on our assessment of the proposed rules, we may incur significant costs to comply with the rules if they are adopted as proposed. We are continuing to evaluate the cost and effect that these proposed new rules will have on our operations. If new laws are enacted or other government actions are taken that restrict or prohibit offshore drilling in our principal areas of operation or impose environmental protection requirements that materially increase the liabilities, financial requirements or operating or equipment costs associated with offshore drilling, exploration, development or production of oil and natural gas, our financial position, operating results and cash flows could be materially adversely affected.  See "Item 1A. Risk Factors - Compliance with or breach of environmental laws can be costly and could limit our operations." 

Non-U.S. Operations

Revenues from non-U.S. operations were 72%, 62% and 61% of our total consolidated revenues during 2015, 2014 and 2013, respectively. Our non-U.S. operations and shipyard rig construction and enhancement projects are subject to political, economic and other uncertainties, including:

• terrorist acts, war and civil disturbances,

• expropriation, nationalization, deprivation or confiscation of our equipment,

• expropriation or nationalization of a customer's property or drilling rights,

• repudiation or nationalization of contracts,

• assaults on property or personnel,

• piracy, kidnapping and extortion demands,

• significant governmental influence over many aspects of local economies and customers,

• unexpected changes in law and regulatory requirements, including changes in interpretation or enforcement of existing laws,

• work stoppages,

• complications associated with repairing and replacing equipment in remote locations,

• limitations on insurance coverage, such as war risk coverage, in certain areas,

• imposition of trade barriers,

• wage and price controls,

• import-export quotas,

• exchange restrictions,

• currency fluctuations,

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• changes in monetary policies,

• uncertainty or instability resulting from hostilities or other crises in the Middle East, West Africa, Latin America or other geographic areas in which we operate,

• changes in the manner or rate of taxation,

• limitations on our ability to recover amounts due,

• increased risk of government and vendor/supplier corruption,

• increased local content requirements,

• the occurrence or threat of epidemic or pandemic diseases or any government response to such occurrence or threat;

• changes in political conditions, and

• other forms of government regulation and economic conditions that are beyond our control.

See "Item 1A. Risk Factors - Our non-U.S. operations involve additional risks not associated with U.S. operations."

Executive Officers

Officers generally serve for a one-year term or until successors are elected and qualified to serve. The table below sets forth certain information regarding our executive officers:

Name	Age	Position
Carl G. Trowell	47	President and Chief Executive Officer
P. Carey Lowe	57	Executive Vice President - Chief Operating Officer
Jonathan Baksht	40	Senior Vice President and Chief Financial Officer
Steven J. Brady	56	Senior Vice President - Eastern Hemisphere
John S. Knowlton	56	Senior Vice President - Technical
Gilles Luca	44	Senior Vice President - Western Hemisphere
Michael T. McGuinty	53	Senior Vice President - General Counsel and Secretary

Set forth below is certain additional information on our executive officers, including the business experience of each executive officer for at least the last five years:

Carl G. Trowell joined Ensco in June 2014 as President and Chief Executive Officer. He is also a member of the Board of Directors. Prior to joining Ensco, Mr. Trowell was President of Schlumberger Integrated Project Management (IPM) and Schlumberger Production Management (SPM) businesses that provide complex oil and gas project solutions ranging from field management, well construction, production and intervention services to well abandonment and rig management. He was promoted to this role after serving as President - Schlumberger WesternGeco Ltd. where he managed more than 6,500 employees with operations in 55 countries. Mr. Trowell began his professional career as a petroleum engineer with Shell before joining Schlumberger where he held a variety of international management positions including Geomarket Manager for North Sea operations and global Vice President of marketing and sales. He has a strong background in the development and deployment of new technologies and has been a member of several industry advisory boards in this capacity. Mr. Trowell is on the advisory board of Energy Ventures, a venture capital company investing in oil and gas technology. Mr. Trowell has a PhD in Earth Sciences from the University of Cambridge, a Master of Business Administration from The Open University and a Bachelor of Science degree in Geology from Imperial College London.

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P. Carey Lowe joined Ensco in 2008 and serves as Executive Vice President and Chief Operating Officer. Prior to being appointed Chief Operating Officer in December 2015, Mr. Lowe served Ensco as Executive Vice President overseeing investor relations and communications, strategy and human resources. Prior to serving as Executive Vice President, he served Ensco as Senior Vice President - Eastern Hemisphere and Senior Vice President with responsibilities including the Deepwater Business Unit, safety, health and environmental matters, capital projects, engineering and strategic planning.  Prior to joining Ensco, Mr. Lowe served as Vice President - Latin America for Occidental Oil & Gas. He also served as President & General Manager, Occidental Petroleum of Qatar Ltd. from 2001 to 2007. Mr. Lowe held various drilling-related management positions with Sedco Forex and Schlumberger Oilfield Services from 1980 to 2000, including Business Manager - Drilling, North and South America and General Manager - Oilfield Services, Saudi Arabia, Bahrain and Kuwait. Following Schlumberger, he was associated with a business-to-business e-procurement company until he joined Occidental during 2001. Mr. Lowe holds a Bachelor of Science Degree in Civil Engineering from Tulane University.

Jonathan Baksht joined Ensco in 2013 and was appointed to his current position of Senior Vice President - Chief Financial Officer in November 2015. Prior to his current position, Mr. Baksht served as Vice President - Finance and Vice President - Treasurer. Prior to joining Ensco, Mr. Baksht served as Senior Vice President - Investment Banking with Goldman Sachs & Co.  Prior to joining Goldman Sachs in 2006, he consulted on strategic initiatives for energy clients at Andersen Consulting.  Mr. Baksht holds a Master of Business Administration from the Kellogg School of Management at Northwestern University and a Bachelor of Science in Electrical Engineering from the University of Texas at Austin.

Steven J. Brady joined Ensco in 2002 and was appointed to his current position of Senior Vice President – Eastern Hemisphere in December 2014. Prior to his current position, Mr. Brady served as Senior Vice President - Western Hemisphere, Vice President – Europe and Mediterranean, General Manager – Middle East and Asia Pacific, and in other leadership positions in the Eastern Hemisphere. Prior to joining Ensco, Mr. Brady spent 18 years in various technical and managerial roles for ConocoPhillips in locations around the world. Mr. Brady holds a Bachelor of Science Degree in Petroleum Engineering from Mississippi State University.

John S. Knowlton joined Ensco in 1998 and was appointed to his current position of Senior Vice President – Technical in May 2011. Prior to his current position, Mr. Knowlton served Ensco as Vice President – Engineering & Capital Projects, General Manager – North & South America, Operations Manager – Asia Pacific Rim, and Operations Manager overseeing the construction and operation of our first ultra-deepwater semisubmersible rig, ENSCO 7500. Before joining Ensco, Mr. Knowlton served in various domestic and international capacities with Ocean Drilling & Exploration Company and Diamond Offshore Drilling, Inc. Mr. Knowlton holds a Bachelor of Science Degree in Civil Engineering from Tulane University.

Gilles Luca joined Ensco in 1997 and was appointed to his current position of Senior Vice President - Western Hemisphere in December 2014. Prior to his current position, Mr. Luca was Vice President - Business Development and Strategic Planning, Vice President - Brazil Business Unit and General Manager - Europe and Africa. Before joining Ensco as an Operations Engineer in The Netherlands, Mr. Luca was employed by Foramer Drilling and Schlumberger with assignments in France and Venezuela. He holds a Master Degree in Petroleum Engineering from the French Petroleum Institute and a Bachelor in Civil Engineering.

Michael T. McGuinty joined Ensco in February 2016 as Senior Vice President - General Counsel and Secretary. Prior to joining Ensco, Mr. McGuinty served as General Counsel and Company Secretary of Abu Dhabi National Energy Company. Previously, Mr. McGuinty spent 18 years with Schlumberger where he held various senior legal management positions in the United States, Europe and the Middle East including Director of Compliance, Deputy General Counsel - Corporate and M&A and Director of Legal Operations. Prior to Schlumberger, Mr. McGuinty practiced corporate and commercial law in Canada and France. Mr. McGuinty holds a Bachelor of Laws and Bachelor of Civil Law from McGill University and a Bachelor of Social Sciences from the University of Ottawa.

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Employees

We employed approximately 6,400 personnel worldwide as of February 24, 2016.  The majority of our personnel work on rig crews and are compensated on an hourly basis.

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Available Information

Our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and amendments to these reports that we file or furnish to the SEC in accordance with the Exchange Act, as amended, are available on our website at www.enscoplc.com. These reports also are available in print without charge by contacting our Investor Relations Department at 713-430-4607 as soon as reasonably practicable after we electronically file the information with, or furnish it to, the SEC.  The information contained on our website is not included as part of, or incorporated by reference into, this report.

Item 1A.Risk Factors

Risks Related to Our Business

There are numerous factors that affect our business and operating results, many of which are beyond our control. The following is a description of significant factors that might cause our future operating results to differ materially from those currently expected. The risks described below are not the only risks facing our Company. Additional risks and uncertainties not specified herein, not currently known to us or currently deemed to be immaterial also may materially adversely affect our business, financial position, operating results and/or cash flows.

The success of our business largely depends on the level of activity in the oil and gas industry, which can be significantly affected by volatile oil and natural gas prices.

The success of our business largely depends on the level of activity in offshore oil and natural gas exploration, development and production. Oil and natural gas prices, and market expectations of potential changes in these prices, significantly affect the level of drilling activity. Historically, when drilling activity and operator capital spending decline, utilization and day rates also decline and drilling may be reduced or discontinued, resulting in an oversupply of drilling rigs. The oversupply of drilling rigs will be exacerbated by the entry of newbuild rigs into the market. Oil prices have declined by more than 70% since mid-2014, with crude oil prices trading below $30 per barrel in January 2016, in contrast to prices in excess of $100 per barrel in July 2014. The decline in oil prices has in turn caused a significant decline in the demand for offshore drilling services. Operators have reduced capital spending and cancelled or deferred existing programs. We expect these trends to continue as long as commodity prices remain at current levels. A sustained period of lower prices, or the perceived risk of a sustained period of lower prices, may further reduce our customers' overall level of activity, in which case demand for our services may further decline and revenues may continue to be adversely affected through lower rig utilization and/or lower day rates.  Numerous factors may affect oil and natural gas prices and the level of demand for our services, including:

• regional and global economic conditions and changes therein,

• oil and natural gas supply and demand,

• expectations regarding future energy prices, 

• the ability of the Organization of Petroleum Exporting Countries ("OPEC") to set and maintain production levels and pricing, 

• capital allocation decisions by our customers, including the relative economics of offshore development versus onshore prospects,

• the level of production by non-OPEC countries, 

• U.S. and non-U.S. tax policy, 

• advances in exploration and development technology,

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• costs associated with exploring for, developing, producing and delivering oil and natural gas,

• rate of discovery of new oil and gas reserves and the rate of decline of existing oil and gas reserves,

• laws and government regulations that limit, restrict or prohibit exploration and development of oil and natural gas in various jurisdictions, or materially increase the cost of such exploration and development,

• the development and exploitation of alternative fuels,

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

• natural disasters or incidents resulting from operating hazards inherent in offshore drilling, such as oil spills, and

• the worldwide military or political environment, including uncertainty or instability resulting from an escalation or additional outbreak of armed hostilities or other crises in oil or natural gas producing areas of the Middle East or geographic areas in which we operate, or acts of terrorism.

The level of offshore exploration, development and production activity and the price for oil and natural gas is volatile and is likely to continue to be volatile in the future. Any prolonged decline in oil and natural gas prices will depress the levels of exploration, development and production activity. Despite significant recent declines in capital spending and cancelled or deferred drilling programs by many operators, oil and gas production has not yet been reduced by amounts sufficient to result in a rebound in pricing, and we may not see sufficient supply reductions or a resulting rebound in pricing for an extended period of time. Certain OPEC countries have reached tentative agreements to freeze production and have indicated that discussions are ongoing regarding production cuts. However, such agreements have not been agreed to by all member countries, and OPEC countries may never come to an agreement on production cuts. The lack of production cuts by OPEC countries, or the perceived risk that OPEC countries are unable to come to an agreement on production cuts or that OPEC countries may not comply with any such agreement, may result in lower commodity prices for an extended period of time.

In addition, continued hostility in foreign countries and the occurrence or threat of terrorist attacks against the United States or other countries could create downward pressure on the economies of the United States and other countries. Moreover, higher commodity prices may not necessarily translate into increased activity, and even during periods of high commodity prices, customers may cancel or curtail their drilling programs, or reduce their levels of capital expenditures for exploration and production for a variety of reasons, including their lack of success in exploration efforts. Advances in onshore exploration and development technologies, particularly with respect to onshore shale plays, could also result in our customers allocating more of their capital expenditure budgets to onshore exploration and production activities and less to offshore activities. These factors could cause our revenues and profits to decline, as a result of declines in utilization and day rates, and limit our future growth prospects. Any significant decline in day rates or utilization of our rigs, particularly our high-specification floaters, could materially reduce our revenues and profitability. In addition, these risks could increase instability in the financial and insurance markets and make it more difficult for us to access capital and obtain insurance coverage that we consider adequate or are otherwise required by our contracts.

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The offshore contract drilling industry historically has been highly competitive and cyclical, with periods of low demand and excess rig availability that could result in adverse effects on our business.

Our industry is highly competitive, and our contracts are traditionally awarded on a competitive bid basis. Pricing, safety records and competency are key factors in determining which qualified contractor is awarded a job. Rig availability, location and technical capabilities also can be significant factors in the determination. In addition, consolidations within the oil and gas industry have reduced the number of available customers, resulting in increased competition for projects. If we are not able to compete successfully, our revenues and profitability may be reduced.

Financial operating results in the offshore contract drilling industry historically have been very cyclical and are primarily related to the demand for drilling rigs and the available supply of drilling rigs.  Demand for rigs is directly related to the regional and worldwide levels of offshore exploration and development spending by oil and gas companies, which is beyond our control. Offshore exploration and development spending may fluctuate substantially from year-to-year and from region-to-region.

The supply of offshore drilling rigs has increased in recent years. Currently, there are approximately 180 newbuild drillships, semisubmersibles and jackup rigs reported to be on order or under construction with delivery expected by the end of 2020.  Approximately 105 of these rigs are scheduled for delivery during 2016, representing an approximate 13% increase in the total worldwide fleet of offshore drilling rigs since year end 2015. Many of these offshore drilling rigs do not have drilling contracts in place. In addition, the supply of marketed offshore drilling rigs could further increase due to depressed market conditions resulting in currently contracted rigs being uncontracted as existing contracts expire. There are no assurances that the market in general or a geographic region in particular will be able to fully absorb the supply of new rigs in future periods.

The increase in supply of offshore drilling rigs in recent years has resulted in an oversupply of offshore drilling rigs and a decline in utilization and/or day rates, a situation which, if it persists for the next few years, could be exacerbated by a prolonged decline in demand for drilling rigs. Lower utilization and/or day rates in one or more of the regions in which we operate could adversely affect our revenues and profitability.

Future periods of reduced demand and/or excess rig supply may require us to idle additional rigs or enter into lower day rate contracts or contracts with less favorable terms. There can be no assurance that the current demand for drilling rigs will increase in the future. Any further decline in demand for drilling rigs or a continued oversupply of drilling rigs could adversely affect our financial position, operating results and cash flows.

Our business will be adversely affected if we are unable to secure contracts on economically favorable terms.

Our ability to renew expiring contracts or obtain new contracts and the terms of any such contracts will depend on market conditions. We may be unable to renew our expiring contracts or obtain new contracts for the rigs under contracts that have expired or been terminated, and the day rates under any new contracts or any renegotiated contracts may be substantially below the existing day rates, which could adversely affect our revenues and profitability.

None of our four rigs currently under construction, which are scheduled for delivery from 2016 to 2018, have a customer contract. There is no assurance that we will secure drilling contracts for these rigs, or future rigs we construct, or that the drilling contracts we may be able to secure will be based upon rates and terms that will provide a reasonable rate of return on these investments. Our failure to secure contractual commitments for these rigs at rates and terms that result in a reasonable return upon completion of construction may result in a material adverse effect on our financial position, operating results and cash flows.

Our customers may be unable or unwilling to fulfill their contractual commitments to us, including their obligations to pay for losses, damages or other liabilities resulting from operations under the contract.

Certain of our customers are subject to liquidity risk and such risk could lead them to seek to repudiate, cancel or renegotiate our drilling contracts for various reasons or fail to fulfill their commitments to us under those contracts. These risks are heightened in periods of depressed market conditions. Our drilling contracts provide for varying levels

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of indemnification from our customers, including with respect to well control and subsurface risks. Our drilling contracts also provide for varying levels of indemnification and allocation of liabilities between our customers and us with respect to loss or damage to property and injury or death to persons arising from the drilling operations we perform. Under our drilling contracts, liability with respect to personnel and property customarily is generally allocated so that we and our customers each assume liability for our respective personnel and property. Our customers typically assume most of the responsibility for and indemnify us from any loss, damage or other liability resulting from pollution or contamination, including clean-up and removal, third-party damages, and fines and penalties arising from operations under the contract when the source of the pollution originates from the well or reservoir, including those resulting from blow-outs or cratering of the well. Notwithstanding a contractual indemnity from a customer, there can be no assurance that our customers will be financially able to assume their responsibility, or honor their indemnity to us, for such losses. In addition, under the laws of certain jurisdictions, such indemnities are not enforceable if the cause of the damage was our gross negligence or willful misconduct. This could result in our having to assume liabilities not otherwise contemplated in our contracts due to customer balance sheet or liquidity issues or applicable law.

We may suffer losses if our customers terminate or seek to renegotiate our contracts, if operations are suspended or interrupted or if a rig becomes a total loss.

In periods of rapid market downturn similar to the current environment, our customers may not be able to honor the terms of existing contracts (including contracts for new rigs under construction), may terminate contracts even where there may be onerous termination fees, may seek to void or otherwise repudiate our contracts including by claiming we have breached the contract, or may seek to renegotiate contract day rates and terms in light of depressed market conditions. Generally our drilling contracts are subject to termination without cause upon notice by the customer. Although our contracts may require the customer to pay an early termination payment in the event of a termination for convenience (without cause), such payment may not fully compensate us for the lost revenue from the contract, and some of our contracts permit termination by the customer without an early termination payment.

For example, we received notice of termination for convenience for ENSCO DS-4 in March 2015 and for ENSCO DS-9 in July 2015, each of which were accompanied by early termination fees that were less than what we would have received over the term of each contract absent termination.

We received a notice in January 2016 from Petrobras asserting that the ENSCO DS-5 drilling services contract is void. We disagree with Petrobras’ assertion that the ENSCO DS-5 drilling services contract is void and plan to pursue our legal rights in connection with this dispute. However, there can be no assurance as to how this dispute will ultimately be resolved. We did not recognize $44.7 million of revenue for ENSCO DS-5 drilling services provided during the fourth quarter of 2015 as we concluded collectability of these amounts was not reasonably assured. Additionally, we recorded a $17.1 million provision for doubtful accounts during the year ended December 31, 2015 for receivables related to ENSCO DS-5 drilling services provided through September 30, 2015. As of December 31, 2015, our receivables from Petrobras related to the ENSCO DS-5 contract were fully reserved on our consolidated balance sheet. See "Item 3. Legal Proceedings - DSA Dispute" for further information.

Our drilling services contracts with Petrobras for ENSCO 6001, 6002, 6003 and 6004 continue to be in full force and effect and all payments under these contracts are current. We note, however, that under the ENSCO 6001 drilling services contract we are nearing the limit for rig downtime that would permit the customer to terminate the contract without compensation. While we have not yet received a notice of termination from the customer for this contract, Petrobras is taking the position that the limit has been exceeded. We are in the process of contesting Petrobras’ position with respect to rig downtime.

Drilling contracts customarily specify automatic termination or termination at the option of the customer in the event of a total loss of the drilling rig and often include provisions addressing termination rights or reduction or cessation of day rates if operations are suspended or interrupted for extended periods due to breakdown of major rig equipment, unsatisfactory performance, "force majeure" events beyond the control of either party or other specified conditions.

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If a customer cancels a contract or if we terminate a contract due to the customer’s breach and, in either case, we are unable to secure a new contract on a timely basis and on substantially similar terms, or if a contract is disputed or suspended for an extended period of time or renegotiated, it could materially and adversely affect our financial condition, results of operations and cash flows.

We may incur impairments as a result of future declines in demand for offshore drilling rigs.

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. The offshore drilling industry historically has been highly cyclical, and it is not unusual for rigs to be idle or underutilized for significant periods of time and subsequently resume full or near full utilization when business cycles change. Likewise, during periods in which rig supply exceeds rig demand, competition may force us to contract our rigs at or near cash break-even rates for extended periods of time.

Since January 1, 2014, we have recorded pre-tax, non-cash losses on impairment of long-lived assets and goodwill of $5.1 billion and $3.3 billion, respectively. Further asset impairments may be necessary if market conditions remain depressed for longer than we expect. There is no remaining goodwill on our consolidated balance sheet as of December 31, 2015.

We may reduce or suspend our dividend in the future.

Our Board of Directors declared a $0.01 quarterly cash dividend per Class A ordinary share for the first quarter of 2016, a $0.14 reduction from the $0.15 dividend per share paid for each of the four fiscal quarters in 2015.  In the future, our Board of Directors may, without advance notice, further reduce or suspend our dividend in order to improve our financial flexibility and best position our company for long-term success. The declaration and amount of future dividends is at the discretion of our Board of Directors and will depend on our profitability, liquidity, financial condition, market outlook, reinvestment opportunities, capital requirements and other factors and restrictions our Board of Directors deems relevant. There can be no assurance that we will pay a dividend in the future.

The loss of a significant customer could adversely affect us.

We provide our services to major international, government-owned and independent oil and gas companies.  During 2015, our five largest customers accounted for 52% of our consolidated revenues in the aggregate, with our largest customer representing 18% of our consolidated revenues.  Our financial position, operating results and cash flows may be materially adversely affected if a major customer terminates its contracts with us, fails to renew its existing contracts with us, requires renegotiation of our contracts or declines to award new contracts to us.

Our current backlog of contract drilling revenue may not be fully realized and may decline significantly in the future, which may have a material adverse effect on our financial position, results of operations or cash flows.

As of December 31, 2015, our contract backlog was approximately $5.8 billion, which represents a decline of $3.9 billion since December 31, 2014. This amount reflects the remaining contractual terms multiplied by the applicable contractual day rate, excluding $79 million in backlog attributable to the ENSCO DS-5 contract that Petrobras has asserted is void. See "Item 3. Legal Proceedings - DSA Dispute" for further information. The contractual revenue may be higher than the actual revenue we receive because of a number of factors, including rig downtime or suspension of operations. Several factors could cause rig downtime or a suspension of operations, many of which are beyond our control, including:

• the early termination, repudiation or renegotiation of contracts,

• breakdowns of equipment,

• work stoppages, including labor strikes,

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• shortages of material and skilled labor,

• surveys by government and maritime authorities,

• periodic classification surveys,

• severe weather, strong ocean currents or harsh operating conditions,

• the occurrence or threat of epidemic or pandemic diseases or any government response to such occurrence or threat, and

• force majeure events.

Our customers may seek to terminate, repudiate or renegotiate our drilling contracts for various reasons. Generally our drilling contracts permit early termination of the contract by the customer for convenience (without cause), exercisable upon advance notice to us, and in some cases without making an early termination payment to us. There can be no assurances that our customers will be able to or willing to fulfill their contractual commitments to us.

The recent decline in oil prices, the perceived risk of a further decline in oil prices, and the resulting downward pressure on utilization has caused and may continue to cause some customers to consider early termination of select contracts despite having to pay onerous early termination fees in some cases. Customers may request to re-negotiate the terms of existing contracts, or they may request early termination or seek to repudiate contracts in some circumstances. Furthermore, as our existing contracts roll off, we may be unable to secure replacement contracts for our rigs. Therefore, revenues recorded in future periods could differ materially from our current backlog. Our inability to realize the full amount of our contract backlog may have a material adverse effect on our financial position, results of operations or cash flows.

We may have difficulty obtaining or maintaining insurance in the future on terms we find acceptable and our insurance coverage may not protect us against all of the risks and hazards we face, including those specific to offshore operations.

Our operations are subject to hazards inherent in the offshore drilling industry, such as blow-outs, reservoir damage, loss of production, loss of well control, uncontrolled formation pressures, lost or stuck drill strings, equipment failures and mechanical breakdowns, punchthroughs, craterings, industrial accidents, fires, explosions, oil spills and pollution. These hazards can cause personal injury or loss of life, severe damage to or destruction of property and equipment, pollution or environmental damage, which could lead to claims by third parties or customers, suspension of operations and contract terminations. Our fleet is also subject to hazards inherent in marine operations, either while on-site or during mobilization, such as capsizing, sinking, grounding, collision, damage from severe weather and marine life infestations.  Additionally, a security breach of our information systems or other technological failure could lead to a material disruption of our operations, information systems, and/or loss of business information, which could result in an adverse impact to our business.  Our drilling contracts provide for varying levels of indemnification from our customers, including with respect to well control and subsurface risks. We also maintain insurance for personal injuries, damage to or loss of equipment and other insurance coverage for various business risks.

We generally identify the operational hazards for which we will procure insurance coverage based on the likelihood of loss, the potential magnitude of loss, the cost of coverage, the requirements of our customer contracts and applicable legal requirements. Although we maintain what we believe to be an appropriate level of insurance covering hazards and risks we currently encounter during our operations, no assurance can be given that we will be able to obtain insurance against all potential risks and hazards.

Furthermore, our insurance carriers may interpret our insurance policies such that they do not cover losses for which we make claims. Our insurance policies may also have exclusions of coverage for some losses. Uninsured

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exposures may include radiation hazards, certain loss or damage to property onboard our rigs and losses relating to shore-based terrorist acts or strikes.

If we are unable to obtain or maintain adequate insurance at rates and with deductibles or retention amounts that we consider commercially reasonable, we may choose to forgo insurance coverage and retain the associated risk of loss or damage.

If a significant accident or other event occurs and is not fully covered by insurance or contractual indemnity (or if our contractual indemnity is not enforceable under applicable law), it could adversely affect our financial position, results of operations or cash flows.

The potential for U.S. Gulf of Mexico hurricane related windstorm damage or liabilities could result in uninsured losses and may cause us to alter our operating procedures during hurricane season, which could adversely affect our business.

Certain areas in and near the U.S. Gulf of Mexico experience hurricanes and other extreme weather conditions on a relatively frequent basis. Some of our drilling rigs in the U.S. Gulf of Mexico are located in areas that could cause them to be susceptible to damage and/or total loss by these storms, and we have a larger concentration of jackup rigs in the U.S. Gulf of Mexico than most of our competitors. We currently have eight jackup rigs and nine floaters in the U.S. Gulf of Mexico. Damage caused by high winds and turbulent seas could result in rig loss or damage, termination of drilling contracts for lost or severely damaged rigs or curtailment of operations on damaged drilling rigs with reduced or suspended day rates for significant periods of time until the damage can be repaired. Moreover, even if our drilling rigs are not directly damaged by such storms, we may experience disruptions in our operations due to damage to our customers' platforms and other related facilities in the area. Our drilling operations in the U.S. Gulf of Mexico have been impacted by hurricanes, including the total loss of one jackup rig during 2004, one platform rig during 2005 and two jackup rigs during 2008, with associated losses of contract revenues and potential liabilities.

Insurance companies incurred substantial losses in the offshore drilling, exploration and production industries as a consequence of hurricanes that occurred in the U.S. Gulf of Mexico during 2004, 2005 and 2008. Accordingly, insurance companies have substantially reduced the nature and amount of insurance coverage available for losses arising from named tropical storm or hurricane damage in the U.S. Gulf of Mexico ("windstorm damage") and have dramatically increased the cost of available windstorm coverage. The tight insurance market not only applies to coverage related to U.S. Gulf of Mexico windstorm damage or loss of our drilling rigs, but also impacts coverage for any potential liabilities to third parties associated with property damage, personal injury or death and environmental liabilities, as well as coverage for removal of wreckage and debris associated with hurricane losses. We have no assurance that the tight insurance market for windstorm damage, liabilities and removal of wreckage and debris will not continue into the foreseeable future.

We decided not to purchase windstorm insurance for hull and machinery losses to our floaters arising from windstorm damage in the U.S. Gulf of Mexico since the renewal of our annual insurance policies in May 2014, due to the significant premium, high deductible and limited coverage for windstorm damage. We opted out of windstorm insurance for our jackups in the U.S. Gulf of Mexico during 2009 and have not since renewed that insurance. We believe it is no longer customary for drilling contractors with similar size and fleet composition to purchase windstorm insurance for rigs in the U.S. Gulf of Mexico, for the aforementioned reasons. Accordingly, we have retained the risk of loss or damage for our eight jackup rigs and our nine floaters arising from windstorm damage in the U.S. Gulf of Mexico.

We have established operational procedures designed to mitigate risk to our jackup rigs in the U.S. Gulf of Mexico during hurricane season. In addition to procedures designed to better secure the drilling package on jackup rigs, improve jackup leg stability and increase the air gap to position the hull above waves, our procedures involve analysis of prospective drilling locations, which may include enhanced bottom surveys. These procedures may result in a decision to decline to operate on a customer-designated location during hurricane season notwithstanding that the location, water depth and other standard operating conditions are within a rig's normal operating range. Our procedures

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and the associated regulatory requirements addressing Mobile Offshore Drilling Unit operations in the U.S. Gulf of Mexico during hurricane season, coupled with our decision to retain (self-insure) certain windstorm-related risks, may result in a significant reduction in the utilization of our jackup rigs in the U.S. Gulf of Mexico.

Our annual insurance policies are up for renewal effective May 31, 2016, and any retained exposures for property loss or damage and wreckage and debris removal or other liabilities associated with U.S. Gulf of Mexico tropical storms or hurricanes may have a material adverse effect on our financial position, operating results and cash flows if we sustain significant uninsured or underinsured losses or liabilities as a result of U.S. Gulf of Mexico tropical storms or hurricanes.

Our non-U.S. operations involve additional risks not typically associated with U.S. operations.

Revenues from non-U.S. operations were 72%, 62% and 61% of our total revenues during 2015, 2014 and 2013, respectively. Our non-U.S. operations and shipyard rig construction and enhancement projects are subject to political, economic and other uncertainties, including:

• terrorist acts, war and civil disturbances, 

• expropriation, nationalization, deprivation or confiscation of our equipment, 

• expropriation or nationalization of a customer's property or drilling rights, 

• repudiation or nationalization of contracts, 

• assaults on property or personnel, 

• piracy, kidnapping and extortion demands, 

• significant governmental influence over many aspects of local economies and customers,

• unexpected changes in law and regulatory requirements, including changes in interpretation or enforcement of existing laws, 

• work stoppages, often due to strikes over which we have little or no control,

• complications associated with repairing and replacing equipment in remote locations, 

• limitations on insurance coverage, such as war risk coverage, in certain areas,

• imposition of trade barriers,

• wage and price controls,

• import-export quotas,

• exchange restrictions, 

• currency fluctuations, 

• changes in monetary policies,

• uncertainty or instability resulting from hostilities or other crises in the Middle East, West Africa, Latin America or other geographic areas in which we operate,

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• changes in the manner or rate of taxation, 

• limitations on our ability to recover amounts due, 

• increased risk of government and vendor/supplier corruption, 

• increased local content requirements,

• the occurrence or threat of epidemic or pandemic diseases or any government response to such occurrence or threat,

• changes in political conditions, and 

• other forms of government regulation and economic conditions that are beyond our control.

We historically have maintained insurance coverage and obtained contractual indemnities that protect us from some, but not all, of the risks associated with our non-U.S. operations such as nationalization, deprivation, expropriation, confiscation, political and war risks. However, there can be no assurance that any particular type of contractual or insurance protection will be available in the future or that we will be able to purchase our desired level of insurance coverage at commercially feasible rates.  Moreover, we may initiate a self-insurance program through one or more captive insurance subsidiaries.  In circumstances where we have insurance protection for some or all of the risks sometimes associated with non-U.S. operations, such insurance may be subject to cancellation on short notice, and it is unlikely that we would be able to remove our rig or rigs from the affected area within the notice period. Accordingly, a significant event for which we are uninsured, underinsured or self-insured, or for which we have not received an enforceable contractual indemnity from a customer, could cause a material adverse effect on our financial position, operating results and cash flows.

We are subject to various tax laws and regulations in substantially all countries in which we operate or have a legal presence. We evaluate applicable tax laws and employ various business structures and operating strategies to obtain the optimal level of taxation on our revenues, income, assets and personnel. Actions by tax authorities that impact our business structures and operating strategies, such as changes to tax treaties, laws and regulations, or the interpretation or repeal of any of the foregoing or changes in the administrative practices and precedents of tax authorities, adverse rulings in connection with audits or otherwise, or other challenges may substantially increase our tax expense.

As required by law, we file periodic tax returns that are subject to review and examination by various revenue agencies within the jurisdictions in which we operate. We cannot predict or provide assurance as to the ultimate outcome of existing or future tax assessments.

Our non-U.S. operations also face the risk of fluctuating currency values, which may impact our revenues, operating costs and capital expenditures. We currently conduct contract drilling operations in certain countries that have experienced substantial fluctuations in the value of their currency compared to the U.S. dollar. In addition, some of the countries in which we operate have occasionally enacted exchange controls. Generally, we have contractually mitigated these risks by invoicing and receiving payment in U.S. dollars (our functional currency) or freely convertible currency and, to the extent possible, by limiting our acceptance of foreign currency to amounts which approximate our expenditure requirements in such currencies. However, not all of our contracts contain these terms and there is no assurance that our contracts will contain such terms in the future.

A portion of the costs and expenditures incurred by our non-U.S. operations, including a portion of the construction payments for new rigs, are settled in local currencies, exposing us to risks associated with fluctuation in the value of these currencies relative to the U.S. dollar. We use foreign currency forward contracts to reduce this exposure in certain cases. However, a relative weakening in the value of the U.S. dollar in relation to the local currencies in these countries may increase our costs and expenditures.

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Our non-U.S. operations are also subject to various laws and regulations in countries in which we operate, including laws and regulations relating to the operation of drilling rigs and the requirements for equipment. We may be required to make significant capital expenditures to operate in such countries, which may not be reimbursed by our customers. Governments in some countries have become increasingly active in regulating and controlling the ownership of oil, natural gas and mineral concessions and companies holding concessions, the exploration of oil and natural gas and other aspects of the oil and gas industry in their countries. In some areas of the world, government activity has adversely affected the amount of exploration and development work performed by major international oil companies and may continue to do so. Moreover, certain countries accord preferential treatment to local contractors or joint ventures or impose specific quotas for local goods and services, which can increase our operational costs and place us at a competitive disadvantage. There can be no assurance that such laws and regulations or activities will not have a material adverse effect on our future operations.

The shipment of goods, services and technology across international borders subjects us to extensive trade laws and regulations. Our import activities are governed by specific customs laws and regulations in each of the countries where we operate. Moreover, many countries, including the United States, control the export and re-export of certain goods, services and technology and impose related export recordkeeping and reporting obligations. Governments also may impose express or de facto economic sanctions against certain countries, persons and other entities that may restrict or prohibit transactions involving such countries, persons and entities.

The laws and regulations concerning import activity, export recordkeeping and reporting, export control and economic sanctions are complex and constantly changing. These laws and regulations may be enacted, amended, enforced or interpreted in a manner materially impacting our operations. Shipments can be delayed and denied export or entry for a variety of reasons, some of which are outside our control and some of which may result from failure to comply with existing legal and regulatory regimes. Shipping delays or denials could cause unscheduled operational downtime. Any failure to comply with applicable legal and regulatory trading obligations also could result in criminal and civil penalties and sanctions, such as fines, imprisonment, exclusion from government contracts, seizure of shipments and loss of import and export privileges.

Our employees, contractors and agents may take actions in violation of our policies and procedures designed to promote compliance with the laws of the jurisdictions in which we operate. Any such violation, even if prohibited by our policies, could have a material adverse effect on our financial position, operating results or cash flows.

Rig construction, upgrade and enhancement projects are subject to risks, including delays and cost overruns, which could have a material adverse effect on our operating results.

We currently have one ultra-deepwater drillship and three jackup rigs under construction. In addition, we may construct additional rigs and continue to upgrade the capability and extend the service lives of our existing rigs. As a result of current market conditions, we may seek to delay delivery of our rigs under construction. In July 2015, we agreed with the shipyard to delay the delivery of ENSCO DS-10, our only remaining floater under construction, until the first quarter of 2017. We also recently agreed with the shipyard to delay delivery of ENSCO 123 until the first quarter of 2018. Other delays may impact the delivery of our drilling rigs under construction or undergoing upgrade or maintenance. As of December 31, 2015, there were approximately 180 new offshore drilling rigs reported to be on order or under construction with delivery expected by the end of 2020. As a result, shipyards and third-party equipment vendors are under significant resource constraints to meet delivery obligations. Such constraints may lead to substantial delivery and commissioning delays and/or equipment failures and/or quality deficiencies. Furthermore, new drilling rigs may face start-up or other operational complications following completion of construction, upgrades or maintenance. Other unexpected difficulties, including equipment failures, design or engineering problems, could result in significant downtime at reduced or zero day rates or the cancellation or termination of drilling contracts.

Rig construction, upgrade, life extension and repair projects are subject to the risks of delay or cost overruns inherent in any large construction project, including the following:

• failure of third-party equipment to meet quality and/or performance standards, 

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• delays in equipment deliveries or shipyard construction, 

• shortages of materials or skilled labor, 

• damage to shipyard facilities or construction work in progress, including damage resulting from fire, explosion, flooding, severe weather, terrorism, war or other armed hostilities, 

• unforeseen design or engineering problems, including those relating to the commissioning of newly designed equipment, 

• unanticipated actual or purported change orders, 

• strikes, labor disputes or work stoppages, 

• financial or operating difficulties of equipment vendors or the shipyard while constructing, enhancing, upgrading, improving or repairing a rig or rigs, 

• unanticipated cost increases, 

• foreign currency exchange rate fluctuations impacting overall cost, 

• inability to obtain the requisite permits or approvals, 

• client acceptance delays,

• disputes with shipyards and suppliers,

• latent damages or deterioration to hull, equipment and machinery in excess of engineering estimates and assumptions,

• claims of force majeure events, and 

• additional risks inherent to shipyard projects in a non-U.S. location.

With respect to our rigs under construction, if we were to secure contracts for such rigs, we would be subject to the risk of delays and other hazards impacting the viability of such contracts, which could have a material adverse effect on our financial position, operating results and cash flows.

Our drilling contracts with national oil companies may expose us to greater risks than we normally assume in drilling contracts with non-governmental customers.

We currently own and operate 11 rigs that are contracted with national oil companies. We also manage a rig for a national oil company. The terms of these contracts are often non-negotiable and may expose us to greater commercial, political and operational risks than we assume in other contracts, such as exposure to materially greater environmental liability and other claims for damages (including consequential damages) and personal injury related to our operations, or the risk that the contract may be terminated by our customer without cause on short-term notice, contractually or by governmental action, under certain conditions that may not provide us with an early termination payment. We can provide no assurance that the increased risk exposure will not have an adverse impact on our future operations or that we will not increase the number of rigs contracted to national oil companies with commensurate additional contractual risks. 

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Legal and regulatory proceedings could affect us adversely.

We are involved in litigation, including various claims, disputes and regulatory proceedings that arise in the ordinary course of business, many of which are uninsured and relate to intellectual property, commercial, operational, employment, regulatory, or other activities.

We operate in a number of countries throughout the world, including countries known to have a reputation for corruption and are subject to the U.S. Foreign Corrupt Practices Act of 1977 (“FCPA”), the U.S. Treasury Department's Office of Foreign Assets Control ("OFAC") regulations, the U.K. Bribery Act ("UKBA"), other U.S. laws and regulations governing our international operations and similar laws in other countries.

In 2010, Pride and its subsidiaries resolved with the U.S. Department of Justice (“DOJ”) and the SEC their previously disclosed investigations into potential violations of the FCPA. However, Pride received preliminary inquiries from governmental authorities of certain of the countries referenced in its settlements with the DOJ and SEC. We could face additional fines, sanctions and other penalties from authorities in these and other relevant jurisdictions, including prohibition of our participating in or curtailment of business operations in those jurisdictions and the seizure of our rigs or other assets. At this stage of such inquiries, we are unable to determine what, if any, legal liability may result. Our customers in those jurisdictions could seek to impose penalties or take other actions adverse to our interests. We could also face other third-party claims by directors, officers, employees, affiliates, advisors, attorneys, agents, stockholders, debt holders, or other interest holders or constituents of our Company. In addition, disclosure of the subject matter of the investigations and settlements could adversely affect our reputation and our ability to obtain new business or retain existing business from our current clients and potential clients, to attract and retain employees and to access the capital markets.

In 2015, we became aware of an internal audit report by Petrobras alleging irregularities in relation to a drilling services agreement Pride entered into for ENSCO DS-5. On January 4, 2016, we received a notice from Petrobras declaring the DS-5 drilling services contract between Petrobras and Ensco void effective immediately. Petrobras’ notice alleges that Samsung Heavy Industries made improper payments to our former marketing consultant who then shared the improper payments with employees of Petrobras and, without specifying any supporting facts or conduct, that Pride had knowledge of this activity and assisted in the procurement of and/or facilitated these improper payments. Our Audit Committee appointed independent counsel to lead an investigation into the alleged irregularities. See "Item 3. Legal Proceedings - Brazil Internal Investigation" and "Item 3. Legal Proceedings - DSA Dispute" for further information on the investigation. Outside of Petrobras’ allegations, we have not been contacted by any Brazil governmental authority regarding alleged wrongdoing by Pride or Ensco or any of their current or former employees. We cannot predict whether any U.S., Brazilian or other governmental authority will seek to investigate this matter, or if a proceeding were opened, the scope or ultimate outcome of any such investigation.

Any violation of the FCPA, OFAC regulations, the UKBA or other applicable anti-corruption laws, by us, our affiliated entities or their respective officers, directors, employees and agents could in some cases provide a customer with termination rights under a contract and result in substantial fines, sanctions, civil and/or criminal penalties and curtailment of operations in certain jurisdictions and could adversely affect our financial condition, results of operations, cash flows or the availability of funds under our revolving credit facility. Further, we may incur significant costs and consume significant internal resources in our efforts to detect, investigate and resolve actual or alleged violations.

Increasing regulatory complexity could adversely impact the costs associated with our offshore drilling operations.

Increases in regulatory requirements, particularly in the U.S. Gulf of Mexico, could significantly increase our costs.  In recent years, we have seen several significant regulatory changes that have affected the way we operate in the U.S. Gulf of Mexico.

Hurricanes Katrina and Rita in 2005 and Hurricanes Gustav and Ike in 2008 caused damage to a number of rigs in the Gulf of Mexico. Rigs that were moved off location by the storms damaged platforms, pipelines, wellheads and other drilling rigs. The U.S. Bureau of Ocean Energy Management, Regulation and Enforcement ("BOEMRE"), and one of its successor agencies, the Bureau of Safety and Environmental Enforcement ("BSEE"), have issued

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guidelines for jackup rig fitness requirements during hurricane seasons, which have been in effect since November 2014. As a result of these guidelines, jackup rigs in the U.S. Gulf of Mexico are required to operate with a higher air gap (the space between the water level and the bottom of the rig's hull) during hurricane season, effectively reducing the water depth in which they can operate. The guidelines also provide for enhanced information and data requirements from oil and gas companies operating in the U.S. Gulf of Mexico.

Following the Macondo well incident in the U.S. Gulf of Mexico, the U.S. Department of the Interior issued Notices to Lessees (“NTLs"), implementing new requirements and/or guidelines that are applicable to drilling operations in the U.S. Gulf of Mexico. Current or future NTLs or other rules, directives and regulations may further impact our customers' ability to obtain permits and commence or continue deep or shallow water operations in the U.S. Gulf of Mexico. Future legislative or regulatory enactments may impose new requirements for well control and blowout prevention equipment that could increase our costs and cause delays in our operations due to unavailability of associated equipment.

Also as a result of the Macondo well incident, BOEMRE and BSEE have promulgated regulations regarding safety and environmental management systems ("SEMS"). During 2013, BSEE adopted a final rule modifying the SEMS requirements. Although directed primarily at operators, the SEMS requirements indirectly affect drilling contractors by imposing requirements for personnel training, written safe work practices and written agreements with operators regarding the application of the operators' and contractors' safety and environmental policies at the worksite. In addition, BSEE has stated that future rulemaking may require offshore drilling contractors to implement their own SEMS programs. The current SEMS regulations and the possibility of additional SEMS rules for contractors could expose us to increased costs.

In 2012, BSEE also issued an interim policy document for use by BSEE inspectors in issuing incidents of noncompliance (“INCs”) to contractors operating under BSEE jurisdiction on the Outer Continental Shelf of the U.S. Gulf of Mexico. The stated purpose of the policy is to provide for consistency in application of BSEE enforcement authority by establishing guidelines for issuance of INCs to contractors in addition to operators. The policy indicates that BSEE's enforcement actions will continue to focus primarily on lessees and operators, but makes it clear that BSEE will “in appropriate circumstances” also issue INCs to contractors for "serious violations" of BSEE regulations. Further, the industry has adopted new standards, including API Standard 53 relating to the maintenance, inspection and testing of well control equipment. The imposition of INCs on contractors exposes us to fines and penalties for violation of BSEE regulations and the new standards expose us to increased costs and loss of revenue.

Since 2014, the United States Coast Guard has proposed new regulations that would impose GPS equipment and positioning requirements for mobile offshore drilling units and jackup rigs operating in the U.S. Gulf of Mexico and issued notices regarding the development of regulations for cybersecurity measures used in the marine and offshore energy sectors for all vessels and facilities that are subject to the Maritime Transportation Security Act of 2002, including our rigs. In April 2015, BSEE proposed new rules that, if and when enacted, would include more stringent design requirements for well control equipment used in offshore drilling operations. Based on our assessment of the proposed rules, we may incur significant costs to comply with the rules if they are adopted as proposed. We are continuing to evaluate the cost and effect that these proposed new rules will have on our operations. Implementation of further guidelines and regulations may subject us to increased costs and limit the operational capabilities of our rigs.

New regulatory, legislative, permitting or certification requirements in the U.S., including laws and regulations that have or may impose increased financial responsibility, oil spill abatement contingency plan capability requirements, or additional operational requirements and certifications, could materially adversely affect our financial condition, operating results or cash flows.

We anticipate that government regulation in other countries where we operate may follow the U.S. in regard to enhanced safety and environmental regulation, which could also result in governments imposing sanctions on contractors when operators fail to comply with regulations that impact drilling operations. Even if not a requirement in these countries, most international operating companies, and many others, are voluntarily complying with some or all of the U.S. inspections and safety and environmental guidelines when operating outside the U.S. Such additional

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governmental regulation and voluntary compliance by operators could increase the cost of our operations and expose us to greater liability.

Laws and governmental regulations may add to costs, limit our drilling activity or reduce demand for our drilling services.

Our operations are affected by political developments and by laws and regulations that relate directly to the oil and gas industry, including initiatives to limit greenhouse gas emissions. The offshore contract drilling industry is dependent on demand for services from the oil and gas industry. Accordingly, we will be directly affected by the approval and adoption of laws and regulations limiting or curtailing exploration and development drilling for oil and natural gas for economic, environmental, safety and other policy reasons. We may be exposed to risks related to new laws or regulations pertaining to climate change, carbon emissions or energy use that could reduce the use of oil or natural gas, thus reducing demand for hydrocarbon-based fuel and our drilling services. Governments also may pass laws or regulations encouraging or mandating the use of alternative energy sources, such as wind power and solar energy, which may reduce demand for oil and natural gas and our drilling services. Furthermore, we may be required to make significant capital expenditures or incur substantial additional costs to comply with new governmental laws and regulations. It is also possible that legislative and regulatory activity could adversely affect our operations by limiting drilling opportunities or significantly increasing our operating costs.

Geopolitical events, terrorist attacks, piracy and military action could affect the markets for our services and have a material adverse effect on our business and cost and availability of insurance.

Geopolitical events have resulted in military actions, terrorist, pirate and other armed attacks, civil unrest, political demonstrations, mass strikes and government responses. Military action by the United States or other nations could escalate, and acts of terrorism, piracy, kidnapping, extortion, acts of war, violence, civil war, or general disorder may initiate or continue. Such acts could be directed against companies such as ours. Such developments have caused instability in the world’s financial and insurance markets in the past. In addition, these developments could lead to increased volatility in prices for oil and natural gas and could affect the markets for our products and services. Insurance premiums could increase and coverage for these kinds of events may be unavailable in the future. Any or all of these effects could have a material adverse effect on our financial position, operating results or cash flows.

Failure to recruit and retain skilled personnel could adversely affect our operations and financial results.

We require skilled personnel to operate our drilling rigs and to provide technical services and support for our business. Historically, competition for the labor required for drilling operations and construction projects has intensified as the number of rigs activated, added to worldwide fleets or under construction increased, leading to shortages of qualified personnel in the industry. During such periods of intensified competition, it is more difficult and costly to recruit and retain qualified employees, especially in foreign countries that require a certain percentage of national employees. If competition for labor were to intensify in the future, we could experience an increase in operating expenses, with a resulting reduction in net income, and our ability to fully staff and operate our rigs could be negatively affected.

We may be required to maintain or increase existing levels of compensation to retain our skilled workforce, especially if our competitors raise their wage rates. We also are subject to potential legislative or regulatory action that may impact working conditions, paid time off or other conditions of employment. If such labor trends continue, they could further increase our costs or limit our ability to fully staff and operate our rigs.

Unionization efforts and labor regulations in certain countries in which we operate could materially increase our costs or limit our flexibility.

Outside of the U.S., we are often subject to collective bargaining agreements that require periodic salary negotiations, which usually result in higher personnel expenses and other benefits. Efforts have been made from time to time to unionize other portions of our workforce. In addition, we have been subjected to strikes or work stoppages

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and other labor disruptions in certain countries. Additional unionization efforts, new collective bargaining agreements or work stoppages could materially increase our costs, reduce our revenues or limit our flexibility.

Certain legal obligations require us to contribute certain amounts to retirement funds or other benefit plans and restrict our ability to dismiss employees. Future regulations or court interpretations established in the countries in which we conduct our operations could increase our costs and materially adversely affect our business, financial condition, operating results or cash flows.

Compliance with or breach of environmental laws can be costly and could limit our operations.

Our operations are subject to laws and regulations controlling the discharge of materials into the environment, pollution, contamination and hazardous waste disposal or otherwise relating to the protection of the environment. Environmental laws and regulations specifically applicable to our business activities could impose significant liability on us for damages, clean-up costs, fines and penalties in the event of oil spills or similar discharges of pollutants or contaminants into the environment or improper disposal of hazardous waste generated in the course of our operations. To date, such laws and regulations have not had a material adverse effect on our operating results, and we have not experienced an accident that has exposed us to material liability arising out of or relating to discharges of pollutants into the environment.  However, the legislative, judicial and regulatory response to a well incident could substantially increase our and our customers' liabilities.  In addition to potential increased liabilities, such legislative, judicial or regulatory action could impose increased financial, insurance or other requirements that may adversely impact the entire offshore drilling industry.

The International Convention on Oil Pollution Preparedness, Response and Cooperation, Marpol 73/78, the U.K. Merchant Shipping Act 1995, the U.K. Merchant Shipping (Oil Pollution Preparedness, Response and Cooperation Convention) Regulations 1998, and other related legislation and regulations and Oil Pollution Act of 1990 ("OPA 90"), the Clean Water Act and other U.S. federal statutes applicable to us and our operations, as well as similar statutes in Texas, Louisiana, other coastal states and other non-U.S. jurisdictions, address oil spill prevention and control and significantly expand liability, fine and penalty exposure across many segments of the oil and gas industry. Such statutes and related regulations impose a variety of obligations on us related to the prevention of oil spills, disposal of waste and liability for resulting damages. For instance, OPA 90 imposes strict and, with limited exceptions, joint and several liability upon each responsible party for oil removal costs as well as a variety of fines, penalties and damages. Although the OPA 90 provides for certain limits of liability, such limits are not applicable where there is any safety violation or where gross negligence is involved. Failure to comply with these statutes and regulations, including OPA 90, may subject us to civil or criminal enforcement action, which may not be covered by contractual indemnification or insurance and could have a material adverse effect on our financial position, operating results and cash flows. Further, remedies under the Clean Water Act and related legislation and the OPA 90 do not preclude claims under state regulations or civil claims for damages to third parties under state laws.

Events in recent years, including the Macondo well incident, have heightened governmental and environmental concerns about the risks associated with offshore oil and gas drilling. We are adversely affected by restrictions on drilling in certain areas in which we operate, including policies and guidelines regarding the approval of drilling permits, restrictions on development and production activities, and directives and regulations that have and may further impact our operations. From time to time, legislative and regulatory proposals have been introduced that would materially limit or prohibit offshore drilling in certain areas, or that would increase the liabilities or costs associated with offshore drilling. If new laws are enacted, or if government actions are taken that restrict or prohibit offshore drilling in our principal areas of operation or that impose environmental or other requirements that materially increase the liabilities, financial requirements or operating or equipment costs associated with offshore drilling, exploration, development, or production of oil and natural gas, our financial position, operating results and cash flows could be materially adversely affected.

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Our debt levels and debt agreement restrictions may limit our liquidity and flexibility in obtaining additional financing and in pursuing other business opportunities.

As of December 31, 2015, we had $5.9 billion in total debt outstanding, representing approximately 47.5% of our total capitalization. Our current indebtedness may have several important effects on our future operations, including:

• a portion of our cash flows from operations will be dedicated to the payment of principal and interest,

• covenants contained in our debt arrangements require us to meet certain financial tests, which may affect our flexibility in planning for, and reacting to, changes in our business and may limit our ability to dispose of assets or place restrictions on the use of proceeds from such dispositions, withstand current or future economic or industry downturns and compete with others in our industry for strategic opportunities, and

• our ability to obtain additional financing to fund working capital requirements, capital expenditures, acquisitions, dividend payments and general corporate or other cash requirements may be limited.

Our ability to maintain a sufficient level of liquidity to meet our financial obligations will be dependent upon our future performance, which will be subject to general economic conditions, industry cycles and financial, business and other factors affecting our operations, many of which are beyond our control. Our future cash flows may be insufficient to meet all of our working capital requirements, debt obligations and contractual commitments, and any insufficiency could negatively impact our business.

To the extent we are unable to repay our debt as it becomes due with cash on hand or from other sources, we will need to refinance our debt, sell assets or repay the debt with the proceeds from equity offerings. Additional indebtedness or equity financing may not be available to us in the future for the refinancing or repayment of existing debt, or if available, such additional debt or equity financing may not be available on a timely basis, or on terms acceptable to us and within the limitations specified in our then existing debt instruments. In addition, in the event we decide to sell additional assets, we can provide no assurance as to the timing of any asset sales or the proceeds that could be realized by us from any such asset sale.

In addition, our access to credit and capital markets depends on the credit ratings assigned to our debt by independent credit rating agencies. There can be no assurance that we will be able to maintain our credit ratings, and any additional actual or anticipated downgrades in our credit ratings, including any announcement that our ratings are under review for a downgrade, could limit our ability to access credit and capital markets, or to restructure or refinance our indebtedness. In addition, future financings or refinancings may result in higher borrowing costs and require more restrictive terms and covenants, which may further restrict our operations. If we are downgraded below investment grade by one or more credit rating agencies, we may have limited or no access to the commercial paper market. Any downgrade or anticipated downgrade in our credit ratings, particularly below investment grade, could have a material adverse impact on our financial position, results of operations and liquidity.

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We have historically made substantial capital expenditures to maintain our fleet, and we may be required to make significant capital expenditures to maintain our competitiveness, to comply with laws and the applicable regulations and standards of governmental authorities and organizations, or to expand our fleet, each of which could adversely affect our financial condition, result of operations and cash flows.

We have historically made substantial capital expenditures to maintain our fleet. These expenditures could increase as a result of changes in:

• offshore drilling technology,

• the cost of labor and materials,

• customer requirements,

• fleet size,

• the cost of replacement parts for existing drilling rigs,

• the geographic location of the drilling rigs,

• length of drilling contracts,

• governmental regulations and maritime self-regulatory organization and technical standards relating to safety, security or the environment, and

• industry standards.

Changes in offshore drilling technology, customer requirements for new or upgraded equipment and competition within our industry may require us to make significant capital expenditures in order to maintain our competitiveness. In addition, changes in governmental regulations, relating to safety or equipment standards, as well as compliance with standards imposed by maritime self-regulatory organizations, may require us to make additional unforeseen capital expenditures. As a result, we may be required to take our rigs out of service for extended periods of time, with corresponding losses of revenues, in order to make such alterations or to add such equipment. In the future, market conditions may not justify these expenditures or enable us to operate our older rigs profitably during the remainder of their economic lives.

Additionally, in order to expand our fleet, we may require additional capital in the future. If we are unable to fund capital with cash flows from operations or sales of non-core assets, we may be required to either incur additional borrowings or raise capital through the sale of debt or equity securities. Our ability to access the capital markets may be limited by our financial condition at the time, by changes in laws and regulations (or interpretation thereof) and by adverse market conditions resulting from, among other things, general economic conditions and contingencies and uncertainties that are beyond our control. If we raise funds by issuing equity securities, existing shareholders may experience dilution. Our failure to obtain the funds for necessary future capital expenditures could have a material adverse effect on our business and on our financial condition, results of operations and cash flows.

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Significant part or equipment shortages, supplier capacity constraints, supplier production disruptions, supplier

quality and sourcing issues or price increases could increase our operating costs, decrease our revenues and adversely impact our operations.

Our reliance on third-party suppliers, manufacturers and service providers to secure equipment, parts, components and sub-systems used in our operations exposes us to potential volatility in the quality, prices and availability of such items. Certain high-specification parts and equipment that we use in our operations may be available only from a small number of suppliers, manufacturers or service providers, or in some cases must be sourced through a single supplier, manufacturer or service provider. Recent industry consolidation has reduced the number of available suppliers. A disruption in the deliveries from such third-party suppliers, manufacturers or service providers, capacity constraints, production disruptions, price increases, quality control issues, recalls or other decreased availability of parts and equipment could adversely affect our ability to meet our commitments to customers, thus adversely impacting our operations and revenues or increase our operating costs.

Our long-term contracts are subject to the risk of cost increases, which could adversely impact our profitability.

In general, our costs increase as the demand for contract drilling services and skilled labor increases. While many of our contracts include cost escalation provisions that allow changes to our day rate based on stipulated cost increases or decreases, the timing and amount earned from these day rate adjustments may differ from our actual increase in costs and certain contracts do not allow for such day rate adjustments. During times of reduced demand, reductions in costs may not be immediate as portions of the crew may be required to prepare our rigs for stacking, after which time the crew members are assigned to active rigs or dismissed. Moreover, as our rigs are mobilized from one geographic location to another, the labor and other operating and maintenance costs can vary significantly. In general, labor costs increase primarily due to higher salary levels and inflation. Equipment maintenance expenses fluctuate depending upon the type of activity a drilling rig is performing and the age and condition of the equipment. Contract preparation expenses vary based on the scope and length of contract preparation required.

Our information technology systems are subject to cybersecurity risks and threats.

We depend on technologies, systems, and networks to conduct our offshore and onshore operations, to collect payments from customers and to pay vendors and employees.  The risks associated with cyber incidents and attacks to our information technology systems could include disruptions of certain systems on our rigs; other impairments of our ability to conduct our operations; loss of intellectual property, proprietary information or customer data; disruption of our customers' operations; and increased costs to prevent, respond to or mitigate cybersecurity events.  If we were to experience a cyber-attack or incident, it could adversely affect our financial position, results of operations and cash flows.    

Governments may pass laws that subject us to additional taxation or may challenge our tax positions, which could adversely affect our financial position, results of operations and cash flows.

There is increasing uncertainty with respect to tax laws, regulations and treaties, and the interpretation and enforcement thereof that may affect our business. For example, the U.K., the U.S. and other countries within which we operate are currently evaluating legislative and regulatory reforms that may result in us being subject to additional taxation or to challenges with respect to the tax positions we adopt. The Organization for Economic Cooperation and Development (“OECD”) recently issued its final reports on Base Erosion and Profit Shifting, which generally focus on situations where profits are earned in low-tax jurisdictions, or payments are made between affiliates from a jurisdiction with high tax rates to a jurisdiction with lower tax rates. Based on the recommendations of the OECD, it is possible that a number of relevant countries may enact changes to their tax laws or practices (prospectively or retroactively), in particular with respect to transfer pricing, which may have a material adverse effect on our financial position, operating results and/or cash flows.

In addition, our tax positions are subject to audit by U.K., U.S. and other foreign tax authorities. Such tax authorities may disagree with our interpretations or assessments of the effects of tax laws, treaties, or regulations or

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their applicability to our corporate structure or certain transactions we have undertaken. Even if we are successful in maintaining our tax positions, we may incur significant expenses in defending our positions and contesting claims asserted by tax authorities. If we are unsuccessful in defending our tax positions, the resulting assessments or ruling could significantly impact our consolidated effective income tax rate in past or future periods.

As a result of these uncertainties, as well as changes in the administrative practices and precedents of tax authorities or other matter (such as changes in applicable accounting rules) that increases the amounts we have provided for income taxes or deferred tax assets and liabilities in our consolidated financial statements, we cannot provide any assurances as to what our consolidated effective income tax rate will be in future periods.  If we are unable to mitigate the negative consequences of any change in law, audit or other matter, this could cause our consolidated effective income tax rate to increase and cause a material adverse effect on our financial position, operating results and/or cash flows.

Our consolidated effective income tax rate may vary substantially from one reporting period to another.

We cannot provide any assurances as to what our consolidated effective income tax rate will be because of, among other matters, uncertainty regarding the nature and extent of our business activities in any particular jurisdiction in the future and the tax laws of such jurisdictions, as well as potential changes in U.K., U.S. and other foreign tax laws, regulations or treaties or the interpretation or enforcement thereof, changes in the administrative practices and precedents of tax authorities or any reclassification or other matter (such as changes in applicable accounting rules) that increases the amounts we have provided for income taxes or deferred tax assets and liabilities in our consolidated financial statements. In addition, 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 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. If we are unable to mitigate the negative consequences of any change in law, audit, business activity or other matter, this could cause our consolidated effective income tax rate to increase and cause a material adverse effect on our financial position, operating results and/or cash flows.

Transfers of our Class A ordinary shares may be subject to stamp duty or stamp duty reserve tax (“SDRT”) in the U.K., which would increase the cost of dealing in our Class A ordinary shares.

Stamp duty and/or SDRT are imposed in the U.K. on certain transfers of chargeable securities (which include shares in companies incorporated in the U.K.) at a rate of 0.5% of the consideration paid for the transfer. Certain transfers of shares to depositary receipt facilities or clearance systems providers are charged at a higher rate of 1.5%.

Pursuant to arrangements that we entered into with the Depository Trust Company (“DTC”), our Class A ordinary shares are eligible to be held in book entry form through the facilities of DTC. Transfers of shares held in book entry form through DTC will not attract a charge to stamp duty or SDRT in the U.K. A transfer of the shares from within the DTC system out of DTC and any subsequent transfers that occur entirely outside the DTC system will attract a charge to stamp duty at a rate of 0.5% of any consideration, which is payable by the transferee of the shares. Any such duty must be paid (and the relevant transfer document stamped by Her Majesty's Revenue & Customs (“HMRC”)) before the transfer can be registered in the share register of Ensco plc. If a shareholder decides to redeposit shares into DTC, the redeposit will attract SDRT at a rate of 1.5% of the value of the shares.

We have put in place arrangements with our transfer agent to require that shares held in certificated form cannot be transferred into the DTC system until the transferor of the shares has first delivered the shares to a depository specified by us so that SDRT may be collected in connection with the initial delivery to the depository. Any such shares will be evidenced by a receipt issued by the depository. Before the transfer can be registered in our share register, the

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transferor will also be required to provide the transfer agent sufficient funds to settle the resultant liability for SDRT, which will be charged at a rate of 1.5% of the value of the shares.

We have obtained a favorable ruling from HMRC in respect of stamp duty and SDRT in relation to both the conversion of our outstanding American Depositary Shares (“ADS”) into Class A ordinary shares in May 2012 and our arrangement with DTC. Furthermore, following decisions of the European Court of Justice and the U.K. First-tier Tax Tribunal, HMRC has announced that it will not seek to apply a charge to stamp duty or SDRT on the issuance of shares (or, where it is integral to the raising of new capital, the transfer of new shares) into a depositary receipt facility or clearance system provider, such as DTC. However, it is possible that the U.K. government may change or enact laws applicable to stamp duty or SDRT in response to this decision, which could have a material effect on the cost of trading in our shares.

If the Class A ordinary shares are not eligible for continued deposit and clearing within the facilities of DTC, then transactions in our securities may be disrupted.

The facilities of DTC are widely-used for rapid electronic transfers of securities between participants within the DTC system, which include numerous major international financial institutions and brokerage firms. Currently, all trades of our Class A ordinary shares on the NYSE are cleared and settled on the facilities of DTC. Our Class A ordinary shares are, at present, eligible for deposit and clearing within the DTC system, pursuant to arrangements with DTC whereby DTC accepted our Class A ordinary shares for deposit, clearing and settlement services, and we agreed to indemnify DTC for any stamp duty and/or SDRT that may be assessed upon it as a result of its service as a clearance system provider for our Class A ordinary shares. However, DTC retains sole discretion to cease to act as a clearance system provider for our Class A ordinary shares at any time.

If DTC determines at any time that our shares are no longer eligible for deposit, clearing and settlement services within its facilities, our shares may become ineligible for continued listing on a U.S. securities exchange or inclusion in the S&P 500, and trading in such shares would be disrupted. In this event, DTC has agreed it will provide us advance notice and assist us, to the extent possible, with efforts to mitigate adverse consequences. While we would pursue alternative arrangements to preserve our listing and maintain trading, any such disruption could have a material adverse effect on the trading price of our Class A ordinary shares.

Investor enforcement of civil judgments against us may be more difficult.

Because our parent company is a public limited company incorporated under the Laws of England and Wales, investors could experience more difficulty enforcing judgments obtained against us in U.S. courts than would have been the case for U.S. judgments obtained against us prior to the redomestication. In addition, it may be more difficult (or impossible) to bring some types of claims against us in courts in England than it would be to bring similar claims against a U.S. company in a U.S. court.

We have less flexibility as a U.K. public limited company with respect to certain aspects of capital management than U.S. corporations due to increased shareholder approval requirements.

Directors of Delaware and other U.S. corporations may issue, without further shareholder approval, shares of common stock authorized in their certificates of incorporation that were not already issued or reserved.  The business corporation laws of Delaware and other U.S. states also provide substantial flexibility in establishing the terms of preferred stock. However, English law provides that a board of directors may only allot shares with the prior authorization of an ordinary resolution of the shareholders, which authorization must state the maximum amount of shares that may be allotted under it and specify the date on which it will expire, which must not be more than five years from the date on which the shareholder resolution is passed. An ordinary resolution was passed by shareholders at our last annual meeting in 2015 to authorize the allotment of additional shares for a one-year term. As this authority will expire in May 2016, an ordinary resolution will be put to shareholders at our next annual shareholder meeting seeking their approval to renew the board's authority to allot shares for an additional one-year term.

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English law also generally provides shareholders pre-emption rights over new shares that are issued for cash. However, it is possible, where the board of directors is generally authorized to allot shares, to exclude pre-emption rights by a special resolution of the shareholders or by a provision in the articles of association. Such exclusion of pre-emption rights will commonly cease to have effect at the same time as the general allotment authority to which it relates is revoked or expires. If the general allotment authority is renewed, the authority excluding pre-emption rights may also be renewed by a special resolution of the shareholders. A special resolution was passed, in conjunction with an allotment authority at our last annual shareholder meeting in 2015, to exclude pre-emption rights for a one-year term. As this authority will expire in May 2016, a special resolution will be put to shareholders at our next annual shareholder meeting seeking their approval to renew the board's authority to exclude pre-emption rights for an additional one-year term.

English law prohibits us from conducting "on-market purchases" as our shares will not be traded on a recognized investment exchange in the U.K. English law also generally prohibits a company from repurchasing its own shares by way of "off-market purchases" without the approval by a special resolution of the shareholders of the terms of the contract by which the purchase(s) is affected. Such approval may only last for a maximum period of five years after the date on which the resolution is passed. A special resolution was passed at the Company's annual shareholder meeting in May 2013 to permit the Company to make "off-market" purchases of its own shares pursuant to certain purchase agreements for a five-year term.

We have no assurances that situations will not arise where such shareholder approval requirements for any of these actions would deprive our shareholders of substantial benefits.

Our articles of association contain anti-takeover provisions.

Certain provisions of our articles of association have anti-takeover effects, such as the ability to issue shares under the Rights Plan (as defined therein). These provisions are intended to ensure that any takeover or change of control of the Company is conducted in an orderly manner, all members of the Company are treated equally and fairly and receive an optimum price for their shares and the long-term success of the Company is safeguarded. Under English law, it may not be possible to implement these provisions in all circumstances.

The Company is not subject to the U.K.'s Code on Takeovers and Mergers (the “Code”).

The Code only applies to an offer for a public company that is registered in the U.K. (or the Channel Islands or the Isle of Man) and the securities of which are not admitted to trading on a regulated market in the U.K. (or the Channel Islands or the Isle of Man) if the company is considered by the Takeover Panel to have its place of central management and control in the U.K. (or the Channel Islands or the Isle of Man). This is known as the "residency test." The test for central management and control under the Takeover Code is different from that used by the U.K. tax authorities. Under the Takeover Code, the Panel will look to where the majority of the directors of the company are themselves resident for the purposes of determining where the company has its place of central management and control. Accordingly, the Code does not currently apply to the Company and the Company therefore does not have the benefit of the protections the Code affords, including, but not limited to, the requirement that a person who acquires an interest in shares carrying 30% or more of the voting rights in the Company must make a cash offer to all other shareholders at the highest price paid in the 12 months before the offer was announced.

English law requires that we meet certain additional financial requirements before we declare dividends and return funds to shareholders.

Under English law, we are only able to declare dividends and return funds to our shareholders out of the accumulated distributable reserves on our statutory balance sheet. Distributable reserves are a company’s accumulated, realized profits, so far as not previously utilized by distribution or capitalization, less its accumulated, realized losses, so far as not previously written off in a reduction or reorganization of capital duly made. Realized profits are created through the remittance of profits of certain subsidiaries to our parent company in the form of dividends.

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English law also provides that a public company can only make a distribution if, among other things (a) the amount of its net assets (that is, the total excess of assets over liabilities) is not less than the total of its called up share capital and non-distributable reserves and (b) if, and to the extent that, the distribution does not reduce the amount of its net assets to less than that total.

We may be unable to remit the profits of our subsidiaries in a timely or tax efficient manner. If at any time we do not have sufficient distributable reserves to declare and pay quarterly dividends, we may undertake a reduction in the capital of the Company, in addition to the reduction in capital taken in 2014, to reduce the amount of our share capital and non-distributable reserves and to create a corresponding increase in our distributable reserves out of which future distributions to shareholders can be made. To comply with English law, a reduction of capital would be subject to (a) approval of shareholders at the annual shareholder meeting by special resolution; (b) confirmation by an order of the English Courts and (c) the Court order being delivered to and registered by the Registrar of Companies in England. If we were to pursue a reduction of capital of the Company as a course of action, and failed to obtain the necessary approvals from shareholders and the English Courts, we may undertake other efforts to allow the Company to declare dividends and return funds to shareholders.

Item 1B.Unresolved Staff Comments

None.

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Item 2.Properties

Contract Drilling Fleet

The following table provides certain information about the rigs in our drilling fleet by reportable segment as of February 24, 2016:

Rig Name	Rig Type	Year Built/ Rebuilt	Design	Maximum  Water Depth/ Drilling Depth	Location	Customer
Floaters
ENSCO DS-1	Drillship	1999/2012	Dynamically Positioned	6,000'/30,000'	Spain	Cold stacked
ENSCO DS-2	Drillship	1999	Dynamically Positioned	6,000'/30,000'	Spain	Cold stacked
ENSCO DS-3	Drillship	2010	Dynamically Positioned	10,000'/40,000'	Gulf of Mexico	BP
ENSCO DS-4	Drillship	2010	Dynamically Positioned	10,000'/40,000'	Gulf of Mexico	Not contracted
ENSCO DS-5	Drillship	2011	Dynamically Positioned	10,000'/40,000'	Gulf of Mexico	Petrobras(1)
ENSCO DS-6	Drillship	2012	Dynamically Positioned	10,000'/40,000'	Spain	BP
ENSCO DS-7	Drillship	2013	Dynamically Positioned	10,000'/40,000'	Angola	TOTAL
ENSCO DS-8	Drillship	2015	Dynamically Positioned	10,000'/40,000'	Angola	TOTAL
ENSCO DS-9	Drillship	2015	Dynamically Positioned	10,000'/40,000'	Singapore	Not contracted
ENSCO DS-10	Drillship	2017	Dynamically Positioned	10,000'/40,000'	South Korea	Under construction(2)
ENSCO 5004	Semisubmersible	1982/2001/2014	F&G Enhanced Pacesetter	1,500'/25,000'	Mediterranean	Mellitah
ENSCO 5005	Semisubmersible	1982/2014	F&G Enhanced Pacesetter	1,500'/25,000'	Brunei	Petronas Carigali
ENSCO 5006	Semisubmersible	1999/2014	Bingo 8000	7,000'/25,000'	Australia	Inpex
ENSCO 6000	Semisubmersible	1987/1996	Dynamically Positioned	3,400'/12,000'	Spain	Cold stacked
ENSCO 6001	Semisubmersible	2000/2010/2014	Megathyst	5,600'/25,000'	Brazil	Petrobras
ENSCO 6002	Semisubmersible	2001/2009/2015	Megathyst	5,600'/25,000'	Brazil	Petrobras
ENSCO 6003	Semisubmersible	2004	Megathyst	5,600'/25,000'	Brazil	Petrobras
ENSCO 6004	Semisubmersible	2004	Megathyst	5,600'/25,000'	Brazil	Petrobras
ENSCO 7500	Semisubmersible	2000	Dynamically Positioned	8,000'/30,000'	Spain	Cold stacked
ENSCO 8500	Semisubmersible	2008	Dynamically Positioned	8,500'/35,000'	Gulf of Mexico	Not contracted
ENSCO 8501	Semisubmersible	2009	Dynamically Positioned	8,500'/35,000'	Gulf of Mexico	Cold stacked
ENSCO 8502	Semisubmersible	2010/2012	Dynamically Positioned	8,500'/35,000'	Gulf of Mexico	Cold stacked
ENSCO 8503	Semisubmersible	2010	Dynamically Positioned	8,500'/35,000'	Gulf of Mexico	Stone Energy
ENSCO 8504	Semisubmersible	2011	Dynamically Positioned	8,500'/35,000'	Malaysia	Chevron
ENSCO 8505	Semisubmersible	2012	Dynamically Positioned	8,500'/35,000'	Gulf of Mexico	Marubeni
ENSCO 8506	Semisubmersible	2012	Dynamically Positioned	8,500'/35,000'	Gulf of Mexico	Not contracted
Jackups
ENSCO 52	Jackup	1983/1997/2013	F&G L-780 MOD II-C	300'/25,000'	Malaysia	Murphy
ENSCO 53	Jackup	1982/2009	F&G L-780 MOD II-C	300'/25,000'	UAE	NDC
ENSCO 54	Jackup	1982/1997/2014	F&G L-780 MOD II-C	300'/25,000'	Saudi Arabia	Saudi Aramco
ENSCO 56	Jackup	1982/1997	F&G L-780 MOD II-C	300'/25,000'	Malaysia	Cold stacked
ENSCO 58	Jackup	1981/2002	F&G L-780 MOD II	250'/30,000'	Bahrain	Cold stacked
ENSCO 67	Jackup	1976/2005	MLT 84-CE	400'/30,000'	Malaysia	Not contracted
ENSCO 68	Jackup	1976/2004	MLT 84-CE	400'/30,000'	Gulf of Mexico	Chevron
ENSCO 70	Jackup	1981/1996/2014	Hitachi K1032N	250'/30,000	United Kingdom	Not contracted
ENSCO 71	Jackup	1982/1995/2012	Hitachi K1032N	225'/25,000'	Denmark	Maersk
ENSCO 72	Jackup	1981/1996	Hitachi K1025N	225'/25,000'	Denmark	Maersk
ENSCO 75	Jackup	1999	MLT Super 116-C	400'/30,000'	Gulf of Mexico	Fieldwood
ENSCO 76	Jackup	2000	MLT Super 116-C	350'/30,000'	Saudi Arabia	Saudi Aramco
ENSCO 80	Jackup	1978/1995	MLT 116-CE	225'/30,000'	United Kingdom	GDF
ENSCO 81	Jackup	1979/2003	MLT 116-C	350'/30,000'	Gulf of Mexico	Cold stacked

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Rig Name	Rig Type	Year Built/ Rebuilt	Design	Maximum  Water Depth/ Drilling Depth	Location	Customer
Jackups
ENSCO 82	Jackup	1979/2003	MLT 116-C	300'/30,000'	Gulf of Mexico	Cold stacked
ENSCO 84	Jackup	1981/2005/2012	MLT 82-SD-C	250'/25,000'	Bahrain	Cold stacked
ENSCO 86	Jackup	1981/2006	MLT 82-SD-C	250'/30,000'	Gulf of Mexico	Cold stacked
ENSCO 87	Jackup	1982/2006	MLT 116-C	350'/25,000'	Gulf of Mexico	Not contracted
ENSCO 88	Jackup	1982/2004/2014	MLT 82-SD-C	250'/25,000'	Saudi Arabia	Saudi Aramco
ENSCO 90	Jackup	1982/2002	MLT 82-SD-C	250'/25,000'	Gulf of Mexico	Cold stacked
ENSCO 91	Jackup	1980/2001/2012	Hitachi Zosen	270'/20,000'	Bahrain	Cold stacked
ENSCO 92	Jackup	1982/1996	MLT 116-C	225'/25,000'	United Kingdom	ConocoPhillips
ENSCO 94	Jackup	1981/2001/2013	Hitachi 250-C	250'/25,000'	Saudi Arabia	Saudi Aramco
ENSCO 96	Jackup	1982/1997/2012	Hitachi 250-C	250'/25,000'	Saudi Arabia	Saudi Aramco
ENSCO 97	Jackup	1980/1997/2012	MLT 82 SD-C	250'/25,000'	Saudi Arabia	Saudi Aramco
ENSCO 99	Jackup	1985/2005	MLT 82 SD-C	250'/30,000'	Gulf of Mexico	Cold stacked
ENSCO 100	Jackup	1987/2009	MLT 150-88-C	350'/30,000	United Kingdom	Premier
ENSCO 101	Jackup	2000	KELFS MOD V-A	400'/30,000'	United Kingdom	BP
ENSCO 102	Jackup	2002	KELFS MOD V-A	400'/30,000'	United Kingdom	GDF
ENSCO 104	Jackup	2002	KELFS MOD V-B	400'/30,000'	UAE	NDC
ENSCO 105	Jackup	2002	KELFS MOD V-B	400'/30,000'	Singapore	Not contracted
ENSCO 106	Jackup	2005	KELFS MOD V-B	400'/30,000'	Malaysia	Not contracted
ENSCO 107	Jackup	2006	KELFS MOD V-B	400'/30,000'	New Zealand	Not contracted
ENSCO 108	Jackup	2007	KELFS MOD V-B	400'/30,000'	Thailand	PTTEP
ENSCO 109	Jackup	2008	KELFS MOD V-Super B	350'/35,000'	Angola	Chevron
ENSCO 110	Jackup	2015	KELFS MOD V-B	400'/30,000'	UAE	NDC
ENSCO 120	Jackup	2013	KFELS Super A	400'/40,000'	United Kingdom	Nexen
ENSCO 121	Jackup	2013	KFELS Super A	400'/40,000'	Denmark	Wintershall
ENSCO 122	Jackup	2014	KFELS Super A	400'/40,000'	Netherlands	NAM
ENSCO 123	Jackup	2018	KFELS Super A	400'/40,000'	Singapore	Under construction(1)
ENSCO 140	Jackup	2016	Cameron Letourneau Super 116E	400'/30,000'	UAE	Under construction(1)
ENSCO 141	Jackup	2016	Cameron Letourneau Super 116E	400'/30,000'	UAE	Under construction(1)

⁽¹⁾ Petrobras has asserted that the ENSCO DS-5 drilling services contract is void. We disagree with Petrobras' assertion and plan to pursue our legal rights in connection with this dispute. See "Item 3. Legal Proceedings - DSA Dispute" for further information.

⁽²⁾  Rig is currently under construction and is not contracted. The "year built" provided is based on the current construction schedule.

The equipment on our drilling rigs includes engines, drawworks, derricks, pumps to circulate drilling fluid, well control systems, drill string and related equipment. The engines power a top-drive mechanism that turns the drill string and drill bit so that the hole is drilled by grinding subsurface materials, which are then returned to the rig by the drilling fluid. The intended water depth, well depth and geological conditions are the principal factors that determine the size and type of rig most suitable for a particular drilling project.

Floater rigs consist of drillship rigs and semisubmersible rigs. Drillship rigs are maritime vessels that have been outfitted with drilling apparatus.  Drillships are self-propelled and can be positioned over a drill site through the use of a computer-controlled propeller or "thruster" (dynamic positioning) system.  Our drillships are capable of drilling in water depths of 10,000 feet or less and are suitable for deepwater drilling in remote locations because of their mobility and large load-carrying capacity.  Although drillships are most often used for deepwater drilling and exploratory well drilling, drillships can also be used as a platform to carry out well maintenance or completion work such as casing and tubing installation or subsea tree installations.

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Semisubmersible rigs are mobile offshore drilling units with pontoons and columns that are partially submerged at the drilling location to provide added stability during drilling operations. Semisubmersible rigs are held in a fixed location over the ocean floor either by being anchored to the sea bottom with mooring chains (moored semisubmersible rig) or dynamically positioned by computer-controlled propellers or "thrusters" (dynamically positioned semisubmersible rig) similar to that used by our drillships.  Moored semisubmersible rigs are most commonly used for drilling in water depths of 4,499 feet or less.  However, ENSCO 5006, which is a moored semisubmersible rig, is capable of deepwater drilling in water depths greater than 5,000 feet.  Dynamically positioned semisubmersible rigs generally are outfitted for drilling in deeper water depths and are well-suited for deepwater development and exploratory well drilling.

Jackup rigs stand on the ocean floor with their hull and drilling equipment elevated above the water on connected leg supports. Jackup rigs are generally preferred over other rig types in shallow water depths of 400 feet or less, primarily because jackup rigs provide a more stable drilling platform with above water well control equipment. Our jackup rigs are of the independent leg design where each leg can be fixed into the ocean floor at varying depths and equipped with a cantilever that allows the drilling equipment to extend outward from the hull over fixed platforms enabling safer drilling of both exploratory and development wells. The jackup rig hull supports the drilling equipment, jacking system, crew quarters, storage and loading facilities, helicopter landing pad and related equipment and supplies.

Over the life of a typical rig, many of the major systems are replaced due to normal wear and tear or technological advancements in drilling equipment. We believe all our rigs are in good condition. As of February 24, 2016, we owned all rigs in our fleet. We also manage the drilling operations for three rigs owned by third-parties. 

We lease our executive offices in London, England in addition to office space in Houston, Texas, Aberdeen, Abu Dhabi, Angola, Australia, Brunei, Denmark, Dubai, Holland, Indonesia, Malaysia, Malta, Mexico, New Zealand, Saudi Arabia, Singapore, Switzerland, Thailand, Vietnam and several additional international locations. We own offices and other facilities in Louisiana and Brazil.

Item 3.  Legal Proceedings

Brazil Internal Investigation

Pride International, Inc. (“Pride”), a company we acquired in 2011, commenced drilling operations in Brazil in 2001. In 2008, Pride entered into a drilling services agreement with Petrobras (the "DSA") for ENSCO DS-5, a drillship ordered from Samsung Heavy Industries, a shipyard in South Korea ("SHI"). Beginning in 2006, Pride conducted periodic compliance reviews of its business with Petrobras, and, after the acquisition of Pride, Ensco conducted similar compliance reviews, the most recent of which commenced in early 2015 after media reports were released regarding ongoing investigations of various kickback and bribery schemes in Brazil involving Petrobras.

While conducting our compliance review, we became aware of an internal audit report by Petrobras alleging irregularities in relation to the DSA. Upon learning of the Petrobras internal audit report, our Audit Committee appointed independent counsel to lead an investigation into the alleged irregularities. Further, in June and July 2015, we voluntarily contacted the SEC and the DOJ, respectively, to advise them of this matter and our Audit Committee’s investigation. Independent counsel, under the direction of our Audit Committee, has substantially completed its investigation by reviewing and analyzing available documents and correspondence and interviewing current and former employees involved in the DSA negotiations and the negotiation of the ENSCO DS-5 construction contract with SHI (the "DS-5 Construction Contract").

To date, our Audit Committee has found no evidence that Pride or Ensco or any of their current or former employees were aware of or involved in any wrongdoing, and our Audit Committee has found no evidence linking Ensco or Pride to any illegal acts committed by our former marketing consultant. Independent counsel has continued to provide the SEC and DOJ with updates throughout the investigation, including detailed briefings regarding its

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investigation and findings. On December 21, 2015, we entered into a one-year tolling agreement with the DOJ, at the agency's request.

Subsequent to initiating our Audit Committee investigation, the Petrobras internal audit report and the alleged irregularities were referenced in Brazilian court documents connected to the prosecution of former Petrobras directors and employees as well as certain other third parties, including our former marketing consultant who provided services to Pride and Ensco in connection with the DSA. Our former marketing consultant has entered into a plea agreement with the Brazilian authorities. On January 10, 2016, Brazilian authorities filed an indictment against a former Petrobras director. This indictment states that the former Petrobras director received bribes paid out of proceeds from a brokerage agreement entered into for purposes of intermediating a drillship construction contract between SHI and Pride, which we believe to be the DS-5 Construction Contract. The parties to the brokerage agreement were a company affiliated with a person acting on behalf of the former Petrobras director, a company affiliated with our former marketing consultant, and SHI. The indictment alleges that amounts paid by SHI under the brokerage agreement ultimately were used to pay bribes to the former Petrobras director. The indictment does not state that Pride or Ensco or any of their current or former employees were involved in the bribery scheme or had any knowledge of the bribery scheme.

On January 4, 2016, we received a notice from Petrobras declaring the DSA void effective immediately. Petrobras’ notice alleges that SHI made improper payments to our former marketing consultant who then shared the improper payments with employees of Petrobras and, without specifying any supporting facts or conduct, that Pride had knowledge of this activity and assisted in the procurement of and/or facilitated these improper payments. We disagree with Petrobras’ assertion that the DSA is void and plan to pursue our legal rights in connection with this dispute, as described further below under "—DSA Dispute."

Outside of Petrobras’ allegations, we have not been contacted by any Brazil governmental authority regarding alleged wrongdoing by Pride or Ensco or any of their current or former employees related to this matter. We cannot predict whether any U.S., Brazilian or other governmental authority will seek to investigate this matter, or if a proceeding were opened, the scope or ultimate outcome of any such investigation. If the SEC or DOJ determines that violations of the FCPA have occurred, or if any governmental authority determines that we have violated applicable anti-bribery laws, they could seek civil and criminal sanctions, including monetary penalties, against us, as well as changes to our business practices and compliance programs, any of which could have a material adverse effect on our business and financial condition. Our customers, business partners and other stakeholders could seek to take actions adverse to our interests. Further, investigating and resolving such allegations is expensive and could consume significant management time and attention. Although our internal investigation is substantially complete, we cannot predict whether any additional allegations will be made or whether any additional facts relevant to the investigation will be uncovered during the course of the investigation and what impact those allegations and additional facts will have on the timing or conclusions of the investigation. Our Audit Committee will examine any such additional allegations and additional facts and the circumstances surrounding them.

DSA Dispute

As described above, on January 4, 2016, Petrobras sent a notice to us declaring the DSA void effective immediately, reserving its rights and stating its intention to seek any restitution to which it may be entitled. We disagree with Petrobras’ assertion that the DSA is void and plan to pursue our legal rights in connection with this dispute. However, at this time, we cannot reasonably determine the validity of Petrobras’ claim or the range of potential exposure, if any. As a result, there can be no assurance as to how this dispute will ultimately be resolved.

Due to this dispute with Petrobras, we did not recognize revenue for services provided under the DSA during the fourth quarter totaling $44.7 million as we concluded collectability of these amounts was not reasonably assured. Additionally, we recorded a $17.1 million provision for doubtful accounts during the fourth quarter of 2015 for receivables related to services provided under the DSA through September 30, 2015. Our receivables from Petrobras related to the ENSCO DS-5 DSA are fully reserved on our consolidated balance sheet as of December 31, 2015.

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Pride FCPA Investigation

During 2010, Pride and its subsidiaries resolved their previously disclosed investigations into potential violations of the FCPA with the DOJ and SEC. The settlement with the DOJ included a deferred prosecution agreement (the "DPA") between Pride and the DOJ and a guilty plea by Pride Forasol, S.A.S., one of Pride’s subsidiaries, to FCPA-related charges. During 2012, the DOJ moved to (i) dismiss the charges against Pride and end the DPA one year prior to its scheduled expiration; and (ii) terminate the unsupervised probation of Pride Forasol, S.A.S. The Court granted the motions.

     Pride has received preliminary inquiries from governmental authorities of certain countries referenced in its settlements with the DOJ and SEC. We could face additional fines, sanctions and other penalties from authorities in these and other relevant jurisdictions, including prohibition of our participating in or curtailment of business operations in certain jurisdictions and the seizure of rigs or other assets. At this stage of such inquiries, we are unable to determine what, if any, legal liability may result. Our customers in certain jurisdictions could seek to impose penalties or take other actions adverse to our business. We could also face other third-party claims by directors, officers, employees, affiliates, advisors, attorneys, agents, stockholders, debt holders, or other stakeholders. In addition, disclosure of the subject matter of the investigations and settlements could adversely affect our reputation and our ability to obtain new business or retain existing business, to attract and retain employees and to access the capital markets.

We cannot currently predict what, if any, actions may be taken by any other applicable government or other authorities or our customers or other third parties or the effect any such actions may have on our financial position, operating results or cash flows.

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 50 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.

During 2013, we reached an agreement in principle with 58 plaintiffs to settle lawsuits filed in Mississippi for a nominal amount. A special master reviewed all 58 cases and made an allocation of settlement funds among the parties.  The District Court Judge reviewed the allocations and accepted the special master’s recommendations and approved the settlements.  The settlement documents for most of the individual plaintiffs have been processed, and the cases have been dismissed. The settlement documents for approximately 13 individual plaintiffs are continuing to be processed.

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 from time to time 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.

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Environmental Matters

We are currently subject to pending notices of assessment relating to spills of drilling fluids, oil, brine, chemicals, grease or fuel from drilling rigs operating offshore Brazil from 2008 to 2015, pursuant to which the governmental authorities have assessed, or are anticipated to assess, fines in an aggregate amount of approximately $150,000. We have contested these notices and appealed certain adverse decisions and are awaiting decisions in these cases. Although we do not expect final disposition of these assessments to have a material adverse effect on our financial position, operating results or cash flows, there can be no assurance as to the ultimate outcome of these assessments. A $150,000 liability related to these matters was included in accrued liabilities and other on our consolidated balance sheet as of December 31, 2015.

We currently are subject to a pending administrative proceeding initiated during 2009 by a Spanish government authority seeking payment in an aggregate amount of approximately $3.0 million for an alleged environmental spill originating from ENSCO 5006 while it was operating offshore Spain. Our customer has posted guarantees with the Spanish government to cover potential penalties. Additionally, we expect to be indemnified for any payments resulting from this incident by our customer under the terms of the drilling contract. A criminal investigation of the incident was initiated during 2010 by a prosecutor in Tarragona, Spain, and the administrative proceedings have been suspended pending the outcome of this investigation. We do not know at this time what, if any, involvement we may have in this investigation.

We intend to vigorously defend ourselves in the administrative proceeding and any criminal investigation. At this time, we are unable to predict the outcome of these matters or estimate the extent to which we may be exposed to any resulting liability. Although we do not expect final disposition of this matter to have a material adverse effect on our financial position, operating results or cash flows, there can be no assurance as to the ultimate outcome of the proceedings.

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.

Item 4.  Mine Safety Disclosures

    Not applicable.

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PART II

Item 5. Market for Registrant's Common Equity, Related Shareholder Matters and Issuer Purchases of Equity Securities

Market Information

The following table provides the high and low sales price of our Class A ordinary share, par value U.S. $0.10 per share, for each period indicated during the last two fiscal years:

	First Quarter		Second Quarter		Third Quarter		Fourth Quarter		Year
2015 High	$	32.28	$	28.40	$	22.21	$	18.93	$	32.28
2015 Low	$	19.78	$	21.04	$	13.42	$	13.26	$	13.26
2014 High	$	57.45	$	55.89	$	55.74	$	41.99	$	57.45
2014 Low	$	47.85	$	48.53	$	40.91	$	25.88	$	25.88

Our Class A ordinary shares are traded on the NYSE under the ticker symbol "ESV." Many of our shareholders hold shares electronically, all of which are owned by a nominee of DTC. We had 77 shareholders of record on February 1, 2016.

Dividends

The following table provides the quarterly cash dividend per share declared and paid during the last two fiscal years:

	First Quarter		Second Quarter		Third Quarter		Fourth Quarter		Year
2015	$	.15	$	.15	$	.15	$	.15	$	0.60
2014	$	.75	$	.75	$	.75	$	.75	$	3.00

Our Board of Directors declared a $0.01 quarterly cash dividend per Class A ordinary share for the first quarter of 2016. The Board of Directors reduced the dividend by $0.14 per share primarily to improve capital management flexibility during the market downturn. Dividend payments are subject to approval by our Board of Directors and could change in future periods. When evaluating dividend payment timing and amounts, our Board of Directors considers several factors, including our profitability, liquidity, financial condition, market outlook, reinvestment opportunities, capital requirements and other factors and restrictions our Board of Directors deems relevant.

Exchange Controls

There are no U.K. government laws, decrees or regulations that restrict or affect the export or import of capital, including but not limited to, foreign exchange controls on remittance of dividends on our ordinary shares or on the conduct of our operations.

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U.K. Taxation

The following paragraphs are intended to be a general guide to current U.K. tax law and what is understood to be HMRC practice applying as of the date of this report (both of which are subject to change at any time, possibly with retrospective effect) in respect of the taxation of capital gains, the taxation of dividends paid by us and stamp duty and SDRT on the transfer of our shares. In addition, the following paragraphs relate only to persons who for U.K. tax purposes are beneficial owners of the shares (“shareholders”).

These paragraphs may not relate to certain classes of holders or beneficial owners of shares, such as our employees or directors, persons who are connected with us, insurance companies, charities, collective investment schemes, pension schemes, trustees or persons who hold shares other than as an investment, or U.K. resident individuals who are not domiciled in the U.K. or who are subject to split-year treatment.

These paragraphs do not describe all of the circumstances in which shareholders may benefit from an exemption or relief from taxation. It is recommended that all shareholders obtain their own taxation advice. In particular, any shareholders who are non-U.K. resident or domiciled are advised to consider the potential impact of any relevant double tax treaties, including the Convention between the United States of America and the United Kingdom for the Avoidance of Double Taxation with respect to Taxes on Income, to the extent applicable.

U.K. Taxation of Dividends

U.K. Withholding Tax - Dividends paid by us will not be subject to any withholding or deduction for, or on account of, U.K. tax, irrespective of the residence or the individual circumstances of the shareholders.

U.K. Income Tax - An individual shareholder who is resident in the U.K. may, depending on his or her individual circumstances, be subject to U.K. income tax on dividends received from us. An individual shareholder who is not resident in the U.K. will not be subject to U.K. income tax on dividends received from us, unless that shareholder carries on (whether alone or in partnership) any trade, profession or vocation through a branch or agency in the U.K. and shares are used by, or held by or for, that branch or agency. In these circumstances, the non-U.K. resident shareholder may, depending on his or her individual circumstances, be subject to U.K. income tax on dividends received from us.

Tax legislation proposed in the U.K. on December 9, 2015 (“Proposed U.K. Legislation”) will, if passed by the U.K. Parliament, change the tax treatment of dividends in the hands of shareholders who are individuals where a dividend is paid on or after April 6, 2016.

On that basis, the tax treatment of a dividend paid by the Company to an individual shareholder will depend on whether the dividend is paid before April 6, 2016 or on or after that date, and this is reflected in the comments that follow.

Current Tax Treatment of Dividends

The rate of U.K. income tax payable with respect to dividends received by higher rate taxpayers in the tax year 2015/2016 is 32.5%. Individuals whose total income subject to income tax exceeds £150,000 will be subject to income tax in respect of dividends in excess of that amount at the rate of 37.5% in the tax year 2015/2016. An individual's dividend income is treated as the top slice of his or her total income subject to income tax.  Individual shareholders who are resident in the U.K. will be entitled to a tax credit equal to one-ninth of the amount of the dividend received from us, which will be taken into account in computing the gross amount of the dividend subject to income tax. The tax credit will be credited against the relevant shareholder's liability (if any) to income tax on the gross amount of the dividend. An individual shareholder who is not subject to U.K. income tax on dividends received from us will not be entitled to claim payment of the tax credit in respect of such dividends. The right to a tax credit for an individual shareholder who is not resident in the U.K. will depend on his or her individual circumstances.

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Tax Treatment of Dividends paid on or after April 6, 2016 if the Proposed U.K. Legislation is passed

Assuming that the Proposed U.K. Legislation is enacted, the tax treatment of dividends paid by the Company to individual shareholders on or after April 6, 2016 will be as follows:

• dividends paid by the Company on or after April 6, 2016 will not carry a tax credit,

• all dividends received by an individual shareholder from the Company (or from other sources) will, except to the extent that they are earned through an Individual Savings Account ("ISA"), self-invested pension plan or other regime which exempts the dividends from income tax, form part of the shareholder's total income for income tax purposes,

• a nil rate of income tax will apply to the first £5,000 of taxable dividend income received by an individual shareholder in a tax year (the “Nil Rate Amount”), regardless of what tax rate would otherwise apply to that dividend income,

• any taxable dividend income received by an individual shareholder in a tax year in excess of the Nil Rate Amount will be taxed at a special rate, as set out below, and

• that tax will be applied to the amount of the dividend income actually received by the individual shareholder (rather than to a grossed-up amount).

Where a shareholder’s taxable dividend income for a tax year exceeds the Nil Rate Amount, the excess amount (the “Relevant Dividend Income”) will be subject to income tax:

• at the rate of 7.5%, to the extent that the Relevant Dividend Income falls below the threshold for the higher rate of income tax,

• at the rate of 32.5%, to the extent that the Relevant Dividend Income falls above the threshold for the higher rate of income tax but below the threshold for the additional rate of income tax, or

• at the rate of 38.1%, to the extent that the Relevant Dividend Income falls above the threshold for the additional rate of income tax.

In determining whether and, if so, to what extent the Relevant Dividend Income falls above or below the threshold for the higher rate of income tax or, as the case may be, the additional rate of income tax, the shareholder’s total dividend income for the tax year in question (including the part within the Nil Rate Amount) will, as noted above, be treated as the highest part of the shareholder’s total income for income tax purposes.

U.K. Corporation Tax - Unless an exemption is available (as discussed below), a corporate shareholder that is resident in the U.K. will be subject to U.K. corporation tax on dividends received from us. A corporate shareholder that is not resident in the U.K. will not be subject to U.K. corporation tax on dividends received from us, unless that shareholder carries on a trade in the U.K. through a permanent establishment in the U.K. and the shares are used by, for or held by or for, the permanent establishment. In these circumstances, the non-U.K. resident corporate shareholder may, depending on its individual circumstances (and if no exemption is available), be subject to U.K. corporation tax on dividends received from us.

The main rate of corporation tax payable with respect to dividends received from us in the financial year 2015 is 20%, and will be the same for the financial year 2016. If dividends paid by us fall within any of the exemptions from U.K. corporation tax set out in Part 9A of the U.K. Corporation Tax Act 2009, the receipt of the dividend by a corporate shareholder generally will be exempt from U.K. corporation tax. Generally, the conditions for one or more of those exemptions from U.K. corporation tax on dividends paid by us should be satisfied, although the conditions

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that must be satisfied in any particular case will depend on the individual circumstances of the relevant corporate shareholder.

Shareholders that are regarded as small companies should generally be exempt from U.K. corporation tax on dividends received from us, unless the dividends are received as part of a tax advantage scheme. Shareholders that are not regarded as small companies should generally be exempt from U.K. corporation tax on dividends received from us on the basis that the shares should be regarded as non-redeemable ordinary shares. Alternatively, shareholders that are not small companies should also generally be exempt from U.K. corporation tax on dividends received from us if they hold shares representing less than 10% of our issued share capital, would be entitled to less than 10% of the profits available for distribution to our equity-holders and would be entitled on a winding up to less than 10% of our assets available for distribution to such equity-holders. In certain limited circumstances, the exemption from U.K. corporation tax will not apply to such shareholders if a dividend is made as part of a scheme that has a main purpose of falling within the exemption from U.K. corporation tax.

U.K. Taxation of Capital Gains

U.K. Withholding Tax - Capital gains accruing to non-U.K. resident shareholders on the disposal of shares will not be subject to any withholding or deduction for or on account of U.K. tax, irrespective of the residence or the individual circumstances of the relevant shareholder.

U.K. Capital Gains Tax - A disposal of shares by an individual shareholder who is resident in the U.K. may, depending on his or her individual circumstances, give rise to a taxable capital gain or an allowable loss for the purposes of U.K. capital gains tax (“CGT”). An individual shareholder who temporarily ceases to be resident or ordinarily resident in the U.K. for a period of less than five years and who disposes of his or her shares during that period of temporary non-residence may be liable to CGT on a taxable capital gain accruing on the disposal on his or her return to the U.K. under certain anti-avoidance rules.

An individual shareholder who is not resident in the U.K. will not be subject to CGT on capital gains arising on the disposal of their shares, unless that shareholder carries on a trade, profession or vocation in the U.K. through a branch or agency in the U.K. and the shares were acquired, used in or for the purposes of the branch or agency or used in or for the purposes of the trade, profession or vocation carried on by the shareholder through the branch or agency. In these circumstances, the relevant non-U.K. resident shareholder may, depending on his or her individual circumstances, be subject to CGT on chargeable gains arising from a disposal of his or her shares. The rate of CGT in the tax year 2015/2016 is 18% for basic rate taxpayers and 28% for higher and additional rate taxpayers, and is expected to be the same in the tax year 2016/2017.

U.K. Corporation Tax - A disposal of shares by a corporate shareholder resident in the U.K. may give rise to a chargeable gain or an allowable capital loss for the purposes of U.K. corporation tax. A corporate shareholder not resident in the U.K. will not be liable for U.K. corporation tax on chargeable gains accruing on the disposal of its shares, unless that shareholder carries on a trade in the U.K. through a permanent establishment in the U.K. and the shares were acquired, used in or for the purposes of the permanent establishment or used in or for the purposes of the trade carried on by the shareholder through the permanent establishment. In these circumstances, the relevant non-U.K. resident shareholder may, depending on its individual circumstances, be subject to U.K. corporation tax on chargeable gains arising from a disposal of its shares.

The financial year for U.K. corporation tax purposes runs from April 1 to March 31. The main rate of U.K. corporation tax on chargeable gains is 20% in the financial year 2015 and 20% in the financial year 2016. Corporate shareholders will be entitled to an indexation allowance in computing the amount of a chargeable gain accruing on a disposal of the shares, which will provide relief for the effects of inflation by reference to movements in the U.K. retail price index.

If the conditions of the applicable shareholding exemption are satisfied in relation to a chargeable gain accruing to a corporate shareholder on a disposal of its shares, the chargeable gain will be exempt from U.K. corporation tax. The conditions of the substantial shareholding exemption that must be satisfied will depend on the individual

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circumstances of the relevant corporate shareholder. One of the conditions of the substantial shareholding exemption that must be satisfied is that the corporate shareholder must have held a substantial shareholding in the Company throughout a twelve-month period beginning not more than two years before the day on which the disposal takes place. Ordinarily, a corporate shareholder will not be regarded as holding a substantial shareholding in us, unless it (whether alone, or together with other group companies) directly holds not less than 10% of our ordinary share capital.

U.K. Stamp Duty and SDRT

The discussion below relates to shareholders wherever resident but not to holders such as market makers, brokers, dealers and intermediaries, to whom special rules apply. Special rules also apply in relation to certain stock lending and repurchase transactions.

Transfer of Shares held in book entry form via DTC - A transfer of shares held in book entry (i.e., electronic) form within the facilities of the DTC will not be subject to U.K. stamp duty or SDRT.

Transfers of Shares out of, or outside of, DTC - Subject to an exemption for certain low value transactions, a transfer of shares from within the DTC system out of that system or any transfer of shares that occurs entirely outside the DTC system generally will be subject to a charge to ad valorem U.K. stamp duty (normally payable by the transferee) at 0.5% of the purchase price of the shares (rounded up to the nearest multiple of £5). SDRT generally will be payable on an unconditional agreement to transfer such shares at 0.5% of the amount or value of the consideration for the transfer. However, such liability for SDRT generally will be cancelled and any SDRT paid will be refunded if the agreement is completed by a duly-stamped transfer within six years of either the date of the agreement or, if the agreement was conditional, the date when the agreement became unconditional.

We have put in place arrangements to require that shares held outside the facilities of DTC cannot be transferred into such facilities (including where shares are re-deposited into DTC by an existing shareholder) until the transferor of the shares has first delivered the shares to a depository we specified, so that SDRT may be collected in connection with the initial delivery to the depository. Before such transfer can be registered in our books, the transferor will be required to put in the depository funds to settle the resultant liability for SDRT, which will be 1.5% of the value of the shares, and to pay the transfer agent such processing fees as may be established from time to time.

Following a decision of the European Court of Justice in 2009 and a decision of the U.K. First-Tier Tax Tribunal in 2012, HMRC has announced that it will not seek to apply the 1.5% charge to stamp duty or SDRT on the issuance of shares (or, where it is integral to the raising of new capital, the transfer of new shares) into depository receipt or clearance systems, such as DTC. Thus, the 1.5% U.K. stamp duty or SDRT charge will apply only to the transfer of existing shares to clearance services or depositary receipt systems in circumstances where the transfer is not integral to the raising of new capital (for example, where shares are re-deposited into DTC by an existing shareholder). Investors should, however, be aware that this area may be subject to further developments in the future.

The above statements are intended only as a general guide to the current U.K. stamp duty and SDRT position. Transfers to certain categories of persons are not liable to U.K. stamp duty or SDRT and transfers to others may be liable at a higher rate than discussed above.

Equity Compensation Plans

For information on shares issued or to be issued in connection with our equity compensation plans, see "Part III, Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters."

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Issuer Purchases of Equity Securities

The following table provides a summary of our repurchases of our equity securities during the quarter ended December 31, 2015.

Issuer Purchases of Equity Securities
Period	Total Number of Securities Purchased(1)	Average Price Paid per Security		Total Number of Securities Purchased as Part of Publicly Announced Plans or Programs (2)	Approximate Dollar Value of Securities that May Yet Be Purchased Under Plans or Programs
October 1 - October 31	2,217	$	13.87	—	$	2,000,000,000
November 1 - November 30	5,758	$	17.70	—	$	2,000,000,000
December 1 - December 31	11,107	$	16.57	—	$	2,000,000,000
Total	19,082	$	16.59	—

⁽¹⁾ During the quarter ended December 31, 2015, equity securities were repurchased from employees and non-employee directors by an affiliated employee benefit trust in connection with the settlement of income tax withholding obligations arising from the vesting of share awards.  Such securities remain available for re-issuance in connection with employee share awards.

⁽²⁾ During 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.

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Performance Chart

The chart below presents a comparison of the five-year cumulative total return, assuming $100 invested on December 31, 2010 for Ensco plc, the Standard & Poor's 500 Stock Price Index, and a self-determined peer group.Total return assumes the reinvestment of dividends, if any, in the security on the ex-dividend date. Since Ensco operates exclusively as an offshore drilling company, a self-determined peer group composed exclusively of major offshore drilling companies has been included as a comparison.^* 

COMPARISON OF 5 YEAR CUMULATIVE TOTAL RETURN*

Among Ensco plc, the S&P 500 Index and Peer Group

*100 invested on 12/31/09 in stock or index, including reinvestment of dividends.

Fiscal year ending December 31.

Copyright© 2016 S&P, a division of The McGraw-Hill Companies Inc. All rights reserved.

Copyright© 2016 Dow Jones & Co. All rights reserved.

	12/10	12/11	12/12	12/13	12/14	12/15
Ensco plc	100.0	90.2	117.2	117.5	65.9	34.9
S&P 500	100.0	102.1	118.5	156.8	178.3	180.8
Peer Group	100.0	82.0	98.7	109.4	50.1	28.6

____________________________________

* Our self-determined peer group is weighted according to market capitalization and consists of the following companies: Atwood Oceanics Inc., Diamond Offshore Drilling Inc., Noble Corporation, Rowan Companies plc, SeaDrill Limited and Transocean Ltd.

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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,
	2015			2014			2013			2012			2011(1)
	(in millions, except per share amounts)
Consolidated Statement of Operations Data
Revenues	$	4,063.4		$	4,564.5		$	4,323.4		$	3,638.8		$	2,443.2
Operating expenses
Contract drilling (exclusive of depreciation)	1,869.6			2,076.9			1,947.1			1,642.8			1,218.3
Loss on impairment	2,746.4			4,218.7			—			—			—
Depreciation	572.5			537.9			496.2			443.8			334.9
General and administrative	118.4			131.9			146.8			148.9			158.6
Operating (loss) income	(1,243.5		)	(2,400.9		)	1,733.3			1,403.3			731.4
Other (expense) income, net	(227.7		)	(147.9		)	(100.1		)	(98.6		)	(57.9		)
Income tax (benefit) expense	(13.9		)	140.5			203.1			228.6			105.6
(Loss) income from continuing operations	(1,457.3		)	(2,689.3		)	1,430.1			1,076.1			567.9
(Loss) income from discontinued operations, net(2)	(128.6		)	(1,199.2		)	(2.2		)	100.6			37.7
Net (loss) income	(1,585.9		)	(3,888.5		)	1,427.9			1,176.7			605.6
Net income attributable to noncontrolling interests	(8.9		)	(14.1		)	(9.7		)	(7.0		)	(5.2		)
Net (loss) income attributable to Ensco	$	(1,594.8	)	$	(3,902.6	)	$	1,418.2		$	1,169.7		$	600.4
(Loss) earnings per share – basic
Continuing operations	$	(6.33	)	$	(11.70	)	$	6.09		$	4.62		$	2.90
Discontinued operations	(0.55		)	(5.18		)	(0.01		)	0.43			0.19
	$	(6.88	)	$	(16.88	)	$	6.08		$	5.05		$	3.09
(Loss) earnings per share - diluted
Continuing operations	$	(6.33	)	$	(11.70	)	$	6.08		$	4.61		$	2.89
Discontinued operations	(0.55		)	(5.18		)	(0.01		)	0.43			0.19
	$	(6.88	)	$	(16.88	)	$	6.07		$	5.04		$	3.08
Net (loss) income attributable to Ensco shares - Basic and Diluted	$	(1,596.8	)	$	(3,910.5	)	$	1,403.1		$	1,157.4		$	593.5
Weighted-average shares outstanding
Basic	232.2			231.6			230.9			229.4			192.2
Diluted	232.2			231.6			231.1			229.7			192.6
Cash dividends per share	$	0.60		$	3.00		$	2.25		$	1.50		$	1.40

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	Year Ended December 31,
	2015		2014		2013		2012		2011(1)
	(in millions)
Consolidated Balance Sheet (as of period end) and Cash Flow Statement Data
Working capital(3)	$	1,509.6	$	1,788.9	$	466.9	$	720.4	$	338.3
Total assets(3)	13,637.0		16,040.8		19,456.4		18,555.4		17,900.0
Long-term debt, net of current portion	5,895.1		5,885.6		4,718.9		4,798.4		4,877.6
Ensco shareholders' equity	6,512.9		8,215.0		12,791.6		11,846.4		10,879.3
Cash flows from operating activities of continuing operations	1,697.9		2,057.9		1,811.2		1,954.6		659.8

⁽¹⁾  Includes the results of Pride International, Inc. ("Pride") from May 31, 2011, the date of the Pride acquisition.  

⁽²⁾  See Note 10 to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" for information on discontinued operations.

⁽³⁾  Prior year amounts have been restated to reflect the adoption of Accounting Standard Update 2015-17 Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes, which requires that deferred tax assets and liabilities be classified as noncurrent on the balance sheet. See Note 1 to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" for additional information.

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

INTRODUCTION

Our Business

We are one of the leading providers of offshore contract drilling services to the international oil and gas industry. We currently own and operate an offshore drilling rig fleet of 64 rigs, with drilling operations in most of the strategic markets around the globe. We also have four rigs under construction. Our rig fleet includes ten drillships, 13 dynamically positioned semisubmersible rigs, three moored semisubmersible rigs and 42 jackup rigs, including rigs under construction.  Our fleet is the world's second largest amongst competitive rigs, our ultra-deepwater fleet is one of the newest in the industry, and our premium jackup fleet is the largest of any offshore drilling company.

Our customers include many 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 spanning approximately 15 countries on six continents. 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.

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 each day we are performing drilling or related services. Our customers bear substantially all of the 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.

Our Industry

Operating results in the offshore contract drilling industry are highly 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 highly cyclical.  Offshore exploration and development spending may fluctuate substantially from year-to-year and from region-to-region.

Oil prices have declined by more than 70% since mid-2014, with crude oil prices trading below $30 per barrel in January 2016, in contrast to prices in excess of $100 per barrel in July 2014. The decline in oil prices has caused a significant decline in the demand for offshore drilling services as many projects become uneconomical resulting in fewer market tenders in recent periods. Operators continue to significantly reduce their capital spending budgets, including the cancellation or deferral of existing programs, and are expected to continue operating under reduced budgets in the current commodity price environment. These declines in capital spending levels, together with the growing oversupply of rigs, have resulted in significantly reduced day rates and utilization, and we expect this trend to continue. If commodity prices remain at current levels, we do not expect a meaningful improvement in demand for offshore drilling services, and contractors may be unable to secure contracts at economically favorable terms.

Recent contract awards, in general, have been short-term in nature and subject to an extremely competitive bidding process. The intense pressure on operating day rates may result in rates that approximate direct operating expenses. In addition, we are seeing increased pressure to accept other less favorable contractual and commercial terms, including reduced or no mobilization and demobilization fees, reduced day rates during downtime, reduced standby, redrill and moving rates, caps on reimbursements for downhole tools, reduced periods to remediate equipment

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breakdowns or other deviations from contractual standards of performance, certain limitations on our ability to be indemnified and reduced early termination fees and notice periods.

We expect 2016 to be an increasingly challenging year for drilling contractors, as customers seek to reduce costs in the near-term by delaying drilling programs, re-negotiating existing contract terms, or terminating or otherwise repudiating drilling contracts altogether.  A further sustained period of lower commodity prices, or the perceived risk of a sustained period of lower commodity prices, will likely result in a reduction in demand for our services, and revenues will continue to be adversely affected through lower rig utilization and lower day rates.  We believe the current market dynamics will not change until we see a meaningful recovery in commodity prices.

Because many factors that affect the market for offshore exploration and development are beyond our control and because rig demand can change quickly, it is difficult for us to predict future industry conditions, demand trends or 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

In the current market, drilling rig supply significantly exceeds drilling rig demand. The decline in customer capital expenditure budgets has led drilling contractors to scrap or cold-stack approximately 90 older floaters since September 2014. Currently, there are approximately 40 marketed floaters that are idle, and approximately 50 competitive floaters have contracts expiring before the end of 2017 without follow-on work. As of February 16, 2016, our floater fleet includes 12 rigs with availability in 2016, and an additional five rigs with availability beginning in 2017.

There are approximately 70 marketed jackups older than 30 years of age that are stacked or idle, and approximately 75 competitive jackups that are 30 years of age or older have contracts that expire before the end of 2017 without follow-on work. As of February 16, 2016, our jackup fleet includes 23rigs with availability in 2016, and an additional five rigs with availability beginning in 2017. These rigs may be unable to find additional work. Operating costs for idle rigs, as well as expenditures required to recertify rigs during regulatory surveys, may prove cost prohibitive and, as a result, drilling contractors may instead elect to cold-stack or scrap these rigs. We expect floater and jackup scrapping and cold-stacking to continue throughout 2016 and 2017.

During the recent newbuild cycle, various industry participants ordered the construction of 320 new drillships, semisubmersible rigs and jackup rigs, approximately 140 of which were delivered during the last three years.

Currently, there are approximately 65 competitive newbuild drillships and semisubmersible rigs reported to be under construction, of which approximately 25 are scheduled to be delivered before the end of 2016. Roughly half of the anticipated 2016 deliveries are without contracts. Several newbuild deliveries have already been delayed into future years, and it is possible that more uncontracted newbuilds will be delayed or cancelled.

Currently, there are approximately 115 competitive newbuild jackup rigs reported to be under construction. Over the past year, several jackup orders have been cancelled, and many newbuild jackups have been delayed. We expect that additional rigs may be delayed or cancelled given limited contracting opportunities. Approximately 80 newbuild jackups are scheduled to be delivered before the end of 2016, most of which are without contracts.

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Liquidity, Backlog and Debt Maturities

We have historically relied on our cash flow from continuing operations to meet liquidity needs and fund the majority of our cash requirements. We periodically rely on the issuance of debt securities to supplement our liquidity needs. Based on our balance sheet, our contractual backlog and $2.25 billion available under our revolving credit facility, we expect to fund our short-term and long-term liquidity needs, including contractual obligations and anticipated capital expenditures, as well as dividends and working capital requirements, from cash and cash equivalents, short-term investments, operating cash flows and, if necessary, funds borrowed under our revolving credit facility or other future financing arrangements.

As of December 31, 2015, our backlog was $5.8 billion as compared to $9.7 billion as of December 31, 2014. Our lower backlog, coupled with lower demand, will result in a decline in revenues and operating cash flows during 2016. As our customers are significantly reducing their capital spending, we may experience further declines in backlog in the future. However, we are also seeking opportunities to reduce capital expenditures and operating expenses to preserve liquidity and provide greater flexibility during the current downturn.

As of December 31, 2015, we had $5.9 billion in total debt outstanding, representing approximately 47.5% of our total capitalization. Our next debt maturity is 2019 with an aggregate principal amount of $500 million, followed by additional maturities in 2020 and 2021 with aggregate principal amounts of $900 million and $1.5 billion, respectively. We have $1.3 billion in cash and cash equivalents and short-term investments and a $2.25 billion senior unsecured revolving credit facility to be used for general corporate purposes with a term that expires in September 2019 (the “Credit Facility”). The Credit Facility requires us to maintain a total debt to total capitalization ratio that is less than or equal to 60%.

Notwithstanding our current liquidity position, if we experience significant further deterioration in demand for offshore drilling and a significantly protracted downturn, our ability to maintain a sufficient level of liquidity to meet our financial obligations would be materially and adversely impacted. Further, our access to credit and capital markets depends on the credit ratings assigned to our debt by independent credit rating agencies. Recently, Moody's announced that our credit rating is under review for a downgrade. There can be no assurance that we will be able to maintain our credit ratings, and any additional actual or anticipated downgrades in our credit ratings, including any announcement that our ratings are under review for a downgrade, could limit our ability to access credit and capital markets, or to restructure or refinance our indebtedness. In addition, future financings or refinancings may result in higher borrowing costs and require more restrictive terms and covenants, which may further restrict our operations. If we are downgraded below investment grade by one or more credit rating agencies, we may have limited or no access to the commercial paper market.

Petrobras Backlog

Our drilling services contracts with Petrobras for ENSCO 6001, 6002, 6003 and 6004 continue to be in full force and effect and all payments under these contracts are current. We note, however, that under the ENSCO 6001 drilling services contract we are nearing the limit for rig downtime that would permit the customer to terminate the contract without compensation. While we have not yet received a notice of termination from the customer for this contract, Petrobras is taking the position that the limit has been exceeded. We are in the process of contesting Petrobras’ position with respect to rig downtime.

Drilling Rig Construction and Delivery

We remain focused on our long-established strategy of high-grading our fleet. We will continue to invest in the expansion of our fleet where we believe strategic opportunities exist.  During the three-year period ended December 31, 2015, we invested approximately $3.2 billion in the construction of new drilling rigs.

During 2014, we entered into an agreement with Lamprell Energy Limited to construct two premium jackup rigs. ENSCO 140 and ENSCO 141 are significantly enhanced versions of the LeTorneau Super 116E jackup design

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and will incorporate Ensco's patented Canti-Leverage Advantage^SM technology. These rigs are scheduled for delivery during the second quarter and the third quarter, respectively. Both rigs are currently uncontracted.

During 2013, we entered into agreements with Keppel FELS ("KFELS") to construct a premium jackup rig (ENSCO 110) and an ultra-premium harsh environment jackup rig (ENSCO 123). ENSCO 110 was delivered during the second quarter of 2015 and commenced drilling operations under a long-term contract in the UAE. We recently agreed with the shipyard to delay delivery of ENSCO 123 until the first half of 2018. ENSCO 123 is currently uncontracted.

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

We previously entered into agreements with Samsung Heavy Industries to construct three ultra-deepwater drillships (ENSCO DS-8, ENSCO DS-9 and ENSCO DS-10). During the third quarter, we agreed with the shipyard to delay delivery of ENSCO DS-10 until the first quarter of 2017. ENSCO DS-10 is currently uncontracted. During 2015, we accepted delivery of ENSCO DS-8 and ENSCO DS-9. ENSCO DS-8 was delivered during the third quarter and commenced drilling operations under a long-term contract in Angola during the fourth quarter. ENSCO DS-9 was delivered during the second quarter and is uncontracted following receipt of a notice of termination for convenience from our customer.

We believe our remaining capital commitments will primarily be funded from cash and cash equivalents, short term investments, operating cash flows 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.

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 eight jackup rigs and three moored semisubmersible rigs during the three-year period ended December 31, 2015. We are marketing for sale six rigs, which were classified as held-for-sale in our financial statements as of December 31, 2015. In February 2016, we determined that an additional six rigs - ENSCO 56, ENSCO 81, ENSCO 82, ENSCO 86, ENSCO 99 and ENSCO DS-1 - would likely be scrapped or otherwise retired.

2015 Segment Highlights

Floaters

Floater revenues declined by $231.6 million, or 9%, primarily due to fewer days under contract across our floater fleet, lower average day rates and lower revenues from ENSCO DS-5. We did not recognize revenue for ENSCO DS-5 drilling services provided during the fourth quarter of $44.7 million as we concluded collectability of these amounts was not reasonably assured. These declines in revenue were offset by a $148.4 million, or 12%, decline in contract drilling expense due to multiple cost control initiatives which reduced personnel costs and other daily rig operating expenses.

In July, we accepted delivery of ENSCO DS-8, which commenced drilling under a long-term contract in Angola during the fourth quarter. We also agreed with the shipyard to delay the delivery of ENSCO DS-10, our only remaining floater under construction, until the first quarter of 2017.

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Also in July, we received a notice of termination for convenience from our ENSCO DS-9 customer. Under the terms of the contract, our customer is obligated to pay us termination fees, which are payable monthly, of two years of the operating day rate (approximately $550,000), which will be reduced pursuant to our obligation to mitigate idle rig costs, such as manning and maintenance activity, while the rig is idle and without a contract. We are in discussions with our customer on the amount of this reduction.  This day rate may also be adjusted if we recontract the rig. Our customer is also contractually obligated to reimburse certain costs that we incurred prior to or as a direct result of the termination. The rig has not been recontracted.

In March, we received notice of early termination for ENSCO DS-4, which was operating in the U.S. Gulf of Mexico. Under the terms of the ENSCO DS-4 drilling contract, the customer was required to pay us a lump sum termination fee which resulted in revenue of $110.6 million. This revenue was recognized at contract termination during the third quarter. We collected the lump sum termination fee in October.

In Angola, we agreed with our customer to extend the contract term for ENSCO DS-7 by twelve months at a reduced day rate, and to early terminate the ENSCO DS-1 contract. ENSCO DS-1 is now cold-stacked in Spain. Additionally, our customer placed ENSCO DS-6 on a special standby rate equal to 70% of the contractual operating rate beginning in late September 2015.

Jackups

     Operating results for our Jackups segment declined during 2015 due to a $968.0 million loss on impairment. Jackup revenues declined by $329.0 million, or 19%, primarily due to fewer days under contract across our jackup fleet, partially offset by newbuild deliveries during 2015 and the latter half of 2014. These declines in revenue were partially offset by a $113.9 million, or 14%, decline in contract drilling expense due to multiple cost control initiatives which reduced personnel costs and other daily rig operating expenses.

In October, we received a notice of termination for convenience for ENSCO 84, which was operating in the Middle East, effective 30 days following receipt. Separately, we agreed to reduced day rates on certain jackup drilling contracts during the third and fourth quarters.

In the Middle East, we executed long-term contracts on ENSCO 110 and ENSCO 104, each with a three-year term, which commenced during the second and third quarters, respectively. We had accepted delivery of ENSCO 110, a premium jackup rig, in April.

In the North Sea, ENSCO 71 and ENSCO 72 were recontracted through July 2018 and September 2018, respectively.

BUSINESS ENVIRONMENT

Floaters

The floater contracting environment continues to be very challenging due to reduced demand, as well as excess newbuild supply. Floater demand has declined significantly in anticipation of a prolonged cyclical downturn in offshore drilling markets. For a second consecutive year, lower commodity prices have caused our customers to rationalize capital expenditures, resulting in the cancellation and delay of drilling programs. In addition, certain customers are requesting contract concessions or terminating or otherwise repudiating drilling contracts. During 2015, we agreed to reduced day rates on certain floater drilling contracts, and we anticipate further contract concessions during 2016. We expect that floater day rates and utilization will remain under pressure until we see a meaningful recovery in commodity prices.

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Currently, there are approximately 65 competitive newbuild drillships and semisubmersible rigs reported to be under construction, of which approximately 25 are scheduled to be delivered before the end of 2016. Roughly half of the anticipated 2016 deliveries are without contracts. Several newbuild deliveries have already been delayed into future years, and it is possible that more uncontracted newbuilds will be delayed or cancelled.

Jackups

Demand for jackups has also declined significantly in anticipation of a prolonged cyclical downturn in offshore drilling markets. As customers continue to rationalize capital spending, they have cancelled and delayed drilling programs. In addition, certain customers are requesting contract concessions or terminating drilling contracts. During 2015, we agreed to reduced day rates on certain jackup drilling contracts, and we anticipate further contract concessions during 2016. We expect that jackup day rates and utilization will remain under pressure until we see a meaningful recovery in commodity prices.

Currently, there are approximately 115 competitive newbuild jackup rigs reported to be under construction. Over the past year, several jackup orders have been cancelled, and many newbuild jackups have been delayed. We expect that additional rigs may be delayed or cancelled given limited contracting opportunities. Approximately 80 newbuild jackups are scheduled to be delivered before the end of 2016, most of which are without contracts.

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, 2015 (in millions):

	2015			2014			2013
Revenues	$	4,063.4		$	4,564.5		$	4,323.4
Operating expenses
Contract drilling (exclusive of depreciation)	1,869.6			2,076.9			1,947.1
Loss on impairment	2,746.4			4,218.7			—
Depreciation	572.5			537.9			496.2
General and administrative	118.4			131.9			146.8
Operating (loss) income	(1,243.5		)	(2,400.9		)	1,733.3
Other expense, net	(227.7		)	(147.9		)	(100.1		)
Provision for income taxes	(13.9		)	140.5			203.1
(Loss) income from continuing operations	(1,457.3		)	(2,689.3		)	1,430.1
Loss from discontinued operations, net	(128.6		)	(1,199.2		)	(2.2		)
Net (loss) income	(1,585.9		)	(3,888.5		)	1,427.9
Net income attributable to noncontrolling interests	(8.9		)	(14.1		)	(9.7		)
Net (loss) income attributable to Ensco	$	(1,594.8	)	$	(3,902.6	)	$	1,418.2

Revenues declined by $501.1 million, or 11%, for the year ended December 31, 2015 as compared to the prior year primarily due to fewer days under contract across our fleet, lower average day rates and lower revenues from ENSCO DS-5. We did not recognize revenue for ENSCO DS-5 drilling services provided during the fourth quarter of $44.7 million as we concluded collectability of these amounts was not reasonably assured. These declines were partially offset by revenue generated from semisubmersible rigs that were undergoing capital enhancement projects during 2014, newbuild additions to our Floater and Jackup fleet, ENSCO DS-4 lump sum termination revenue and ENSCO DS-9 revenue.

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Contract drilling expenses declined by $207.3 million, or 10%, for the year ended December 31, 2015 as compared to the prior year primarily due to rig stackings, as well as other cost control initiatives which reduced personnel costs and other daily rig operating expenses. These declines were partially offset by costs generated from semisubmersible rigs that were undergoing capital enhancement projects during 2014 and newbuild additions to our Floater and Jackup fleet.

During 2015, we recorded a non-cash loss on impairment totaling $2.7 billion, of which $2.5 billion related to impairment of certain floaters and jackups and $276.1 million related to impairment of Floater and Jackup goodwill. During 2014, we recorded a non-cash loss on impairment totaling $4.2 billion, of which $3.0 billion related to impairment of our Floater goodwill and $1.2 billion related to impairment of certain floaters and jackups.

During 2014, revenues and contract drilling expense increased by $241.1 million, or 6%, and $129.8 million, or 7%, respectively, as compared to the prior year. The increase in revenues was primarily due to the addition of newbuild rigs to both our floater and jackup fleet and an increase in average day rates across our existing fleet, partially offset by a decline in utilization. The increase in contract drilling expense was due to the aforementioned additions to our fleet and higher personnel and repair and maintenance costs.

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. We expect operating results to decline in 2016 and 2017 as long-term contracts expire, and our rigs either go uncontracted or we renew contracts at significantly lower day 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, 2015, 2014 and 2013:

	2015	2014	2013
Floaters(1)(3)	22	20	26
Jackups(2)(3)	36	36	44
Under construction(3)(4)	4	7	6
Held-for-sale(1)(2)	6	7	—
Total	68	70	76

⁽¹⁾  During 2014, we sold ENSCO 5000 and classified ENSCO 5001, ENSCO 5002, ENSCO 6000, ENSCO 7500 and ENSCO DS-2 as held-for-sale. During 2015, we sold ENSCO 5001 and ENSCO 5002.

⁽²⁾  During 2014, we sold ENSCO 83, ENSCO 89, ENSCO 93, ENSCO 98, ENSCO 85, ENSCO 69 and Pride Wisconsin and classified ENSCO 58 and ENSCO 90 as held-for-sale. During 2015, we classified ENSCO 91 as held-for-sale.

⁽³⁾  During 2015, we accepted delivery of two ultra-deepwater drillships (ENSCO DS-8 and ENSCO DS-9) and one premium jackup rig (ENSCO 110). ENSCO DS-8 commenced a long-term drilling contract during the fourth quarter. ENSCO DS-9 was delivered during the second quarter and is uncontracted following receipt of notice of termination for convenience from our customer. ENSCO 110 commenced a long-term drilling contract during the second quarter.

During 2014, we accepted delivery of one ultra-premium harsh environment jackup rig, ENSCO 122, and commenced a long-term drilling contract during the fourth quarter.

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⁽⁴⁾  During 2014, we entered into an agreement with Lamprell plc to construct two high-specification jackup rigs, ENSCO 140 and ENSCO 141, which are scheduled for delivery during the second quarter and third quarter of 2016, respectively. Both rigs remain uncontracted.

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, 2015:

	2015		2014		2013
Rig Utilization(1)
Floaters	69%		79%		84%
Jackups	73%		89%		92%
Total	72%		85%		89%
Average Day Rates(2)
Floaters	$	416,346	$	456,023	$	435,526
Jackups	136,451		140,033		125,700
Total	$	233,325	$	242,884	$	226,703

⁽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 early contract terminations, 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, 2015 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 (loss) income and were included in "Reconciling Items." 

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Year Ended December 31, 2015

	Floaters			Jackups			Other		Operating Segments Total			Reconciling Items			Consolidated Total
Revenues	$	2,466.0		$	1,445.6		$	151.8	$	4,063.4		$	—		$	4,063.4
Operating expenses
Contract drilling   (exclusive of depreciation)	1,052.8			693.5			123.3		1,869.6			—			1,869.6
Loss on impairment	1,778.4			968.0					2,746.4			—			2,746.4
Depreciation	382.4			175.7			—		558.1			14.4			572.5
General and administrative	—			—			—		—			118.4			118.4
Operating (loss) income	$	(747.6	)	$	(391.6	)	$	28.5	$	(1,110.7	)	$	(132.8	)	$	(1,243.5	)

Year Ended December 31, 2014

	Floaters			Jackups		Other		Operating Segments Total			Reconciling Items			Consolidated Total
Revenues	$	2,697.6		$	1,774.6	$	92.3	$	4,564.5		$	—		$	4,564.5
Operating expenses
Contract drilling   (exclusive of depreciation)	1,201.2			807.4		68.3		2,076.9			—			2,076.9
Loss in impairment	3,982.3			236.4		—		4,218.7			—			4,218.7
Depreciation	358.1			171.2		—		529.3			8.6			537.9
General and administrative	—			—		—		—			131.9			131.9
Operating (loss) income	$	(2,844.0	)	$	559.6	$	24.0	$	(2,260.4	)	$	(140.5	)	$	(2,400.9	)

Year Ended December 31, 2013

	Floaters		Jackups		Other		Operating Segments Total		Reconciling Items			Consolidated Total
Revenues	$	2,659.6	$	1,588.7	$	75.1	$	4,323.4	$	—		$	4,323.4
Operating expenses
Contract drilling   (exclusive of depreciation)	1,126.0		762.6		58.5		1,947.1		—			1,947.1
Depreciation	342.2		147.5		—		489.7		6.5			496.2
General and administrative	—		—		—		—		146.8			146.8
Operating income (loss)	$	1,191.4	$	678.6	$	16.6	$	1,886.6	$	(153.3	)	$	1,733.3

Floaters

During 2015, Floater revenues declined by $231.6 million, or 9%, as compared to the prior year. The decline in revenues was primarily due to fewer days under contract across our fleet, lower average day rates and lower revenues from ENSCO DS-5. We did not recognize revenue for ENSCO DS-5 drilling services provided during the fourth quarter of $44.7 million as we concluded collectability of these amounts was not reasonably assured. These declines were partially offset by revenue generated from semisubmersible rigs ENSCO 5004, ENSCO 5005 and ENSCO 5006, all of which were undergoing capital enhancement projects during 2014, ENSCO DS-4 lump sum termination revenue of $110.6 million, ENSCO DS-9 revenues and the addition of ENSCO DS-8 to our fleet.

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Contract drilling expense declined by $148.4 million, or 12%, as compared to the prior year primarily due to rig stackings as well as other cost control initiatives which reduced personnel costs and other daily rig operating expenses. These declines were partially offset by higher contract drilling expense for the aforementioned semisubmersible rigs that were undergoing capital enhancement projects during 2014 and contract drilling expense for ENSCO DS-8 and ENSCO DS-9.

We recognized a loss on impairment of $1,778.4 million during the year ended December 31, 2015 related to certain floaters and our remaining goodwill, compared to $3,982.3 million during the year ended December 31, 2014. See "Impairment of Long-Lived Assets" below for detailed explanations of our loss on impairment.

Depreciation expense increased by $24.3 million, or 7%, primarily due to capital enhancement projects on certain semisubmersible rigs during 2014, partially offset by lower depreciation expense on floaters that were impaired during 2014.

During 2014, Floater revenues increased by $38 million, or 1%, as compared to the prior year. The increase in revenues was primarily due to commencement of the ENSCO DS-7 drilling contract during the fourth quarter of 2013 and an increase in average day rates across our Floater fleet. These increases were partially offset by a decline in utilization attributable to certain rigs. ENSCO 5004 and ENSCO 5006 were in the shipyard for capital enhancement projects, and ENSCO 8503 incurred several months of uncontracted downtime primarily during the first quarter.

During 2014, contract drilling expense increased by $75.2 million, or 7%, as compared to the prior year, primarily due to the aforementioned addition of ENSCO DS-7 to our fleet. To a lesser extent, higher personnel and repair and maintenance costs also contributed to the increase in contract drilling expense. These increases were partially offset by lower contract drilling expense for ENSCO 5006 and lower windstorm insurance costs during 2014 following our decision to not renew our windstorm policy for floaters in the U.S. Gulf of Mexico. Contract drilling expense during 2013 also included a $14.2 million provision for doubtful accounts related to OGX receivables. Depreciation expense for 2014 increased by $15.9 million, or 5%, compared to the prior year, primarily due to the addition of ENSCO DS-7 to our fleet, partially offset by lower depreciation as a result of the aforementioned impairments.

Jackups

During 2015, Jackup revenues declined by $329.0 million, or 19%, as compared to the prior year. The decline in revenues was primarily due to fewer days under contract across our fleet, the sale of ENSCO 83, ENSCO 89 and ENSCO 98 and a decline in average day rates. These declines were partially offset by the commencement of ENSCO 110 drilling operations during 2015 and ENSCO 120, ENSCO 121 and ENSCO 122 drilling operations during 2014.

Contract drilling expense declined by $113.9 million, or 14%, as compared to the prior year, primarily due to rig stackings, as well as other cost control initiatives which reduced personnel costs and other daily rig operating expenses. Contract drilling expense also declined due to the sale of the aforementioned jackup rigs, partially offset by the recent additions to our fleet. Depreciation expense increased by $4.5 million, or 3%, primarily due to the additions to our fleet.

We recognized a loss on impairment of $968.0 million during the year ended December 31, 2015 related to certain jackups and goodwill, compared to $236.4 million during the year ended December 31, 2014 related to certain jackups. Detailed explanations of our loss on impairment are provided below.

During 2014, Jackup revenues increased by $185.9 million, or 12%, as compared to the prior year.  The increase in revenues was primarily due to an increase in average day rates across our fleet and commencement of the ENSCO 120, ENSCO 121 and ENSCO 122 drilling contracts. These increases were partially offset by a decline in utilization for certain rigs in the fleet.

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Contract drilling expense increased by $44.8 million, or 6%, as compared to the prior year, primarily due to the aforementioned additions to our fleet and an increase in personnel and repair and maintenance costs. Depreciation expense increased by $23.7 million, or 16%, primarily due to the additions to our fleet.

Impairment of Long-Lived Assets

Year Ended December 31, 2015 - During 2015, we recorded a pre-tax, non-cash loss on impairment of long-lived assets of $2,618.9 million, of which $2,470.3 million was included in (loss) income from continuing operations and $148.6 million was included in loss from discontinued operations, net in our consolidated statement of operations.

Assets held-for-sale

We continually assess our rig portfolio and actively work with our rig broker to market certain rigs that no longer meet our standards for economic returns or are not part of our long-term strategic plan. On a quarterly basis, we assess whether any rig meets the criteria established by Financial Accounting Standards Board 360-10-45 for held-for-sale classification on our balance sheet. All rigs classified as held-for-sale are recorded at fair value, less costs to sell. We measure the fair value of our assets held-for-sale by applying a market approach based on unobservable third-party estimated prices that would be received in exchange for the assets in an orderly transaction between market participants. We reassess the fair value of our held-for-sale assets on a quarterly basis and adjust the carrying value, as necessary.

During 2015, we adopted the Financial Accounting Standards Board’s Accounting Standards Update 2014-08, Presentation of Financial Statements (Topic 205) and Property, Plant, and Equipment (Topic 360): Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity ("Update 2014-08"). Under the new guidance, only disposals representing a strategic shift in operations should be presented as discontinued operations. As a result, individual assets that were classified as held-for-sale during 2015 are not reported as discontinued operations. Rigs that were classified as held-for-sale prior to 2015 continue to be reported as discontinued operations.

During the third quarter, we began marketing for sale ENSCO 91, an older, less capable jackup rig that we cold-stacked during the second quarter. We concluded that the rig met the held-for-sale criteria during the third quarter and its carrying value was reduced to fair value, less costs to sell, based on its estimated sales price. We recorded a pre-tax, non-cash loss on impairment totaling $10.0 million, which was included in loss on impairment within income from continuing operations in our consolidated statement of operations for the year ended December 31, 2015.

Also during the third quarter, we concluded that impairments were required on certain held-for-sale rigs as a result of declines in fair value. We recorded a pre-tax, non-cash loss on impairment totaling $25.6 million, which was included in loss from discontinued operations, net, in our consolidated statement of operations for the year ended December 31, 2015.

During the fourth quarter, we concluded that additional impairments were required due to our decision to sell our held-for-sale rigs for scrap value. As a result, we recognized a pre-tax, non-cash loss on impairment of $115.8 million, which was included in loss from discontinued operations, net, in our consolidated statement of operations for the year ended December 31, 2015. See “Note 10 - Discontinued Operations” for additional information on rigs classified as held-for-sale and presented in discontinued operations.

Our six held-for-sale rigs have a remaining aggregate carrying value of $5.5 million and are included in other assets, net, on our consolidated balance sheet as of December 31, 2015.

Assets held-for-use

On a quarterly basis, we evaluate the carrying value of our property and equipment to identify events or changes in circumstances ("triggering events") that indicate the carrying value may not be recoverable.

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During the fourth quarter, commodity prices declined with Brent crude oil prices trading around $35 per barrel as of December 31, 2015. Commodity prices continued to decline further into 2016, and Brent crude oil prices reached a ten-year low of approximately $26 per barrel in January 2016. These prices resulted in significant capital spending reductions by our customers, causing a decline in day rates for the few contracts executed during the fourth quarter. Customers have delayed drilling programs and are exploring subletting opportunities for contracted rigs thereby exacerbating supply pressure. In addition, certain customers are requesting contract concessions or terminating drilling contracts. Customers are expected to continue to operate under reduced budgets until we see a meaningful recovery in commodity prices. The significant supply and demand imbalance will continue to be adversely impacted by future newbuild deliveries, program delays and lower capital spending by operators. These adverse changes resulted in further deterioration in our forecasted day rates and utilization during the fourth quarter. As a result, we concluded that a triggering event had occurred.

Based on the asset impairment analysis performed as of December 31, 2015, we recorded a pre-tax, non-cash loss on impairment with respect to certain floaters and jackups totaling $2,460.3 million. The impairment charge was included in loss on impairment in our consolidated statement of operations for the year ended December 31, 2015. We measured the fair value of these rigs by applying either an income approach, using projected discounted cash flows, or a market approach. These valuations were based on unobservable inputs that require significant judgments for which there is limited information, including assumptions regarding future day rates, utilization, operating costs and capital requirements.

In instances where we applied an income approach, forecasted day rates and utilization take into account current market conditions and our anticipated business outlook, both of which have been impacted by the adverse changes in the business environment observed during the fourth quarter. The day rates reflect contracted rates during the respective contracted periods and our estimate of market day rates in uncontracted periods. The forecasted market day rates were depressed in the near-term but were forecasted to grow in the longer-term and terminal period. Operating costs were forecasted using a combination of our historical average operating costs and expected future costs, adjusted for an estimated inflation factor. Capital requirements were based on our estimates of future capital costs, taking into consideration our historical trends. The estimated capital requirements included cash outflows to maintain the current operating condition of our rigs through their remaining useful lives.

In instances where we applied a market approach, the fair value was based on unobservable third-party estimated prices that would be received in exchange for the assets in an orderly transaction between market participants. We validated all third-party estimated prices using our forecasts of economic returns for the respective rigs or other market data.

If the global economy, our overall business outlook, and/or our expectations regarding the marketability of one or more of our drilling rigs deteriorate further, we may conclude that a triggering event has occurred and perform a recoverability test that could lead to a material impairment charge in future periods.

Year Ended December 31, 2014 - During 2014, we recorded a pre-tax, non-cash loss on impairment of long-lived assets of $2,463.1 million, of which $1,220.8 million was included in (loss) income from continuing operations and $1,242.3 million was included in loss from discontinued operations, net, in our consolidated statement of operations. These losses were recorded during the second and fourth quarters of 2014.

During the second quarter of 2014, demand for floaters deteriorated as a result of continued reductions in capital spending by operators in addition to delays in operators’ drilling programs. The reduction in demand, combined with the increasing supply from newbuild floater deliveries, led to a very competitive market. In general, contracting activity declined significantly, and day rates and utilization came under pressure, especially for older, less capable floaters.

In response to the adverse change in the floaters business climate, we evaluated our older, less capable floaters and committed to a plan to sell five rigs. ENSCO 5000, ENSCO 5001, ENSCO 5002, ENSCO 6000 and ENSCO 7500 were removed from our portfolio of rigs marketed for contract drilling services and classified as held-for-sale.

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These rigs were written down to fair value, less costs to sell. We recorded a pre-tax, non-cash loss on impairment totaling $546.4 million during the second quarter associated with these rigs. The impairment charge was included in loss from discontinued operations, net, in our consolidated statement of operations for the year ended December 31, 2014.

Also during the second quarter of 2014, as a result of the adverse change in the floater business climate, our decision to sell five floaters and the impairment charge incurred on the held-for-sale floaters, we concluded that a triggering event had occurred and performed an asset impairment analysis on our remaining older, less capable floaters.

Based on the analysis performed as of May 31, 2014, we recorded an additional pre-tax, non-cash loss on impairment with respect to four other floaters totaling $991.5 million, of which $288.0 million related to ENSCO DS-2 that was removed from our portfolio of rigs marketed for contract drilling services during the fourth quarter of 2014. The ENSCO DS-2 impairment charge was reclassified to loss from discontinued operations, net, in our consolidated statement of operations for the year ended December 31, 2014. The remaining $703.5 million impairment charge was included in loss on impairment in our consolidated statement of operations for the year ended December 31, 2014. We measured the fair value of these rigs by applying an income approach, using projected discounted cash flows. These valuations were based on unobservable inputs that require significant judgments for which there is limited information, including assumptions regarding future day rates, utilization, operating costs and capital requirements.

During the fourth quarter of 2014, Brent crude oil prices declined from approximately $95 per barrel to near $55 per barrel on December 31, 2014. These declines resulted in further reductions in capital spending by operators, including the cancellation or deferral of planned drilling programs. As a result, day rates and utilization came under further pressure, especially for older, less capable rigs.

In response to the adverse change in business climate, we evaluated our aged rigs and committed to a plan to sell one additional floater and two jackups. ENSCO DS-2, ENSCO 58 and ENSCO 90 were removed from our portfolio of rigs marketed for contract drilling services. These rigs were written down to fair value, less costs to sell. In addition to the asset impairment recorded during the second quarter, we recorded an additional pre-tax, non-cash loss on impairment totaling $407.9 million during the fourth quarter on our held-for-sale rigs. The impairment charge was included in loss from discontinued operations, net, in our consolidated statement of operations for the year ended December 31, 2014.

Also during the fourth quarter of 2014, as a result of the decline in commodity prices and adverse changes in the offshore drilling market, our decision to sell an additional floater and two jackups and the impairment charge incurred on the held-for-sale rigs, we concluded that a triggering event had occurred and performed an asset impairment analysis for all floaters and jackups.

Based on the analysis performed as of December 31, 2014, we recorded an additional pre-tax, non-cash loss on impairment with respect to two older, less capable floaters and ten older, less capable jackups totaling $517.3 million. The impairment charge was included in loss on impairment in our consolidated statement of operations for the year ended December 31, 2014. We measured the fair value of these rigs by applying either an income approach, using projected discounted cash flows, or a market approach. These valuations were based on unobservable inputs that require significant judgments for which there is limited information, including assumptions regarding future day rates, utilization, operating costs and capital requirements.  In instances where we applied a market approach, the fair value was based on unobservable third-party estimated prices that would be received in exchange for the assets in an orderly transaction between market participants. We validated all third-party estimated prices using our forecasts of economic returns for the respective rigs.

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Impairment of Goodwill

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, represent our reporting units. We test goodwill for impairment on an annual basis or when events or changes in circumstances indicate that a potential impairment exists. 

Year Ended December 31, 2015 - As part of our annual goodwill impairment test, we considered the decline in Brent crude oil prices to around $35 per barrel as of December 31, 2015. Commodity prices continued to decline further into 2016, and Brent crude oil prices reached a ten-year low of approximately $26 per barrel in January 2016. These prices resulted in significant capital spending reductions by our customers, causing a decline in day rates for the few contracts executed during the fourth quarter. Customers have delayed drilling programs and are exploring subletting opportunities for contracted rigs thereby exacerbating supply pressure. In addition, certain customers are requesting contract concessions or terminating drilling contracts. Customers are expected to continue to operate under reduced budgets in the current commodity price environment. The significant supply and demand imbalance will continue to be adversely impacted by future newbuild deliveries, program delays and lower capital spending by operators. These adverse changes resulted in further deterioration in our forecasted day rates and utilization during the fourth quarter.

Additionally, during the latter half of 2015, our stock price declined significantly, trading between $13.26 and $22.21. Our average stock price was $17.21and $16.34 during the third and fourth quarters, respectively. Our stock price continued to decline during 2016, reaching a 20-year low closing price of approximately $8.00 in February. During the first half of 2015, our average stock price was $25.31.

We considered the deterioration in our forecasted day rates and utilization, the sustained decline in our stock price and the impairment charge on certain rigs during the fourth quarter and concluded it was more-likely-than-not that the fair values of both the Floaters and Jackups reporting units were less than their carrying amounts.

We estimated the fair values of each reporting unit using an income approach. In the current market environment, we concluded the income approach provided a better estimate of fair value compared to other valuation approaches. Based on the valuations performed as of December 31, 2015, both the Floater and Jackup reporting unit estimated fair values were less than their carrying values; therefore, we concluded that the Floater and Jackup goodwill balances were impaired.

We compared the estimated fair value of each reporting unit to the fair values of all assets and liabilities within the respective reporting unit to calculate the implied fair value of goodwill. As a result, we recorded a non-cash loss on impairment of $192.6 million and $83.5 million for the Jackups and Floaters reporting units, respectively, which was included in loss on impairment in our consolidated statement of operations for the year ended December 31, 2015. There is no goodwill on our consolidated balance sheet as of December 31, 2015.

The income approach was based on a discounted cash flow model, which utilized present values of cash flows to estimate fair value and was based on unobservable inputs that require significant judgments for which there is limited information. The future cash flows were projected based on our estimates of future day rates, utilization, operating costs, capital requirements, growth rates and terminal values. Forecasted day rates and utilization take into account current market conditions and our anticipated business outlook, both of which have been impacted by the adverse changes in the business environment observed during the fourth quarter. The day rates reflect contracted rates during the respective contracted periods and our estimate of market day rates in uncontracted periods. The forecasted market day rates were depressed in the near-term but were forecasted to grow in the longer-term and terminal period.

Operating costs were forecasted using a combination of our historical average operating costs and expected future costs, adjusted for an estimated inflation factor. Capital requirements in the discounted cash flow model were based on our estimates of future capital costs, taking into consideration our historical trends. The estimated capital

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requirements included cash outflows for new rig construction and cash outflows to maintain the current operating condition of our rigs through their remaining marketable lives.

A terminal period was used to reflect our estimate of stable, perpetual growth. The terminal period reflects a terminal growth rate of 3.0%, which includes an estimated inflation factor. The future cash flows were discounted using a market-participant risk-adjusted weighted average cost of capital of 11.5%. These assumptions were derived from unobservable inputs and reflect our judgments and assumptions.

We evaluated the estimated fair value of our reporting units compared to our market capitalization as of December 31, 2015. The aggregate fair values of our reporting units exceeded our market capitalization, and we believe the resulting implied control premium was reasonable based on recent market transactions within our industry or other relevant benchmark data.

Year Ended December 31, 2014 - As part of our annual goodwill impairment test as of December 31, 2014, we considered the significant decline in commodity prices during the fourth quarter of 2014. Specifically, Brent crude oil prices declined from approximately $95 per barrel at September 30, 2014 to near $55 per barrel at December 31, 2014. These declines resulted in further reductions in capital spending by operators, including the cancellation or deferral of planned drilling programs, which caused further deterioration in forecasted day rates and utilization.

Our stock price also declined significantly during the latter half of 2014, reaching a five-year low of $25.88 on December 16th. Our stock traded between $25.88 and $41.99 during the fourth quarter of 2014 and averaged $35.23 during this period.

We considered the adverse changes in the floater business climate, the sustained decline in our stock price and the impairment charge on older, less capable floaters during the fourth quarter and concluded it was more-likely-than-not that the fair value of the Floater reporting unit was less than its carrying amount.

We estimated the fair value of the Floater reporting unit using a blended income and market approach. Based on the valuation performed as of December 31, 2014, the reporting unit estimated fair value was less than the carrying value; therefore, we concluded that the Floater goodwill balance was impaired.  We compared the estimated fair value of the reporting unit to the fair value of all assets and liabilities within the reporting unit to calculate the implied fair value of goodwill. As a result, we recorded a non-cash loss on impairment totaling $3.0 billion which was included in loss on impairment in our consolidated statement of operations for the year ended December 31, 2014.

We evaluated the estimated fair value of our reporting units compared to our market capitalization as of December 31, 2014. To perform this assessment, we used a market approach to estimate the fair value of the Jackups reporting unit. The aggregate fair values of our reporting units exceeded our market capitalization, and we believe the resulting implied control premium was reasonable based on recent market transactions within our industry or other relevant benchmark data.

We performed a qualitative assessment for our Jackup reporting unit as of December 31, 2014. Goodwill impairment tests performed during prior years indicated that the fair value of the Jackup reporting unit significantly exceeded its carrying amount. Despite the adverse changes in the offshore drilling business climate, we concluded that the fair value remained substantially in excess of the carrying value of the reporting unit, as evidenced by the estimated fair value of the Jackup reporting unit calculated for the purpose of reconciling the fair value of our reporting units to our market capitalization. Therefore, we concluded that it remained more-likely-than-not that the Jackup reporting unit was not impaired.

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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, 2015 (in millions):

	2015			2014			2013
Interest income	$	9.9		$	13.0		$	16.6
Interest expense, net:
Interest expense	(303.7		)	(239.6		)	(226.5		)
Capitalized interest	87.4			78.2			67.7
	(216.3		)	(161.4		)	(158.8		)
Other, net	(21.3		)	.5			42.1
	$	(227.7	)	$	(147.9	)	$	(100.1	)

During 2015 and 2014, interest income declined as compared to the respective prior year periods primarily due to declining outstanding principal amounts for reimbursement of mobilization and upgrade costs on certain long-term drilling contracts due from customers.

Interest expense during 2015 and 2014 increased$64.1 million, or 27%, and $13.1 million, or 6%, as compared to the prior year, respectively, due to our issuance of senior notes in March 2015 and September 2014, partially offset by the redemption of our 3.25% senior notes due 2016 ("2016 Senior Notes") and our U.S. Maritime Administration ("MARAD") obligations.

Interest expense capitalized during 2015 and 2014increased$9.2 million, or 12%, and $10.5 million, or 16%, respectively, as compared to the prior year due to an increase in the average outstanding amount of capital invested in newbuild construction.

During 2015, other, net included a pre-tax loss of $33.5 million related to the extinguishment of our 2016 Notes and our MARAD obligations.  This loss was partially offset by a $6.4 million gain on settlement of outstanding tax indemnification liabilities.

During 2013, other, net included a $30.6 million reimbursement from the Mexican tax authority with respect to the 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 operations 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 and losses, inclusive of offsetting fair value derivatives, were $5.4 million of gains, $2.6 million of losses and $6.4 million of gains, and were included in other, net in our consolidated statements of operations for the years ended December 31, 2015, 2014 and 2013, respectively.

Net unrealized gains of $700,000, $2.3 million and $6.2 million from marketable securities held in our supplemental executive retirement plans ("SERP") were included in other, net in our consolidated statements of operations for the years ended December 31, 2015, 2014 and 2013, respectively. The fair value measurement of our marketable securities held in the SERP is discussed in Note 2 to our consolidated financial statements.

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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 generally 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.

During the years ended December 31, 2015, 2014 and 2013, we recorded an income tax benefit of $13.9 million and income tax expenses of $140.5 million and $203.1 million, respectively. Our consolidated effective income tax rates were .9%, (5.5)% and 12.4% during the same periods, respectively.

Our 2015 consolidated effective income tax rate includes the impact of various discrete tax items, primarily related to a $192.5 million tax benefit associated with rig impairments and $11.0 million tax benefit resulting from the reduction of a valuation allowance on US foreign tax credits.

Our consolidated effective income tax rate for 2014 includes the impact of various discrete tax items, including the recognition of a net $18.4 million tax expense associated with liabilities for unrecognized tax benefits and other adjustments relating to prior years and a $16.4 million tax benefit associated with rig impairments. In addition, we recognized a net $41.4 million tax benefit in connection with the utilization of foreign tax credits that were previously subject to a valuation allowance.

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.

Excluding the impact of the aforementioned discrete tax items and goodwill and asset impairments, our consolidated effective income tax rates for the years ended December 31, 2015, 2014 and 2013 were 16.0%, 10.7% and 12.2%, respectively. The changes in our consolidated effective income tax rate excluding discrete tax items during the three-year period result primarily from changes in the relative components of our earnings from the various taxing jurisdictions in which our drilling rigs are operated and/or owned and the differences in the tax rates in such tax jurisdictions.

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Discontinued Operations

Our business strategy has been to focus on ultra-deepwater floater and premium jackup operations. We continually assess our rig portfolio and actively work with our rig broker to market certain rigs that no longer meet our standards for economic returns or are not part of our long-term strategic plan. Consistent with this strategy, we sold the following rigs during the three-year period ended December 31, 2015 (in millions):

Rig(3)	Date of Rig Sale	Segment(1)	Net Proceeds		Net Book Value(2)		Pre-tax(Loss)/Gain
ENSCO 5001	December 2015	Floaters	$	2.4	$	2.5	$	(.1	)
ENSCO 5002	June 2015	Floaters	1.6		—		1.6
ENSCO 5000	December 2014	Floaters	1.3		.5		.8
ENSCO 93	September 2014	Jackups	51.7		52.9		(1.2		)
ENSCO 85	April 2014	Jackups	64.4		54.1		10.3
ENSCO 69 & Pride Wisconsin	January 2014	Jackups	32.2		8.6		23.6
Pride Pennsylvania	March 2013	Jackups	15.5		15.7		(.2		)
			$	169.1	$	134.3	$	34.8

⁽¹⁾ The rigs' operating results were reclassified to discontinued operations in our consolidated statements of operations for each of the years in the three-year period ended December 31, 2015 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⁾ In September 2014, we sold jackup rigs ENSCO 83, ENSCO 89, ENSCO 93 and ENSCO 98, all of which were contracted to Pemex. As described below, the loss on sale and operating results of ENSCO 93 were included in loss from discontinued operations, net in our consolidated statement of operations for the three-year period ended December 31, 2015. Due to our long-term charter agreements with the purchaser, ENSCO 83, ENSCO 89 and ENSCO 98 operating results were included in income from continuing operations.

During 2014, we committed to a plan to sell six floaters and two jackups. ENSCO 5000, ENSCO 5001, ENSCO 5002, ENSCO 6000, ENSCO 7500, ENSCO DS-2, ENSCO 58 and ENSCO 90 were removed from our portfolio of rigs marketed for contract drilling services. The operating results from these rigs were included in loss from discontinued operations, net in our consolidated statement of operations for the three-year period ended December 31, 2015.

On a quarterly basis, we reassess the fair values of our held-for-sale rigs to determine whether any adjustments to the carrying values are necessary.  We recorded a non-cash loss on impairment totaling $120.6 million (net of tax benefits of $28.0 million) and $1.2 billion (net of tax benefits of $83.5 million), for the years ended December 31, 2015 and 2014, respectively, as a result of declines in the estimated fair values of our held-for-sale rigs. The loss on impairment was included in loss from discontinued operations, net in our consolidated statement of operations for the years ended December 31, 2015 and 2014, respectively. We measured the fair value of held-for-sale rigs by applying a market approach, which was based on an unobservable third-party estimated price that would be received in exchange for the assets in an orderly transaction between market participants.

During 2015, we sold ENSCO 5001 and ENSCO 5002 for net proceeds of $2.4 million and $1.6 million, respectively, which were included in investing activities of discontinued operations in our consolidated statement of cash flows for the year ended December 31, 2015. During 2014, we sold ENSCO 5000 for net proceeds of $1.3 million, which was included in investing activities of discontinued operations in our consolidated statement of cash flows for the year ended December 31, 2014. The remaining three floaters and two jackups that are included in discontinued operations are being actively marketed for sale and were classified as held-for-sale on our December 31, 2015 consolidated balance sheet.

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During 2014, we sold ENSCO 93, a jackup contracted to Pemex. In connection with this sale, we executed a charter agreement with the purchaser to continue operating the rig for the remainder of the Pemex contract, which ended in July 2015, less than one year from the date of sale. Our management services following the sale did not constitute significant ongoing involvement and therefore, the $1.2 million loss on sale was included in loss from discontinued operations, net, in our consolidated statement of operations for the year ended December 31, 2014. ENSCO 93 operating results were included in loss from discontinued operations, net, in our consolidated statement of operations for the three-year period ended December 31, 2015. Net proceeds from the sale of $51.7 million were included in investing activities of discontinued operations in our consolidated statement of cash flows for the year ended December 31, 2014. See "Note 12 - Sale-leaseback" for additional information.

During 2014, we sold ENSCO 85 for net proceeds of $64.4 million and ENSCO 69 and Pride Wisconsin for net proceeds of $32.2 million. The operating results of these rigs were included in loss from discontinued operations, net in our consolidated statement of operations. The net proceeds from the sale of ENSCO 85 were included in investing activities of discontinued operations in our consolidated statement of cash flows for the year ended December 31, 2014. The net proceeds from the sale of ENSCO 69 and Pride Wisconsin were received in December 2013 and included in investing activities of discontinued operations in our consolidated statement of cash flows for the year ended December 31, 2013.

The following table summarizes (loss) income from discontinued operations for each of the years in the three-year period ended December 31, 2015 (in millions):

	2015			2014			2013
Revenues	$	19.5		$	325.0		$	596.4
Operating expenses	39.5			372.0			577.6
Operating (loss) income	(20.0		)	(47.0		)	18.8
Other income	—			—			.3
Income tax benefit (expense)	7.7			(30.7		)	(20.2		)
Loss on impairment, net	(120.6		)	(1,158.8		)	—
Gain (loss) on disposal of discontinued operations, net	4.3			37.3			(1.1		)
Loss from discontinued operations	$	(128.6	)	$	(1,199.2	)	$	(2.2	)

Income tax benefit (expense) from discontinued operations for the year ended December 31, 2015 included $12.6 million of discrete tax benefits.

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

LIQUIDITY AND CAPITAL RESOURCES

We have historically relied on our cash flow from continuing operations to meet liquidity needs and fund the majority of our cash requirements. We periodically rely on the issuance of debt securities to supplement our liquidity needs. A substantial portion of our cash has 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.

Based on our balance sheet, $5.8 billion of contractual backlog and $2.25 billion available under our revolving credit facility, we believe our remaining capital commitments, debt service payments and dividend payments will primarily be funded from cash and cash equivalents, short-term investments, operating cash flows and, if necessary, funds borrowed under our revolving credit facility. We may decide to access debt and/or equity markets to raise additional capital, refinance existing debt or increase liquidity as necessary.

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As of December 31, 2015, we had $5.9 billion in total debt outstanding, representing approximately 47.5% of our total capitalization. Our next debt maturity is 2019 with an aggregate principal amount of $500 million, followed by additional maturities in 2020 and 2021 with aggregate principal amounts of $900 million and $1.5 billion, respectively. We have $1.3 billion in cash and cash equivalents and short-term investments and a $2.25 billion available under our Credit Facility. The Credit Facility requires us to maintain a total debt to total capitalization ratio that is less than or equal to 60%.

Notwithstanding our current liquidity position, if we experience significant further deterioration in demand for offshore drilling and a significantly protracted downturn, our ability to maintain a sufficient level of liquidity to meet our financial obligations would be materially and adversely impacted. Further, our access to credit and capital markets depends on the credit ratings assigned to our debt by independent credit rating agencies. Recently, Moody's announced that our credit rating is under review for a downgrade. There can be no assurance that we will be able to maintain our credit ratings, and any additional actual or anticipated downgrades in our credit ratings, including any announcement that our ratings are under review for a downgrade, could limit our ability to access credit and capital markets, or to restructure or refinance our indebtedness. In addition, future financings or refinancings may result in higher borrowing costs and require more restrictive terms and covenants, which may further restrict our operations. If we are downgraded below investment grade by one or more credit rating agencies, we may have limited or no access to the commercial paper market.

During the three-year period ended December 31, 2015, our primary sources of cash were an aggregate $5.6 billion generated from operating activities of continuing operations and $2.3 billion in proceeds from the issuance of senior notes. Our primary uses of cash during the same period included $4.9 billion for the construction, enhancement and other improvement of our drilling rigs, including $3.2 billion invested in newbuild construction, and $1.4 billion for dividend payments.

Detailed explanations of our liquidity and capital resources for each of the years in the three-year period ended December 31, 2015 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, 2015 were as follows (in millions):

	2015		2014		2013
Cash flows from operating activities of continuing operations	$	1,697.9	$	2,057.9	$	1,811.2
Capital expenditures on continuing operations:
New rig construction	$	1,238.8	$	699.5	$	1,282.5
Rig enhancements	164.5		537.4		239.0
Minor upgrades and improvements	216.2		329.8		242.0
	$	1,619.5	$	1,566.7	$	1,763.5

During 2015, cash flows from continuing operations declined by $360.0 million, or 17%, as compared to the prior year.  The decline primarily resulted from a $571.7 million decline in cash receipts from contract drilling services and a $69.0 million increase in cash paid for interest, partially offset by a $257.2 million decline in cash payments related to contract drilling expenses.

During 2014, cash flows from continuing operations increased by $246.7 million, or 14%, as compared to the prior year.  The increase primarily resulted from a $503.1 million increase in cash receipts from contract drilling services, partially offset by a $259.2 million increase in cash payments related to contract drilling expenses.

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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 $267.0 million for the year ended December 31, 2014 as compared to $70.0 million for the year ended December 31, 2013.

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, 2015, we invested $3.2 billion in the construction of new drilling rigs and an additional $940.9 million enhancing the capability and extending the useful lives of our existing fleet.

Based on our current projections, we expect capital expenditures during 2016 to include approximately $275 million for newbuild construction, approximately $25 million for rig enhancement projects and approximately $150 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.

Dividends

Our Board of Directors declared a $0.01 quarterly cash dividend per Class A ordinary share for the first quarter of 2016. The Board of Directors reduced the dividend by $0.14 per share primarily to improve capital management flexibility during the market downturn. In the future, our Board of Directors may, without advance notice, determine to reduce or suspend our dividend in order to maintain our financial flexibility and best position our company for long-term success. The declaration and amount of future dividends is at the discretion of our Board of Directors. When evaluating dividend payment timing and amounts, our Board of Directors considers several factors, including our profitability, liquidity, financial condition, market outlook, reinvestment opportunities and capital requirements. There can be no assurance that we will pay a dividend in the future.

Financing and Capital Resources

Our total debt, total capital and total debt to total capital ratios as of December 31, 2015, 2014 and 2013 are summarized below (in millions, except percentages):

	2015			2014			2013
Total debt	$	5,895.1		$	5,920.4		$	4,766.4
Total capital*	12,408.0			14,135.4			17,558.0
Total debt to total capital	47.5		%	41.9		%	27.1		%

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

During 2015, our total capital declined by $1,727.4 million and our total debt to total capital ratio increased from 41.9% to 47.5% primarily due to a pre-tax, non-cash loss on impairment of $2.9 billion.

Senior Notes

During the first quarter, we issued $700.0 million aggregate principal amount of unsecured 5.20% senior notes due 2025 (the “2025 Notes”) at a discount of $2.6 million and $400.0 million aggregate principal amount of unsecured 5.75% senior notes due 2044 (the “New 2044 Notes”) at a discount of $18.7 million in a public offering. Interest on the 2025 Notes is payable semiannually on March 15 and September 15 of each year commencing September 15, 2015. Interest on the New 2044 Notes is payable semiannually on April 1 and October 1 of each year commencing on April 1, 2015.

During 2014, we issued $625.0 million aggregate principal amount of unsecured 4.50% senior notes due 2024 (the "2024 Notes") at a discount of $850,000 and $625.0 million aggregate principal amount of unsecured 5.75% senior notes due 2044 (the "Existing 2044 Notes" and together with the New 2044 Notes, the "2044 Notes") at a discount of $2.8 million. Interest on the 2024 Notes and the Existing 2044 Notes is payable semiannually on April 1 and October

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1 of each year commencing on April 1, 2015. The Existing 2044 Notes and the New 2044 Notes are treated as a single series of debt securities under the indenture governing the notes (the "2044 Notes").

During 2011, we issued $1.5 billion aggregate principal amount of unsecured 4.70% senior notes due 2021 (the “2021 Notes”) at a discount of $29.6 million in a public offering. Interest on the 2021 Notes is payable semiannually on March 15 and September 15 of each year.

Upon consummation of the Pride acquisition during 2011, we assumed the acquired company's outstanding debt comprised of $900.0 million aggregate principal amount of unsecured 6.875% senior notes due 2020, $500.0 million aggregate principal amount of unsecured 8.5% senior notes due 2019 and $300.0 million aggregate principal amount of unsecured 7.875% senior notes due 2040 (collectively, the "Acquired Notes" and together with the 2021 Notes, 2024 Notes, 2025 Notes and 2044 Notes, the "Senior Notes").  Ensco plc has fully and unconditionally guaranteed the performance of all Pride obligations with respect to the Acquired Notes.  See "Note 15 - Guarantee of Registered Securities" for additional information on the guarantee of the Acquired Notes. 

We may redeem the 2024 Notes, 2025 Notes and 2044 Notes in whole, at any time or in part from time to time, prior to maturity. If we elect to redeem the 2024 Notes and 2025 Notes before the date that is three months prior to the maturity date or the 2044 Notes before the date that is six months prior to the maturity date, we will pay an amount equal to 100% of the principal amount of the notes redeemed plus accrued and unpaid interest and a "make-whole" premium. If we elect to redeem the 2024 Notes, 2025 Notes or 2044 Notes on or after the aforementioned dates, we will pay an amount equal to 100% of the principal amount of the notes redeemed plus accrued and unpaid interest but we are not required to pay a "make-whole" premium.

We may redeem each series of the 2021 Notes and the 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 the Senior Notes contain customary events of default, including failure to pay principal or interest on such notes when due, among others. The indentures governing the Senior 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.

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 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 and the indenture pursuant to which the Debentures were issued also contain customary events of default, including failure to pay principal or interest on the Debentures when due, among others. The indenture also 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.

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Redemption of 2016 Senior Notes and MARAD Obligations

During 2011, we issued $1.0 billion of 3.25% senior notes due 2016 (the “2016 Notes”). In March 2015, we commenced a cash tender offer (the “Tender Offer”) for the 2016 Notes. Tendered notes totaling $854.6 million were settled on March 12, 2015 for $878.0 million (excluding accrued interest) using a portion of the net proceeds from the issuance of the 2025 Notes and New 2044 Notes. Under the terms of the Tender Offer, we paid a premium totaling approximately $23.4 million, which approximates the “make-whole” premium that would have been required had we elected to redeem the debt. Additionally, we recorded charges of $1.7 million for unamortized debt discounts and $1.5 million for unamortized debt issuance costs, resulting in a total pre-tax loss on debt extinguishment of $26.6 million included in other, net, in our consolidated statement of operations for the year ended December 31, 2015.

Concurrent with the settlement of the Tender Offer, we exercised our right to redeem the remaining 2016 Notes. In April 2015, we completed the redemption of the remaining $145.4 million of 2016 Notes using a portion of the net proceeds from the 2025 Notes and New 2044 Notes. The redemption payment included a "make-whole" premium of $3.8 million which was recorded as a loss on debt extinguishment and included in other, net, in our consolidated statement of operations for the year ended December 31, 2015.

In April 2015, we used the remaining net proceeds from 2025 Notes and the New 2044 Notes, together with cash on hand, to redeem $51.0 million of our 4.33% MARAD notes due 2016 and 4.65% MARAD bonds due 2020 (the “MARAD Obligations”). We incurred additional losses on debt extinguishment of $3.1 million, which were included in other, net, in our consolidated statement of operations for the year ended December 31, 2015. These losses primarily consisted of a "make-whole" premium.

In July 2015, we redeemed the remaining $14.3 million aggregate principal amount of the MARAD Obligations.

Commercial Paper

We participate in a commercial paper program with three 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 $2.25 billion. Amounts issued under the commercial paper program are supported by the available and unused committed capacity under our credit facility. As a result, amounts issued under the commercial paper program are limited by the amount of our available and unused committed capacity under our credit facility. The proceeds of such financings may be used for capital expenditures and other general corporate purposes. The commercial paper bears interest at rates that vary based on market conditions and the ratings assigned by credit rating agencies at the time of issuance. If we are downgraded below investment grade by one or more credit rating agencies, we may have limited or no access to the commercial paper market. The weighted-average interest rate on our commercial paper borrowings was 0.41% and 0.26% during 2015 and 2014, respectively.  Commercial paper maturities 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, 2015 and 2014.

Revolving Credit

We have a $2.25 billion senior unsecured revolving credit facility with a syndicate of banks to be used for general corporate purposes with a term expiring on September 30, 2019 (the "Credit Facility").

Advances under the Credit Facility bear interest at Base Rate or LIBOR plus an applicable margin rate, depending on our credit ratings. We are required to pay a quarterly commitment fee on the undrawn portion of the $2.25 billion commitment, which is also based on our credit ratings.

During the fourth quarter, Moody's and Standard & Poor's each downgraded our senior unsecured rating one notch to Baa2 and BBB, respectively. As a result, the applicable margin rate for advances under our Credit Facility and the quarterly commitment fee percentage increased by 0.125% per annum and 0.025% per annum, respectively,

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under our Credit Facility. Currently, the applicable margin rates are 0.25% per annum for Base Rate advances and 1.25% per annum for LIBOR advances. Also, our quarterly commitment fee is 0.15% per annum on the undrawn portion of the $2.25 billion commitment. Amounts repaid may be re-borrowed during the term of the Credit Facility. There can be no assurance that ratings agencies will not further downgrade our credit ratings, and any such further downgrade, or the perceived risk of further downgrades, may limit our ability to access credit and capital markets, restructure or refinance our debt, result in higher borrowing costs or require more restrictive terms and covenants, which may further restrict our operations. See “Item 1A. Risk Factors - Our debt levels and debt agreement restrictions may limit our liquidity and flexibility in obtaining additional financing and in pursuing other business opportunities.”

The Credit Facility requires us to maintain a total debt to total capitalization ratio that is less than or equal to a specified percentage. In March 2015, we amended the Credit Facility to increase the percentage from 50% to 60%. The Credit Facility also contains customary restrictive covenants, including, among others, prohibitions on creating, incurring or assuming certain debt and liens; entering into certain merger arrangements; selling, leasing, transferring or otherwise disposing of all or substantially all of our assets; making a material change in the nature of the business; and entering into certain transactions with affiliates. We have the right, subject to receipt of commitments from lenders, to increase the commitments under the Credit Agreement to an aggregate amount of up to $2.75 billion and to extend the term of the Credit Agreement by one year on up to two occasions.

As of December 31, 2015, we were in compliance in all material respects with our covenants under the Credit Facility. We expect to remain in compliance with our Credit Facility covenants during 2016. We had no amounts outstanding under the Credit Facility as of December 31, 2015and 2014.

Other Financing Matters

     We filed an automatically effective shelf registration statement on Form S-3 with the SEC on January 15, 2015, 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 2018.

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 shares 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.

Subject to market conditions, our leverage and liquidity positions and other factors, we may retire certain outstanding senior notes and debentures prior to scheduled maturities through debt repurchases, either in the open market, in privately negotiated transactions or through redemptions or tender offers. These transactions may be funded by cash generated from operations, borrowings under our credit facility or the issuance of debt instruments or equity. Such transactions may impact the amount and composition of our outstanding debt, interest expense or otherwise impact our capital structure and liquidity.

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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 existing cash and short-term investments, future operating cash flows and borrowings under our 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, 2015 and the periods in which such obligations are due (in millions):

	Payments due by period
	2016		2017 and 2018		2019 and 2020		Thereafter		Total
Principal payments on long-term debt	$	—	$	—	$	1,400.0	$	4,300.0	$	5,700.0
Interest payments on long-term debt	332.8		665.5		601.8		2,244.2		3,844.3
New rig construction agreements	169.6		535.4		—		—		$	705.0
Operating leases	45.3		30.3		20.7		53.4		149.7
Derivative instruments	21.6		1.5		—		—		23.1
Total contractual obligations(1)	$	569.3	$	1,232.7	$	2,022.5	$	6,597.6	$	10,422.1

⁽¹⁾  Contractual obligations do not include $171.0 million of unrecognized tax benefits, inclusive of interest and penalties, included on our consolidated balance sheet as of December 31, 2015.  We are unable to specify with certainty the future periods in which we may be obligated to settle such amounts.

a

Other Commitments

We have other commitments that we are contractually obligated to fulfill with cash under certain circumstances.  These commitments include letters of credit 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 are not normally called, as we typically comply with the underlying performance requirement. As of December 31, 2015, 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, 2015 (in millions):

	Commitment expiration by period
	2016		2017 and 2018		2019 and 2020		Thereafter		Total
Letters of Credit	$	47.0	$	22.8	$	—	$	.2	$	70.0

Liquidity

Our liquidity position as of December 31, 2015, 2014 and 2013 is summarized below (in millions, except ratios):

	2015		2014		2013
Cash and cash equivalents	$	121.3	$	664.8	$	165.6
Short-term investments	1,180.0		757.3		50.0
Working capital	1,509.6		1,788.9		466.9
Current ratio	2.9		2.6		1.4

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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 and, if necessary, funds borrowed under our revolving credit facility.

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.

If we experience significant further deterioration in demand for offshore drilling and a significantly protracted recovery, our ability to maintain a sufficient level of liquidity to meet our financial obligations would be adversely impacted. Further, our access to credit and capital markets depends on the credit ratings assigned to our debt by independent credit rating agencies. Recently, Moody's announced that our credit rating is under review for a downgrade. There can be no assurance that we will be able to maintain our credit ratings, and any additional actual or anticipated downgrades in our credit ratings, including any announcement that our ratings are under review for a downgrade, could limit our ability to access credit and capital markets, or to restructure or refinance our indebtedness. In addition, future financings or refinancings may result in higher borrowing costs and require more restrictive terms and covenants, which may further restrict our operations. If we are downgraded below investment grade by one or more credit rating agencies, we may have limited or no access to the commercial paper market.

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.

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.

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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, 2015, we had cash flow hedges outstanding to exchange an aggregate $311.6 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, 2015, we held derivatives not designated as hedging instruments to exchange an aggregate $125.7 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, 2015 would approximate $18.9 million. Approximately $12.6 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 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.

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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 our derivatives mature during the next 18 months. See Note 5 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 us 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 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, 2015, the carrying value of our property and equipment totaled $11.1 billion, which represented 81% of total assets.  This carrying value reflects the application of our property and equipment accounting policies, which incorporate our 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 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 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.

On December 31, 2015, we evaluated our current judgments and assumptions used in determining the useful lives of our drilling rigs. We considered both historical experience and expectations of future operations, utilization and performance of our assets based on recent changes in the current market environment. As a result, we reduced the useful lives of certain floaters and jackups effective January 1, 2016. Also, we recorded a pre-tax, non-cash loss on impairment of long-lived assets held-for-use of $2.5 billion during 2015. We estimate these changes will cause a net decline in depreciation expense of approximately $150 million for the year ended December 31, 2016.

Our fleet of 22 floater rigs marketed for contract drilling services, exclusive of one rig under construction, represented 65% of the gross cost and 65% of the net carrying amount of our depreciable property and equipment as of December 31, 2015.  Our floater rigs are depreciated over useful lives ranging from ten to 35 years.  Our fleet of 36 jackup rigs marketed for contract drilling services, exclusive of three rigs under construction, represented 20% of

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the gross cost and 18% of the net carrying amount of our depreciable property and equipment as of December 31, 2015.  Our jackup rigs are depreciated over useful lives ranging from ten to 30 years.  The following table provides an analysis of estimated increases and decreases in depreciation expense from continuing operations that would have been recognized for the year ended December 31, 2015 for various assumed changes in the useful lives of our drilling rigs effective January 1, 2015:

Increase (decrease) in useful lives of our drilling rigs	Estimated (decrease) increase in depreciation expense that would have been recognized (in millions)
10%	$(47.5)
20%	(87.2)
(10%)	51.8
(20%)	111.2

Impairment of Long-Lived Assets and Goodwill

During the year ended December 31, 2015, we recorded a pre-tax, non-cash loss on impairment of long-lived assets of $2.6 billion and a non-cash loss on impairment of all of our Floaters and Jackups reporting unit goodwill of $276.1 million. There is no remaining goodwill on our consolidated balance sheet as of December 31, 2015. See "Note 3 - Property and Equipment" and "Note 8 - Goodwill and Other Intangible Assets and Liabilities" to our consolidated financial statements for additional information on our property and equipment and goodwill, respectively.

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. 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.

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, our 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 conduct impairment testing of our goodwill on an annual basis or when events or changes in circumstances indicate that a potential impairment exists. Testing is performed at the reporting unit level, which is defined as an operating segment or a component of an operating segment that constitutes a business for which financial information is available and is regularly viewed by management. 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. We have determined that our two reportable segments, Floaters and Jackups, represent our reporting units.

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When testing goodwill for impairment, we consider whether or not to first assess qualitative factors to determine whether the existence of events or circumstances lead to a determination that 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, or, alternatively, if we elect to forgo the qualitative assessment, we perform a quantitative assessment whereby we estimate the fair value of each reporting unit. 

The calculation of fair values of our reporting units is based on an income and/or market approach. The income approach is based on estimates of future discounted cash flows to be generated by our drilling rigs, which reflect our 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. The market approach is based upon the application of price-to-earnings multiples against our estimates of future earnings adjusted for a control premium. 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 not considered 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.

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 our judgments and assumptions regarding future industry conditions and operations, as well as estimates of expected utilization levels, day rates, expense levels and capital requirements. The estimates, judgments and assumptions used 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, 2015, our consolidated balance sheet included a $111.7 million net deferred income tax asset, a $59.7 million liability for income taxes currently payable and a $171.0 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 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.

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The carrying values of liabilities for income taxes currently payable and unrecognized tax benefits are based on our interpretation of applicable tax laws and incorporate 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 November 2015, the Financial Accounting Standards Board issued Accounting Standards Update 2015-17, Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes, which requires that deferred tax assets and liabilities be classified as noncurrent on the balance sheet. This update is effective for annual and interim periods beginning after December 15, 2016. Early adoption is permitted for all entities as of the beginning of an interim or annual reporting period. This update may be applied either prospectively to all deferred tax assets and liabilities or retrospectively to all periods presented. We elected to early adopt this update on a retrospective basis effective December 31, 2015. Accordingly, all current deferred tax assets and liabilities were reclassified to noncurrent on the balance sheet for all periods presented. As a result of adopting this update retrospectively, we reclassified current deferred tax assets and liabilities of $43.8 million and $2.5 million, respectively, on our consolidated balance sheet as of December 31, 2014.

In July 2015, the Financial Accounting Standards Board issued Accounting Standards Update 2015-11, Inventory (Topic 330): Simplifying the Measurement of Inventory ("Update 2015-11"), which requires that inventory be measured at the lower of cost and net realizable value. Net realizable value is the estimated selling price in the ordinary course of business, less reasonably predictable costs of completion, disposal and transportation. Update 2015-11 is effective for annual and interim periods for fiscal years beginning after December 15, 2016. We will adopt the accounting standard on a prospective basis effective January 1, 2017. We do not expect the adoption to have a material effect on our consolidated financial statements.

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In April 2015, the Financial Accounting Standards Board issued Accounting Standards Update 2015-03, Interest - Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs, as updated by Update 2015-15, Interest - Imputation of Interest (Subtopic 835-30): Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements - Amendments to SEC Paragraphs Pursuant to Staff Announcements at June 18, 2015 EITF Meeting, which require that debt issuance costs related to a recognized debt liability be presented on the balance sheet as a direct deduction from the carrying amount of the related debt liability, consistent with debt discounts. Debt issuance costs related to line-of-credit arrangements may be presented as an asset regardless of whether there are any outstanding borrowings on the arrangement. These updates are effective for annual and interim periods for fiscal years beginning after December 15, 2015. Early application is permitted. We will adopt these accounting standards on a retrospective basis effective January 1, 2016. There will be no impact to the manner in which debt issuance costs are amortized on our consolidated financial statements.

In May 2014, the Financial Accounting Standards Board issued Accounting Standards Update 2014-09, Revenue from Contracts with Customers (Topic 606) ("Update 2014-09"), which requires an entity to recognize the amount of revenue to which it expects to be entitled for the transfer of promised goods or services to customers. In July 2015, the Financial Accounting Standards Board voted to delay the effective date one year. Update 2014-09 is now effective for annual and interim periods for fiscal years beginning after December 15, 2017, though companies have an option of adopting the standard for fiscal years beginning after December 15, 2016. Update 2014-09 will replace most existing revenue recognition guidance in U.S. GAAP and may be adopted using a retrospective, modified retrospective or cumulative effect approach. We are currently evaluating the effect that Update 2014-09 will have on our consolidated financial statements and related disclosures.

In June 2014, the Financial Accounting Standards Board issued Accounting Standards Update 2014-12, Compensation- Stock Compensation (Topic 718): Accounting for Share Payments When the Terms of an Award Provide That a Performance Target Could be Achieved After the Requisite Service Period ("Update 2014-12"). The new guidance clarifies that entities should treat performance targets that can be met after the requisite service period of a share-based payment award as performance conditions that affect vesting. Update 2014-12 is effective for annual and interim periods for fiscal years beginning after December 15, 2015 and early adoption is permitted. We will adopt the accounting standard on a prospective basis effective January 1, 2016. We do not expect the adoption to have a material effect on our consolidated financial statements.

In August 2014, the Financial Accounting Standards Board issued Accounting Standards Update 2014-15, Presentation of Financial Statements - Going Concern (Subtopic 205-40): Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern (“Update 2014-15”). The new guidance clarifies management’s responsibility to evaluate whether there is substantial doubt about an entity’s ability to continue as a going concern and to provide related footnote disclosures. Update 2014-15 is effective for annual periods ending after December 15, 2016 and for annual periods and interim periods thereafter. Early adoption is permitted. We will adopt the accounting standard on January 1, 2016. We do not expect the adoption to have a material effect on our consolidated financial statements.     

Item 7A.  Quantitative and Qualitative Disclosures About Market Risk

Information required under Item 7A. has been incorporated into "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Market Risk."

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

84

reporting system is designed to provide reasonable assurance as to the reliability of our financial reporting and the preparation and presentation of consolidated financial statements in accordance with accounting principles generally accepted in the United States, as well as to safeguard assets from unauthorized use or disposition. 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 (2013) 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, 2015 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 24, 2016

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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, 2015 and 2014, and the related consolidated statements of operations, comprehensive (loss) income, and cash flows for each of the years in the three-year period ended December 31, 2015. 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, 2015 and 2014, and the results of their operations and their cash flows for each of the years in the three‑year period ended December 31, 2015, 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, 2015, based on criteria established in Internal Control - Integrated Framework(2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 24, 2016 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

/s/ KPMG LLP

Houston, Texas

February 24, 2016

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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, 2015, based on criteria established in Internal Control - Integrated Framework (2013) 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, 2015, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

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, 2015 and 2014, and the related consolidated statements of operations, comprehensive (loss) income, and cash flows for each of the years in the three-year period ended December 31, 2015, and our report dated February 24, 2016 expressed an unqualified opinion on those consolidated financial statements.

 /s/ KPMG LLP

Houston, Texas

February 24, 2016

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ENSCO PLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(in millions, except per share amounts)

	Year Ended December 31,
	2015			2014			2013
OPERATING REVENUES	$	4,063.4		$	4,564.5		$	4,323.4
OPERATING EXPENSES
Contract drilling (exclusive of depreciation)	1,869.6			2,076.9			1,947.1
Loss on impairment	2,746.4			4,218.7			—
Depreciation	572.5			537.9			496.2
General and administrative	118.4			131.9			146.8
	5,306.9			6,965.4			2,590.1
OPERATING (LOSS) INCOME	(1,243.5		)	(2,400.9		)	1,733.3
OTHER INCOME (EXPENSE)
Interest income	9.9			13.0			16.6
Interest expense, net	(216.3		)	(161.4		)	(158.8		)
Other, net	(21.3		)	.5			42.1
	(227.7		)	(147.9		)	(100.1		)
(LOSS) INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	(1,471.2		)	(2,548.8		)	1,633.2
PROVISION FOR INCOME TAXES
Current income tax expense	144.1			264.0			193.0
Deferred income tax (benefit) expense	(158.0		)	(123.5		)	10.1
	(13.9		)	140.5			203.1
(LOSS) INCOME FROM CONTINUING OPERATIONS	(1,457.3		)	(2,689.3		)	1,430.1
LOSS FROM DISCONTINUED OPERATIONS, NET	(128.6		)	(1,199.2		)	(2.2		)
NET (LOSS) INCOME	(1,585.9		)	(3,888.5		)	1,427.9
NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS	(8.9		)	(14.1		)	(9.7		)
NET (LOSS) INCOME ATTRIBUTABLE TO ENSCO	$	(1,594.8	)	$	(3,902.6	)	$	1,418.2
(LOSS) EARNINGS PER SHARE - BASIC
Continuing operations	$	(6.33	)	$	(11.70	)	$	6.09
Discontinued operations	(0.55		)	(5.18		)	(0.01		)
	$	(6.88	)	$	(16.88	)	$	6.08
(LOSS) EARNINGS PER SHARE - DILUTED
Continuing operations	$	(6.33	)	$	(11.70	)	$	6.08
Discontinued operations	(0.55		)	(5.18		)	(0.01		)
	$	(6.88	)	$	(16.88	)	$	6.07
NET (LOSS) INCOME ATTRIBUTABLE TO ENSCO SHARES - BASIC AND DILUTED	$	(1,596.8	)	$	(3,910.5	)	$	1,403.1
WEIGHTED-AVERAGE SHARES OUTSTANDING
Basic	232.2			231.6			230.9
Diluted	232.2			231.6			231.1
CASH DIVIDENDS PER SHARE	$	0.60		$	3.00		$	2.25

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

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ENSCO PLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE (LOSS) INCOME

(in millions)

	Year Ended December 31,
	2015			2014			2013
NET (LOSS) INCOME	$	(1,585.9	)	$	(3,888.5	)	$	1,427.9
OTHER COMPREHENSIVE (LOSS) INCOME, NET
Net change in fair value of derivatives	(23.6		)	(11.7		)	(5.8		)
Reclassification of net losses (gains) on derivative instruments from other comprehensive income into net income	22.2			(.9		)	2.0
Other	2.0			6.3			1.9
NET OTHER COMPREHENSIVE INCOME (LOSS)	.6			(6.3		)	(1.9		)
COMPREHENSIVE (LOSS) INCOME	(1,585.3		)	(3,894.8		)	1,426.0
COMPREHENSIVE INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS	(8.9		)	(14.1		)	(9.7		)
COMPREHENSIVE (LOSS) INCOME ATTRIBUTABLE TO ENSCO	$	(1,594.2	)	$	(3,908.9	)	$	1,416.3

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

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ENSCO PLC AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in millions, except share and par value amounts)

	December 31,
ASSETS	2015			2014
CURRENT ASSETS
Cash and cash equivalents	$	121.3		$	664.8
Short-term investments	1,180.0			757.3
Accounts receivable, net	582.0			883.3
Other	401.8			585.6
Total current assets	2,285.1			2,891.0
PROPERTY AND EQUIPMENT, AT COST	12,719.4			14,975.5
Less accumulated depreciation	1,631.6			2,440.7
Property and equipment, net	11,087.8			12,534.8
GOODWILL	—			276.1
OTHER ASSETS, NET	264.1			338.9
	$	13,637.0		$	16,040.8
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable - trade	$	224.6		$	373.2
Accrued liabilities and other	550.9			694.1
Current maturities of long-term debt	—			34.8
Total current liabilities	775.5			1,102.1
LONG-TERM DEBT	5,895.1			5,885.6
DEFERRED INCOME TAXES	4.4			162.9
OTHER LIABILITIES	444.8			667.3
COMMITMENTS AND CONTINGENCIES
ENSCO SHAREHOLDERS' EQUITY
Class A ordinary shares, U.S. $.10 par value, 450.0 million shares authorized,        243.1 million and 240.7 million shares issued as of December 31, 2015 and 2014	24.3			24.1
Class B ordinary shares, £1 par value, 50,000 shares authorized and issued        as of December 31, 2015 and 2014	.1			.1
Additional paid-in capital	5,554.5			5,517.5
Retained earnings	985.3			2,720.4
Accumulated other comprehensive income	12.5			11.9
Treasury shares, at cost, 7.8 million shares and 6.5 million shares as of December 31, 2015 and 2014	(63.8		)	(59.0		)
Total Ensco shareholders' equity	6,512.9			8,215.0
NONCONTROLLING INTERESTS	4.3			7.9
Total equity	6,517.2			8,222.9
	$	13,637.0		$	16,040.8

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

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ENSCO PLC AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (in millions)
	Year Ended December 31,
	2015			2014			2013
OPERATING ACTIVITIES
Net (loss) income	$	(1,585.9	)	$	(3,888.5	)	$	1,427.9
Adjustments to reconcile net (loss) income to net cash provided by operating activities of continuing operations:
Loss on impairment	2,746.4			4,218.7			—
Depreciation expense	572.5			537.9			496.2
Deferred income tax (benefit) expense	(158.0		)	(123.5		)	10.1
Loss from discontinued operations, net	128.6			1,199.2			2.2
Share-based compensation expense	40.2			45.1			50.3
Loss on extinguishment of debt	33.5			—			—
Bad debt expense	24.1			(5.0		)	11.7
Amortization of intangibles and other, net	(1.4		)	(7.9		)	(28.4		)
Other	(18.1		)	(11.4		)	(7.7		)
Changes in operating assets and liabilities	(84.0		)	93.3			(151.1		)
Net cash provided by operating activities of continuing operations	1,697.9			2,057.9			1,811.2
INVESTING ACTIVITIES
Purchases of short-term investments	(1,780.0		)	(790.6		)	(50.0		)
Additions to property and equipment	(1,619.5		)	(1,566.7		)	(1,763.5		)
Maturities of short-term investments	1,357.3			83.3			50.0
Net proceeds from disposition of assets	1.6			169.2			6.0
Net cash used in investing activities of continuing operations	(2,040.6		)	(2,104.8		)	(1,757.5		)
FINANCING ACTIVITIES
Proceeds from issuance of senior notes	1,078.7			1,246.4			—
Reduction of long-term borrowings	(1,072.5		)	(60.1		)	(47.5		)
Cash dividends paid	(141.2		)	(703.0		)	(525.6		)
Premium paid on redemption of debt	(30.3		)	—			—
Debt financing costs	(10.5		)	(13.4		)	(4.6		)
Proceeds from exercise of share options	.3			2.6			22.3
Other	(16.3		)	(29.8		)	(21.7		)
Net cash (used in) provided by financing activities	(191.8		)	442.7			(577.1		)
DISCONTINUED OPERATIONS
Operating activities	(10.9		)	(3.8		)	169.3
Investing activities	2.2			107.2			32.8
Net cash (used in) provided by discontinued operations	(8.7		)	103.4			202.1
Effect of exchange rate changes on cash and cash equivalents	(.3		)	—			(.2		)
(DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS	(543.5		)	499.2			(321.5		)
CASH AND CASH EQUIVALENTS, BEGINNING OF YEAR	664.8			165.6			487.1
CASH AND CASH EQUIVALENTS, END OF YEAR	$	121.3		$	664.8		$	165.6

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

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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 and operate an offshore drilling rig fleet of 64 rigs spanning most of the strategic markets around the globe. Our rig fleet includes ten drillships, 13 dynamically positioned semisubmersible rigs, three moored semisubmersible rigs and 42 jackup rigs, including four rigs under construction.  Our fleet is the world's second largest amongst competitive rigs, our ultra-deepwater fleet is one of the newest in the industry, and our premium jackup fleet is the largest of any offshore drilling company.

Our customers include many 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 spanning approximately 15 countries on six continents. 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.

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 each day we are performing drilling or related services. Our customers bear substantially all of the 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.

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").

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 continue to report our consolidated financial results in U.S. dollars and in accordance with U.S. generally accepted accounting principles ("U.S. GAAP"). We also 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 U.S. GAAP, which the Board of 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 will be prepared in accordance with Financial Reporting Standard 102 The Financial Reporting Standard applicable in the UK and Republic of Ireland (“FRS 102”) as issued in August 2014. An explanation of how the transition to FRS 102 has affected financial position and financial performance of the Group will be provided in those statements, which will be 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.

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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 U.S. GAAP requires us 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 operations.  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.  Net foreign currency exchange gains and losses, inclusive of offsetting fair value derivatives, were $5.4 million of gains, $2.6 million of losses and $6.4 million of gains, and were included in other, net, in our consolidated statements of operations for the years ended December 31, 2015, 2014 and 2013, 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 $1.2 billion and $757.3 million as of December 31, 2015 and 2014, respectively. 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, 2015, 2014 and 2013. To mitigate our credit risk, our investments in time deposits are diversified across multiple, high-quality financial institutions.

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 are incurred. 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 twoto 30 years. Other equipment, including computer and communications hardware and software costs, is depreciated over estimated useful lives ranging from three to six years.

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On December 31, 2015, we evaluated our current judgments and assumptions used in determining the useful lives of our drilling rigs. We considered both historical experience and expectations of future operations, utilization and performance of our assets based on recent changes in the current market environment. As a result, we reduced the useful lives of certain floaters and jackups effective January 1, 2016. We estimate this reduction in useful lives will increase depreciation expense by approximately $20.0 million for the year ended December 31, 2016.

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.

During 2015, we recorded a pre-tax, non cash loss on impairment of long-lived assets of $2.6 billion, of which $2.5 billion related to our long-lived assets held-for-use. See "Note 3 - Property and Equipment" for additional information on these impairments. We estimate the impairment charge on our held-for-use assets will cause a decline in depreciation expense of approximately $170 million for the year ended December 31, 2016.

If the global economy deteriorates and/or our expectation relative to future offshore drilling industry conditions decline, it is reasonably possible that additional 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

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, represent our reporting units.

We test goodwill for impairment on an annual basis as of December 31 or when events or changes in circumstances indicate that a potential impairment exists.  When testing goodwill for impairment, we first consider whether or not to assess qualitative factors to determine whether the existence of events or circumstances lead to a determination that 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, or, alternatively, if we elect to forgo the qualitative assessment, 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 the drilling rigs in the reporting unit.

As of December 31, 2015, given the deterioration in forecasted day rates and utilization, the sustained decline in our stock price and the impairment charge on certain rigs during the fourth quarter, we elected to forgo the qualitative assessment and performed a quantitative assessment on both reporting units. As a result of the quantitative assessment, we concluded that our Floater and Jackup reporting units' goodwill balances were impaired. We recorded a non-cash loss on impairment of $192.6 million and $83.5 million for the Jackups and Floaters reporting units, respectively, which was included in loss on impairment in our consolidated statement of operations for the year ended December 31, 2015. There is no remaining goodwill on our consolidated balance sheet as of December 31, 2015. See "Note 8 - Goodwill and Other Intangible Assets and Liabilities" for additional information on our goodwill.

Operating Revenues and Expenses

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.

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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 $77.0 million and $95.7 million as of December 31, 2015 and 2014, respectively. Deferred mobilization revenue was included in accrued liabilities and other, and other liabilities on our consolidated balance sheets and totaled $111.8 million and $149.4 million as of December 31, 2015 and 2014, 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, and the cost 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 $287.2 million and $428.9 million as of December 31, 2015 and 2014, respectively.

We may receive termination fees if certain drilling contracts are terminated by the customer prior to the end of the contractual term. Such compensation is recognized as revenues when services have been completed under the terms of the contract, the termination fee can be reasonably measured and collectability is reasonably assured.

For the year ended December 31, 2015, operating revenues included $110.6 million for the ENSCO DS-4 lump sum termination fee, which we collected in October, as well as $98.3 million related to the ENSCO DS-9 termination, which included an $18.4 million lump-sum fee for mobilization, capital upgrades and day rate revenue earned during initial acceptance testing. Under the terms of the ENSCO DS-9 contract, our customer is obligated to pay us monthly termination fees for a period of two years equal to the operating day rate (approximately $550,000), which will be reduced pursuant to our obligation to mitigate idle rig costs, such as manning and maintenance activity, while the rig is idle and without a contract. We are in discussions with our customer on the amount of this reduction.  The day rate may also be adjusted if we recontract the rig.

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 $21.2 million and $20.0 million as of December 31, 2015 and 2014, 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 operations.

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Derivative Instruments

We use derivatives to reduce our exposure to various market risks, primarily foreign currency exchange rate risk. See "Note 5 - 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 operations based on the change in the fair value of the derivative. When a forecasted transaction is probable of not 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 operations.

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, a natural hedging relationship generally exists 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 operations.

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.

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Interest and penalties relating to income taxes are included in current income tax expense in our consolidated statement of operations.

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 9 - 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 operations 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 7 - 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 2 - 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 (loss) 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 includes the effect of all potentially dilutive performance awards and excludes non-vested shares.

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The following table is a reconciliation of (loss) income from continuing operations 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, 2015 (in millions):

	2015			2014			2013
(Loss) income from continuing operations attributable to Ensco	$	(1,466.1	)	$	(2,703.1	)	$	1,421.6
Income from continuing operations allocated to non-vested share awards	(2.0		)	(7.9		)	(15.1		)
(Loss) income from continuing operations attributable to Ensco shares	$	(1,468.1	)	$	(2,711.0	)	$	1,406.5

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, 2015 (in millions):

	2015	2014	2013
Weighted-average shares - basic	232.2	231.6	230.9
Potentially dilutive shares	—	—	.2
Weighted-average shares - diluted	232.2	231.6	231.1

Antidilutive share options totaling 800,000, 400,000 and 300,000 for the years ended December 31, 2015, 2014 and 2013, respectively, 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 operations. 

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Loss (income) from continuing operations attributable to Ensco for each of the years in the three-year period ended December 31, 2015 was as follows (in millions):

	2015			2014			2013
(Loss) income from continuing operations	$	(1,457.3	)	$	(2,689.3	)	$	1,430.1
Income from continuing operations attributable to noncontrolling interests	(8.8		)	(13.8		)	(8.5		)
(Loss) income from continuing operations attributable to Ensco	$	(1,466.1	)	$	(2,703.1	)	$	1,421.6

Loss from discontinued operations attributable to Ensco for each of the years in the three-year period ended December 31, 2015 was as follows (in millions):

	2015			2014			2013
Loss from discontinued operations	$	(128.6	)	$	(1,199.2	)	$	(2.2	)
Income from discontinued operations attributable to noncontrolling interests	(.1		)	(.3		)	(1.2		)
Loss from discontinued operations attributable to Ensco	$	(128.7	)	$	(1,199.5	)	$	(3.4	)

New Accounting Pronouncements

In November 2015, the Financial Accounting Standards Board issued Accounting Standards Update 2015-17, Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes, which requires that deferred tax assets and liabilities be classified as noncurrent on the balance sheet. This update is effective for annual and interim periods beginning after December 15, 2016. Early adoption is permitted for all entities as of the beginning of an interim or annual reporting period. This update may be applied either prospectively to all deferred tax assets and liabilities or retrospectively to all periods presented. We elected to early adopt this update on a retrospective basis effective December 31, 2015. Accordingly, all current deferred tax assets and liabilities were reclassified to noncurrent on the balance sheet for all periods presented. As a result of adopting this update retrospectively, we reclassified current deferred tax assets and liabilities of $43.8 million and $2.5 million, respectively, on our consolidated balance sheet as of December 31, 2014.

In April 2015, the Financial Accounting Standards Board issued Accounting Standards Update 2015-03, Interest - Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs, as updated by Update 2015-15, Interest - Imputation of Interest (Subtopic 835-30): Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements - Amendments to SEC Paragraphs Pursuant to Staff Announcements at June 18, 2015 EITF Meeting, which require that debt issuance costs related to a recognized debt liability be presented on the balance sheet as a direct deduction from the carrying amount of the related debt liability, consistent with debt discounts. Debt issuance costs related to line-of-credit arrangements may be presented as an asset regardless of whether there are any outstanding borrowings on the arrangement. These updates are effective for annual and interim periods for fiscal years beginning after December 15, 2015. Early application is permitted. We will adopt these accounting standards on a retrospective basis effective January 1, 2016. There will be no impact to the manner in which debt issuance costs are amortized on our consolidated financial statements.

In May 2014, the Financial Accounting Standards Board issued Accounting Standards Update 2014-09, Revenue from Contracts with Customers (Topic 606) ("Update 2014-09"), which requires an entity to recognize the amount of revenue to which it expects to be entitled for the transfer of promised goods or services to customers. In July 2015, the Financial Accounting Standards Board voted to delay the effective date one year. Update 2014-09 is now effective for annual and interim periods for fiscal years beginning after December 15, 2017, though companies have an option of adopting the standard for fiscal years beginning after December 15, 2016. Update 2014-09 will replace most existing revenue recognition guidance in U.S. GAAP and may be adopted using a retrospective, modified

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retrospective or cumulative effect approach. We are currently evaluating the effect that Update 2014-09 will have on our consolidated financial statements and related disclosures.

In April 2014, the Financial Accounting Standards Board issued Accounting Standards Update 2014-08, Presentation of Financial Statements (Topic 205) and Property, Plant, and Equipment (Topic 360): Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity ("Update 2014-08"). The new guidance changes the criteria for reporting discontinued operations and enhances disclosure requirements. Under the new guidance, only disposals representing a strategic shift in operations should be presented as discontinued operations. We adopted Update 2014-08 effective January 1, 2015. Our adoption will generally reduce the number of rig disposals reported as discontinued operations since only rig disposals representing a strategic shift in operations will be reported as discontinued operations prospectively in our condensed consolidated financial statements. Operating results related to rigs classified as held-for-sale prior to the adoption of Update 2014-08 will continue to be reported as discontinued operations.   

2.  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, 2015 and 2014 (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, 2015
Supplemental executive retirement plan assets	$	33.1	$	—		$	—	$	33.1
Total financial assets	33.1		—			—		33.1
Derivatives, net	—		(19.7		)	—		(19.7		)
Total financial liabilities	$	—	$	(19.7	)	$	—	$	(19.7	)
As of December 31, 2014
Supplemental executive retirement plan assets	$	43.2	$	—		$	—	$	43.2
Total financial assets	43.2		—			—		43.2
Derivatives, net	—		(26.3		)	—		(26.3		)
Total financial liabilities	$	—	$	(26.3	)	$	—	$	(26.3	)

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, 2015 and 2014.  The fair value measurements of assets held in the SERP were based on quoted market prices. Net unrealized gains of $700,000, $2.3 million and $6.2 million from marketable securities held in our SERP were included in other, net, in our consolidated statements of operations for the years ended December 31, 2015, 2014 and 2013, respectively.

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Derivatives

Our derivatives were measured at fair value on a recurring basis using Level 2 inputs as of December 31, 2015 and 2014.  See "Note 5 - 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, 2015 and 2014 were as follows (in millions):

	December 31, 2015				December 31, 2014
	Carrying Value		Estimated   Fair Value		Carrying Value		Estimated   Fair Value
4.70% Senior notes due 2021	$	1,482.7	$	1,254.0	$	1,479.9	$	1,505.3
5.75% Senior notes due 2044	1,004.2		707.1		622.3		615.8
6.875% Senior notes due 2020	990.9		850.5		1,008.2		1,008.5
5.20% Senior notes due 2025	697.6		505.2		—		—
4.50% Senior notes due 2024	624.3		417.4		624.2		602.0
8.50% Senior notes due 2019	566.4		510.2		583.8		611.8
7.875% Senior notes due 2040	379.8		244.0		381.2		363.8
7.20% Debentures due 2027	149.2		133.5		149.2		171.4
3.25% Senior notes due 2016	—		—		998.0		1,018.3
4.33% MARAD bonds due 2016	—		—		46.6		46.8
4.65% MARAD bonds due 2020	—		—		27.0		29.7
Total	$	5,895.1	$	4,621.9	$	5,920.4	$	5,973.4

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, 2015 and 2014.

See "Note 3 - Property and Equipment" for additional information on the fair value measurement of property and equipment and "Note 8 - Goodwill and Other Intangible Assets and Liabilities" for additional information on the fair value measurement of goodwill.

3.  PROPERTY AND EQUIPMENT

Property and equipment as of December 31, 2015 and 2014 consisted of the following (in millions):

	2015		2014
Drilling rigs and equipment	$	11,001.8	$	13,253.2
Other	180.0		135.0
Work in progress	1,537.6		1,587.3
	$	12,719.4	$	14,975.5

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During 2015, drilling rigs and equipment declined$2.3 billion primarily due to a loss on impairment of $2.6 billion and depreciation expense of $572.5 million. These declines were partially offset by ENSCO DS-8 and ENSCO 110, which were placed into service during 2015, and capital upgrades to the existing rig fleet.

Work in progress as of December 31, 2015 primarily consisted of $1.1 billion related to the construction of ultra deepwater drillships ENSCO DS-9 and ENSCO DS-10, $259.8 million related to the construction of ENSCO 140 and ENSCO 141 premium jackups rigs and $71.1 million related to the construction of ENSCO 123, an ultra-premium harsh environment jackup rig. ENSCO DS-9 has been delivered but has not been placed into service.

Work in progress as of December 31, 2014 primarily consisted of $820.1 million related to the construction of ENSCO DS-8, ENSCO DS-9 and ENSCO DS-10 ultra-deepwater drillships, $233.1 million related to a capital enhancement project on ENSCO 5006, $179.3 million related to the construction of ENSCO 110, ENSCO 140 and ENSCO 141 premium jackup rigs, $59.2 million related to the construction of ENSCO 123 ultra-premium harsh environment jackup rig and costs associated with various modification and enhancement projects.

Impairment of Long-Lived Assets

Year Ended December 31, 2015 - During 2015, we recorded a pre-tax, non-cash loss on impairment of long-lived assets of $2,618.9 million, of which $2,470.3 million was included in (loss) income from continuing operations and $148.6 million was included in loss from discontinued operations, net in our consolidated statement of operations.

Assets held-for-sale

We continually assess our rig portfolio and actively work with our rig broker to market certain rigs that no longer meet our standards for economic returns or are not part of our long-term strategic plan. On a quarterly basis, we assess whether any rig meets the criteria established by Financial Accounting Standards Board 360-10-45 for held-for-sale classification on our balance sheet. All rigs classified as held-for-sale are recorded at fair value, less costs to sell. We measure the fair value of our assets held-for-sale by applying a market approach based on unobservable third-party estimated prices that would be received in exchange for the assets in an orderly transaction between market participants. We reassess the fair value of our held-for-sale assets on a quarterly basis and adjust the carrying value, as necessary.

During 2015, we adopted the Financial Accounting Standards Board’s Accounting Standards Update 2014-08, Presentation of Financial Statements (Topic 205) and Property, Plant, and Equipment (Topic 360): Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity ("Update 2014-08"). Under the new guidance, only disposals representing a strategic shift in operations should be presented as discontinued operations. As a result, individual assets that were classified as held-for-sale during 2015 are not reported as discontinued operations. Rigs that were classified as held-for-sale prior to 2015 continue to be reported as discontinued operations.

During the third quarter, we began marketing for sale ENSCO 91, an older, less capable jackup rig that we cold-stacked during the second quarter. We concluded that the rig met the held-for-sale criteria during the third quarter and its carrying value was reduced to fair value, less costs to sell, based on its estimated sales price. We recorded a pre-tax, non-cash loss on impairment totaling $10.0 million, which was included in loss on impairment within income from continuing operations in our consolidated statement of operations for the year ended December 31, 2015.

Also during the third quarter, we concluded that impairments were required on certain held-for-sale rigs as a result of declines in fair value. We recorded a pre-tax, non-cash loss on impairment totaling $25.6 million, which was included in loss from discontinued operations, net, in our consolidated statement of operations for the year ended December 31, 2015.

During the fourth quarter, we concluded that additional impairments were required due to our decision to sell our held-for-sale rigs for scrap value. As a result, we recognized a pre-tax, non-cash loss on impairment of $115.8

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million, which was included in loss from discontinued operations, net, in our consolidated statement of operations for the year ended December 31, 2015. See “Note 10 - Discontinued Operations” for additional information on rigs classified as held-for-sale and presented in discontinued operations.

Our six held-for-sale rigs have a remaining aggregate carrying value of $5.5 million and are included in other assets, net, on our consolidated balance sheet as of December 31, 2015.

Assets held-for-use

On a quarterly basis, we evaluate the carrying value of our property and equipment to identify events or changes in circumstances ("triggering events") that indicate the carrying value may not be recoverable.

During the fourth quarter, commodity prices declined with Brent crude oil prices trading around $35 per barrel as of December 31, 2015. Commodity prices continued to decline further into 2016, and Brent crude oil prices reached a ten-year low of approximately $26 per barrel in January 2016. These prices resulted in significant capital spending reductions by our customers, causing a decline in day rates for the few contracts executed during the fourth quarter. Customers have delayed drilling programs and are exploring subletting opportunities for contracted rigs thereby exacerbating supply pressure. In addition, certain customers are requesting contract concessions or terminating drilling contracts. Customers are expected to continue to operate under reduced budgets until we see a meaningful recovery in commodity prices. The significant supply and demand imbalance will continue to be adversely impacted by future newbuild deliveries, program delays and lower capital spending by operators. These adverse changes resulted in further deterioration in our forecasted day rates and utilization during the fourth quarter. As a result, we concluded that a triggering event had occurred.

Based on the asset impairment analysis performed as of December 31, 2015, we recorded a pre-tax, non-cash loss on impairment with respect to certain floaters and jackups totaling $2,460.3 million. The impairment charge was included in loss on impairment in our consolidated statement of operations for the year ended December 31, 2015. We measured the fair value of these rigs by applying either an income approach, using projected discounted cash flows, or a market approach. These valuations were based on unobservable inputs that require significant judgments for which there is limited information, including assumptions regarding future day rates, utilization, operating costs and capital requirements.

In instances where we applied an income approach, forecasted day rates and utilization take into account current market conditions and our anticipated business outlook, both of which have been impacted by the adverse changes in the business environment observed during the fourth quarter. The day rates reflect contracted rates during the respective contracted periods and our estimate of market day rates in uncontracted periods. The forecasted market day rates were depressed in the near-term but were forecasted to grow in the longer-term and terminal period. Operating costs were forecasted using a combination of our historical average operating costs and expected future costs, adjusted for an estimated inflation factor. Capital requirements were based on our estimates of future capital costs, taking into consideration our historical trends. The estimated capital requirements included cash outflows to maintain the current operating condition of our rigs through their remaining useful lives.

In instances where we applied a market approach, the fair value was based on unobservable third-party estimated prices that would be received in exchange for the assets in an orderly transaction between market participants. We validated all third-party estimated prices using our forecasts of economic returns for the respective rigs or other market data.

If the global economy, our overall business outlook, and/or our expectations regarding the marketability of one or more of our drilling rigs deteriorate further, we may conclude that a triggering event has occurred and perform a recoverability test that could lead to a material impairment charge in future periods.

Year Ended December 31, 2014 - During 2014, we recorded a pre-tax, non-cash loss on impairment of long-lived assets of $2,463.1 million, of which $1,220.8 million was included in (loss) income from continuing operations

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and $1,242.3 million was included in loss from discontinued operations, net, in our consolidated statement of operations. These losses were recorded during the second and fourth quarters of 2014.

During the second quarter of 2014, demand for floaters deteriorated as a result of continued reductions in capital spending by operators in addition to delays in operators’ drilling programs. The reduction in demand, combined with the increasing supply from newbuild floater deliveries, led to a very competitive market. In general, contracting activity declined significantly, and day rates and utilization came under pressure, especially for older, less capable floaters.

In response to the adverse change in the floaters business climate, we evaluated our older, less capable floaters and committed to a plan to sell five rigs. ENSCO 5000, ENSCO 5001, ENSCO 5002, ENSCO 6000 and ENSCO 7500 were removed from our portfolio of rigs marketed for contract drilling services and classified as held-for-sale. These rigs were written down to fair value, less costs to sell. We recorded a pre-tax, non-cash loss on impairment totaling $546.4 million during the second quarter associated with these rigs. The impairment charge was included in loss from discontinued operations, net, in our consolidated statement of operations for the year ended December 31, 2014.

Also during the second quarter of 2014, as a result of the adverse change in the floater business climate, our decision to sell five floaters and the impairment charge incurred on the held-for-sale floaters, we concluded that a triggering event had occurred and performed an asset impairment analysis on our remaining older, less capable floaters.

Based on the analysis performed as of May 31, 2014, we recorded an additional pre-tax, non-cash loss on impairment with respect to four other floaters totaling $991.5 million, of which $288.0 million related to ENSCO DS-2 that was removed from our portfolio of rigs marketed for contract drilling services during the fourth quarter of 2014. The ENSCO DS-2 impairment charge was reclassified to loss from discontinued operations, net, in our consolidated statement of operations for the year ended December 31, 2014. The remaining $703.5 million impairment charge was included in loss on impairment in our consolidated statement of operations for the year ended December 31, 2014. We measured the fair value of these rigs by applying an income approach, using projected discounted cash flows. These valuations were based on unobservable inputs that require significant judgments for which there is limited information, including assumptions regarding future day rates, utilization, operating costs and capital requirements.

During the fourth quarter of 2014, Brent crude oil prices declined from approximately $95 per barrel to near $55 per barrel on December 31, 2014. These declines resulted in further reductions in capital spending by operators, including the cancellation or deferral of planned drilling programs. As a result, day rates and utilization came under further pressure, especially for older, less capable rigs.

In response to the adverse change in business climate, we evaluated our aged rigs and committed to a plan to sell one additional floater and two jackups. ENSCO DS-2, ENSCO 58 and ENSCO 90 were removed from our portfolio of rigs marketed for contract drilling services. These rigs were written down to fair value, less costs to sell. In addition to the asset impairment recorded during the second quarter, we recorded an additional pre-tax, non-cash loss on impairment totaling $407.9 million during the fourth quarter on our held-for-sale rigs. The impairment charge was included in loss from discontinued operations, net, in our consolidated statement of operations for the year ended December 31, 2014.

Also during the fourth quarter of 2014, as a result of the decline in commodity prices and adverse changes in the offshore drilling market, our decision to sell an additional floater and two jackups and the impairment charge incurred on the held-for-sale rigs, we concluded that a triggering event had occurred and performed an asset impairment analysis for all floaters and jackups.

Based on the analysis performed as of December 31, 2014, we recorded an additional pre-tax, non-cash loss on impairment with respect to two older, less capable floaters and ten older, less capable jackups totaling $517.3 million. The impairment charge was included in loss on impairment in our consolidated statement of operations for the year ended December 31, 2014. We measured the fair value of these rigs by applying either an income approach,

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using projected discounted cash flows, or a market approach. These valuations were based on unobservable inputs that require significant judgments for which there is limited information, including assumptions regarding future day rates, utilization, operating costs and capital requirements.  In instances where we applied a market approach, the fair value was based on unobservable third-party estimated prices that would be received in exchange for the assets in an orderly transaction between market participants. We validated all third-party estimated prices using our forecasts of economic returns for the respective rigs.

4.  DEBT

The carrying value of long-term debt as of December 31, 2015 and 2014 consisted of the following (in millions):

	2015		2014
4.70% Senior notes due 2021	$	1,482.7	$	1,479.9
5.75% Senior notes due 2044	1,004.2		622.3
6.875% Senior notes due 2020	990.9		1,008.2
5.20% Senior notes due 2025	697.6		—
4.50% Senior notes due 2024	624.3		624.2
8.50% Senior notes due 2019	566.4		583.8
7.875% Senior notes due 2040	379.8		381.2
7.20% Debentures due 2027	149.2		149.2
3.25% Senior notes due 2016	—		998.0
4.33% MARAD bonds due 2016	—		46.6
4.65% MARAD bonds due 2020	—		27.0
Total debt	5,895.1		5,920.4
Less current maturities	—		(34.8		)
Total long-term debt	$	5,895.1	$	5,885.6

 Senior Notes

During the first quarter, we issued $700.0 million aggregate principal amount of unsecured 5.20% senior notes due 2025 (the “2025 Notes”) at a discount of $2.6 million and $400.0 million aggregate principal amount of unsecured 5.75% senior notes due 2044 (the “New 2044 Notes”) at a discount of $18.7 million in a public offering. Interest on the 2025 Notes is payable semiannually on March 15 and September 15 of each year commencing September 15, 2015. Interest on the New 2044 Notes is payable semiannually on April 1 and October 1 of each year commencing on April 1, 2015.

During 2014, we issued $625.0 million aggregate principal amount of unsecured 4.50% senior notes due 2024 (the "2024 Notes") at a discount of $850,000 and $625.0 million aggregate principal amount of unsecured 5.75% senior notes due 2044 (the "Existing 2044 Notes" and together with the New 2044 Notes, the "2044 Notes") at a discount of $2.8 million. Interest on the 2024 Notes and the Existing 2044 Notes is payable semiannually on April 1 and October 1 of each year commencing on April 1, 2015. The Existing 2044 Notes and the New 2044 Notes are treated as a single series of debt securities under the indenture governing the notes (the "2044 Notes").

During 2011, we issued $1.5 billion aggregate principal amount of unsecured 4.70% senior notes due 2021 (the “2021 Notes”) at a discount of $29.6 million in a public offering. Interest on the 2021 Notes is payable semiannually on March 15 and September 15 of each year.

Upon consummation of the Pride acquisition during 2011, we assumed the acquired company's outstanding debt comprised of $900.0 million aggregate principal amount of unsecured 6.875% senior notes due 2020, $500.0

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million aggregate principal amount of unsecured 8.5% senior notes due 2019 and $300.0 million aggregate principal amount of unsecured 7.875% senior notes due 2040 (collectively, the "Acquired Notes" and together with the 2021 Notes, 2024 Notes, 2025 Notes and 2044 Notes, the "Senior Notes").  Ensco plc has fully and unconditionally guaranteed the performance of all Pride obligations with respect to the Acquired Notes.  See "Note 15 - Guarantee of Registered Securities" for additional information on the guarantee of the Acquired Notes. 

We may redeem the 2024 Notes, 2025 Notes and 2044 Notes in whole, at any time or in part from time to time, prior to maturity. If we elect to redeem the 2024 Notes and 2025 Notes before the date that is three months prior to the maturity date or the 2044 Notes before the date that is six months prior to the maturity date, we will pay an amount equal to 100% of the principal amount of the notes redeemed plus accrued and unpaid interest and a "make-whole" premium. If we elect to redeem the 2024 Notes, 2025 Notes or 2044 Notes on or after the aforementioned dates, we will pay an amount equal to 100% of the principal amount of the notes redeemed plus accrued and unpaid interest but we are not required to pay a "make-whole" premium.

We may redeem each series of the 2021 Notes and the 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 the Senior Notes contain customary events of default, including failure to pay principal or interest on such notes when due, among others. The indentures governing the Senior 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.

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 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 and the indenture pursuant to which the Debentures were issued also contain customary events of default, including failure to pay principal or interest on the Debentures when due, among others. The indenture also 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.

Redemption of 2016 Senior Notes and MARAD Obligations

During 2011, we issued $1.0 billion of 3.25% senior notes due 2016 (the “2016 Notes”). In March 2015, we commenced a cash tender offer (the “Tender Offer”) for the 2016 Notes. Tendered notes totaling $854.6 million were settled on March 12, 2015 for $878.0 million (excluding accrued interest) using a portion of the net proceeds from the issuance of the 2025 Notes and New 2044 Notes. Under the terms of the Tender Offer, we paid a premium totaling approximately $23.4 million, which approximates the “make-whole” premium that would have been required had we elected to redeem the debt. Additionally, we recorded charges of $1.7 million for unamortized debt discounts and $1.5 million for unamortized debt issuance costs, resulting in a total pre-tax loss on debt extinguishment of $26.6 million included in other, net, in our consolidated statement of operations for the year ended December 31, 2015.

Concurrent with the settlement of the Tender Offer, we exercised our right to redeem the remaining 2016 Notes. In April 2015, we completed the redemption of the remaining $145.4 million of 2016 Notes using a portion of the net proceeds from the 2025 Notes and New 2044 Notes. The redemption payment included a "make-whole" premium of $3.8 million which was recorded as a loss on debt extinguishment and included in other, net, in our consolidated statement of operations for the year ended December 31, 2015.

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In April 2015, we used the remaining net proceeds from the 2025 Notes and New 2044 Notes, together with cash on hand, to redeem $51.0 million of our 4.33% MARAD notes due 2016 and 4.65% MARAD bonds due 2020 (the “MARAD Obligations”). We incurred additional losses on debt extinguishment of $3.1 million, which were included in other, net, in our consolidated statement of operations for the year ended December 31, 2015. These losses primarily consisted of a "make-whole" premium.

In July 2015, we redeemed the remaining $14.3 million aggregate principal amount of the MARAD Obligations.

Commercial Paper

We participate in a commercial paper program with three 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 $2.25 billion. Amounts issued under the commercial paper program are supported by the available and unused committed capacity under our credit facility. As a result, amounts issued under the commercial paper program are limited by the amount of our available and unused committed capacity under our credit facility. The proceeds of such financings may be used for capital expenditures and other general corporate purposes. The commercial paper bears interest at rates that vary based on market conditions and the ratings assigned by credit rating agencies at the time of issuance. If we are downgraded below investment grade by one or more credit rating agencies, we may have limited or no access to the commercial paper market. The weighted-average interest rate on our commercial paper borrowings was 0.41% and 0.26% during 2015 and 2014, respectively.  Commercial paper maturities 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, 2015 and 2014.

Revolving Credit

We have a $2.25 billion senior unsecured revolving credit facility with a syndicate of banks to be used for general corporate purposes with a term expiring on September 30, 2019 (the "Credit Facility").

Advances under the Credit Facility bear interest at Base Rate or LIBOR plus an applicable margin rate, depending on our credit ratings. We are required to pay a quarterly commitment fee on the undrawn portion of the $2.25 billion commitment, which is also based on our credit ratings.

During the fourth quarter, Moody's and Standard & Poor's downgraded our senior unsecured rating one notch to Baa2 and BBB, respectively. As a result, the applicable margin rate for advances under our Credit Facility and the quarterly commitment fee percentage increased by 0.125% per annum and 0.025% per annum, respectively, under our Credit Facility. Currently, the applicable margin rates are 0.25% per annum for Base Rate advances and 1.25% per annum for LIBOR advances. Also, our quarterly commitment fee is 0.15% per annum on the undrawn portion of the $2.25 billion commitment. Amounts repaid may be re-borrowed during the term of the Credit Facility. There can be no assurance that ratings agencies will not further downgrade our credit ratings, and any such further downgrade, or the perceived risk of further downgrades, may limit our ability to access debt capital markets, restructure or refinance our debt, result in higher borrowing costs or require more restrictive terms and covenants, which may further restrict our operations.

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The Credit Facility requires us to maintain a total debt to total capitalization ratio that is less than or equal to a specified percentage. In March 2015, we amended the Credit Facility to increase the percentage from 50% to 60%. The Credit Facility also contains customary restrictive covenants, including, among others, prohibitions on creating, incurring or assuming certain debt and liens; entering into certain merger arrangements; selling, leasing, transferring or otherwise disposing of all or substantially all of our assets; making a material change in the nature of the business; and entering into certain transactions with affiliates. We have the right, subject to receipt of commitments from lenders, to increase the commitments under the Credit Agreement to an aggregate amount of up to $2.75 billion and to extend the term of the Credit Agreement by one year on up to two occasions.

As of December 31, 2015, we were in compliance in all material respects with our covenants under the Credit Facility. We expect to remain in compliance with our Credit Facility covenants during 2016. We had no amounts outstanding under the Credit Facility as of December 31, 2015and 2014.

Maturities

The aggregate maturities of our debt, excluding net unamortized premiums of $195.1 million, as of December 31, 2015 were as follows (in millions):

2016	$	—
2017	—
2018	—
2019	500.0
2020	900.0
Thereafter	4,300.0
Total	$	5,700.0

Interest expense totaled $216.3 million, $161.4 million and $158.8 million for the years ended December 31, 2015, 2014 and 2013, respectively, which was net of interest amounts capitalized of $87.4 million, $78.2 million and $67.7 million in connection with newbuild rig construction and other capital projects.  

5.  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 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 2 - Fair Value Measurements" for additional information on the fair value measurement of our derivatives.

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As of December 31, 2015 and 2014, our consolidated balance sheets included net foreign currency derivative liabilities of $19.7 million and $26.3 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, 2015 and 2014 consisted of the following (in millions):

	Derivative Assets				Derivative Liabilities
	2015		2014		2015		2014
Derivatives Designated as Hedging Instruments
Foreign currency forward contracts - current(1)	$	.6	$	.4	$	20.7	$	17.2
Foreign currency forward contracts - non-current(2)	.2		.1		1.5		2.9
	.8		.5		22.2		20.1
Derivatives not Designated as Hedging Instruments
Foreign currency forward contracts - current(1)	2.6		.2		.9		6.9
	2.6		.2		.9		6.9
Total	$	3.4	$	.7	$	23.1	$	27.0

⁽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, 2015, we had cash flow hedges outstanding to exchange an aggregate $311.6 million for various foreign currencies, including $152.3 million for British pounds, $57.8 million for Brazilian reais, $37.9 million for Australian dollars, $34.1 million for Euros, $13.2 million for Singapore dollars and $16.3 million for other currencies.

Gains and losses, net of tax, on derivatives designated as cash flow hedges included in our consolidated statements of operations and comprehensive income for each of the years in the three-year period ended December 31, 2015 were as follows (in millions):

	Loss Recognized in Other Comprehensive Income ("OCI") on Derivatives   (Effective Portion)									(Loss) Gain Reclassified from  AOCI into Income (Effective Portion)(1)									Loss Recognized in Income on Derivatives (Ineffective Portion and Amount Excluded from Effectiveness Testing)(2)
	2015			2014			2013			2015			2014			2013			2015			2014			2013
Interest rate lock contracts(3)	$	—		$	—		$	—		$	(.6	)	$	(.4	)	$	(.4	)	$	—		$	—		$	—
Foreign currency forward contracts(4)	(23.6		)	(11.7		)	(5.8		)	(21.6		)	1.3			(1.6		)	(.1		)	(.7		)	(.3		)
Total	$	(23.6	)	$	(11.7	)	$	(5.8	)	$	(22.2	)	$	.9		$	(2.0	)	$	(.1	)	$	(.7	)	$	(.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.

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⁽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 operations.

⁽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 operations.

⁽⁴⁾  During the year ended December 31, 2015, $22.5 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 operations. During the year ended December 31, 2014, $400,000 of gains 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 operations. During the year ended December 31, 2013, $2.5 million of losses were reclassified from AOCI into contract drilling and $900,000 of gains were reclassified from AOCI into depreciation expense in our consolidated statement of operations.

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, 2015, we held derivatives not designated as hedging instruments to exchange an aggregate $125.7 million for various foreign currencies, including $73.8 million for Euros, $16.6 million for Swiss francs, $11.1 million for British pounds, $8.7 million for Mexican Pesos, $7.8 million for Australian dollars and $7.7 million for other currencies.

Net losses of $17.3 million and $24.8 million and net gains of $3.6 million associated with our derivatives not designated as hedging instruments were included in other, net, in our consolidated statements of operations for the years ended December 31, 2015, 2014 and 2013, respectively.

As of December 31, 2015, 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	$	(11.2	)
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	$	(10.7	)

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6.  SHAREHOLDERS' EQUITY

Activity in our various shareholders' equity accounts for each of the years in the three-year period ended December 31, 2015 was as follows (in millions):

	Shares	Par Value		Additional Paid-in Capital			Retained Earnings			AOCI			Treasury Shares			Noncontrolling Interest
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
Dividends paid	—	—		—			(525.6		)	—			—			—
Distributions to noncontrolling interests	—	—		—			—			—			—			(8.1		)
Shares issued under share-based compensation plans, net	1.9	.2		21.8			—			—			(.1		)	—
Tax benefits 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
Net (loss) income	—	—		—			(3,902.6		)	—			—			14.1
Dividends paid	—	—		—			(704.3		)	—			—			—
Distributions to noncontrolling interests	—	—		—			—			—			—			(13.5		)
Shares issued in connection with share-based compensation plans, net	1.1	.1		.4			—			—			(.1		)	—
Tax benefit from share-based compensation	—	—		1.2			—			—			—			—
Repurchase of shares	—	—		—			—			—			(13.7		)	—
Share-based compensation cost	—	—		48.7			—			—			—			—
Net other comprehensive loss	—	—		—			—			(6.3		)	—			—
BALANCE, December 31, 2014	240.7	24.2		5,517.5			2,720.4			11.9			(59.0		)	7.9
Net (loss) income	—	—		—			(1,594.8		)	—			—			8.9
Dividends paid	—	—		—			(140.3		)	—			—			—
Distributions to noncontrolling interests	—	—		—			—			—			—			(12.5		)
Shares issued in connection with share-based compensation plans, net	2.4	.2		—			—			—			(.2		)	—
Tax expense from share-based compensation	—	—		(2.4		)	—			—			—			—
Repurchase of shares	—	—		—			—			—			(4.6		)	—
Share-based compensation cost	—	—		39.4			—			—			—			—
Net other comprehensive income	—	—		—			—			.6			—			—
BALANCE, December 31, 2015	243.1	$	24.4	$	5,554.5		$	985.3		$	12.5		$	(63.8	)	$	4.3

During 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 during 2018. As of December 31, 2015, there had been no share repurchases under this program.

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7.  BENEFIT PLANS

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"). Under the 2012 LTIP, as amended, 23.0 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, 2015, there were 12.9 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 and Units

Grants of non-vested share awards and non-vested share units 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, and our non-vested share units have 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, 2015 (in millions):

	2015			2014			2013
Contract drilling	$	19.5		$	20.9		$	21.3
General and administrative	17.8			20.7			21.6
Non-vested share award related compensation expense included in operating expenses	37.3			41.6			42.9
Tax benefit	(4.8		)	(5.1		)	(5.4		)
Total non-vested share award related compensation expense included in net income	$	32.5		$	36.5		$	37.5

The following table summarizes the value of non-vested shares granted and vested during each of the years in the three-year period ended December 31, 2015:

	2015		2014		2013
Weighted-average grant-date fair value of   non-vested share awards granted (per share)	$	23.95	$	51.22	$	59.79
Total fair value of non-vested share awards   vested during the period (in millions)	$	18.0	$	46.2	$	49.6

The following table summarizes non-vested share activity for the year ended December 31, 2015 (shares in thousands): 

	Shares		Weighted-Average Grant-Date Fair Value
Non-vested share awards as of December 31, 2014	2,641		$	52.86
Granted	2,116		23.95
Vested	(787	)	51.42
Forfeited	(827	)	41.23
Non-vested share awards as of December 31, 2015	3,143		$	36.46

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As of December 31, 2015, there was $88.2 million of total unrecognized compensation cost related to non-vested share awards and non-vested share units, which is expected to be recognized over a weighted-average period of 2.0 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, 2015, options granted to purchase 458,000 shares with a weighted average exercise price of $41.51 were outstanding under the 2012 LTIP and predecessor or acquired plans. No options have been granted since 2011, and there were no unrecognized compensation costs related to options as of December 31, 2015.

Performance Awards

Under the 2012 LTIP, performance awards may be issued to our senior executive officers. Performance awards granted during 2013, 2014 and 2015 are payable in Ensco shares upon attainment of specified performance goals based on relative total shareholder return ("TSR") and relative return on capital employed ("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 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 2015, 2014 and 2013 totaled $8.3 million, $7.4 million and $8.2 million, respectively. The aggregate fair value of performance awards vested during 2015, 2014 and 2013 totaled $4.6 million, $6.9 million and $7.4 million, respectively.

During the years ended December 31, 2015, 2014 and 2013, we recognized $2.9 million, $3.4 million and $6.6 million of compensation expense for performance awards, respectively, which was included in general and administrative expense in our consolidated statements of operations.  As of December 31, 2015, there was $6.3 million of total unrecognized compensation cost related to unvested performance awards, which is expected to be recognized over a weighted-average period of 2.0 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 $18.9 million, $20.7 million and $21.1 million for the years ended December 31, 2015, 2014 and 2013, respectively.  Any additional discretionary contributions made into the plans require approval of the Board of Directors and are generally paid in cash.  We recorded additional discretionary contribution provisions of $27.5 million, $30.7 million and $55.3 million for the years ended December 31, 2015, 2014 and 2013, respectively.  Matching contributions and additional discretionary contributions

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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.

8.  GOODWILL AND OTHER INTANGIBLE ASSETS AND LIABILITIES

Goodwill

The carrying amount of goodwill as of December 31, 2015 is detailed below by reporting unit (in millions):

	December 31, 2015								December 31, 2014
	Gross Carrying Amount		Accumulated Impairment Losses			Net Carrying Amount			Gross Carrying Amount		Accumulated Impairment Losses			Net Carrying Amount
Floaters
Balance, beginning of period	$	3,081.4	$	(2,997.9	)	$	83.5		$	3,081.4	$	—		$	3,081.4
Loss on impairment	—		(83.5		)	(83.5		)	—		(2,997.9		)	(2,997.9		)
Balance, end of period	$	3,081.4	$	(3,081.4	)	$	—		$	3,081.4	$	(2,997.9	)	$	83.5
Jackups
Balance, beginning of period	$	192.6	$	—		$	192.6		$	192.6	$	—		$	192.6
Loss on impairment	—		(192.6		)	(192.6		)	—		—			—
Balance, end of period	$	192.6	$	(192.6	)	$	—		$	192.6	$	—		$	192.6

Impairment of Goodwill

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, represent our reporting units. We test goodwill for impairment on an annual basis or when events or changes in circumstances indicate that a potential impairment exists. 

Year Ended December 31, 2015 - As part of our annual goodwill impairment test, we considered the decline in Brent crude oil prices to around $35 per barrel as of December 31, 2015. Commodity prices continued to decline further into 2016, and Brent crude oil prices reached a ten-year low of approximately $26 per barrel in January 2016. These prices resulted in significant capital spending reductions by our customers, causing a decline in day rates for the few contracts executed during the fourth quarter. Customers have delayed drilling programs and are exploring subletting opportunities for contracted rigs thereby exacerbating supply pressure. In addition, certain customers are requesting contract concessions or terminating drilling contracts. Customers are expected to continue to operate under reduced budgets in the current commodity price environment. The significant supply and demand imbalance will continue to be adversely impacted by future newbuild deliveries, program delays and lower capital spending by operators. These adverse changes resulted in further deterioration in our forecasted day rates and utilization during the fourth quarter.

Additionally, during the latter half of 2015, our stock price declined significantly, trading between $13.26 and $22.21. Our average stock price was $17.21and $16.34 during the third and fourth quarters, respectively. Our stock price continued to decline during 2016, reaching a 20-year low closing price of approximately $8.00 in February. During the first half of 2015, our average stock price was $25.31.

We considered the deterioration in our forecasted day rates and utilization, the sustained decline in our stock price and the impairment charge on certain rigs during the fourth quarter and concluded it was more-likely-than-not that the fair values of both the Floaters and Jackups reporting units were less than their carrying amounts.

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We estimated the fair values of each reporting unit using an income approach. In the current market environment, we concluded the income approach provided a better estimate of fair value compared to other valuation approaches. Based on the valuations performed as of December 31, 2015, both the Floater and Jackup reporting unit estimated fair values were less than their carrying values; therefore, we concluded that the Floater and Jackup goodwill balances were impaired.

We compared the estimated fair value of each reporting unit to the fair values of all assets and liabilities within the respective reporting unit to calculate the implied fair value of goodwill. As a result, we recorded a non-cash loss on impairment of $192.6 million and $83.5 million for the Jackups and Floaters reporting units, respectively, which was included in loss on impairment in our consolidated statement of operations for the year ended December 31, 2015. There is no goodwill on our consolidated balance sheet as of December 31, 2015.

The income approach was based on a discounted cash flow model, which utilized present values of cash flows to estimate fair value and was based on unobservable inputs that require significant judgments for which there is limited information. The future cash flows were projected based on our estimates of future day rates, utilization, operating costs, capital requirements, growth rates and terminal values. Forecasted day rates and utilization take into account current market conditions and our anticipated business outlook, both of which have been impacted by the adverse changes in the business environment observed during the fourth quarter. The day rates reflect contracted rates during the respective contracted periods and our estimate of market day rates in uncontracted periods. The forecasted market day rates were depressed in the near-term but were forecasted to grow in the longer-term and terminal period.

Operating costs were forecasted using a combination of our historical average operating costs and expected future costs, adjusted for an estimated inflation factor. Capital requirements in the discounted cash flow model were based on our estimates of future capital costs, taking into consideration our historical trends. The estimated capital requirements included cash outflows for new rig construction and cash outflows to maintain the current operating condition of our rigs through their remaining marketable lives.

A terminal period was used to reflect our estimate of stable, perpetual growth. The terminal period reflects a terminal growth rate of 3.0%, which includes an estimated inflation factor. The future cash flows were discounted using a market-participant risk-adjusted weighted average cost of capital of 11.5%. These assumptions were derived from unobservable inputs and reflect our judgments and assumptions.

We evaluated the estimated fair value of our reporting units compared to our market capitalization as of December 31, 2015. The aggregate fair values of our reporting units exceeded our market capitalization, and we believe the resulting implied control premium was reasonable based on recent market transactions within our industry or other relevant benchmark data.

Year Ended December 31, 2014 - As part of our annual goodwill impairment test as of December 31, 2014, we considered the significant decline in commodity prices during the fourth quarter of 2014. Specifically, Brent crude oil prices declined from approximately $95 per barrel at September 30, 2014 to near $55 per barrel at December 31, 2014. These declines resulted in further reductions in capital spending by operators, including the cancellation or deferral of planned drilling programs, which caused further deterioration in forecasted day rates and utilization.

Our stock price also declined significantly during the latter half of 2014, reaching a five-year low of $25.88 on December 16th. Our stock traded between $25.88 and $41.99 during the fourth quarter of 2014 and averaged $35.23 during this period.

We considered the adverse changes in the floater business climate, the sustained decline in our stock price and the impairment charge on older, less capable floaters during the fourth quarter and concluded it was more-likely-than-not that the fair value of the Floater reporting unit was less than its carrying amount.

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We estimated the fair value of the Floater reporting unit using a blended income and market approach. Based on the valuation performed as of December 31, 2014, the reporting unit estimated fair value was less than the carrying value; therefore, we concluded that the Floater goodwill balance was impaired.  We compared the estimated fair value of the reporting unit to the fair value of all assets and liabilities within the reporting unit to calculate the implied fair value of goodwill. As a result, we recorded a non-cash loss on impairment totaling $3.0 billion which was included in loss on impairment in our consolidated statement of operations for the year ended December 31, 2014.

We evaluated the estimated fair value of our reporting units compared to our market capitalization as of December 31, 2014. To perform this assessment, we used a market approach to estimate the fair value of the Jackups reporting unit. The aggregate fair values of our reporting units exceeded our market capitalization, and we believe the resulting implied control premium was reasonable based on recent market transactions within our industry or other relevant benchmark data.

We performed a qualitative assessment for our Jackup reporting unit as of December 31, 2014. Goodwill impairment tests performed during prior years indicated that the fair value of the Jackup reporting unit significantly exceeded its carrying amount. Despite the adverse changes in the offshore drilling business climate, we concluded that the fair value remained substantially in excess of the carrying value of the reporting unit, as evidenced by the estimated fair value of the Jackup reporting unit calculated for the purpose of reconciling the fair value of our reporting units to our market capitalization. Therefore, we concluded that it remained more-likely-than-not that the Jackup reporting unit was not impaired.

Drilling Contract Intangibles

In connection with the Pride acquisition, we recorded intangible assets and liabilities representing the estimated fair values of the acquired company's firm drilling contracts in place at the date of acquisition 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, 2015 and 2014 were as follows (in millions):

	December 31, 2015								December 31, 2014
	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	$	(163.3	)	$	45.7		$	209.0	$	(130.6	)	$	78.4
Amortization	—		(41.4		)	(41.4		)	—		(32.7		)	(32.7		)
Balance, end of period	$	209.0	$	(204.7	)	$	4.3		$	209.0	$	(163.3	)	$	45.7
Drilling contract intangible liabilities
Balance, beginning of period	$	278.0	$	(237.3	)	$	40.7		$	278.0	$	(208.9	)	$	69.1
Amortization	—		(28.1		)	(28.1		)	—		(28.4		)	(28.4		)
Balance, end of period	$	278.0	$	(265.4	)	$	12.6		$	278.0	$	(237.3	)	$	40.7

The various factors considered in the determination of the fair values of our drilling contract intangibles were (1) the day rate of 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 date of acquisition.  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

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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 increase to future operating revenues related to the amortization of these intangible assets and liabilities as of December 31, 2015, is as follows (in millions):

2016	$	8.3
Total	$	8.3

9.  INCOME TAXES

We generated losses of $578.2 million and $460.3 million from continuing operations before income taxes in the U.S. and losses of $893.0 million and $2.1 billion from continuing operations before income taxes in non-U.S. countries for the years ended December 31, 2015 and 2014, respectively.

We generated income of $173.4 million from continuing operations before income taxes in the U.S. and income of $1.5 billion from continuing operations before income taxes in non-U.S. countries for the year ended December 31, 2013.

The following table summarizes components of our provision for income taxes from continuing operations for each of the years in the three-year period ended December 31, 2015 (in millions):

	2015			2014			2013
Current income tax expense:
U.S.	$	18.7		$	114.8		$	94.4
Non-U.S.	125.4			149.2			98.6
	144.1			264.0			193.0
Deferred income tax (benefit) expense:
U.S.	(180.4		)	(86.7		)	19.2
Non-U.S.	22.4			(36.8		)	(9.1		)
	(158.0		)	(123.5		)	10.1
Total income tax (benefit) expense	$	(13.9	)	$	140.5		$	203.1

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Deferred Taxes

The following table summarizes significant components of deferred income tax assets (liabilities) as of December 31, 2015 and 2014 (in millions):

	2015			2014
Deferred tax assets:
Net operating loss carryforwards	$	228.7		$	204.5
Premium on long-term debt	86.0			99.2
Foreign tax credits	84.1			98.6
Deferred Revenue	77.7			103.0
Employee benefits, including share-based compensation	40.5			39.5
Other	20.5			16.7
Total deferred tax assets	537.5			561.5
Valuation allowance	(266.4		)	(271.3		)
Net deferred tax assets	271.1			290.2
Deferred tax liabilities:
Property and equipment	(97.1		)	(314.2		)
Intercompany transfers of property	(21.2		)	(23.0		)
Deferred costs	(15.3		)	(20.2		)
Other	(25.8		)	(14.1		)
Total deferred tax liabilities	(159.4		)	(371.5		)
Net deferred tax asset (liability)	$	111.7		$	(81.3	)

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, 2015, we had deferred tax assets of $84.1 million for U.S. foreign tax credits (“FTC”) and $228.7 million related to $979.2 million of net operating loss (“NOL”) carryforwards, which can be used to reduce our income taxes payable in future years.  The FTC expire between 2022 and 2023.  NOL carryforwards, which were generated in various jurisdictions worldwide, include $599.0 million that do not expire and $380.2 million that will expire, if not utilized, beginning in 2016 through 2020.  Due to the uncertainty of realization, we have a $259.8 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.

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Effective Tax Rate

     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 generally not subject to U.K. taxation. 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. Our consolidated effective income tax rate on continuing operations for each of the years in the three-year period ended December 31, 2015, differs from the U.K. statutory income tax rate as follows:

	2015		2014		2013
U.K. statutory income tax rate	20.2	%	21.5	%	23.3	%
Non-U.K. taxes	(12.3	)	(1.3	)	(13.2	)
Goodwill and asset impairments	(4.0	)	(25.3	)	—
Valuation allowance	(1.5	)	(1.1	)	1.0
Other	(1.5	)	.7		1.3
Effective income tax rate	.9	%	(5.5	)%	12.4	%

Our 2015 consolidated effective income tax rate includes the impact of various discrete tax items, primarily related to a $192.5 million tax benefit associated with rig impairments and $11.0 million tax benefit resulting from the reduction of a valuation allowance on US foreign tax credits.

Our consolidated effective income tax rate for 2014 includes the impact of various discrete tax items, including the recognition of a net $18.4 million tax expense associated with liabilities for unrecognized tax benefits and other adjustments relating to prior years and a $16.4 million tax benefit associated with rig impairments. In addition, we recognized a net $41.4 million tax benefit in connection with the utilization of foreign tax credits that were previously subject to a valuation allowance.

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.

Excluding the impact of the aforementioned discrete tax items and goodwill and asset impairments, our consolidated effective income tax rates for the years ended December 31, 2015, 2014 and 2013 were 16.0%, 10.7% and 12.2%, respectively. The changes in our consolidated effective income tax rate excluding discrete tax items during the three years result primarily from changes in the relative components of our earnings from the various taxing jurisdictions in which our drilling rigs are operated and/or owned and the differences in the tax rates in such tax jurisdictions.

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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, 2015, we had $140.6 million of unrecognized tax benefits, of which $119.3 million was included in other liabilities on our consolidated balance sheet and the remaining $21.3 million, which is associated with a tax position taken in tax years with NOL carryforwards, was presented as a reduction of deferred tax assets. As of December 31, 2014, we had $134.4 million of unrecognized tax benefits, of which $115.9 million was included in other liabilities on our consolidated balance sheet and the remaining $18.5 million, which is associated with a tax position taken in tax years with NOL carryforwards, was presented as a reduction of deferred tax assets. If recognized, $108.3 million of the $140.6 million unrecognized tax benefits as of December 31, 2015 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, 2015 and 2014 is as follows (in millions):

	2015			2014
Balance, beginning of year	$	134.4		$	151.7
Increases in unrecognized tax benefits as a result       of tax positions taken during prior years	15.7			16.3
Increases in unrecognized tax benefits as a result       of tax positions taken during the current year	6.6			5.5
Decreases in unrecognized tax benefits as a result       of tax positions taken during prior years	(2.1		)	(15.5		)
Settlements with taxing authorities	(0.6		)	(14.2		)
Lapse of applicable statutes of limitations	(5.6		)	(.7		)
Impact of foreign currency exchange rates	(7.8		)	(8.7		)
Balance, end of year	$	140.6		$	134.4

Accrued interest and penalties totaled $30.4 million and $26.5 million as of December 31, 2015 and 2014, respectively, and were included in other liabilities on our consolidated balance sheets. We recognized net expense of $3.9 million and $9.2 million and benefits of $1.6 million associated with interest and penalties during the years ended December 31, 2015, 2014 and 2013, respectively. Interest and penalties are included in current income tax expense in our consolidated statements of operations.

Our 2011 and subsequent years U.S. Federal tax returns remain subject to examination. Tax years as early as 2005 remain subject to examination in the other major tax jurisdictions in which we operated.

Statutes of limitations applicable to certain of our tax positions lapsed during 2015, 2014 and 2013, resulting in net income tax benefits, inclusive of interest and penalties, of $7.6 million, $2.4 million and $3.1 million, respectively.

Absent the commencement of examinations by tax authorities, statutes of limitations applicable to certain of our tax positions will lapse during 2016.  Therefore, it is reasonably possible that our unrecognized tax benefits will decline during the next 12 months by $64.9 million, inclusive of $9.5 million of accrued interest and penalties, of which up to $62.2 million would impact our consolidated effective income tax rate if recognized.

Intercompany Transfer of Drilling Rigs

During the three-year period ended December 31, 2015, we transferred ownership of certain drilling rigs among our subsidiaries, including one semisubmersible rig during 2015, three jackup rigs during 2014 and two semisubmersible rigs during 2013.  There were no income tax liabilities or reversing temporary differences associated with the intercompany transfers of drilling rigs during these periods.

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As of December 31, 2015 and 2014, the unamortized balance associated with deferred charges for income taxes incurred in connection with intercompany transfers of drilling rigs totaled $37.1 million and $39.7 million, respectively, and was included in other assets, net, on our consolidated balance sheets. Current income tax expense for the years ended December 31, 2015, 2014 and 2013 included $2.6 million, $2.6 million and $4.1 million, respectively, of amortization of income taxes incurred in connection with intercompany transfers of drilling rigs.

As of December 31, 2015 and 2014, the unamortized balance associated with the deferred tax liability for reversing temporary differences of transferred drilling rigs totaled $21.2 million and $23.0 million, respectively, and was included in deferred income taxes on our consolidated balance sheets.  Deferred income tax benefit for the years ended December 31, 2015, 2014 and 2013 included benefits of $1.8 million, $1.8 million and $1.9 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 sufficient 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.

As of December 31, 2015 and 2014, the aggregate undistributed earnings of the subsidiaries for which we maintain a policy and intention to reinvest earnings indefinitely totaled $2.3 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, 2015.

10.  DISCONTINUED OPERATIONS

Our business strategy has been to focus on ultra-deepwater floater and premium jackup operations. We continually assess our rig portfolio and actively work with our rig broker to market certain rigs that no longer meet our standards for economic returns or are not part of our long-term strategic plan. Consistent with this strategy, we sold the following rigs during the three-year period ended December 31, 2015 (in millions):

Rig(3)	Date of Rig Sale	Segment(1)	Net Proceeds		Net Book Value(2)		Pre-tax(Loss)/Gain
ENSCO 5001	December 2015	Floaters	$	2.4	$	2.5	$	(.1	)
ENSCO 5002	June 2015	Floaters	1.6		—		1.6
ENSCO 5000	December 2014	Floaters	1.3		.5		.8
ENSCO 93	September 2014	Jackups	51.7		52.9		(1.2		)
ENSCO 85	April 2014	Jackups	64.4		54.1		10.3
ENSCO 69 & Pride Wisconsin	January 2014	Jackups	32.2		8.6		23.6
Pride Pennsylvania	March 2013	Jackups	15.5		15.7		(.2		)
			$	169.1	$	134.3	$	34.8

⁽¹⁾ The rigs' operating results were reclassified to discontinued operations in our consolidated statements of operations for each of the years in the three-year period ended December 31, 2015 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⁾ In September 2014, we sold jackup rigs ENSCO 83, ENSCO 89, ENSCO 93 and ENSCO 98, all of which are contracted to Pemex. As described below, the loss on sale and operating results of ENSCO 93 were included in

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loss from discontinued operations, net, in our consolidated statement of operations for the three-year period ended December 31, 2015. Due to our long-term charter agreements with the purchaser, ENSCO 83, ENSCO 89 and ENSCO 98 operating results were included in income from continuing operations.

During 2014, we committed to a plan to sell six floaters and two jackups. ENSCO 5000, ENSCO 5001, ENSCO 5002, ENSCO 6000, ENSCO 7500, ENSCO DS-2, ENSCO 58 and ENSCO 90 were removed from our portfolio of rigs marketed for contract drilling services. The operating results from these rigs were included in loss from discontinued operations, net in our consolidated statement of operations for the three-year period ended December 31, 2015.

On a quarterly basis, we reassess the fair values of our held-for-sale rigs to determine whether any adjustments to the carrying values are necessary.  We recorded a non-cash loss on impairment totaling $120.6 million (net of tax benefits of $28.0 million) and $1.2 billion (net of tax benefits of $83.5 million), for the years ended December 31, 2015 and 2014, respectively, as a result of declines in the estimated fair values of our held-for-sale rigs. The loss on impairment was included in loss from discontinued operations, net, in our consolidated statement of operations for the years ended December 31, 2015 and 2014, respectively. We measured the fair value of held-for-sale rigs by applying a market approach, which was based on an unobservable third-party estimated price that would be received in exchange for the assets in an orderly transaction between market participants.

During 2015, we sold ENSCO 5001 and ENSCO 5002 for net proceeds of $2.4 million and $1.6 million, respectively, which were included in investing activities of discontinued operations in our consolidated statement of cash flows for the year ended December 31, 2015. During 2014, we sold ENSCO 5000 for net proceeds of $1.3 million, which was included in investing activities of discontinued operations in our consolidated statement of cash flows for the year ended December 31, 2014. The remaining three floaters and two jackups that are included in discontinued operations are being actively marketed for sale and were classified as held-for-sale on our December 31, 2015 consolidated balance sheet.

During 2014, we sold ENSCO 93, a jackup contracted to Pemex. In connection with this sale, we executed a charter agreement with the purchaser to continue operating the rig for the remainder of the Pemex contract, which ended in July 2015, less than one year from the date of sale. Our management services following the sale did not constitute significant ongoing involvement and therefore, the $1.2 million loss on sale was included in loss from discontinued operations, net, in our consolidated statement of operations for the year ended December 31, 2014. ENSCO 93 operating results were included in loss from discontinued operations, net, in our consolidated statement of operations for the three-year period ended December 31, 2015. Net proceeds from the sale of $51.7 million were included in investing activities of discontinued operations in our consolidated statement of cash flows for the year ended December 31, 2014. See "Note 12 - Sale-leaseback" for additional information.

During 2014, we sold ENSCO 85 for net proceeds of $64.4 million and ENSCO 69 and Pride Wisconsin for net proceeds of $32.2 million. The operating results of these rigs were included in loss from discontinued operations, net, in our consolidated statement of operations. The net proceeds from the sale of ENSCO 85 were included in investing activities of discontinued operations in our consolidated statement of cash flows for the year ended December 31, 2014. The net proceeds from the sale of ENSCO 69 and Pride Wisconsin were received in December 2013 and included in investing activities of discontinued operations in our consolidated statement of cash flows for the year ended December 31, 2013.

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The following table summarizes (loss) income from discontinued operations for each of the years in the three-year period ended December 31, 2015 (in millions):

	2015			2014			2013
Revenues	$	19.5		$	325.0		$	596.4
Operating expenses	39.5			372.0			577.6
Operating (loss) income	(20.0		)	(47.0		)	18.8
Other income	—			—			.3
Income tax benefit (expense)	7.7			(30.7		)	(20.2		)
Loss on impairment, net	(120.6		)	(1,158.8		)	—
Gain (loss) on disposal of discontinued operations, net	4.3			37.3			(1.1		)
Loss from discontinued operations	$	(128.6	)	$	(1,199.2	)	$	(2.2	)

Income tax benefit (expense) from discontinued operations for the year ended December 31, 2015 included $12.6 million of discrete tax benefits.

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

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11.  COMMITMENTS AND CONTINGENCIES

Leases

We are obligated under leases for certain of our offices and equipment.  Rental expense relating to operating leases was $50.9 million, $54.4 million and $49.1 million during the years ended December 31, 2015, 2014 and 2013, respectively. Future minimum rental payments under our noncancellable operating lease obligations are as follows: $45.3 million during 2016; $18.3 million during 2017; $12.0 million during 2018; $10.6 million during 2019; $10.1 million during 2020 and $53.4 million thereafter.

Capital Commitments

The following table summarizes the cumulative amount of contractual payments made as of December 31, 2015 for our rigs under construction and estimated timing of our remaining contractual payments (in millions): 

	Cumulative Paid(1)		2016		2017		2018		Total(2)
ENSCO DS-10	$	236.2	$	9.3	$	310.5	$	—	$	556.0
ENSCO 123	53.5		3.2		9.5		215.4		281.6
ENSCO 140	156.8		39.9		—		—		196.7
ENSCO 141	78.4		117.2		—		—		195.6
	$	524.9	$	169.6	$	320.0	$	215.4	$	1,229.9

⁽¹⁾ Cumulative paid represents the aggregate amount of contractual payments made from commencement of the construction agreement through December 31, 2015.

⁽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.

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.

Brazil Internal Investigation

Pride International, Inc. (“Pride”), a company we acquired in 2011, commenced drilling operations in Brazil in 2001. In 2008, Pride entered into a drilling services agreement with Petrobras (the "DSA") for ENSCO DS-5, a drillship ordered from Samsung Heavy Industries, a shipyard in South Korea ("SHI"). Beginning in 2006, Pride conducted periodic compliance reviews of its business with Petrobras, and, after the acquisition of Pride, Ensco conducted similar compliance reviews, the most recent of which commenced in early 2015 after media reports were released regarding ongoing investigations of various kickback and bribery schemes in Brazil involving Petrobras.

While conducting our compliance review, we became aware of an internal audit report by Petrobras alleging irregularities in relation to the DSA. Upon learning of the Petrobras internal audit report, our Audit Committee appointed independent counsel to lead an investigation into the alleged irregularities. Further, in June and July 2015, we voluntarily contacted the SEC and the DOJ, respectively, to advise them of this matter and our Audit Committee’s investigation. Independent counsel, under the direction of our Audit Committee, has substantially completed its investigation by reviewing and analyzing available documents and correspondence and interviewing current and former employees involved in the DSA negotiations and the negotiation of the ENSCO DS-5 construction contract with SHI (the "DS-5 Construction Contract").

To date, our Audit Committee has found no evidence that Pride or Ensco or any of their current or former employees were aware of or involved in any wrongdoing, and our Audit Committee has found no evidence linking Ensco or Pride to any illegal acts committed by our former marketing consultant. Independent counsel has continued

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to provide the SEC and DOJ with updates throughout the investigation, including detailed briefings regarding its investigation and findings. On December 21, 2015, we entered into a one-year tolling agreement with the DOJ, at the agency's request.

Subsequent to initiating our Audit Committee investigation, the Petrobras internal audit report and the alleged irregularities were referenced in Brazilian court documents connected to the prosecution of former Petrobras directors and employees as well as certain other third parties, including our former marketing consultant who provided services to Pride and Ensco in connection with the DSA. Our former marketing consultant has entered into a plea agreement with the Brazilian authorities. On January 10, 2016, Brazilian authorities filed an indictment against a former Petrobras director. This indictment states that the former Petrobras director received bribes paid out of proceeds from a brokerage agreement entered into for purposes of intermediating a drillship construction contract between SHI and Pride, which we believe to be the DS-5 Construction Contract. The parties to the brokerage agreement were a company affiliated with a person acting on behalf of the former Petrobras director, a company affiliated with our former marketing consultant, and SHI. The indictment alleges that amounts paid by SHI under the brokerage agreement ultimately were used to pay bribes to the former Petrobras director. The indictment does not state that Pride or Ensco or any of their current or former employees were involved in the bribery scheme or had any knowledge of the bribery scheme.

On January 4, 2016, we received a notice from Petrobras declaring the DSA void effective immediately. Petrobras’ notice alleges that SHI made improper payments to our former marketing consultant who then shared the improper payments with employees of Petrobras and, without specifying any supporting facts or conduct, that Pride had knowledge of this activity and assisted in the procurement of and/or facilitated these improper payments. We disagree with Petrobras’ assertion that the DSA is void and plan to pursue our legal rights in connection with this dispute, as described further below under "—DSA Dispute."

Outside of Petrobras’ allegations, we have not been contacted by any Brazil governmental authority regarding alleged wrongdoing by Pride or Ensco or any of their current or former employees related to this matter. We cannot predict whether any U.S., Brazilian or other governmental authority will seek to investigate this matter, or if a proceeding were opened, the scope or ultimate outcome of any such investigation. If the SEC or DOJ determines that violations of the FCPA have occurred, or if any governmental authority determines that we have violated applicable anti-bribery laws, they could seek civil and criminal sanctions, including monetary penalties, against us, as well as changes to our business practices and compliance programs, any of which could have a material adverse effect on our business and financial condition. Although our internal investigation is substantially complete, we cannot predict whether any additional allegations will be made or whether any additional facts relevant to the investigation will be uncovered during the course of the investigation and what impact those allegations and additional facts will have on the timing or conclusions of the investigation. Our Audit Committee will examine any such additional allegations and additional facts and the circumstances surrounding them.

DSA Dispute

As described above, on January 4, 2016, Petrobras sent a notice to us declaring the DSA void effective immediately, reserving its rights and stating its intention to seek any restitution to which it may be entitled. We disagree with Petrobras’ assertion that the DSA is void and plan to pursue our legal rights in connection with this dispute. However, at this time, we cannot reasonably determine the validity of Petrobras’ claim or the range of potential exposure, if any. As a result, there can be no assurance as to how this dispute will ultimately be resolved.

Due to this dispute with Petrobras, we did not recognize revenue for services provided under the DSA during the fourth quarter totaling $44.7 million as we concluded collectability of these amounts was not reasonably assured. Additionally, we recorded a $17.1 million provision for doubtful accounts during the fourth quarter of 2015 for receivables related to services provided under the DSA through September 30, 2015. Our receivables from Petrobras related to the ENSCO DS-5 DSA are fully reserved on our consolidated balance sheet as of December 31, 2015.

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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 50 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.

During 2013, we reached an agreement in principle with 58 plaintiffs to settle lawsuits filed in Mississippi for a nominal amount. A special master reviewed all 58 cases and made an allocation of settlement funds among the parties.  The District Court Judge reviewed the allocations and accepted the special master’s recommendations and approved the settlements.  The settlement documents for most of the individual plaintiffs have been processed, and the cases have been dismissed. The settlement documents for approximately 13 individual plaintiffs are continuing to be processed.

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 from time to time 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 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 outstanding as of December 31, 2015 totaled $70.0 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, 2015, we had not been required to make collateral deposits with respect to these agreements.

12.  SALE-LEASEBACK

During 2014, we sold jackup rigs ENSCO 83, ENSCO 89, ENSCO 93 and ENSCO 98, all of which were contracted to Pemex. We received proceeds of $211.8 million and incurred commissions and other incremental, direct costs of $5.3 million. The carrying value of these rigs was $169.6 million.

In connection with this sale, we executed charter agreements with the purchaser to continue operating the rigs for the remainder of the Pemex contracts. We accounted for the transaction as a sale-leaseback, whereby we retained a significant portion of the remaining use of the rigs as a result of the charter agreements.

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We recorded an aggregate gain on sale of $7.5 million at the time of disposal, which represented the portion of the gain that exceeded the present value of payments due under the charter agreements, included in contract drilling expense in our consolidated statement of operations for the year ended December 31, 2014. The remaining $29.4 million gain was deferred and amortized to contract drilling expense within the Jackup segment over the remaining charter term of each rig. Of the $29.4 million deferred gain, $22.4 million and $7.0 million were recognized in contract drilling expense in our consolidated statement of operations for the years ended December 31, 2015 and December 31, 2014, respectively,

Due to our long-term charter agreements with the purchaser, ENSCO 83, ENSCO 89 and ENSCO 98 operating results for periods beginning after the date of sale (September 30, 2014) were included in income from continuing operations within the Other segment. Operating results for these rigs prior to September 30, 2014 were included in income from continuing operations within the Jackup segment.

The ENSCO 93 contract with Pemex ended July 2015, less than one year from the date of sale. Therefore, our rig management operations following the sale did not constitute significant ongoing involvement. As a result, ENSCO 93 operating results were included in loss from discontinued operations, net, in our consolidated statements of operations for the three-year period ended December 31, 2015. Additionally, the loss on sale of $1.2 million was included in loss from discontinued operations, net in our consolidated statements of operations for the year ended December 31, 2014. The proceeds from the sale were included in investing activities of discontinued operations in our consolidated statement of cash flows for the year ended December 31, 2014. See "Note 10 - Discontinued Operations" for additional information.

13.  SEGMENT INFORMATION

    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, 2015 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." We measure segment assets as property and equipment.

Year Ended December 31, 2015

	Floaters			Jackups			Other		Operating Segments Total			Reconciling Items			Consolidated Total
Revenues	$	2,466.0		$	1,445.6		$	151.8	$	4,063.4		$	—		$	4,063.4
Operating expenses
Contract drilling   (exclusive of depreciation)	1,052.8			693.5			123.3		1,869.6			—			1,869.6
Loss on impairment	1,778.4			968.0					2,746.4			—			2,746.4
Depreciation	382.4			175.7			—		558.1			14.4			572.5
General and administrative	—			—			—		—			118.4			118.4
Operating (loss) income	$	(747.6	)	$	(391.6	)	$	28.5	$	(1,110.7	)	$	(132.8	)	$	(1,243.5	)
Property and equipment, net	$	8,535.6		$	2,481.2		$	—	$	11,016.8		$	71.0		$	11,087.8
Capital expenditures	$	1,176.6		$	434.7		$	—	$	1,611.3		$	8.2		$	1,619.5

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Year Ended December 31, 2014

	Floaters			Jackups		Other		Operating Segments Total			Reconciling Items			Consolidated Total
Revenues	$	2,697.6		$	1,774.6	$	92.3	$	4,564.5		$	—		$	4,564.5
Operating expenses
Contract drilling   (exclusive of depreciation)	1,201.2			807.4		68.3		2,076.9			—			2,076.9
Loss on impairment	3,982.3			236.4		—		4,218.7			—			4,218.7
Depreciation	358.1			171.2		—		529.3			8.6			537.9
General and administrative	—			—		—		—			131.9			131.9
Operating (loss) income	$	(2,844.0	)	$	559.6	$	24.0	$	(2,260.4	)	$	(140.5	)	$	(2,400.9	)
Property and equipment, net	$	9,462.3		$	2,995.3	$	—	$	12,457.6		$	77.2		$	12,534.8
Capital expenditures	$	855.5		$	666.3	$	—	$	1,521.8		$	44.9		$	1,566.7

Year Ended December 31, 2013

	Floaters		Jackups		Other		Operating Segments Total		Reconciling Items			Consolidated Total
Revenues	$	2,659.6	$	1,588.7	$	75.1	$	4,323.4	$	—		$	4,323.4
Operating expenses
Contract drilling   (exclusive of depreciation)	1,126.0		762.6		58.5		1,947.1		—			1,947.1
Depreciation	342.2		147.5		—		489.7		6.5			496.2
General and administrative	—		—		—		—		146.8			146.8
Operating income (loss)	$	1,191.4	$	678.6	$	16.6	$	1,886.6	$	(153.3	)	$	1,733.3
Property and equipment, net	$	11,303.4	$	2,961.6	$	—	$	14,265.0	$	46.0		$	14,311.0
Capital expenditures	$	1,028.6	$	708.3	$	—	$	1,736.9	$	26.6		$	1,763.5

Information about Geographic Areas

As of December 31, 2015, our Floaters segment consisted of nine drillships, 13 dynamically positioned semisubmersible rigs and three moored semisubmersible rigs deployed in various locations. Additionally, our Floaters segment included one ultra-deepwater drillship under construction in South Korea.  

Our Jackups segment consisted of 42 jackup rigs, of which 39 were deployed in various locations, and three of which were under construction in Singapore and the United Arab Emirates.  

As of December 31, 2015, the geographic distribution of our drilling rigs by operating segment was as follows:

	Floaters	Jackups	Total
Middle East, Africa, Asia & Pacific Rim	6	18	24
North & South America	13	7	20
Europe & the Mediterranean	3	11	14
Middle East, Africa, Asia & Pacific Rim (under construction)	1	3	4
Held-For-Sale	3	3	6
Total	26	42	68

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We provide management services on three rigs owned by third-parties not included in the table above. 

For purposes of our long-lived asset geographic disclosure, we attribute 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 our long-lived assets was as follows (in millions):

	Long-lived Assets
	2015		2014		2013
United States	$	4,731.8	$	5,240.4	$	4,617.8
Angola	1,471.1		1,913.5		2,543.7
Brazil	210.8		1,459.0		2,447.5
Other countries	4,674.1		3,921.9		4,702.0
Total	$	11,087.8	$	12,534.8	$	14,311.0

14.  SUPPLEMENTAL FINANCIAL INFORMATION

Consolidated Balance Sheet Information

Accounts receivable, net, as of December 31, 2015 and 2014 consisted of the following (in millions):

	2015			2014
Trade	$	595.0		$	878.8
Other	16.3			15.9
	611.3			894.7
Allowance for doubtful accounts	(29.3		)	(11.4		)
	$	582.0		$	883.3

Other current assets as of December 31, 2015 and 2014 consisted of the following (in millions):

	2015		2014
Inventory	$	235.3	$	240.3
Prepaid taxes	73.5		90.6
Deferred costs	52.1		61.9
Prepaid expenses	20.5		33.8
Assets held-for-sale	5.5		152.4
Other	14.9		6.6
	$	401.8	$	585.6

Assets held-for-sale primarily consists of drilling rigs and equipment. See "Note 3 - Property and Equipment" and "Note 10 - Discontinued Operations" for additional information on the assets classified as held-for-sale on our balance sheet as of December 31, 2015.

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Other assets, net, as of December 31, 2015 and 2014 consisted of the following (in millions):

	2015		2014
Deferred tax assets	$	94.8	$	63.1
Deferred costs	82.3		82.3
Prepaid taxes on intercompany transfers of property	37.1		39.7
Supplemental executive retirement plan assets	33.1		43.2
Intangible assets	5.4		49.0
Unbilled receivables	1.7		18.6
Warranty and other claim receivables	—		30.6
Other	9.7		12.4
	$	264.1	$	338.9

      Accrued liabilities and other as of December 31, 2015 and 2014 consisted of the following (in millions):

	2015		2014
Deferred revenue	$	197.2	$	241.3
Personnel costs	161.6		214.0
Accrued interest	88.4		83.8
Taxes	70.8		94.5
Derivative liabilities	21.6		24.1
Other	11.3		36.4
	$	550.9	$	694.1

Other liabilities as of December 31, 2015 and 2014 consisted of the following (in millions):

	2015		2014
Deferred revenue	$	218.6	$	373.2
Unrecognized tax benefits (inclusive of interest and penalties)	149.7		142.4
Supplemental executive retirement plan liabilities	34.4		45.1
Personnel costs	17.7		26.1
Intangible liabilities	12.6		40.7
Other	11.8		39.8
	$	444.8	$	667.3

Accumulated other comprehensive income as of December 31, 2015 and 2014 consisted of the following (in millions):

	2015			2014
Currency Translation Adjustment	$	7.8		$	5.1
Derivative Instruments	6.6			8.0
Other	(1.9		)	(1.2		)
	$	12.5		$	11.9

130

Consolidated Statement of Operations Information

Repair and maintenance expense related to continuing operations for each of the years in the three-year period ended December 31, 2015 was as follows (in millions):

	2015		2014		2013
Repair and maintenance expense	$	270.1	$	357.2	$	287.8

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, 2015 was as follows (in millions):

	2015			2014			2013
(Decrease) increase in liabilities	(379.2		)	208.2			(10.3		)
Decrease (increase) in accounts receivable	269.5			(38.5		)	(46.7		)
Decrease (increase) in other assets	25.7			(76.4		)	(94.1		)
	$	(84.0	)	$	93.3		$	(151.1	)

During 2015, the net change in operating assets and liabilities declined by $177.3 million as compared to the prior year. The net change during 2015 was primarily due to a decline in accrued liabilities related to the amortization of deferred revenue, partially offset by a decline in accounts receivable due to lower revenues from contract drilling services.

During 2014, the net change in operating assets and liabilities increased by $244.4 million as compared to the prior year due to an increase in accrued liabilities for the receipt of up-front lump-sum fees that were recorded as deferred revenue on our consolidated balance sheet.

Cash paid for interest and income taxes for each of the years in the three-year period ended December 31, 2015 was as follows (in millions):

	2015		2014		2013
Interest, net of amounts capitalized	$	249.3	$	170.0	$	182.2
Income taxes	97.3		218.2		195.4

Capitalized interest totaled $87.4 million, $78.2 million and $67.7 million during the years ended December 31, 2015, 2014 and 2013, respectively. Capital expenditure accruals totaling $60.9 million, $137.2 million and $111.8 million for the years ended December 31, 2015, 2014 and 2013, 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 Pride firm drilling contracts in place at the Pride acquisition date, debt premiums related to the fair value adjustment of Pride debt instruments, deferred charges for income taxes incurred on intercompany transfers of drilling rigs and certain other deferred costs.

131

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 our expectations. During 2014 and 2015, we insured certain receivables deemed to have a higher credit risk. 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 our derivative counterparties. See "Note 5 - Derivative Instruments" for additional information on our derivative activity.

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.

Consolidated revenues by customer for the years ended December 31, 2015, 2014 and 2013 were as follows:

	2015		2014		2013
BP (1)	18	%	16	%	10	%
Petrobras(2)	14	%	9	%	14	%
Other	68	%	75	%	76	%
	100	%	100	%	100	%

\

⁽¹⁾  For the years ended December 31 2015, 2014 and 2013, 81%, 80% and 84% of the revenues provided by BP, respectively, were attributable to our Floaters segment.

For the year ended December 31, 2015, revenues provided by BP included $110.6 million for the ENSCO DS-4 lump sum termination fee.

⁽²⁾  For the years ended December 31, 2015, 2014 and 2013, all Petrobras revenues were attributable to our Floaters segment.

For purposes of our geographic disclosure, we attribute revenues to the geographic location where such revenues are earned. Consolidated revenues by region for the years ended December 31, 2015, 2014 and 2013 were as follows (in millions):

	2015		2014		2013
U.S. Gulf of Mexico(1)	$	1,151.5	$	1,712.4	$	1,687.2
Angola(2)	586.5		607.9		365.9
Brazil(3)	468.5		459.1		683.7
United Kingdom(4)	400.7		406.2		308.4
Other	1,456.2		1,378.9		1,278.2
	$	4,063.4	$	4,564.5	$	4,323.4

132

⁽¹⁾  For the years ended December 31, 2015, 2014 and 2013, 86%, 79% and 77% of the revenues earned in the U.S. Gulf of Mexico, respectively, were attributable to our Floaters segment.

⁽²⁾  For the years ended December 31, 2015, 2014 and 2013, 88%, 100% and 96% of the revenues earned in Angola, respectively, were attributable to our Floaters segment.

⁽³⁾  For the years ended December 31, 2015, 2014 and 2013, all revenues were attributable to our Floaters segment.

⁽⁴⁾  For the years ended December 31, 2015, 2014 and 2013, all were revenues attributable to our Jackups segment.

15.  GUARANTEE OF REGISTERED SECURITIES

In connection with the Pride acquisition, 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, 2015. 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, 2015.

133

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 operations for each of the years in the three-year period ended December 31, 2015; our condensed consolidating statements of comprehensive (loss) income for each of the years in the three-year period ended December 31, 2015; our condensed consolidating balance sheets as of December 31, 2015 and 2014; and our condensed consolidating statements of cash flows for each of the years in the three-year period ended December 31, 2015, in accordance with Rule 3-10 of Regulation S-X. 

134

ENSCO PLC AND SUBSIDIARIES CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS Year Ended December 31, 2015 (in millions)
	Ensco plc			ENSCO International Incorporated			Pride International, Inc.			Other Non-guarantor Subsidiaries of Ensco			Consolidating Adjustments			Total
OPERATING REVENUES	$	31.7		$	163.5		$	—		$	4,199.4		$	(331.2	)	$	4,063.4
OPERATING EXPENSES
Contract drilling (exclusive of depreciation)	29.2			163.5			—			2,008.1			(331.2		)	1,869.6
Loss on impairment	—			—			—			2,746.4			—			2,746.4
Depreciation	.1			13.8			—			558.6			—			572.5
General and administrative	51.5			.2			—			66.7			—			118.4
OPERATING LOSS	(49.1		)	(14.0		)	—			(1,180.4		)	—			(1,243.5		)
OTHER (EXPENSE) INCOME, NET	(169.5		)	(28.6		)	(71.5		)	41.9			—			(227.7		)
LOSS FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	(218.6		)	(42.6		)	(71.5		)	(1,138.5		)	—			(1,471.2		)
INCOME TAX (BENEFIT) EXPENSE	—			(190.6		)	—			176.7			—			(13.9		)
DISCONTINUED OPERATIONS, NET	—			—			—			(128.6		)	—			(128.6		)
EQUITY LOSS IN AFFILIATES, NET OF TAX	(1,376.2		)	(1,672.8		)	(1,771.5		)	—			4,820.5			—
NET LOSS	(1,594.8		)	(1,524.8		)	(1,843.0		)	(1,443.8		)	4,820.5			(1,585.9		)
NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS	—			—			—			(8.9		)	—			(8.9		)
NET LOSS ATTRIBUTABLE TO ENSCO	$	(1,594.8	)	$	(1,524.8	)	$	(1,843.0	)	$	(1,452.7	)	$	4,820.5		$	(1,594.8	)

135

ENSCO PLC AND SUBSIDIARIES CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS Year Ended December 31, 2014 (in millions)
	Ensco plc			ENSCO International Incorporated			Pride International, Inc.			Other Non-guarantor Subsidiaries of Ensco			Consolidating Adjustments			Total
OPERATING REVENUES	$	34.5		$	145.4		$	—		$	4,683.0		$	(298.4	)	$	4,564.5
OPERATING EXPENSES
Contract drilling (exclusive of depreciation)	31.8			145.4			—			2,198.1			(298.4		)	2,076.9
Loss on impairment	—			—			—			4,218.7			—			4,218.7
Depreciation	.2			7.6			—			530.1			—			537.9
General and administrative	52.0			.4			—			79.5			—			131.9
OPERATING LOSS	(49.5		)	(8.0		)	—			(2,343.4		)	—			(2,400.9		)
OTHER (EXPENSE) INCOME, NET	(67.0		)	(43.3		)	(54.7		)	17.1			—			(147.9		)
LOSS FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	(116.5		)	(51.3		)	(54.7		)	(2,326.3		)	—			(2,548.8		)
INCOME TAX (BENEFIT) EXPENSE	—			(44.9		)	—			185.4			—			140.5
DISCONTINUED OPERATIONS, NET	—			—			—			(1,199.2		)	—			(1,199.2		)
EQUITY LOSS IN AFFILIATES, NET OF TAX	(3,786.1		)	(3,651.0		)	(3,744.3		)	—			11,181.4			—
NET LOSS	(3,902.6		)	(3,657.4		)	(3,799.0		)	(3,710.9		)	11,181.4			(3,888.5		)
NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS	—			—			—			(14.1		)	—			(14.1		)
NET LOSS ATTRIBUTABLE TO ENSCO	$	(3,902.6	)	$	(3,657.4	)	$	(3,799.0	)	$	(3,725.0	)	$	11,181.4		$	(3,902.6	)

136

ENSCO PLC AND SUBSIDIARIES CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS 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		$	—		$	4,446.4		$	(307.4	)	$	4,323.4
OPERATING EXPENSES
Contract drilling (exclusive of depreciation)	27.5			149.4			—			2,077.6			(307.4		)	1,947.1
Depreciation	.3			4.0			—			491.9			—			496.2
General and administrative	63.5			.5			—			82.8			—			146.8
OPERATING (LOSS) INCOME	(56.3		)	(4.5		)	—			1,794.1			—			1,733.3
OTHER (EXPENSE) INCOME, NET	(65.6		)	(9.4		)	(27.9		)	2.8			—			(100.1		)
(LOSS) INCOME BEFORE INCOME TAXES	(121.9		)	(13.9		)	(27.9		)	1,796.9			—			1,633.2
INCOME TAX EXPENSE	—			92.5			—			110.6			—			203.1
DISCONTINUED OPERATIONS, NET	—			—			—			(2.2		)	—			(2.2		)
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

137

ENSCO PLC AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE (LOSS) INCOME

Year Ended December 31, 2015

(in millions)

	Ensco plc			ENSCO International Incorporated			Pride International, Inc.			Other Non-Guarantor Subsidiaries of Ensco			Consolidating Adjustments		Total
NET LOSS	$	(1,594.8	)	$	(1,524.8	)	$	(1,843.0	)	$	(1,443.8	)	$	4,820.5	$	(1,585.9	)
OTHER COMPREHENSIVE (LOSS) INCOME, NET
Net change in fair value of derivatives	—			(23.6		)	—			—			—		(23.6		)
Reclassification of net losses on derivative instruments from other comprehensive income into net income	—			22.2			—			—			—		22.2
Other	—			—			—			2.0			—		2.0
NET OTHER COMPREHENSIVE (LOSS) INCOME	—			(1.4		)	—			2.0			—		.6
COMPREHENSIVE LOSS	(1,594.8		)	(1,526.2		)	(1,843.0		)	(1,441.8		)	4,820.5		(1,585.3		)
COMPREHENSIVE INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS	—			—			—			(8.9		)	—		(8.9		)
COMPREHENSIVE LOSS ATTRIBUTABLE TO ENSCO	$	(1,594.8	)	$	(1,526.2	)	$	(1,843.0	)	$	(1,450.7	)	$	4,820.5	$	(1,594.2	)

138

ENSCO PLC AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE (LOSS) INCOME

Year Ended December 31, 2014

(in millions)

	Ensco plc			ENSCO International Incorporated			Pride International, Inc.			Other Non-Guarantor Subsidiaries of Ensco			Consolidating Adjustments		Total
NET LOSS	$	(3,902.6	)	$	(3,657.4	)	$	(3,799.0	)	$	(3,710.9	)	$	11,181.4	$	(3,888.5	)
OTHER COMPREHENSIVE (LOSS) INCOME, NET
Net change in fair value of derivatives	—			(11.7		)	—			—			—		(11.7		)
Reclassification of net gains on derivative instruments from other comprehensive income into net income	—			(.9		)	—			—			—		(.9		)
Other	—			—			—			6.3			—		6.3
NET OTHER COMPREHENSIVE (LOSS) INCOME	—			(12.6		)	—			6.3			—		(6.3		)
COMPREHENSIVE LOSS	(3,902.6		)	(3,670.0		)	(3,799.0		)	(3,704.6		)	11,181.4		(3,894.8		)
COMPREHENSIVE INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS	—			—			—			(14.1		)	—		(14.1		)
COMPREHENSIVE LOSS ATTRIBUTABLE TO ENSCO	$	(3,902.6	)	$	(3,670.0	)	$	(3,799.0	)	$	(3,718.7	)	$	11,181.4	$	(3,908.9	)

139

ENSCO PLC AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE (LOSS) 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

140

ENSCO PLC AND SUBSIDIARIES CONDENSED CONSOLIDATING BALANCE SHEETS December 31, 2015 (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	$	94.0	$	—	$	2.0		$	25.3	$	—		$	121.3
Short-term investments	1,180.0		—		—			—		—			1,180.0
Accounts receivable, net	1.2		—		—			580.8		—			582.0
Accounts receivable from   affiliates	808.7		237.3		—			148.1		(1,194.1		)	—
Other	.2		229.3		—			172.3		—			401.8
Total current assets	2,084.1		466.6		2.0			926.5		(1,194.1		)	2,285.1
PROPERTY AND EQUIPMENT, AT COST	1.8		117.5		—			12,600.1		—			12,719.4
Less accumulated depreciation	1.8		47.7		—			1,582.1		—			1,631.6
Property and equipment, net	—		69.8		—			11,018.0		—			11,087.8
DUE FROM AFFILIATES	1,303.7		5,270.0		2,035.5			6,869.9		(15,479.1		)	—
INVESTMENTS IN AFFILIATES	7,743.8		—		—			—		(7,743.8		)	—
OTHER ASSETS, NET	26.3		43.3		—			324.9		(130.4		)	264.1
	$	11,157.9	$	5,849.7	$	2,037.5		$	19,139.3	$	(24,547.4	)	$	13,637.0
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable and accrued   liabilities	$	60.7	$	69.6	$	34.8		$	610.4	$	—		$	775.5
Accounts payable to affiliates	19.4		176.3		—			998.4		(1,194.1		)	—
Current maturities of long-term   debt	—		—		—			—		—			—
Total current liabilities	80.1		245.9		34.8			1,608.8		(1,194.1		)	775.5
DUE TO AFFILIATES	751.9		4,354.3		1,763.7			8,609.2		(15,479.1		)	—
LONG-TERM DEBT	3,808.7		149.2		1,937.2			—		—			5,895.1
DEFERRED INCOME TAXES	—		130.4		—			4.4		(130.4		)	4.4
INVESTMENTS IN AFFILIATES	—		442.0		1,319.3			—		(1,761.3		)	—
OTHER LIABILITIES	—		5.3		—			439.5		—			444.8
ENSCO SHAREHOLDERS' EQUITY (DEFICIT)	6,517.2		522.6		(3,017.5		)	8,473.1		(5,982.5		)	6,512.9
NONCONTROLLING INTERESTS	—		—		—			4.3		—			4.3
Total equity (deficit)	6,517.2		522.6		(3,017.5		)	8,477.4		(5,982.5		)	6,517.2
	$	11,157.9	$	5,849.7	$	2,037.5		$	19,139.3	$	(24,547.4	)	$	13,637.0

141

ENSCO PLC AND SUBSIDIARIES CONDENSED CONSOLIDATING BALANCE SHEETS December 31, 2014 (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	$	287.4	$	—	$	90.8		$	286.6	$	—		$	664.8
Short-term investments	712.0		—		—			45.3		—			757.3
Accounts receivable, net	—		—		—			883.3		—			883.3
Accounts receivable from   affiliates	34.5		210.4		—			134.6		(379.5		)	—
Other	4.1		68.9		—			512.6		—			585.6
Total current assets	1,038.0		279.3		90.8			1,862.4		(379.5		)	2,891.0
PROPERTY AND EQUIPMENT, AT COST	2.1		71.5		—			14,901.9		—			14,975.5
Less accumulated depreciation	1.7		34.1		—			2,404.9		—			2,440.7
Property and equipment, net	.4		37.4		—			12,497.0		—			12,534.8
GOODWILL	—		—		—			276.1		—			276.1
DUE FROM AFFILIATES	2,873.2		4,748.2		1,835.0			6,308.8		(15,765.2		)	—
INVESTMENTS IN AFFILIATES	9,084.8		1,233.5		461.6			—		(10,779.9		)	—
OTHER ASSETS, NET	17.0		47.4		—			274.5		—			338.9
	$	13,013.4	$	6,345.8	$	2,387.4		$	21,218.8	$	(26,924.6	)	$	16,040.8
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable and accrued      liabilities	$	47.8	$	42.8	$	34.3		$	942.4	$	—		$	1,067.3
Accounts payable to affiliates	23.5		158.3		—			197.7		(379.5		)	—
Current maturities of long-term   debt	—		—		—			34.8		—			34.8
Total current liabilities	71.3		201.1		34.3			1,174.9		(379.5		)	1,102.1
DUE TO AFFILIATES	994.8		3,817.4		1,547.7			9,405.3		(15,765.2		)	—
LONG-TERM DEBT	3,724.4		149.2		1,973.2			38.8		—			5,885.6
DEFERRED INCOME TAXES	—		158.8		—			4.1		—			162.9
OTHER LIABILITIES	—		6.1		7.0			654.2		—			667.3
ENSCO SHAREHOLDERS' EQUITY	8,222.9		2,013.2		(1,174.8		)	9,933.6		(10,779.9		)	8,215.0
NONCONTROLLING INTERESTS	—		—		—			7.9		—			7.9
Total equity	8,222.9		2,013.2		(1,174.8		)	9,941.5		(10,779.9		)	8,222.9
	$	13,013.4	$	6,345.8	$	2,387.4		$	21,218.8	$	(26,924.6	)	$	16,040.8

142

ENSCO PLC AND SUBSIDIARIES CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS Year Ended December 31, 2015 (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      operatingactivities of continuing operations	$	(71.1	)	$	2.0		$	(114.0	)	$	1,881.0		$	—	$	1,697.9
INVESTING ACTIVITIES
Purchases of short-term investments	(1,780.0		)	—			—			—			—		(1,780.0		)
Additions to property and equipment	—			—			—			(1,619.5		)	—		(1,619.5		)
Maturities of short-term investments	1,312.0			—			—			45.3			—		1,357.3
Net proceeds from disposition of assets	.3			—			—			1.3			—		1.6
Net cash used in investing activities of continuing operations	(467.7		)	—			—			(1,572.9		)	—		(2,040.6		)
FINANCING ACTIVITIES
Proceeds from debt issuance	1,078.7			—			—			—			—		1,078.7
Reduction of long-term   borrowings	(1,072.5		)	—			—			—			—		(1,072.5		)
Cash dividends paid	(141.2		)	—			—			—			—		(141.2		)
Premium paid on redemption of debt	(30.3		)	—			—			—			—		(30.3		)
Debt financing costs	(10.5		)	—			—			—			—		(10.5		)
Proceeds from exercise of share   options	.3			—			—			—			—		.3
Advances from (to) affiliates	526.2			(2.0		)	25.2			(549.4		)	—		—
Other	(5.3		)	—			—			(11.0		)	—		(16.3		)
Net cash provided by (used in)          financing activities	345.4			(2.0		)	25.2			(560.4		)	—		(191.8		)
DISCONTINUED OPERATIONS
Operating activities	—			—			—			(10.9		)	—		(10.9		)
Investing activities	—			—			—			2.2			—		2.2
Net cash used in discontinued operations	—			—			—			(8.7		)	—		(8.7		)
Effect of exchange rate changes on cash and cash equivalents	—			—			—			(.3		)	—		(0.3		)
DECREASE IN CASH AND CASH EQUIVALENTS	(193.4		)	—			(88.8		)	(261.3		)	—		(543.5		)
CASH AND CASH EQUIVALENTS, BEGINNING OF YEAR	287.4			—			90.8			286.6			—		664.8
CASH AND CASH EQUIVALENTS, END OF YEAR	$	94.0		$	—		$	2.0		$	25.3		$	—	$	121.3

143

ENSCO PLC AND SUBSIDIARIES CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS Year Ended December 31, 2014 (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      operatingactivities of continuing operations	$	(63.8	)	$	(167.6	)	$	(90.9	)	$	2,380.2		$	—	$	2,057.9
INVESTING ACTIVITIES
Additions to property and   equipment	—			(37.2		)	—			(1,529.5		)	—		(1,566.7		)
Purchases of short-term investments	(716.1		)	—			—			(74.5		)	—		(790.6		)
Net proceeds from disposition of assets	—			—			—			169.2			—		169.2
Maturities of short-term investments	—			—			—			83.3			—		83.3
Net cash used in investing activities of continuing operations	(716.1		)	(37.2		)	—			(1,351.5		)	—		(2,104.8		)
FINANCING ACTIVITIES
Proceeds from debt issuance	1,246.4			—			—			—			—		1,246.4
Cash dividends paid	(703.0		)	—			—			—			—		(703.0		)
Reduction of long-term   borrowings	—			—			—			(60.1		)	—		(60.1		)
Debt financing costs	(13.4		)	—			—			—			—		(13.4		)
Proceeds from exercise of share   options	2.6			—			—			—			—		2.6
Advances from (to) affiliates	501.9			204.3			176.8			(883.0		)	—		—
Other	(13.7		)	—			—			(16.1		)	—		(29.8		)
Net cash provided by (used in)          financing activities	1,020.8			204.3			176.8			(959.2		)	—		442.7
DISCONTINUED OPERATIONS
Operating activities	—			—			—			(3.8		)	—		(3.8		)
Investing activities	—			—			—			107.2			—		107.2
Net cash provided by discontinued operations	—			—			—			103.4			—		103.4
Effect of exchange rate changes   on cash and cash equivalents	—			—			—			—			—		—
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	240.9			(.5		)	85.9			172.9			—		499.2
CASH AND CASH EQUIVALENTS, BEGINNING OF YEAR	46.5			.5			4.9			113.7			—		165.6
CASH AND CASH EQUIVALENTS, END OF YEAR	$	287.4		$	—		$	90.8		$	286.6		$	—	$	664.8

144

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      operatingactivities of continuing operations	$	(114.8	)	$	(128.7	)	$	(62.9	)	$	2,117.6		$	—	$	1,811.2
INVESTING ACTIVITIES
Additions to property and equipment	—			—			—			(1,763.5		)	—		(1,763.5		)
Purchases of short-term investments	—			—			—			(50.0		)	—		(50.0		)
Maturities of short-term investments	—			—			—			50.0			—		50.0
Net proceeds from disposition of assets	—			(4.1		)	—			10.1			—		6.0
Net cash used in investing activities of    continuing operations	—			(4.1		)	—			(1,753.4		)	—		(1,757.5		)
FINANCING ACTIVITIES
Cash dividends paid	(525.6		)	—			—			—			—		(525.6		)
Reduction of long-term borrowing	—			—			—			(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	—			—			—			169.3			—		169.3
Investing activities	—			—			—			32.8			—		32.8
Net cash provided by discontinued operations	—			—			—			202.1			—		202.1
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

145

16.  UNAUDITED QUARTERLY FINANCIAL DATA

The following tables summarize our unaudited quarterly consolidated income statement data for the years ended December 31, 2015 and 2014 (in millions, except per share amounts):

2015	First  Quarter			Second Quarter			Third Quarter			Fourth  Quarter			Year
Operating revenues	$	1,163.9		$	1,059.0		$	1,012.2		$	828.3		$	4,063.4
Operating expenses
Contract drilling (exclusive of depreciation)	518.3			502.6			433.5			415.2			1,869.6
Loss on impairment	—			—			2.4			2,744.0			2,746.4
Depreciation	137.1			140.5			145.2			149.7			572.5
General and administrative	30.1			29.7			28.4			30.2			118.4
Operating income (loss)	478.4			386.2			402.7			(2,510.8		)	(1,243.5		)
Other expense, net	(72.6		)	(55.4		)	(52.4		)	(47.3		)	(227.7		)
Income (loss) from continuing operations before income taxes	405.8			330.8			350.3			(2,558.1		)	(1,471.2		)
Income tax expense (benefit)	77.7			58.0			33.2			(182.8		)	(13.9		)
Income (loss) from continuing operations	328.1			272.8			317.1			(2,375.3		)	(1,457.3		)
Loss from discontinued operations, net	(.2		)	(10.1		)	(23.3		)	(95.0		)	(128.6		)
Net income (loss)	327.9			262.7			293.8			(2,470.3		)	(1,585.9		)
Net income attributable to noncontrolling interests	(3.2		)	(2.4		)	(1.8		)	(1.5		)	(8.9		)
Net income (loss) attributable to Ensco	$	324.7		$	260.3		$	292.0		$	(2,471.8	)	$	(1,594.8	)
Earnings (loss) per share – basic and diluted
Continuing operations	$	1.38		$	1.15		$	1.34		$	(10.23	)	$	(6.33	)
Discontinued operations	—			(0.04		)	(0.10		)	(0.41		)	(0.55		)
	$	1.38		$	1.11		$	1.24		$	(10.64	)	$	(6.88	)

146

2014	First  Quarter			Second Quarter			Third Quarter			Fourth  Quarter			Year
Operating revenues	$	1,066.7		$	1,136.6		$	1,201.4		$	1,159.8		$	4,564.5
Operating expenses
Contract drilling (exclusive of depreciation)	520.2			542.5			500.2			514.0			2,076.9
Loss on Impairment	—			703.5			—			3,515.2			4,218.7
Depreciation	131.1			132.2			135.2			139.4			537.9
General and administrative	38.1			36.2			29.3			28.3			131.9
Operating income (loss)	377.3			(277.8		)	536.7			(3,037.1		)	(2,400.9		)
Other expense, net	(29.1		)	(30.8		)	(38.4		)	(49.6		)	(147.9		)
Income (loss) from continuing operations before income taxes	348.2			(308.6		)	498.3			(3,086.7		)	(2,548.8		)
Income tax expense (benefit)	49.5			42.6			74.6			(26.2		)	140.5
Income (loss) from continuing operations	298.7			(351.2		)	423.7			(3,060.5		)	(2,689.3		)
(Loss) income from discontinued operations, net	(2.0		)	(818.4		)	9.2			(388.0		)	(1,199.2		)
Net income (loss)	296.7			(1,169.6		)	432.9			(3,448.5		)	(3,888.5		)
Net income attributable to noncontrolling interests	(4.2		)	(3.1		)	(3.5		)	(3.3		)	(14.1		)
Net income (loss) attributable to Ensco	$	292.5		$	(1,172.7	)	$	429.4		$	(3,451.8	)	$	(3,902.6	)
Earnings (loss) per share – basic and diluted
Continuing operations	$	1.26		$	(1.53	)	$	1.79		$	(13.22	)	$	(11.70	)
Discontinued operations	(0.01		)	(3.54		)	0.04			(1.67		)	(5.18		)
	$	1.25		$	(5.07	)	$	1.83		$	(14.89	)	$	(16.88	)

147

Item 9.  Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

Not applicable.

Item 9A.  Controls and Procedures

CONCLUSION REGARDING THE EFFECTIVENESS OF DISCLOSURE CONTROLS AND PROCEDURES

Based on their evaluation as of the end of the period covered by this Annual Report on Form 10-K, our management, with the participation of our Chief Executive Officer and Chief Financial Officer, has concluded that our disclosure controls and procedures, as defined in Rule 13a-15 under the Exchange Act, are effective.

During the fiscal quarter ended December 31, 2015, there were no changes in our internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

See "Item 8. Financial Statements and Supplementary Data" for Management's Report on Internal Control Over Financial Reporting.

Item 9B.  Other Information

    Not applicable.

148

PART III

Item 10.  Directors, Executive Officers and Corporate Governance

The information required by this item with respect to our directors, corporate governance matters, committees of the Board of Directors and Section 16(a) of the Exchange Act is contained in our Proxy Statement for the Annual General Meeting of Shareholders ("Proxy Statement") to be filed with the SEC not later than 120 days after the end of our fiscal year ended December 31, 2015 and incorporated herein by reference.

The information required by this item with respect to our executive officers is set forth in "Executive Officers" in Part I of this Annual Report on Form 10-K.

The guidelines and procedures of the Board of Directors are outlined in our Corporate Governance Policy. The committees of the Board of Directors operate under written charters adopted by the Board of Directors. The Corporate Governance Policy and committee charters are available on our website at www.enscoplc.com in the Corporate Governance section and are available in print without charge by contacting our Investor Relations Department at 713-430-4607.

We have a Code of Business Conduct Policy that applies to all employees, including our principal executive officer, principal financial officer and controller. The Code of Business Conduct Policy is available on our website at www.enscoplc.com in the Corporate Governance section and is available in print without charge by contacting our Investor Relations Department. We intend to disclose any amendments to or waivers from our Code of Business Conduct Policy by posting such information on our website. Our Proxy Statement contains governance disclosures, including information on our Code of Business Conduct Policy, the Ensco Corporate Governance Policy, the director nomination process, shareholder director nominations, shareholder communications to the Board of Directors and director attendance at the Annual General Meeting of Shareholders.

Item 11.  Executive Compensation

    The information required by this item is contained in our Proxy Statement and incorporated herein by reference.

149

Item 12.  Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters

The following table summarizes certain information related to our compensation plans under which our shares are authorized for issuance as of December 31, 2015:

Plan category	Number of securities to be issued upon exercise of outstanding options, warrants and rights	Weighted-average exercise price of outstanding options, warrants and rights		Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a))(1)
	(a)	(b)		(c)
Equity compensation      plans approved by       security holders	270,408	$	43.81	12,860,394
Equity compensation      plans not approved by      security holders(2)	187,877	38.19		—
Total	458,285	$	41.51	12,860,394

(1)

Under the 2012 LTIP, 12.9 million shares remained available for future issuances of non-vested share awards, share option awards and performance awards as of December 31, 2015.  Our performance awards will be settled in Ensco shares.

(2)

In connection with the Pride acquisition, we assumed Pride’s option plan and the outstanding options thereunder. As of December 31, 2015, options to purchase 187,877 shares at a weighted-average exercise price of $38.19 per share were outstanding under this plan. No shares are available for future issuance under this plan, no further options will be granted under this plan and the plan will be terminated upon the earlier of the exercise or expiration date of the last outstanding option.

Additional information required by this item is included in our Proxy Statement and incorporated herein by reference.

Item 13.  Certain Relationships and Related Transactions, and Director Independence

    The information required by this item is contained in our Proxy Statement and incorporated herein by reference.

Item 14.  Principal Accounting Fees and Services

    The information required by this item is contained in our Proxy Statement and incorporated herein by reference.

150

Item 15.  Exhibits, Financial Statement Schedules

(a)	The following documents are filed as part of this report:
	1.  Financial Statements
	Reports of Independent Registered Public Accounting Firm	86
	Consolidated Statements of Operations	88
	Consolidated Statements of Comprehensive Income	89
	Consolidated Balance Sheets	90
	Consolidated Statements of Cash Flows	91
	Notes to Consolidated Financial Statements	92
	2.  Financial Statement Schedules:
	The schedules for which provision is made in the applicable accounting regulations of the SEC are not required under the related instructions or are inapplicable or provided elsewhere in the financial statements and, therefore, have been omitted.

 3.  Exhibits

Exhibit         Number	Exhibit
3.1	Certificate of Incorporation on Change of Name (incorporated by reference to Exhibit 3.1 to the Registrant's Current Report on Form 8-K filed on April 1, 2010, File No. 1-8097).
3.2	Articles of Association of Ensco plc (incorporated by reference to Annex 2 to the Registrant's Proxy Statement on Form DEF 14A filed on April 5, 2013, as adopted by Special Resolution passed on May 20, 2013, File No. 1-8097).
4.1	Indenture, dated November 20, 1997, between ENSCO International Incorporated and Deutsche Bank Trust Company Americas (successor to Bankers Trust Company), as Trustee (incorporated by reference to Exhibit 4.1 to the Registrant's Current Report on Form 8-K filed on November 24, 1997, File No. 1-8097).
4.2	First Supplemental Indenture, dated November 20, 1997, between ENSCO International Incorporated and Deutsche Bank Trust Company Americas (successor to Bankers Trust Company, as Trustee (incorporated by reference to Exhibit 4.2 to the Registrant's Current Report on Form 8-K, filed on November 24, 1997, File No. 1-8097).
4.3	Second Supplemental Indenture, dated December 22, 2009, among ENSCO International Incorporated, Ensco International plc and Deutsche Bank Trust Company Americas, as Trustee (incorporated by reference to Exhibit 4.1 to the Registrant's Current Report on Form 8-K filed on December 23, 2009, File No. 1-8097).
4.4	Form of Debenture (incorporated by reference to Exhibit 4.4 to the Registrant's Current Report on Form 8-K filed on November 24, 1997, File No. 1-8097).
4.5	Indenture, dated July 1, 2004, between Pride International, Inc. and The Bank of New York Mellon, as Trustee, including the form of notes issued pursuant thereto (successor to JPMorgan Chase Bank) (incorporated by reference to Exhibit 4.1 to Pride's Registration Statement on Form S-4 filed on August 10, 2004, File No. 333-118104).
4.6	Second Supplemental Indenture, dated June 2, 2009, between Pride International, Inc. and The Bank of New York Mellon, as Trustee, including the form of notes issued pursuant thereto (incorporated by reference to Exhibit 4.1 to Pride's Quarterly Report on Form 10-Q for the quarter ended June 30, 2009, File No. 1-13289).

151

4.7	Third Supplemental Indenture, dated August 6, 2010, between Pride International, Inc. and The Bank of New York Mellon, as Trustee, including the form of notes issued pursuant thereto (incorporated by reference to Exhibit 4.3 to Pride's Quarterly Report on Form 10-Q for the quarter ended September 30, 2010, File No. 1-13289).
4.8	Fourth Supplemental Indenture, dated May 31, 2011, among Ensco plc, Pride International, Inc. and The Bank of New York Mellon, as Trustee (incorporated by reference to Exhibit 4.4 to the Registrant's Current Report on Form 8-K filed on May 31, 2011, File No. 1-8097).
4.9	Form of Guarantee by Ensco plc (incorporated by reference to Exhibit 4.4  to the Registrant's Current Report on Form 8-K filed on May 31, 2011, File No. 1-8097).
4.10	Indenture, dated March 17, 2011, between Ensco plc and Deutsche Bank Trust Company Americas, as Trustee (incorporated by reference to Exhibit 4.22 to Post-Effective Amendment No. 2 to the Registrant's Registration Statement on Form S-3 filed on March 17, 2011, File No. 333-156705).
4.11	First Supplemental Indenture, dated March 17, 2011, between Ensco plc and Deutsche Bank Trust Company Americas, as Trustee (incorporated by reference to Exhibit 4.23 to Post-Effective Amendment No. 2 to the Registrant's Registration Statement on Form S-3 filed on March 17, 2011, File No. 333-156705).
4.12	Second Supplemental Indenture, dated as of September 29, 2014, between Ensco plc and Deutsche Bank Trust Company Americas, as Trustee (incorporated by reference to Exhibit 4.1 to the Registrant's Quarterly Report on Form 10-Q filed on October 30, 2014, File No.1-8097).
4.13	Third Supplemental Indenture, dated as of March 12, 2015, between Ensco plc and Deutsche Bank Trust Company Americas, as Trustee (incorporated by reference to Exhibit 4.3 to the Registrant's Current Report on Form 8-K filed on March 12, 2015, File No. 1-8097).
4.14	Form of Note for 4.50% Senior Notes due 2024 (incorporated by reference to Exhibit 4.2 to the Registrant's Quarterly Report on Form 10-Q filed on October 30, 2014, File No.1-8097).
4.15	Form of Note for 5.75% Senior Notes due 2044 (incorporated by reference to Exhibit 4.3 to the Registrant's Quarterly Report on Form 10-Q filed on October 30, 2014, File No.1-8097).
4.16	Form of Note for 5.20% Senior Notes due 2025 (incorporated by reference to Exhibit 4.4 to the Registrant's Current Report on Form 8-K filed on March 12, 2015, File No. 1-8097).
4.17	Form of Global Note for 4.700% Senior Notes due 2021 (incorporated by reference to Exhibit B of Exhibit 4.23 to Post-Effective Amendment No. 2 to the Registrant's Registration Statement on Form S-3 filed on March 17, 2011, File No. 333-156705).
4.18	Form of Deed of Release of Shareholders (incorporated by reference to Annex A to the Registrant's Proxy Statement on Schedule 14A filed on April 5, 2011, File No. 1-8097).
10.1	Fourth Amended and Restated Credit Agreement, dated May 7, 2013, by and among Ensco plc, and Pride International, Inc., as Borrowers, the Banks named therein, Citibank, N.A., as Administrative Agent, DNB Bank ASA, as Syndication Agent, Deutsche Bank Securities Inc., HSBC Bank USA, NA and Wells Fargo Bank, National Association, as Co-Documentation Agents, and Citigroup Global Markets Inc., DNB Markets, Inc., Deutsche Bank Securities Inc., HSBC Securities (USA) Inc. and Wells Fargo Securities, LLC, as Joint Lead Arrangers and Joint Book Managers (incorporated by reference to Exhibit 10.1 to the Registrant's Current Report on Form 8-K filed on May 13, 2013, File No. 1-8097).
10.2	First Amendment to the Fourth Amended and Restated Credit Agreement, dated as of September 30, 2014, by and among Ensco plc, and Pride International, Inc., the lenders named therein, and Citibank, N.A., as Administrative Agent (incorporated by reference to Exhibit 10.1 to the Registrant's Current Report filed on Form 8-K on October 1, 2014 File No. 1-8097).
10.3	Second Amendment to Fourth Amended and Restated Credit Agreement, dated as of March 9, 2015, by and among Ensco plc, Pride International, Inc., the lenders party thereto and Citibank, N.A., as Administrative Agent (incorporated by reference to Exhibit 10.1 to the Registrant's Current Report filed on Form 8-K on March 12, 2015 File No. 1-8097)
+10.4	Pride International, Inc. 1998 Long-Term Incentive Plan (As Amended and Restated Effective February 17, 2005) (incorporated by reference to Exhibit 10.21 to Pride's Annual Report on Form 10-K for the year ended December 31, 2004, File No. 1-13289).
+10.5	Amendment to Pride International, Inc. 1998 Long-Term Incentive Plan (As Amended and Restated Effective February 17, 2005) (incorporated by reference to Exhibit 4.37 to the Registrant's Registration Statement on Form S-8 filed on May 31, 2011, File No. 333-174611).

152

+10.6	2012 Amendment to the Pride International, Inc. 1998 Long-Term Incentive Plan (As Amended and Restated Effective February 17, 2005 and As Assumed by Ensco plc as of May 31, 2011), effective May 14, 2012 (incorporated by reference to Exhibit 10.4 to the Registrant's Current Report on Form 8-K filed on May 15, 2012, File No. 1-8097).
+10.7	Pride International, Inc. 2004 Directors' Stock Incentive Plan (As Amended and Restated Effective March 26, 2008) (incorporated by reference to Appendix B to Pride's Proxy Statement on Schedule 14A filed on April 9, 2008, File No. 1-13289).
+10.8	First Amendment to the Pride International, Inc. 2004 Directors' Stock Incentive Plan (As Amended and Restated March 26, 2008), effective August 14, 2008 (incorporated by reference to Exhibit 10.2 to Pride's Quarterly Report on Form 10-Q for the quarter ended September 30, 2008, File No. 1-13289).
+10.9	Amendment to the Pride International, Inc. 2004 Directors' Stock Incentive Plan (As Amended and Restated Effective March 26, 2008), effective May 31, 2011 (incorporated by reference to Exhibit 4.36 to the Registrant's Registration Statement on Form S-8 filed on May 31, 2011, File No. 333-174611).
+10.10	2012 Amendment to the Pride International, Inc. 2004 Directors' Stock Incentive Plan (As Amended and Restated Effective March 26, 2008 and As Assumed by Ensco plc as of May 31, 2011), effective May 14, 2012 (incorporated by reference to Exhibit 10.5 to the Registrant's Current Report on Form 8-K filed on May 15, 2012, File No. 1-8097).
+10.11	Pride International, Inc. 2007 Long-Term Incentive Plan (As Amended and Restated Effective March 24, 2010) (incorporated by reference to Appendix A to Pride's Proxy Statement on Schedule 14A filed on April 1, 2010, File No. 1-13289).
+10.12	First Amendment to Pride International, Inc. 2007 Long-Term Incentive Plan (As Amended and Restated Effective March 16, 2010), effective August 13, 2010 (incorporated by reference to Exhibit 10.1 to Pride's Quarterly Report on Form 10-Q for the quarter ended September 30, 2010, File No. 1-13289).
+10.13	Amendment to the Pride International, Inc. 2007 Long-Term Incentive Plan (As Amended and Restated Effective March 16, 2010), effective May 31, 2011 (incorporated by reference to Exhibit 4.35 to the Registrant's Registration Statement on Form S-8 filed on May 31, 2011, File No. 333-174611).
+10.14	2012 Amendment to the Pride International, Inc. 2007 Long-Term Incentive Plan (As Amended and Restated Effective March 16, 2010 and As Assumed by Ensco plc as of May 31, 2011), effective May 14, 2012 (incorporated by reference to Exhibit 10.6 to the Registrant's Current Report on Form 8-K filed on May 15, 2012, File No. 1-8097).
+10.15	Deed of Assumption by Ensco plc relating to Equity Incentive Plans of Pride International, Inc., dated May 26, 2011 (incorporated by reference to Exhibit 4.34 to the Registrant's Registration Statement on Form S-8 filed on May 31, 2011, File No. 333-174611).
+10.16	Form of Deed of Release of Directors (incorporated by reference to Annex B to the Registrant's Proxy Statement on Schedule 14A filed on April 5, 2011, File No. 1-8097).
+10.17	Form of Deed of Indemnity for Directors and Executive Officers of Ensco plc (incorporated by reference to Exhibit 10.27 to the Registrant's Quarterly Report on Form 10-Q for the quarter ended June 30, 2011, File No. 1-8097).
+10.18	ENSCO Non-Employee Director Deferred Compensation Plan, effective January 1, 2004 (incorporated by reference to Exhibit 10.1 to the Registrant's Quarterly Report on Form 10-Q for the quarter ended September 30, 2003, File No. 1-8097).
+10.19	Amendment No. 1 to the ENSCO Non-Employee Director Deferred Compensation Plan, dated March 11, 2008 (incorporated by reference to Exhibit 10.3 to the Registrant's Quarterly Report on Form 10-Q for the quarter ended March 31, 2008, File No. 1-8097).
+10.20	Amendment No. 2 to the ENSCO Non-Employee Director Deferred Compensation Plan, dated August 4, 2009 (incorporated by reference to Exhibit 10.4 to the Registrant's Quarterly Report on Form 10-Q for the quarter ended September 30, 2009, File No. 1-8097).
+10.21	Amendment No. 3 to the ENSCO Non-Employee Director Deferred Compensation Plan, dated December 22, 2009 (incorporated by reference to Exhibit 10.11 to the Registrant's Current Report on Form 8-K filed on December 23, 2009, File No. 1-8097).

153

+10.22	Amendment No. 4 to the ENSCO Non-Employee Director Deferred Compensation Plan, dated May 14, 2012 (incorporated by reference to Exhibit 10.7 to the Registrant's Current Report on Form 8-K filed on May 15, 2012, File No. 1-8097).
+10.23	ENSCO Supplemental Executive Retirement Plan (As Amended and Restated Effective January 1, 2004) (incorporated by reference to Exhibit 10.2 to the Registrant's Quarterly Report on Form 10-Q for the quarter ended September 30, 2003, File No. 1-8097).
+10.24	Amendment No. 1 to the ENSCO Supplemental Executive Retirement Plan (As Amended and Restated Effective January 1, 2004), dated March 11, 2008 (incorporated by reference to Exhibit 10.1 to the Registrant's Quarterly Report on Form 10-Q for the quarter ended March 31, 2008, File No. 1-8097).
+10.25	Amendment No. 2 to the ENSCO Supplemental Executive Retirement Plan (As Amended and Restated Effective January 1, 2004), dated November 4, 2008 (incorporated by reference to Exhibit 10.57 to the Registrant's Annual Report on Form 10-K for the year ended December 31, 2008, File No. 1-8097).
+10.26	Amendment No. 3 to the ENSCO Supplemental Executive Retirement Plan (As Amended and Restated Effective January 1, 2004), dated August 4, 2009 (incorporated by reference to Exhibit 10.2 to the Registrant's Quarterly Report on Form 10-Q for the quarter ended September 30, 2009, File No. 1-8097).
+10.27	Amendment No. 4 to the ENSCO Supplemental Executive Retirement Plan (As Amended and Restated Effective January 1, 2004), dated December 22, 2009 (incorporated by reference to Exhibit 10.10 to the Registrant's Current Report on Form 8-K filed on December 23, 2009, File No. 1-8097).
+10.28	Amendment No. 5 to the Ensco Supplemental Executive Retirement Plan (As Amended and Restated Effective January 1, 2004), dated May 14, 2012 (incorporated by reference to Exhibit 10.8 to the Registrant's Current Report on Form 8-K filed on May 15, 2012, File No. 1-8097).
+10.29	ENSCO Supplemental Executive Retirement Plan and Non-Employee Director Deferred Compensation Plan Trust Agreement (As Revised and Restated Effective January 1, 2004), dated August 27, 2003 (incorporated by reference to Exhibit 10.3 to the Registrant's Quarterly Report on Form 10-Q for the quarter ended September 30, 2003, File No. 1-8097).
+10.30	ENSCO 2005 Supplemental Executive Retirement Plan (As Amended and Restated Effective January 1, 2005), dated November 4, 2008 (incorporated by reference to Exhibit 10.56 to the Registrant's Annual Report on Form 10-K for the year ended December 31, 2008, File No. 1-8097).
+10.31	Amendment No. 1 to the ENSCO 2005 Supplemental Executive Retirement Plan (As Amended and Restated Effective January 1, 2005), dated August 4, 2009 (incorporated by reference to Exhibit 10.3 to the Registrant's Quarterly Report on Form 10-Q for the quarter ended September 30, 2009, File No. 1-8097).
+10.32	Amendment No. 2 to the ENSCO 2005 Supplemental Executive Retirement Plan (As Amended and Restated Effective January 1, 2005), dated November 3, 2009 (incorporated by reference to Exhibit 10.31 to the Registrant's Annual Report on Form 10-K for the year ended December 31, 2009, File No. 1-8097).
+10.33	Amendment No. 3 to the ENSCO 2005 Supplemental Executive Retirement Plan (As Amended and Restated Effective January 1, 2005), dated December 22, 2009 (incorporated by reference to Exhibit 10.8 to the Registrant's Current Report on Form 8-K filed on December 23, 2009, File No. 1-8097).
+10.34	Amendment No. 4 to the Ensco 2005 Supplemental Executive Retirement Plan (As Amended and Restated Effective January 1, 2005), dated May 14, 2012 (incorporated by reference to Exhibit 10.10 to the Registrant's Current Report on Form 8-K filed on May 15, 2012, File No. 1-8097).
+10.35	Amendment No. 5 to the Ensco 2005 Amended and Restated Supplemental Executive Retirement Plan (As Amended and Restated Effective January 1, 2005), dated May 14, 2012 (incorporated by reference to Exhibit 10.10 to the Registrant's Current Report on Form 8-K filed on May 15, 2012, File No. 1-8097).
+10.36	ENSCO 2005 Benefit Reserve Trust, effective January 1, 2005 (incorporated by reference to Exhibit 99.3 to the Registrant's Current Report on Form 8-K filed on January 5, 2005, File No. 1-8097).
+10.37	Deed of Assumption relating to Equity Incentive Plans of ENSCO International Incorporated, dated December 22, 2009, executed by Ensco International plc (incorporated by reference to Exhibit 10.1 to the Registrant's Current Report on Form 8-K filed on December 23, 2009, File No. 1-8097).

154

+10.38	ENSCO International Incorporated 2005 Long-Term Incentive Plan (As Revised and Restated on December 22, 2009 and As Assumed by Ensco International plc as of December 23, 2009), effective December 23, 2009 (incorporated by reference to Exhibit 10.3 to the Registrant's Current Report on Form 8-K filed on December 23, 2009, File No. 1-8097).
+10.39	First Amendment to the ENSCO International Incorporated 2005 Long-Term Incentive Plan (As Revised and Restated on December 22, 2009 and As Assumed by Ensco plc as of December 23, 2009), dated March 1, 2011 (incorporated by reference to Exhibit 10.2 to the Registrant's Quarterly Report on Form 10-Q for the period ending March 31, 2011, File No. 1-8097).
+10.40	Second Amendment to the ENSCO International Incorporated 2005 Long-Term Incentive Plan (As Revised and Restated on December 22, 2009 and As Assumed by Ensco plc as of December 23, 2009), effective August 23, 2011 (incorporated by reference to Exhibit 10.2 to the Registrant's Quarterly Report on Form 10-Q for the period ending September 30, 2011, File No. 1-8097).
+10.41	Third Amendment to the ENSCO International Incorporated 2005 Long-Term Incentive Plan (As Revised and Restated on December 22, 2009 and As Assumed by Ensco plc as of December 23, 2009), dated May 14, 2012 (incorporated by reference to Exhibit 10.1 to the Registrant's Current Report on Form 8-K filed on May 15, 2012, File No. 1-8097).
+10.42	Fourth Amendment to the ENSCO International Incorporated 2005 Long-Term Incentive Plan (As Revised and Restated on December 22, 2009 and As Assumed by Ensco plc as of December 23, 2009), dated January 1, 2013 (incorporated by reference to Exhibit 10.1 to the Registrant's Quarterly Report on Form 10-Q for the period ending June 30, 2013, File No. 1-8097).
+10.43	Form of ENSCO International Incorporated 2005 Long-Term Incentive Plan Performance Unit Award Agreement Terms and Conditions (incorporated by reference to Exhibit 10.7 to the Registrant's Current Report on Form 8-K filed on November 6, 2009, File No. 1-8097).
+10.44	Form of Ensco Performance-Based Long-Term Incentive Award Summary (incorporated by reference to Exhibit 10.6 to the Registrant's Current Report on Form 8-K filed on November 6, 2009, File No. 1-8097).
*+10.45	Amended and Restated ENSCO International Incorporated 2005 Cash Incentive Plan (as revised and restated for amendments through March 30, 2015) (incorporated by reference to Annex 3 to the Registrant's Proxy Statement on Schedule 14A filed on April 3, 2015, File No. 1-8097).
+10.46	Form of ENSCO International Incorporated Director Indemnification Agreement (incorporated by reference to Exhibit 10.1 to the Registrant's Current Report on Form 8-K filed on November 6, 2009, File No. 1-8097).
+10.47	Form of ENSCO International Incorporated Executive Officer Indemnification Agreement (incorporated by reference to Exhibit 10.2 to the Registrant's Current Report on Form 8-K filed on November 6, 2009, File No. 1-8097).
+10.48	Form of ENSCO International Incorporated Director and/or Officer Indemnification Agreement with Daniel W. Rabun (incorporated by reference to Exhibit 10.3 to the Registrant's Current Report on Form 8-K filed on November 6, 2009, File No. 1-8097).
+10.49	Form of ENSCO International Incorporated Director and/or Officer Indemnification Agreement with John Mark Burns (incorporated by reference to Exhibit 10.4 to the Registrant's Current Report on Form 8-K filed on November 6, 2009, File No. 1-8097).
+10.50	Form of Indemnification Agreement of ENSCO International Incorporated (incorporated by reference to Exhibit 10.12 to the Registrant's Current Report on Form 8-K filed on December 23, 2009, File No. 1-8097).
+10.51	Form of Deed of Indemnity of Ensco International plc (incorporated by reference to Exhibit 10.13 to the Registrant's Current Report on Form 8-K filed on December 23, 2009, File No. 1-8097).
+10.52	Employment Offer Letter between ENSCO International Incorporated and Mark Burns, dated May 19, 2008 and accepted on May 22, 2008 (incorporated by reference to Exhibit 10.3 to the Registrant's Quarterly Report on Form 10-Q for the quarter ended June 30, 2008, File No. 1-8097).
+10.53	Employment Offer Letter between ENSCO International Incorporated and Carey Lowe, dated June 23, 2008 and accepted July 22, 2008 (incorporated by reference to Exhibit 10.1 to the Registrant's Quarterly Report on Form 10-Q for the quarter ended September 30, 2008, File No. 1-8097).
+10.54	Summary of Relocation Benefits of Certain Executive Officers (incorporated by reference to Item 5.02 to the Registrant's Current Report on Form 8-K filed on December 1, 2009, File No. 1-8097).

155

+10.55	Ensco plc 2012 Long-Term Incentive Plan, effective January 1, 2012 (incorporated by reference to Annex A to the Registrant's Proxy Statement filed on April 4, 2012, File No. 1-8097).
+10.56	First Amendment to the Ensco plc 2012 Long-Term Incentive Plan, effective August 21, 2012 (incorporated by reference to the Registrant's Quarterly Report on Form 10-Q for the quarter ended September 30, 2012, File No. 1-8097).
+10.57	Second Amendment to the Ensco plc 2012 Long-Term Incentive Plan, effective January 1, 2013 (incorporated by reference to Exhibit 10.2 to the Registrant's Quarterly Report on Form 10-Q for the quarter ended June 30, 2013, File No. 1-8097).
+10.58	Third Amendment to the Ensco plc 2012 Long-Term Incentive Plan, effective March 30, 2015 (incorporated by reference to Exhibit 10.1 to the Registrant's Current Report on Form 8-K filed on May 19, 2015, File No. 1-8097).
+10.59	Deed of Variation among Ensco Global Resources Limited, Carl Trowell and Ensco Services Limited, dated June 2, 2014, together with the Employment Agreement between Ensco Global Resources Limited and Carl Trowell, dated May 3, 2014 and attached as a schedule to the Deed of Variation (incorporated by reference to Exhibit 10.1 of the Registrant's Quarterly Report on Form 10-Q filed on August 1, 2014, File No. 1-8097).
+10.60	Form of Deed of Indemnity entered into between Ensco plc and Carl Trowell as of June 2, 2014 (incorporated by reference to Exhibit 10.2 of the Registrant's Quarterly Report on Form 10-Q filed on August 1, 2014, File No. 1-8097).
+10.61	Retirement Agreement dated November 13, 2015 between Ensco plc and James W. Swent III (incorporated by reference to Exhibit 10.1 to the Registrant's Current Report on Form 8-K filed on November 16, 2015, File No. 1-8097).
+10.62	Separation Agreement dated December 8, 2015 between Ensco plc and J. Mark Burns (incorporated by reference to Exhibit 10.1 to the Registrant's Current Report on Form 8-K filed on December 11, 2015, File No. 1-8097).
*12.1	Computation of ratio of earnings to fixed charges.
*21.1	Subsidiaries of the Registrant.
*23.1	Consent of Independent Registered Public Accounting Firm.
*31.1	Certification of the Chief Executive Officer of Registrant pursuant to Rule 13a-14 or 15d-14 of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
*31.2	Certification of the Chief Financial Officer of Registrant pursuant to Rule 13a-14 or 15d-14 of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
**32.1	Certification of the Chief Executive Officer of Registrant pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
**32.2	Certification of the Chief Financial Officer of Registrant pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
*101.INS	XBRL Instance Document
*101.SCH	XBRL Taxonomy Extension Schema
*101.CAL	XBRL Taxonomy Extension Calculation Linkbase
*101.DEF	XBRL Taxonomy Extension Definition Linkbase
*101.LAB	XBRL Taxonomy Extension Label Linkbase
*101.PRE	XBRL Taxonomy Extension Presentation Linkbase
* ** +	Filed herewith. Furnished herewith. Management contracts or compensatory plans and arrangements required to be filed as exhibits pursuant to Item 15(b) of this report.

156

Certain agreements relating to our long-term debt have not been filed as exhibits as permitted by paragraph (b)(4)(iii)(A) of Item 601 of Regulation S-K since the total amount of securities authorized under any such agreements do not exceed 10% of our total assets on a consolidated basis. Upon request, we will furnish to the SEC all constituent agreements defining the rights of holders of our long-term debt not filed herewith.

157

PART IV

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized, on February 24, 2016.

                       Ensco plc

                       (Registrant)

By   /s/         CARL G. TROWELL                                      

                     Carl G. Trowell

                     President and Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the Registrant and in the capacities and on the date indicated.

Signatures	Title	Date
/s/     CARL G. TROWELL                            Carl G. Trowell	President and Chief Executive Officer and Director	February 24, 2016
/s/     PAUL E. ROWSEY III                            Paul E. Rowsey III	Chairman	February 24, 2016
/s/     J. RODERICK CLARK                         J. Roderick Clark	Director	February 24, 2016
/s/     ROXANNE J. DECYK                         Roxanne J. Decyk	Director	February 24, 2016
/s/     MARY E. FRANCIS CBE               Mary E. Francis CBE	Director	February 24, 2016
/s/     C. CHRISTOPHER GAUT                    C. Christopher Gaut	Director	February 24, 2016
/s/     GERALD W. HADDOCK                     Gerald W. Haddock	Director	February 24, 2016
/s/     FRANCIS S. KALMAN                     Francis S. Kalman	Director	February 24, 2016
/s/     KEITH O. RATTIE                          Keith O. Rattie	Director	February 24, 2016
/s/     JONATHAN H. BAKSHT                     Jonathan H. Baksht	Senior Vice President and     Chief Financial Officer     (principal financial officer)	February 24, 2016
/s/     ROBERT W. EDWARDS III             Robert W. Edwards III	Vice President - Finance (principal accounting officer)	February 24, 2016

158

INDEX TO EXHIBITS

Exhibit         Number	Exhibit
3.1	Certificate of Incorporation on Change of Name (incorporated by reference to Exhibit 3.1 to the Registrant's Current Report on Form 8-K filed on April 1, 2010, File No. 1-8097).
3.2	Articles of Association of Ensco plc (incorporated by reference to Annex 2 to the Registrant's Proxy Statement on Form DEF 14A filed on April 5, 2013, as adopted by Special Resolution passed on May 20, 2013, File No. 1-8097).
4.1	Indenture, dated November 20, 1997, between ENSCO International Incorporated and Deutsche Bank Trust Company Americas (successor to Bankers Trust Company), as Trustee (incorporated by reference to Exhibit 4.1 to the Registrant's Current Report on Form 8-K filed on November 24, 1997, File No. 1-8097).
4.2	First Supplemental Indenture, dated November 20, 1997, between ENSCO International Incorporated and Deutsche Bank Trust Company Americas (successor to Bankers Trust Company, as Trustee (incorporated by reference to Exhibit 4.2 to the Registrant's Current Report on Form 8-K, filed on November 24, 1997, File No. 1-8097).
4.3	Second Supplemental Indenture, dated December 22, 2009, among ENSCO International Incorporated, Ensco International plc and Deutsche Bank Trust Company Americas, as Trustee (incorporated by reference to Exhibit 4.1 to the Registrant's Current Report on Form 8-K filed on December 23, 2009, File No. 1-8097).
4.4	Form of Debenture (incorporated by reference to Exhibit 4.4 to the Registrant's Current Report on Form 8-K filed on November 24, 1997, File No. 1-8097).
4.5	Indenture, dated July 1, 2004, between Pride International, Inc. and The Bank of New York Mellon, as Trustee, including the form of notes issued pursuant thereto (successor to JPMorgan Chase Bank) (incorporated by reference to Exhibit 4.1 to Pride's Registration Statement on Form S-4 filed on August 10, 2004, File No. 333-118104).
4.6	Second Supplemental Indenture, dated June 2, 2009, between Pride International, Inc. and The Bank of New York Mellon, as Trustee, including the form of notes issued pursuant thereto (incorporated by reference to Exhibit 4.1 to Pride's Quarterly Report on Form 10-Q for the quarter ended June 30, 2009, File No. 1-13289).
4.7	Third Supplemental Indenture, dated August 6, 2010, between Pride International, Inc. and The Bank of New York Mellon, as Trustee, including the form of notes issued pursuant thereto (incorporated by reference to Exhibit 4.3 to Pride's Quarterly Report on Form 10-Q for the quarter ended September 30, 2010, File No. 1-13289).
4.8	Fourth Supplemental Indenture, dated May 31, 2011, among Ensco plc, Pride International, Inc. and The Bank of New York Mellon, as Trustee (incorporated by reference to Exhibit 4.4 to the Registrant's Current Report on Form 8-K filed on May 31, 2011, File No. 1-8097).
4.9	Form of Guarantee by Ensco plc (incorporated by reference to Exhibit 4.4  to the Registrant's Current Report on Form 8-K filed on May 31, 2011, File No. 1-8097).
4.10	Indenture, dated March 17, 2011, between Ensco plc and Deutsche Bank Trust Company Americas, as Trustee (incorporated by reference to Exhibit 4.22 to Post-Effective Amendment No. 2 to the Registrant's Registration Statement on Form S-3 filed on March 17, 2011, File No. 333-156705).
4.11	First Supplemental Indenture, dated March 17, 2011, between Ensco plc and Deutsche Bank Trust Company Americas, as Trustee (incorporated by reference to Exhibit 4.23 to Post-Effective Amendment No. 2 to the Registrant's Registration Statement on Form S-3 filed on March 17, 2011, File No. 333-156705).
4.12	Second Supplemental Indenture, dated as of September 29, 2014, between Ensco plc and Deutsche Bank Trust Company Americas, as Trustee (incorporated by reference to Exhibit 4.1 to the Registrant's Quarterly Report on Form 10-Q filed on October 30, 2014, File No.1-8097).

159

4.13	Third Supplemental Indenture, dated as of March 12, 2015, between Ensco plc and Deutsche Bank Trust Company Americas, as Trustee (incorporated by reference to Exhibit 4.3 to the Registrant's Current Report on Form 8-K filed on March 12, 2015, File No. 1-8097).
4.14	Form of Note for 4.50% Senior Notes due 2024 (incorporated by reference to Exhibit 4.2 to the Registrant's Quarterly Report on Form 10-Q filed on October 30, 2014, File No.1-8097).
4.15	Form of Note for 5.75% Senior Notes due 2044 (incorporated by reference to Exhibit 4.3 to the Registrant's Quarterly Report on Form 10-Q filed on October 30, 2014, File No.1-8097).
4.16	Form of Note for 5.20% Senior Notes due 2025 (incorporated by reference to Exhibit 4.4 to the Registrant's Current Report on Form 8-K filed on March 12, 2015, File No. 1-8097).
4.17	Form of Global Note for 4.700% Senior Notes due 2021 (incorporated by reference to Exhibit B of Exhibit 4.23 to Post-Effective Amendment No. 2 to the Registrant's Registration Statement on Form S-3 filed on March 17, 2011, File No. 333-156705).
4.18	Form of Deed of Release of Shareholders (incorporated by reference to Annex A to the Registrant's Proxy Statement on Schedule 14A filed on April 5, 2011, File No. 1-8097).
10.1	Fourth Amended and Restated Credit Agreement, dated May 7, 2013, by and among Ensco plc, and Pride International, Inc., as Borrowers, the Banks named therein, Citibank, N.A., as Administrative Agent, DNB Bank ASA, as Syndication Agent, Deutsche Bank Securities Inc., HSBC Bank USA, NA and Wells Fargo Bank, National Association, as Co-Documentation Agents, and Citigroup Global Markets Inc., DNB Markets, Inc., Deutsche Bank Securities Inc., HSBC Securities (USA) Inc. and Wells Fargo Securities, LLC, as Joint Lead Arrangers and Joint Book Managers (incorporated by reference to Exhibit 10.1 to the Registrant's Current Report on Form 8-K filed on May 13, 2013, File No. 1-8097).
10.2	First Amendment to the Fourth Amended and Restated Credit Agreement, dated as of September 30, 2014, by and among Ensco plc, and Pride International, Inc., the lenders named therein, and Citibank, N.A., as Administrative Agent (incorporated by reference to Exhibit 10.1 to the Registrant's Current Report filed on Form 8-K on October 1, 2014 File No. 1-8097).
10.3	Second Amendment to Fourth Amended and Restated Credit Agreement, dated as of March 9, 2015, by and among Ensco plc, Pride International, Inc., the lenders party thereto and Citibank, N.A., as Administrative Agent (incorporated by reference to Exhibit 10.1 to the Registrant's Current Report filed on Form 8-K on March 12, 2015 File No. 1-8097)
+10.4	Pride International, Inc. 1998 Long-Term Incentive Plan (As Amended and Restated Effective February 17, 2005) (incorporated by reference to Exhibit 10.21 to Pride's Annual Report on Form 10-K for the year ended December 31, 2004, File No. 1-13289).
+10.5	Amendment to Pride International, Inc. 1998 Long-Term Incentive Plan (As Amended and Restated Effective February 17, 2005) (incorporated by reference to Exhibit 4.37 to the Registrant's Registration Statement on Form S-8 filed on May 31, 2011, File No. 333-174611).
+10.6	2012 Amendment to the Pride International, Inc. 1998 Long-Term Incentive Plan (As Amended and Restated Effective February 17, 2005 and As Assumed by Ensco plc as of May 31, 2011), effective May 14, 2012 (incorporated by reference to Exhibit 10.4 to the Registrant's Current Report on Form 8-K filed on May 15, 2012, File No. 1-8097).
+10.7	Pride International, Inc. 2004 Directors' Stock Incentive Plan (As Amended and Restated Effective March 26, 2008) (incorporated by reference to Appendix B to Pride's Proxy Statement on Schedule 14A filed on April 9, 2008, File No. 1-13289).
+10.8	First Amendment to the Pride International, Inc. 2004 Directors' Stock Incentive Plan (As Amended and Restated March 26, 2008), effective August 14, 2008 (incorporated by reference to Exhibit 10.2 to Pride's Quarterly Report on Form 10-Q for the quarter ended September 30, 2008, File No. 1-13289).
+10.9	Amendment to the Pride International, Inc. 2004 Directors' Stock Incentive Plan (As Amended and Restated Effective March 26, 2008), effective May 31, 2011 (incorporated by reference to Exhibit 4.36 to the Registrant's Registration Statement on Form S-8 filed on May 31, 2011, File No. 333-174611).
+10.10	2012 Amendment to the Pride International, Inc. 2004 Directors' Stock Incentive Plan (As Amended and Restated Effective March 26, 2008 and As Assumed by Ensco plc as of May 31, 2011), effective May 14, 2012 (incorporated by reference to Exhibit 10.5 to the Registrant's Current Report on Form 8-K filed on May 15, 2012, File No. 1-8097).

160

+10.11	Pride International, Inc. 2007 Long-Term Incentive Plan (As Amended and Restated Effective March 24, 2010) (incorporated by reference to Appendix A to Pride's Proxy Statement on Schedule 14A filed on April 1, 2010, File No. 1-13289).
+10.12	First Amendment to Pride International, Inc. 2007 Long-Term Incentive Plan (As Amended and Restated Effective March 16, 2010), effective August 13, 2010 (incorporated by reference to Exhibit 10.1 to Pride's Quarterly Report on Form 10-Q for the quarter ended September 30, 2010, File No. 1-13289).
+10.13	Amendment to the Pride International, Inc. 2007 Long-Term Incentive Plan (As Amended and Restated Effective March 16, 2010), effective May 31, 2011 (incorporated by reference to Exhibit 4.35 to the Registrant's Registration Statement on Form S-8 filed on May 31, 2011, File No. 333-174611).
+10.14	2012 Amendment to the Pride International, Inc. 2007 Long-Term Incentive Plan (As Amended and Restated Effective March 16, 2010 and As Assumed by Ensco plc as of May 31, 2011), effective May 14, 2012 (incorporated by reference to Exhibit 10.6 to the Registrant's Current Report on Form 8-K filed on May 15, 2012, File No. 1-8097).
+10.15	Deed of Assumption by Ensco plc relating to Equity Incentive Plans of Pride International, Inc., dated May 26, 2011 (incorporated by reference to Exhibit 4.34 to the Registrant's Registration Statement on Form S-8 filed on May 31, 2011, File No. 333-174611).
+10.16	Form of Deed of Release of Directors (incorporated by reference to Annex B to the Registrant's Proxy Statement on Schedule 14A filed on April 5, 2011, File No. 1-8097).
+10.17	Form of Deed of Indemnity for Directors and Executive Officers of Ensco plc (incorporated by reference to Exhibit 10.27 to the Registrant's Quarterly Report on Form 10-Q for the quarter ended June 30, 2011, File No. 1-8097).
+10.18	ENSCO Non-Employee Director Deferred Compensation Plan, effective January 1, 2004 (incorporated by reference to Exhibit 10.1 to the Registrant's Quarterly Report on Form 10-Q for the quarter ended September 30, 2003, File No. 1-8097).
+10.19	Amendment No. 1 to the ENSCO Non-Employee Director Deferred Compensation Plan, dated March 11, 2008 (incorporated by reference to Exhibit 10.3 to the Registrant's Quarterly Report on Form 10-Q for the quarter ended March 31, 2008, File No. 1-8097).
+10.20	Amendment No. 2 to the ENSCO Non-Employee Director Deferred Compensation Plan, dated August 4, 2009 (incorporated by reference to Exhibit 10.4 to the Registrant's Quarterly Report on Form 10-Q for the quarter ended September 30, 2009, File No. 1-8097).
+10.21	Amendment No. 3 to the ENSCO Non-Employee Director Deferred Compensation Plan, dated December 22, 2009 (incorporated by reference to Exhibit 10.11 to the Registrant's Current Report on Form 8-K filed on December 23, 2009, File No. 1-8097).
+10.22	Amendment No. 4 to the ENSCO Non-Employee Director Deferred Compensation Plan, dated May 14, 2012 (incorporated by reference to Exhibit 10.7 to the Registrant's Current Report on Form 8-K filed on May 15, 2012, File No. 1-8097).
+10.23	ENSCO Supplemental Executive Retirement Plan (As Amended and Restated Effective January 1, 2004) (incorporated by reference to Exhibit 10.2 to the Registrant's Quarterly Report on Form 10-Q for the quarter ended September 30, 2003, File No. 1-8097).
+10.24	Amendment No. 1 to the ENSCO Supplemental Executive Retirement Plan (As Amended and Restated Effective January 1, 2004), dated March 11, 2008 (incorporated by reference to Exhibit 10.1 to the Registrant's Quarterly Report on Form 10-Q for the quarter ended March 31, 2008, File No. 1-8097).
+10.25	Amendment No. 2 to the ENSCO Supplemental Executive Retirement Plan (As Amended and Restated Effective January 1, 2004), dated November 4, 2008 (incorporated by reference to Exhibit 10.57 to the Registrant's Annual Report on Form 10-K for the year ended December 31, 2008, File No. 1-8097).
+10.26	Amendment No. 3 to the ENSCO Supplemental Executive Retirement Plan (As Amended and Restated Effective January 1, 2004), dated August 4, 2009 (incorporated by reference to Exhibit 10.2 to the Registrant's Quarterly Report on Form 10-Q for the quarter ended September 30, 2009, File No. 1-8097).

161

+10.27	Amendment No. 4 to the ENSCO Supplemental Executive Retirement Plan (As Amended and Restated Effective January 1, 2004), dated December 22, 2009 (incorporated by reference to Exhibit 10.10 to the Registrant's Current Report on Form 8-K filed on December 23, 2009, File No. 1-8097).
+10.28	Amendment No. 5 to the Ensco Supplemental Executive Retirement Plan (As Amended and Restated Effective January 1, 2004), dated May 14, 2012 (incorporated by reference to Exhibit 10.8 to the Registrant's Current Report on Form 8-K filed on May 15, 2012, File No. 1-8097).
+10.29	ENSCO Supplemental Executive Retirement Plan and Non-Employee Director Deferred Compensation Plan Trust Agreement (As Revised and Restated Effective January 1, 2004), dated August 27, 2003 (incorporated by reference to Exhibit 10.3 to the Registrant's Quarterly Report on Form 10-Q for the quarter ended September 30, 2003, File No. 1-8097).
+10.30	ENSCO 2005 Supplemental Executive Retirement Plan (As Amended and Restated Effective January 1, 2005), dated November 4, 2008 (incorporated by reference to Exhibit 10.56 to the Registrant's Annual Report on Form 10-K for the year ended December 31, 2008, File No. 1-8097).
+10.31	Amendment No. 1 to the ENSCO 2005 Supplemental Executive Retirement Plan (As Amended and Restated Effective January 1, 2005), dated August 4, 2009 (incorporated by reference to Exhibit 10.3 to the Registrant's Quarterly Report on Form 10-Q for the quarter ended September 30, 2009, File No. 1-8097).
+10.32	Amendment No. 2 to the ENSCO 2005 Supplemental Executive Retirement Plan (As Amended and Restated Effective January 1, 2005), dated November 3, 2009 (incorporated by reference to Exhibit 10.31 to the Registrant's Annual Report on Form 10-K for the year ended December 31, 2009, File No. 1-8097).
+10.33	Amendment No. 3 to the ENSCO 2005 Supplemental Executive Retirement Plan (As Amended and Restated Effective January 1, 2005), dated December 22, 2009 (incorporated by reference to Exhibit 10.8 to the Registrant's Current Report on Form 8-K filed on December 23, 2009, File No. 1-8097).
+10.34	Amendment No. 4 to the Ensco 2005 Supplemental Executive Retirement Plan (As Amended and Restated Effective January 1, 2005), dated May 14, 2012 (incorporated by reference to Exhibit 10.10 to the Registrant's Current Report on Form 8-K filed on May 15, 2012, File No. 1-8097).
+10.35	Amendment No. 5 to the Ensco 2005 Amended and Restated Supplemental Executive Retirement Plan (As Amended and Restated Effective January 1, 2005), dated May 14, 2012 (incorporated by reference to Exhibit 10.10 to the Registrant's Current Report on Form 8-K filed on May 15, 2012, File No. 1-8097).
+10.36	ENSCO 2005 Benefit Reserve Trust, effective January 1, 2005 (incorporated by reference to Exhibit 99.3 to the Registrant's Current Report on Form 8-K filed on January 5, 2005, File No. 1-8097).
+10.37	Deed of Assumption relating to Equity Incentive Plans of ENSCO International Incorporated, dated December 22, 2009, executed by Ensco International plc (incorporated by reference to Exhibit 10.1 to the Registrant's Current Report on Form 8-K filed on December 23, 2009, File No. 1-8097).
+10.38	ENSCO International Incorporated 2005 Long-Term Incentive Plan (As Revised and Restated on December 22, 2009 and As Assumed by Ensco International plc as of December 23, 2009), effective December 23, 2009 (incorporated by reference to Exhibit 10.3 to the Registrant's Current Report on Form 8-K filed on December 23, 2009, File No. 1-8097).
+10.39	First Amendment to the ENSCO International Incorporated 2005 Long-Term Incentive Plan (As Revised and Restated on December 22, 2009 and As Assumed by Ensco plc as of December 23, 2009), dated March 1, 2011 (incorporated by reference to Exhibit 10.2 to the Registrant's Quarterly Report on Form 10-Q for the period ending March 31, 2011, File No. 1-8097).
+10.40	Second Amendment to the ENSCO International Incorporated 2005 Long-Term Incentive Plan (As Revised and Restated on December 22, 2009 and As Assumed by Ensco plc as of December 23, 2009), effective August 23, 2011 (incorporated by reference to Exhibit 10.2 to the Registrant's Quarterly Report on Form 10-Q for the period ending September 30, 2011, File No. 1-8097).
+10.41	Third Amendment to the ENSCO International Incorporated 2005 Long-Term Incentive Plan (As Revised and Restated on December 22, 2009 and As Assumed by Ensco plc as of December 23, 2009), dated May 14, 2012 (incorporated by reference to Exhibit 10.1 to the Registrant's Current Report on Form 8-K filed on May 15, 2012, File No. 1-8097).

162

+10.42	Fourth Amendment to the ENSCO International Incorporated 2005 Long-Term Incentive Plan (As Revised and Restated on December 22, 2009 and As Assumed by Ensco plc as of December 23, 2009), dated January 1, 2013 (incorporated by reference to Exhibit 10.1 to the Registrant's Quarterly Report on Form 10-Q for the period ending June 30, 2013, File No. 1-8097).
+10.43	Form of ENSCO International Incorporated 2005 Long-Term Incentive Plan Performance Unit Award Agreement Terms and Conditions (incorporated by reference to Exhibit 10.7 to the Registrant's Current Report on Form 8-K filed on November 6, 2009, File No. 1-8097).
+10.44	Form of Ensco Performance-Based Long-Term Incentive Award Summary (incorporated by reference to Exhibit 10.6 to the Registrant's Current Report on Form 8-K filed on November 6, 2009, File No. 1-8097).
*+10.45	Amended and Restated ENSCO International Incorporated 2005 Cash Incentive Plan (as revised and restated for amendments through March 30, 2015) (incorporated by reference to Annex 3 to the Registrant's Proxy Statement on Schedule 14A filed on April 3, 2015, File No. 1-8097).
+10.46	Form of ENSCO International Incorporated Director Indemnification Agreement (incorporated by reference to Exhibit 10.1 to the Registrant's Current Report on Form 8-K filed on November 6, 2009, File No. 1-8097).
+10.47	Form of ENSCO International Incorporated Executive Officer Indemnification Agreement (incorporated by reference to Exhibit 10.2 to the Registrant's Current Report on Form 8-K filed on November 6, 2009, File No. 1-8097).
+10.48	Form of ENSCO International Incorporated Director and/or Officer Indemnification Agreement with Daniel W. Rabun (incorporated by reference to Exhibit 10.3 to the Registrant's Current Report on Form 8-K filed on November 6, 2009, File No. 1-8097).
+10.49	Form of ENSCO International Incorporated Director and/or Officer Indemnification Agreement with John Mark Burns (incorporated by reference to Exhibit 10.4 to the Registrant's Current Report on Form 8-K filed on November 6, 2009, File No. 1-8097).
+10.50	Form of Indemnification Agreement of ENSCO International Incorporated (incorporated by reference to Exhibit 10.12 to the Registrant's Current Report on Form 8-K filed on December 23, 2009, File No. 1-8097).
+10.51	Form of Deed of Indemnity of Ensco International plc (incorporated by reference to Exhibit 10.13 to the Registrant's Current Report on Form 8-K filed on December 23, 2009, File No. 1-8097).
+10.52	Employment Offer Letter between ENSCO International Incorporated and Mark Burns, dated May 19, 2008 and accepted on May 22, 2008 (incorporated by reference to Exhibit 10.3 to the Registrant's Quarterly Report on Form 10-Q for the quarter ended June 30, 2008, File No. 1-8097).
+10.53	Employment Offer Letter between ENSCO International Incorporated and Carey Lowe, dated June 23, 2008 and accepted July 22, 2008 (incorporated by reference to Exhibit 10.1 to the Registrant's Quarterly Report on Form 10-Q for the quarter ended September 30, 2008, File No. 1-8097).
+10.54	Summary of Relocation Benefits of Certain Executive Officers (incorporated by reference to Item 5.02 to the Registrant's Current Report on Form 8-K filed on December 1, 2009, File No. 1-8097).
+10.55	Ensco plc 2012 Long-Term Incentive Plan, effective January 1, 2012 (incorporated by reference to Annex A to the Registrant's Proxy Statement filed on April 4, 2012, File No. 1-8097).
+10.56	First Amendment to the Ensco plc 2012 Long-Term Incentive Plan, effective August 21, 2012 (incorporated by reference to the Registrant's Quarterly Report on Form 10-Q for the quarter ended September 30, 2012, File No. 1-8097).
+10.57	Second Amendment to the Ensco plc 2012 Long-Term Incentive Plan, effective January 1, 2013 (incorporated by reference to Exhibit 10.2 to the Registrant's Quarterly Report on Form 10-Q for the quarter ended June 30, 2013, File No. 1-8097).
+10.58	Third Amendment to the Ensco plc 2012 Long-Term Incentive Plan, effective March 30, 2015 (incorporated by reference to Exhibit 10.1 to the Registrant's Current Report on Form 8-K filed on May 19, 2015, File No. 1-8097).
+10.59	Deed of Variation among Ensco Global Resources Limited, Carl Trowell and Ensco Services Limited, dated June 2, 2014, together with the Employment Agreement between Ensco Global Resources Limited and Carl Trowell, dated May 3, 2014 and attached as a schedule to the Deed of Variation (incorporated by reference to Exhibit 10.1 of the Registrant's Quarterly Report on Form 10-Q filed on August 1, 2014, File No. 1-8097).

163

+10.60	Form of Deed of Indemnity entered into between Ensco plc and Carl Trowell as of June 2, 2014 (incorporated by reference to Exhibit 10.2 of the Registrant's Quarterly Report on Form 10-Q filed on August 1, 2014, File No. 1-8097).
+10.61	Retirement Agreement dated November 13, 2015 between Ensco plc and James W. Swent III (incorporated by reference to Exhibit 10.1 to the Registrant's Current Report on Form 8-K filed on November 16, 2015, File No. 1-8097).
+10.62	Separation Agreement dated December 8, 2015 between Ensco plc and J. Mark Burns (incorporated by reference to Exhibit 10.1 to the Registrant's Current Report on Form 8-K filed on December 11, 2015, File No. 1-8097).
*12.1	Computation of ratio of earnings to fixed charges.
*21.1	Subsidiaries of the Registrant.
*23.1	Consent of Independent Registered Public Accounting Firm.
*31.1	Certification of the Chief Executive Officer of Registrant pursuant to Rule 13a-14 or 15d-14 of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
*31.2	Certification of the Chief Financial Officer of Registrant pursuant to Rule 13a-14 or 15d-14 of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
**32.1	Certification of the Chief Executive Officer of Registrant pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
**32.2	Certification of the Chief Financial Officer of Registrant pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
*101.INS	XBRL Instance Document
*101.SCH	XBRL Taxonomy Extension Schema
*101.CAL	XBRL Taxonomy Extension Calculation Linkbase
*101.DEF	XBRL Taxonomy Extension Definition Linkbase
*101.LAB	XBRL Taxonomy Extension Label Linkbase
*101.PRE	XBRL Taxonomy Extension Presentation Linkbase
* ** +	Filed herewith. Furnished herewith. Management contracts or compensatory plans and arrangements required to be filed as exhibits pursuant to Item 15(b) of this report.

Certain agreements relating to our long-term debt have not been filed as exhibits as permitted by paragraph (b)(4)(iii)(A) of Item 601 of Regulation S-K since the total amount of securities authorized under any such agreements do not exceed 10% of our total assets on a consolidated basis. Upon request, we will furnish to the SEC all constituent agreements defining the rights of holders of our long-term debt not filed herewith.

164