10-K 1 esv-20161231x10k.htm 10-K Document


 
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, 2016
 
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, 2016 of $9.71) of Ensco plc held by non-affiliates of Ensco plc at that date was approximately 2,913,950,000.
 
As of February 22, 2017, there were 302,954,662 Class A ordinary shares of Ensco plc issued and outstanding.
 
DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Company's Proxy Statement for the 2017 General Meeting of Shareholders are incorporated by reference into Part III of this report.




 
 
 
 
TABLE OF CONTENTS
 
 
 
 
 
 
 
 
PART I
ITEM 1.
 
 
ITEM 1A.
 
 
ITEM 1B.
 
 
ITEM 2.
 
 
ITEM 3.
 
 
ITEM 4.
 
 
 
 
 
 
 
 
PART II
ITEM 5.
 


 
ITEM 6.
 
 
ITEM 7.
 
 
ITEM 7A.
 
 
ITEM 8.
 
 
ITEM 9.
 
 
ITEM 9A.
 
 
ITEM 9B.
 
 
 
 
 
PART III
ITEM 10.

 
ITEM 11.

 
ITEM 12.

 
ITEM 13.

 
ITEM 14.

 
 
 
 
 
 
 
 
PART IV
ITEM 15.
 
 


 
 
SIGNATURES





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 ("Securities Act"), 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; 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:
 
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;

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

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;

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, 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;

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;

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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, operations or financial results;

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 currently own and operate an offshore drilling rig fleet of 57 rigs, with drilling operations in most of the strategic markets around the globe. We also have two rigs under construction. Our rig fleet includes eight drillships, 10 dynamically positioned semisubmersible rigs, three moored semisubmersible rigs and 38 jackup rigs, including rigs under construction.  We operate the world's second largest fleet amongst competitive rigs, including one of the newest ultra-deepwater fleets in the industry, and a leading premium jackup fleet.

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 14 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 for which we receive a daily rate that may vary throughout the duration of the contractual term. The day rate we earn can vary between the full day rate and zero rate, depending on the operations of the rig. 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.

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.

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, 2016, we invested approximately $2.1 billion in the construction of new drilling rigs.

Based on our balance sheet and contractual backlog of $3.6 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.


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Floaters

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 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. During 2015, we agreed with the shipyard to delay delivery of ENSCO DS-10 until the first quarter of 2017. In January 2017, we agreed to further delay delivery of ENSCO DS-10 and $75.0 million of the final milestone payment until the first quarter of 2019 or such earlier date that we elect to take delivery. ENSCO DS-9 and ENSCO DS-10 are being actively marketed.

Jackups

During 2014, we entered into an agreement with Lamprell Energy Limited ("Lamprell") to construct two premium jackup rigs. ENSCO 140 and ENSCO 141 are significantly enhanced versions of the LeTourneau Super 116E jackup design and will incorporate Ensco's patented Canti-Leverage AdvantageSM technology. ENSCO 140 and ENSCO 141 were delivered during the third and fourth quarters of 2016, respectively. Both rigs are uncontracted and are being actively marketed. As part of our agreement with Lamprell, these rigs will be warm stacked in the shipyard at no additional cost to us for up to two years.

We previously entered into agreements with Keppel FELS ("KFELS") to construct four ultra-premium harsh environment jackup rigs (ENSCO 120, ENSCO 121, ENSCO 122 and ENSCO 123) and a premium jackup rig (ENSCO 110). ENSCO 120 was delivered during the third quarter of 2013, ENSCO 121 was delivered during the fourth quarter of 2013, ENSCO 122 was delivered during the third quarter of 2014 and ENSCO 110 was delivered during the second quarter of 2015. During the first quarter of 2016, we agreed with the shipyard to delay delivery of ENSCO 123 until the first quarter of 2018. ENSCO 123 is uncontracted.

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 11 jackup rigs, three dynamically positioned semisubmersible rigs, three moored semisubmersible rigs and two drillships during the three-year period ended December 31, 2016. We are marketing for sale two rigs, which were classified as held-for-sale in our financial statements as of December 31, 2016.

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 own and operate an offshore drilling rig fleet of 57 rigs. We also have two rigs under construction. Our rig fleet includes eight drillships (including one drillship under construction), 10 dynamically positioned semisubmersible rigs, three moored semisubmersible rigs and 38 jackup rigs (including one rig under construction).  Of our 59 rigs, 25 are located in the Middle East, Africa and Asia Pacific (including two rigs under construction), 16 are located in North and South America (including Brazil) and 18 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, plug and abandonment and decommissioning work. 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.”

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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) if operations are suspended for a specified period of time due to breakdown of major rig equipment, unsatisfactory performance, or "force majeure" events or (iii) at the convenience (without cause) of the customer (in certain 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 operations are suspended due to events beyond our reasonable control, equipment breakdown and repair, negligence or unsatisfactory performance or other specified conditions or during periods of re-drilling damaged portions of the well), 

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 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, including certain cost increases due to changes in applicable law, from our customers through day rate adjustment or direct reimbursement.    

In general, recent contract awards have been short-term in nature and subject to an extremely competitive bidding process. The intense pressure on operating day rates has resulted in rates that approximate, or are slightly lower than, 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/or demobilization fees; reduced or zero day rates during downtime; reduced standby, redrill and moving rates and limited periods in which such rates are payable; caps on reimbursements for downhole tools; reduced periods to remediate equipment breakdowns or other deviations from contractual standards of performance before the operator may terminate the contract; certain limitations on our ability to be indemnified; increases in the nature and amounts of liability allocated to us; and reduced early termination fees and/or termination notice periods.

Financial information regarding our operating segments and geographic regions is presented in Note 13 and Note 14 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."


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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 28, 2017 and February 24, 2016, respectively.

The following table summarizes our contract backlog of business as of December 31, 2016 and 2015 (in millions):
 
2016
 
2015
 
 
 
 
Floaters
$
2,154.9

 
$
3,919.5

Jackups
1,185.0

 
1,751.7

Other
281.4

 
86.2

Total
$
3,621.3

 
$
5,757.4


As of December 31, 2016, our backlog was $3.6 billion as compared to $5.8 billion as of December 31, 2015. Our floater backlog declined $1.8 billion primarily due to revenues realized during 2016, contract day rate concessions on certain rigs and contract terminations, partially offset by contract extensions. The remaining $371.5 million decline primarily related to our jackups segment and was largely due to revenues realized during 2016, partially offset by contract extensions and new contract awards.
    
The following table summarizes our contract backlog of business as of December 31, 2016 and the periods in which such revenues are expected to be realized (in millions):
 
2017
 
2018
 
2019
 
2020
and Beyond
 
 Total
Floaters
$
968.7

 
$
562.0

 
$
416.8

 
$
207.4

 
$
2,154.9

Jackups
544.2

 
362.9

 
103.2

 
174.7

 
1,185.0

Other
55.7

 
55.8

 
55.8

 
114.1

 
281.4

Total
$
1,568.6

 
$
980.7

 
$
575.8

 
$
496.2

 
$
3,621.3


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 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 unscheduled repairs, maintenance requirements, newbuild rig delivery dates, 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 decline 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.”

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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, 2017. 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, we decided not to purchase first party windstorm insurance for our rigs in the U.S. Gulf of Mexico. Accordingly, we have retained the risk for windstorm damage to our eight jackups and six floaters 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) regardless of the cause of the loss or damage. However, in certain drilling contracts our customer’s responsibility for damage to its property and the property of its other contractors contains an exception to the extent the loss or damage is due to our negligence, which exception is usually subject to negotiated caps on a per occurrence basis.  In other contracts, our customers do not assume liability for loss or damage to their property and the property of their other contractors regardless of cause. 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, cratering and seepage, 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

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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 and, in some cases, pay for some of the costs to repair the well.

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 all our 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 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, especially 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.


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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 2016, our five largest customers accounted for 50% of consolidated revenues. Total and BP, our largest customers, accounted for 13% and 12% 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.  There are numerous competitors with significant resources in the offshore contract drilling industry.

Governmental Regulation

Our operations are affected by political initiatives and by laws and regulations that relate 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 and political initiatives could adversely affect our operations in the future by significantly increasing our operating costs or restricting areas open for drilling activity.  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, or for which indemnity is prohibited by applicable law 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.


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The International Convention on Oil Pollution Preparedness, Response and Cooperation, the International Convention on Civil Liability for Oil Pollution Damage 1992, the U.K. Merchant Shipping Act 1995, Marpol 73/78 (the International Convention for the Prevention of Pollution from Ships), the U.K. Merchant Shipping (Oil Pollution Preparedness, Response and Co-operation Convention) Regulations 1998, as amended, 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 have significantly expanded potential 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, or for which indemnity is prohibited under applicable law, and could have a material adverse effect on our financial position, operating results and cash flows.

High-profile and catastrophic events such as the 2010 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 decommissioning operations. BSEE also issued regulations requiring operators to have safety and environmental management systems ("SEMS") prior to conducting operations and requiring operators and contractors to agree on how the contractors will assist the operators in complying with the SEMS. In addition, in August 2012, BSEE issued Interim Policy Document stating that it would begin issuing Incidents of Non-Compliance ("INC's") to contractors as well as operators for serious violations of BSEE regulations. Although we have not yet incurred 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.

In November 2014, the United States Coast Guard ("USCG") 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. These regulations are expected to be issued late in 2017 or early 2018. On July 28, 2016, BSEE adopted a new well-control rule that will be implemented in phases over the next several years. This new rule includes more stringent design requirements for well-control equipment used in offshore drilling operations. We are continuing to evaluate the cost and effect that these new rules will have on our operations. Based on our current assessment of the rules, we do not expect to incur significant costs to comply with the rule. 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 additional regulatory (including 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." 


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Non-U.S. Operations

Revenues from non-U.S. operations were 81%, 72% and 62% of our total consolidated revenues during 2016, 2015 and 2014, 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, 

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;


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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
 
48

 
President and Chief Executive Officer
P. Carey Lowe
 
58

 
Executive Vice President - Chief Operating Officer
Jonathan Baksht
 
41

 
Senior Vice President and Chief Financial Officer
Steven J. Brady
 
57

 
Senior Vice President - Eastern Hemisphere
John S. Knowlton
 
57

 
Senior Vice President - Technical
Gilles Luca
 
45

 
Senior Vice President - Western Hemisphere
Michael T. McGuinty
 
54

 
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. In August 2016, Mr. Trowell became a non-executive director on the board of Ophir Energy plc. 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.

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.


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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.

Employees

We employed approximately 4,900 personnel worldwide as of December 31, 2016.  The majority of our personnel work on rig crews and are compensated on an hourly basis.

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.


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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 and natural gas prices have historically been volatile, and have declined significantly from prices in excess of $100 since mid-2014, with crude oil prices trading around $55 per barrel in January 2017. The decline in oil prices has caused a significant decline in the demand for offshore drilling services as opportunities for new drilling contracts have substantially decreased and the number of available rigs has increased. 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. The lack of a meaningful recovery of oil and natural gas prices or further price reductions or volatility in prices, may cause our customers to maintain historically low levels or further reduce their 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 come to agreements to set and maintain production levels and pricing and to implement such agreements, 

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,

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,


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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.

Despite significant declines in capital spending and cancelled or deferred drilling programs by many operators since 2015, oil and gas production has not yet been reduced by amounts sufficient to result in a rebound in pricing to levels seen prior to the current downturn, and we may not see sufficient supply reductions or a resulting rebound in pricing for an extended period of time. Further, the recent agreements of OPEC and certain non-OPEC countries to freeze and/or cut production may not be fully realized. The lack of actual production cuts or freezes, or the perceived risk that OPEC countries may not comply with such agreements, may result in depressed 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 further, 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.

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. If we are not able to compete successfully, our revenues and profitability may be reduced.

The offshore contract drilling industry historically has been very cyclical and is 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 significantly in recent years. Delivery of newbuild drilling rigs has increased and will continue to increase rig supply and could curtail a strengthening, or trigger a further reduction, in utilization and day rates. Currently, there are approximately 145 newbuild drillships, semisubmersibles and jackup rigs reported to be on order or under construction with delivery expected by the end of 2020.  Approximately 100 of these rigs are scheduled for delivery during 2017, representing an approximate 12% increase in the total worldwide fleet of offshore drilling rigs since year-end 2016. Many of these offshore drilling rigs do not have drilling contracts

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in place. In addition, the supply of marketed offshore drilling rigs could further increase due to depressed market conditions resulting in an increase in uncontracted rigs 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 significant decline in oil and gas prices and resulting reduction in spending by our customers, together with 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 day rates, a situation which may persist for many years.

Such a prolonged period of reduced demand and/or excess rig supply may require us to idle additional rigs and enter into low day rate contracts or contracts with unfavorable 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 have 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.

Our two rigs under construction, which are scheduled for delivery in 2018 and 2019, are currently uncontracted. 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 contracts for these rigs at day 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 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 of indemnification from our customers, including with respect to well control, reservoir liability and pollution. 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 and third-party damages 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 under certain circumstances are not enforceable if the cause of the damage was our gross negligence or willful misconduct. This could result in us having to assume liabilities not otherwise contemplated in our contracts due to customer balance sheet or liquidity issues or applicable law.


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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 market downturns 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. Since early 2015, we have renegotiated a number of contracts and received termination notices with respect to several of our rigs. Generally, our drilling contracts are subject to termination without cause or termination for convenience upon notice by the customer. In certain cases, our contracts require the customer to pay an early termination payment in the event of a termination for convenience (without cause). Such payment would provide some level of compensation to us for the lost revenue from the contract and in many cases would not fully compensate us for the lost revenue. Certain of our contracts permit termination by the customer without an early termination payment. Furthermore, financially distressed customers may seek to negotiate reduced termination payments as part of a restructuring package.

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.

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 position, operating results 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.

During the two years ended December 31, 2015, we have recorded pre-tax, non-cash losses on impairment of long-lived assets and goodwill of $5.1 billion and $3.3 billion. Further asset impairments may be necessary if market conditions remain depressed for longer than we expect. We have no goodwill on our balance sheet as of December 31, 2016 or 2015.

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 2016, our five largest customers accounted for 50% of our consolidated revenues in the aggregate, with our largest customer representing 13% 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, operating results or cash flows.

As of December 31, 2016, our contract backlog was approximately $3.6 billion, which represents a decline of $2.1 billion since December 31, 2015. This amount reflects the remaining contractual terms multiplied by the

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applicable contractual day rate. 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,

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 certain 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 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 certain cases. Customers may continue to request to renegotiate the terms of existing contracts, or they may request early termination or seek to repudiate contracts in some circumstances. Furthermore, as our existing contracts expire, we may be unable to secure new 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, operating results 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. For example, most of our drilling contracts incorporate a broad exclusion that limits the customer's indemnity for damages and losses resulting from our gross

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negligence and willful misconduct and for fines and penalties and punitive damages levied or assessed directly against us. 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, or that we will be able to maintain the same levels and types of coverage that we have maintained in the past.

Furthermore, our insurance carriers may interpret our insurance policies such that they do not cover losses for all of our claims. Our insurance policies may also have exclusions of coverage for some losses. Uninsured 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, operating results 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 six 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 do not purchase windstorm insurance for hull and machinery losses to our floaters arising from windstorm damage in the U.S. Gulf of Mexico , due to the significant premium, high deductible and limited coverage for windstorm

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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 six 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 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, 2017, 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 these 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 81%, 72% and 62% of our total revenues during 2016, 2015 and 2014, 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, 


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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, 

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.

In June 2016, the U.K. voted to exit from the E.U. (commonly referred to as “Brexit”). The impact of Brexit and the resulting U.K./E.U. relationship are uncertain for companies doing business both in the U.K. and the overall global economy. Approximately 9% of our total revenues were generated in the U.K. for the year ended December 31, 2016. Brexit, or similar events in other jurisdictions, can impact global markets, including foreign exchange and securities markets, which may have an adverse impact on our business and operations as a result of changes in currency exchange rates, tariffs, treaties and other regulatory matters.

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.


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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 certain capital expenditures, 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.

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 could have a material adverse effect on our financial position, operating results or cash flows.


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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 20 rigs that are contracted with national oil companies. 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. 

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 each quarter during 2016, a $0.14 reduction from the $0.15 dividend per share paid for each quarter during 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 us 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.

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.

During 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 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 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 our former marketing consultant both received and procured improper payments from Samsung Heavy Industries for employees of Petrobras and 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

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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, operating results, 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. As a result of jackup rig fitness requirements during hurricane seasons issued by The Bureau of Safety and Environmental Enforcement (“BSEE”) and its predecessor agency, 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, BSEE and its predecessor agency promulgated regulations regarding safety and environmental management systems ("SEMS"). During 2013, BSEE adopted a final rule modifying the SEMS requirements. Although only operators are currently required to have a SEMS, the SEMS regulations require written agreements between operators and contractors regarding the contractors’ support of the operators' safety and environmental policies at the worksite, including requirements for personnel training and written safe work practices. 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. The imposition of INCs on contractors exposes us to fines and penalties for violation of BSEE regulations and the 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

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energy sectors for all vessels and facilities that are subject to the Maritime Transportation Security Act of 2002, including our rigs. The proposed GPS equipment and positioning regulations are expected to be issued late in 2017 or early 2018. In 2016, BSEE adopted a new well control rule that will be implemented in phases over the next several years. This new rule includes more stringent design requirements for well control equipment used in offshore drilling operations. We are continuing to evaluate the cost and effect that these new rules will have on our operations. Based on our current assessment of the rules, we do not expect to incur significant costs to comply with the rule. Implementation of further guidelines and regulations may subject us to increased costs and limit the operational capabilities of our rigs.

Any new or additional 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 position, 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 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.


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

We currently have one ultra-deepwater drillship and one jackup rig under construction. In the future, 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 2016, we agreed with the shipyard constructing the ENSCO 123 to delay the delivery of the rig until the first quarter of 2018. We also recently agreed with the shipyard constructing the ENSCO DS-10 to delay delivery of the drillship until the first quarter of 2019. During periods of heightened rig construction projects, shipyards and third-party equipment vendors may be under significant resource constraints to meet delivery obligations. Such constraints may lead to substantial delivery and commissioning delays, 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, 

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.


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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.

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 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 position, 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, the International Convention on Civil Liability for Oil Pollution Damage 1992, the U.K. Merchant Shipping Act 1995, Marpol 73/78 (the International Convention for the Prevention of Pollution from Ships), the U.K. Merchant Shipping (Oil Pollution Preparedness, Response and Co-operation Convention) Regulations 1998, as amended, 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

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other non-U.S. jurisdictions, address oil spill prevention, reporting and control and have significantly expanded potential 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.

High profile and catastrophic events in recent years, including the 2010 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.

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, 2016, we had $5.3 billion in total debt outstanding, representing approximately 39.0% 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

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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. Moody’s Investor Services, Inc. and Standard & Poor’s Rating Services downgraded our credit rating to below investment-grade in February 2016 and December 2016, respectively. Our credit ratings, and any additional actual or anticipated downgrades in our credit ratings, could limit our ability to access credit and capital markets, or to restructure or refinance our indebtedness. As a result of our downgrades, future financings or refinancings may result in higher borrowing costs and require more restrictive terms and covenants, which may further restrict our operations. With our current credit ratings below investment grade, we have no access to the commercial paper market. Our credit ratings, and any additional actual or anticipated downgrades in our credit ratings, could have a material adverse impact on our financial position, results of operations and liquidity.

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

30



adverse market conditions resulting from, among others, general economic conditions, 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 position, operating results and cash flows.

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 and/or 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, operating results and cash flows.    

The accounting method for our 2024 Convertible Notes could have a material effect on our reported financial results.
Under U.S. GAAP, we must separately account for the liability and equity components of convertible debt instruments, such as our 3.00% exchangeable senior notes due 2024 (the “2024 Convertible Notes”) in a manner that reflects the issuer’s economic interest cost. The equity component representing the conversion feature is recorded in additional paid-in capital within the shareholders’ equity section of our consolidated balance sheet. The carrying value of the debt component is recorded with a corresponding discount that will result in a significant amount of non-cash interest expense from the accretion of the discounted carrying value up to the principal amount over the term of the 2024 Convertible Notes. The equity component is not remeasured if we continue to meet certain conditions for equity classification under U.S. GAAP, including maintaining the ability to settle the 2024 Convertible Notes entirely in

31



shares. During periods in which we are unable to meet the conditions for equity classification, the equity component or a portion thereof would be remeasured through earnings, which could adversely affect our operating results.

Upon conversion of the 2024 Convertible Notes, holders will receive cash, our Class A ordinary shares or a combination thereof, at our election. Our intent is to settle the principal amount of the 2024 Convertible Notes in cash upon conversion. If the conversion value exceeds the principal amount (i.e., our share price exceeds the exchange price on the date of conversion), we expect to deliver shares equal to our conversion obligation in excess of the principal amount. During each respective reporting period that our average share price exceeds the exchange price, an assumed number of shares required to settle the conversion obligation in excess of the principal amount will be included in the denominator for our computation of diluted earnings per share using the treasury stock method. If we are unable to demonstrate our intent to settle the principal amount in cash, or are otherwise unable to utilize the treasury stock method, our diluted earnings per share would be adversely affected. See Note 4 to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" for additional information on our 2024 Convertible Notes.

Governments may pass laws that subject us to additional taxation or may challenge our tax positions, which could adversely affect our financial position, operating results 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”) has 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 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 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 rulings 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 matters (such as changes in applicable accounting rules) that increase 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 matters, this could cause our consolidated effective income tax rate to increase and cause a material adverse effect on our financial position, operating results and 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 future 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 other matters (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

32



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. In periods of declining profitability, our income tax expense may not decline proportionately with income. Further, we may continue to incur income tax expense in periods in which we operate at a loss. 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 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 matters, this could cause our consolidated effective income tax rate to increase and cause a material adverse effect on our financial position, operating results and 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 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 our 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

33



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, 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 2016 to authorize the allotment of additional shares for a one-year term. As this authority will expire in May 2017, 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.

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 2016, to exclude pre-emption rights for a one-year term. As this authority will expire in May 2017, special resolutions 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.

34




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.

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.

35



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 22, 2017:
 
 
 
Rig Name
 
 
  Rig Type
 
 
Year Built/
Rebuilt
 
 
 
Design      
 
   Maximum
 Water Depth/
Drilling Depth
 
 
  Location   
 
 
Status    
Floaters
 
 
 
 
 
 
 
 
 
 
ENSCO DS-3
Drillship
 
2010
 
Dynamically Positioned
 
10,000'/40,000'
 
Spain
Preservation stacked(1)
ENSCO DS-4
Drillship
 
2010
 
Dynamically Positioned
 
10,000'/40,000'
 
Spain
Preservation stacked(1)
ENSCO DS-5
Drillship
 
2011
 
Dynamically Positioned
 
10,000'/40,000'
 
Spain
Preservation stacked(1)
ENSCO DS-6
Drillship
 
2012
 
Dynamically Positioned
 
10,000'/40,000'
 
Egypt
Under contract
ENSCO DS-7
Drillship
 
2013
 
Dynamically Positioned
 
10,000'/40,000'
 
Spain
Available
ENSCO DS-8
Drillship
 
2015
 
Dynamically Positioned
 
10,000'/40,000'
 
Angola
Under contract
ENSCO DS-9
Drillship
 
2015
 
Dynamically Positioned
 
10,000'/40,000'
 
Singapore
Available
ENSCO DS-10
Drillship
 
2019
 
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
Under contract
ENSCO 5005
Semisubmersible
 
1982/2014
 
F&G Enhanced Pacesetter
 
1,500'/25,000'
 
Singapore
Preservation stacked(1)
ENSCO 5006
Semisubmersible
 
1999/2014
 
Bingo 8000
 
7,000'/25,000'
 
Australia
Under contract
ENSCO 6001
Semisubmersible
 
2000/2010/2014
 
Megathyst
 
5,600'/25,000'
 
Brazil
Under contract
ENSCO 6002
Semisubmersible
 
2001/2009/2015
 
Megathyst
 
5,600'/25,000'
 
Brazil
Under contract
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
Preservation stacked(1)
ENSCO 8501
Semisubmersible
 
2009
 
Dynamically Positioned
 
8,500'/35,000'
 
Gulf of Mexico
Preservation stacked(1)
ENSCO 8502
Semisubmersible
 
2010/2012
 
Dynamically Positioned
 
8,500'/35,000'
 
Gulf of Mexico
Preservation stacked(1)
ENSCO 8503
Semisubmersible
 
2010
 
Dynamically Positioned
 
8,500'/35,000'
 
Gulf of Mexico
Under contract
ENSCO 8504
Semisubmersible
 
2011
 
Dynamically Positioned
 
8,500'/35,000'
 
Singapore
Available
ENSCO 8505
Semisubmersible
 
2012
 
Dynamically Positioned
 
8,500'/35,000'
 
Gulf of Mexico
Under contract
ENSCO 8506
Semisubmersible
 
2012
 
Dynamically Positioned
 
8,500'/35,000'
 
Gulf of Mexico
Preservation stacked(1)
 
 
 
 
 
 
 
 
 
 
 
Jackups
 
 
 
 
 
 
 
 
 
 
ENSCO 52
Jackup
 
1983/1997/2013
 
F&G L-780 MOD II-C
 
300'/25,000'
 
Malaysia
Under contract
ENSCO 54
Jackup
 
1982/1997/2014
 
F&G L-780 MOD II-C
 
300'/25,000'
 
Saudi Arabia
Under contract
ENSCO 56
Jackup
 
1982/1997
 
F&G L-780 MOD II-C
 
300'/25,000'
 
Malaysia
Cold stacked
ENSCO 67
Jackup
 
1976/2005
 
MLT 84-CE
 
400'/30,000'
 
Indonesia
Under contract
ENSCO 68
Jackup
 
1976/2004
 
MLT 84-CE
 
400'/30,000'
 
Gulf of Mexico
Under contract
ENSCO 70
Jackup
 
1981/1996/2014
 
Hitachi K1032N
 
250'/30,000
 
United Kingdom
Cold stacked
ENSCO 71
Jackup
 
1982/1995/2012
 
Hitachi K1032N
 
225'/25,000'
 
Denmark
Under contract
ENSCO 72
Jackup
 
1981/1996
 
Hitachi K1025N
 
225'/25,000'
 
Netherlands
Under contract
ENSCO 75
Jackup
 
1999
 
MLT Super 116-C
 
400'/30,000'
 
Gulf of Mexico
Under contract
ENSCO 76
Jackup
 
2000
 
MLT Super 116-C
 
350'/30,000'
 
Saudi Arabia
Under contract
ENSCO 80
Jackup
 
1978/1995
 
MLT 116-CE
 
225'/30,000'
 
United Kingdom
Under contract
ENSCO 81
Jackup
 
1979/2003
 
MLT 116-C
 
350'/30,000'
 
Gulf of Mexico
Cold stacked
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'
 
Saudi Arabia
Under contract
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
Under contract
ENSCO 88
Jackup
 
1982/2004/2014
 
MLT 82-SD-C
 
250'/25,000'
 
Saudi Arabia
Under contract
ENSCO 90
Jackup
 
1982/2002
 
MLT 82-SD-C
 
250'/25,000'
 
Gulf of Mexico
Cold stacked
ENSCO 92
Jackup
 
1982/1996
 
MLT 116-C
 
225'/25,000'
 
United Kingdom
Under contract

36



 
 
Rig Name
 
 
  Rig Type
 
 
Year Built/
Rebuilt
 
 
 
Design      
 
   Maximum
 Water Depth/
Drilling Depth
 
 
  Location   
 
 
Customer    
Jackups
 
 
 
 
 
 
 
 
 
 
ENSCO 96
Jackup
 
1982/1997/2012
 
Hitachi 250-C
 
250'/25,000'
 
Saudi Arabia
Under contract
ENSCO 97
Jackup
 
1980/1997/2012
 
MLT 82 SD-C
 
250'/25,000'
 
Saudi Arabia
Under contract
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
Under contract
ENSCO 101
Jackup
 
2000
 
KFELS MOD V-A
 
400'/30,000'
 
Netherlands
Under contract
ENSCO 102
Jackup
 
2002
 
KFELS MOD V-A
 
400'/30,000'
 
United Kingdom
Available
ENSCO 104
Jackup
 
2002
 
KFELS MOD V-B
 
400'/30,000'
 
UAE
Under contract
ENSCO 105
Jackup
 
2002
 
KFELS MOD V-B
 
400'/30,000'
 
Singapore
Cold stacked
ENSCO 106
Jackup
 
2005
 
KFELS MOD V-B
 
400'/30,000'
 
Malaysia
Available
ENSCO 107
Jackup
 
2006
 
KFELS MOD V-B
 
400'/30,000'
 
Australia
Under contract
ENSCO 108
Jackup
 
2007
 
KFELS MOD V-B
 
400'/30,000'
 
Thailand
Under contract
ENSCO 109
Jackup
 
2008
 
KFELS MOD V-Super B
 
350'/35,000'
 
Angola
Under contract
ENSCO 110
Jackup
 
2015
 
KFELS MOD V-B
 
400'/30,000'
 
UAE
Available
ENSCO 120
Jackup
 
2013
 
KFELS Super A
 
400'/40,000'
 
United Kingdom
Available
ENSCO 121
Jackup
 
2013
 
KFELS Super A
 
400'/40,000'
 
Denmark
Under contract
ENSCO 122
Jackup
 
2014
 
KFELS Super A
 
400'/40,000'
 
Netherlands
Under contract
ENSCO 123
Jackup
 
2018
 
KFELS Super A
 
400'/40,000'
 
Singapore
Under construction(2)
ENSCO 140
Jackup
 
2016
 
Cameron Letourneau Super 116E
 
400'/30,000'
 
UAE
Available
ENSCO 141
Jackup
 
2016
 
Cameron Letourneau Super 116E
 
400'/30,000'
 
UAE
Available

(1) 
Prior to stacking, upfront steps are taken to preserve the rig. This may include a quayside power source to dehumidify key equipment and/or provide electric current to the hull to prevent corrosion. Also, certain equipment may be removed from the rig for storage in a temperature-controlled environment. While stacked, large equipment that remains on the rig is periodically inspected and maintained by Ensco personnel. These steps are designed to reduce time and lower cost to reactivate the rig when market conditions improve.

(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 drillships and semisubmersibles. Drillships 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.
    
Semisubmersibles are mobile offshore drilling units with pontoons and columns that are partially submerged at the drilling location to provide added stability during drilling operations. Semisubmersibles 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 semisubmersibles are most commonly used for drilling in water depths of 4,499 feet or less.  However, ENSCO 5006, which is a moored semisubmersible, is capable of deepwater drilling in water depths greater than 5,000 feet.  Dynamically positioned semisubmersibles generally

37



are outfitted for drilling in deeper water depths and are well-suited for deepwater development and exploratory well drilling. Further, we have two hybrid semisubmersibles, ENSCO 8503 and ENSCO 8505, which leverage both moored and dynamically positioned configurations. This hybrid design provides multi-faceted drilling solutions to customers with both shallow water and deepwater requirements.
 
Jackup rigs stand on the ocean floor with their hull and drilling equipment elevated above the water on connected leg supports. Jackups are generally preferred over other rig types in shallow water depths of 400 feet or less, primarily because jackups provide a more stable drilling platform with above water well control equipment. Our jackups 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 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 28, 2017, we owned all rigs in our fleet. We also manage the drilling operations for two rigs owned by third-parties. 
 
We lease our executive offices in London, England in addition to office space in Houston, Texas, Aberdeen, Australia, Brunei, Denmark, Dubai, Holland, Indonesia, Malaysia, Malta, Mexico, Saudi Arabia, Singapore, Thailand, Vietnam and several additional international locations. We own offices and other facilities in Louisiana, Angola and Brazil.

Item 3.  Legal Proceedings

Brazil Internal Investigation

Pride International LLC, formerly 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, who provided services to Pride and Ensco in connection with the DSA. Independent counsel has continued 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. On March 7, 2016, we entered into a one-year tolling agreement with the SEC.
Subsequent to initiating our Audit Committee investigation, 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, referenced the alleged irregularities cited in the Petrobras internal audit report. Our former

38



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 our former marketing consultant both received and procured improper payments from SHI for employees of Petrobras and that Pride had knowledge of this activity and assisted in the procurement of and/or facilitated these improper payments. We disagree with Petrobras’ allegations. See "-DSA Dispute" below for additional information.
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 Pride's involvement in 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’ declaration that the DSA is void. We believe that Petrobras has repudiated the DSA and have therefore accepted the DSA as terminated on April 8, 2016 (the "Termination Date"). At this time, we cannot reasonably determine the validity of Petrobras' claim or the range of our potential exposure, if any. As a result, there can be no assurance as to how this dispute will ultimately be resolved.

We did not recognize revenue for amounts owed to us under the DSA from the beginning of the fourth quarter of 2015 through the Termination Date, as we concluded that collectability of these amounts was not reasonably assured. Additionally, our receivables from Petrobras related to the DSA from prior to the fourth quarter of 2015 are fully reserved in our consolidated balance sheet as of December 31, 2016. We have initiated arbitration proceedings in the U.K. against Petrobras seeking payment of all amounts owed to us under the DSA, in addition to any other amounts to which we are entitled, and intend to vigorously pursue our claims. Petrobras subsequently filed a counterclaim seeking restitution of certain sums paid under the DSA less value received by Petrobras under the DSA. We have also initiated separate arbitration proceedings in the U.K. against SHI for any losses we have incurred in connection with the foregoing. SHI subsequently filed a statement of defense disputing our claim. There can be no assurance as to how these arbitration proceedings will ultimately be resolved.


39



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 are currently named as defendants, along with numerous third-party companies as co-defendants, in multi-party lawsuits filed in Mississippi and Louisiana by approximately 32 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. The settlement documents for these lawsuits have been processed, and the cases have been dismissed.

We intend to vigorously defend against the remaining lawsuits and have filed responsive pleadings preserving all defenses and challenges to jurisdiction and venue. We expect final disposition of these lawsuits to be immaterial to our financial position, operating results and cash flows.

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 2016, pursuant to which the governmental authorities have assessed, or are anticipated to assess, fines. 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 $190,000 liability related to these matters was included in accrued liabilities and other on our consolidated balance sheet as of December 31, 2016.
 
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

40



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.

41



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 shares, 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
2016 High
 
$
16.10

 
$
12.36

 
$
10.89

 
$
12.03

 
$
16.10

2016 Low
 
$
7.25

 
$
9.00

 
$
6.50

 
$
7.19

 
$
7.19

 
 
 
 
 
 
 
 
 
 
 
2015 High
 
$
32.28

 
$
28.40

 
$
22.21

 
$
18.93

 
$
32.28

2015 Low
 
$
19.78

 
$
21.04

 
$
13.42

 
$
13.26

 
$
13.26


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 75 shareholders of record on February 1, 2017.
 
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
2016
 
$
.01

 
$
.01

 
$
.01

 
$
.01

 
$
0.04

2015
 
$
.15

 
$
.15

 
$
.15

 
$
.15

 
$
0.60

    
Our Board of Directors declared a $0.01 quarterly cash dividend for the first quarter of 2017. We currently intend to continue paying dividends for the foreseeable future. However, the declaration and amount of future dividends is at the discretion of our Board of Directors and could change in future periods. In the future, our Board of Directors may, without advance notice, determine to reduce or suspend our dividend in order to improve our financial flexibility and best position us for long-term success. 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.

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.


42



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, persons who could be treated for U.K. tax purposes as holding their shares as carried interest, 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.

The tax treatment of dividends paid by the Company to individual shareholders is as follows:

dividends paid by the Company 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).


43



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 2016 is 20%, and will be 19% for the financial year 2017. 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 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.


44



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 for 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 2016/2017 is 10% for basic rate taxpayers and 20% for higher and additional rate taxpayers, and is expected to be the same in the tax year 2017/2018.

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 2016 and 19% in the financial year 2017. 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 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.


45



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."


46



Issuer Purchases of Equity Securities
 
The following table provides a summary of our repurchases of our equity securities during the quarter ended December 31, 2016.

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 
4,472

 
$
8.06

 

 
$
2,000,000,000

November 1 - November 30
18,338

 
$
8.33

 

 
$
2,000,000,000

December 1 - December 31
6,999

 
$
10.00

 

 
$
2,000,000,000

Total 
29,809

 
$
8.68

 

 
 


(1)
During the quarter ended December 31, 2016, 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 repurchase 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.



47



Performance Chart    
    
The chart below presents a comparison of the five-year cumulative total return, assuming $100 invested on December 31, 2011 for Ensco plc, the Standard & Poor's MidCap 400 Index, 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.* Ensco is no longer part of the Standard & Poor's 500 Stock Price Index. The Standard & Poor's MidCap 400 Index includes Ensco and has been included as a comparison.

COMPARISON OF 5 YEAR CUMULATIVE TOTAL RETURN(1) 
Among Ensco plc, the S&P MidCap 400 Index, the S&P 500 Index and Peer Group
a5yeargrapha01.jpg
(1)100 invested on 12/31/11 in stock or index, including reinvestment of dividends.
Fiscal year ending December 31.

Copyright© 2017 S&P, a division of The McGraw-Hill Companies Inc. All rights reserved.

 
12/11
 
12/12
 
12/13
 
12/14
 
12/15
 
12/16
 
 
 
 
 
 
 
 
 
 
 
 
Ensco plc
100.0

 
129.9

 
130.2

 
73.0

 
38.7

 
24.5

S&P MidCap 400
100.0

 
117.9

 
157.4

 
172.7

 
169.0

 
204.0

S&P 500
100.0

 
116.0

 
153.6

 
174.6

 
177.0

 
198.2

Peer Group
100.0

 
120.3

 
133.3

 
61.1

 
34.9

 
34.3

____________________________________
* 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.

48



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,
 
2016
 
2015
 
2014
 
2013
 
2012
  
(in millions, except per share amounts)
Consolidated Statement of Operations Data
 
 
 

 
 

 
 

 
 

Revenues
$
2,776.4

 
$
4,063.4

 
$
4,564.5

 
$
4,323.4

 
$
3,638.8

Operating expenses
 

 
 

 
 

 
 

 
 

Contract drilling (exclusive of depreciation)
1,301.0

 
1,869.6

 
2,076.9

 
1,947.1

 
1,642.8

Loss on impairment

 
2,746.4

 
4,218.7

 

 

Depreciation
445.3

 
572.5

 
537.9

 
496.2

 
443.8

General and administrative
100.8

 
118.4

 
131.9

 
146.8

 
148.9

Operating income (loss)
929.3


(1,243.5
)

(2,400.9
)

1,733.3


1,403.3

Other income (expense), net
68.2

 
(227.7
)
 
(147.9
)
 
(100.1
)
 
(98.6
)
Income tax expense (benefit)
108.5

 
(13.9
)
 
140.5

 
203.1

 
228.6

Income (loss) from continuing operations
889.0

 
(1,457.3
)

(2,689.3
)

1,430.1


1,076.1

Income (loss) from discontinued operations, net(1)
8.1

 
(128.6
)
 
(1,199.2
)
 
(2.2
)
 
100.6

Net income (loss)
897.1

 
(1,585.9
)

(3,888.5
)

1,427.9


1,176.7

Net income attributable to noncontrolling interests
(6.9
)
 
(8.9
)
 
(14.1
)
 
(9.7
)
 
(7.0
)
Net income (loss) attributable to Ensco
$
890.2

 
$
(1,594.8
)

$
(3,902.6
)

$
1,418.2


$
1,169.7

Earnings (loss) per share – basic
 

 
 

 
 

 
 

 
 

Continuing operations
$
3.10

 
$
(6.33
)
 
$
(11.70
)
 
$
6.09

 
$
4.62

Discontinued operations
0.03

 
(0.55
)
 
(5.18
)
 
(0.01
)
 
0.43

 
$
3.13

 
$
(6.88
)

$
(16.88
)

$
6.08


$
5.05

Earnings (loss) per share - diluted
 

 
 

 
 

 
 

 
 

Continuing operations
$
3.10

 
$
(6.33
)
 
$
(11.70
)
 
$
6.08

 
$
4.61

Discontinued operations
0.03

 
(0.55
)
 
(5.18
)
 
(0.01
)
 
0.43

 
$
3.13

 
$
(6.88
)

$
(16.88
)

$
6.07


$
5.04

Net income (loss) attributable to Ensco shares - Basic and Diluted
$
873.6

 
$
(1,596.8
)
 
$
(3,910.5
)
 
$
1,403.1

 
$
1,157.4

Weighted-average shares outstanding
 

 
 

 
 

 
 

 
 

Basic
279.1

 
232.2

 
231.6

 
230.9

 
229.4

Diluted
279.1

 
232.2

 
231.6

 
231.1

 
229.7

Cash dividends per share
$
0.04

 
$
0.60

 
$
3.00

 
$
2.25

 
$
1.50

(1) 
See Note 10 to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" for information on discontinued operations.


49



 
Year Ended December 31,
 
2016
 
2015
 
2014
 
2013
 
2012
  
(in millions)
Consolidated Balance Sheet and Cash Flow Statement Data
 
 
 
 
 
 
 
 
 
Working capital
$
2,424.9

 
$
1,509.6

 
$
1,788.9

 
$
466.9

 
$
720.4

Total assets
14,374.5

 
13,610.5

 
16,023.3

 
19,446.8

 
18,554.7

Long-term debt, net of current portion
4,942.6

 
5,868.6

 
5,868.1

 
4,709.3

 
4,797.7

Ensco shareholders' equity
8,250.6

 
6,512.9

 
8,215.0

 
12,791.6

 
11,846.4

Cash flows from operating activities of continuing operations
1,077.4

 
1,697.9

 
2,057.9

 
1,811.2

 
1,954.6

 




50



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 57 rigs, with drilling operations in most of the strategic markets around the globe. We also have two rigs under construction. Our rig fleet includes eight drillships, 10 dynamically positioned semisubmersible rigs, three moored semisubmersible rigs and 38 jackup rigs, including rigs under construction.  We operate the world's second largest fleet amongst competitive rigs, including one of the newest ultra-deepwater fleets in the industry, and a leading premium jackup fleet.

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 14 countries on six continents. The markets in which we operate include the U.S. Gulf of 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 for which we receive a daily rate that may vary throughout the duration of the contractual term. The day rate we earn can vary between the full day rate and zero rate, depending on the operations of the rig. 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. Low demand and excess supply can independently affect day rates and utilization of drilling rigs. Therefore, adverse changes in either of these factors can result in adverse changes in our industry. 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 highly cyclical and beyond our control.  Offshore exploration and development spending may fluctuate substantially from year-to-year and from region-to-region.

The contracting environment remained very challenging for offshore drilling contractors during 2016 with customers requesting contract concessions or terminating drilling contracts. Crude oil prices ranged from a 12-year low of $26 to $55 per barrel during 2016. The sustained decline in oil prices from 2014 highs caused a significant decline in the demand for offshore drilling services as many projects became uneconomical, resulting in fewer market tenders in recent periods. Operators significantly reduced 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. Declines in capital spending levels, together with the oversupply of rigs, have resulted in significantly reduced day rates and utilization. Although oil prices have stabilized between $45 and $55 per barrel, we do not expect a meaningful improvement in demand for offshore drilling services in the near term. When market conditions improve, we expect jackup demand to improve first as shallow-water drilling is typically shorter term in nature, requires less capital investment and generally presents less risk to operators.


51



In general, recent contract awards have been short-term in nature and subject to an extremely competitive bidding process. The intense pressure on operating day rates has resulted in rates that approximate, or are slightly lower than, 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/or demobilization fees; reduced or zero day rates during downtime; reduced standby, redrill and moving rates and limited periods in which such rates are payable; caps on reimbursements for downhole tools; reduced periods to remediate equipment breakdowns or other deviations from contractual standards of performance before the operator may terminate the contract; certain limitations on our ability to be indemnified; increases in the nature and amounts of liability allocated to us; and reduced early termination fees and/or termination notice periods.

We expect 2017 to be a challenging year for drilling contractors as current contracts expire and new contracts are executed at lower rates. While commodity prices have improved, they have not yet improved to a level that provides stability in the market sufficient to support additional demand. Should commodity prices decline from current levels, we will likely experience a further reduction in demand for our services, and revenues will continue to be adversely affected through lower rig utilization and day rates.  We believe the current market dynamics will not change until we see a sustained meaningful recovery in commodity prices sufficient to bring customer demand into balance with rig supply.
  
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 for both floaters and jackups. The decline in customer capital expenditure budgets has led to a lack of contracting opportunities resulting in the retirement of 75 floaters since the beginning of the downturn. Approximately 40 marketed floaters older than 30 years are idle, and approximately 30 additional floaters older than 30 years have contracts expiring by the end of 2018 without follow-on work. Operating costs associated with keeping these rigs idle as well as expenditures required to recertify these aging rigs may prove cost prohibitive. Drilling contractors will likely elect to scrap or cold-stack some or all of these rigs.

Since the beginning of the downturn, drilling contractors have retired 31 jackups. Approximately 90 marketed jackups older than 30 years are idle, and approximately 65 jackups that are 30 years or older have contracts expiring by the end of 2017 without follow-on work. Expenditures required to recertify these aging rigs may prove cost prohibitive and drilling contractors may instead elect to scrap or cold-stack these rigs. We expect jackup scrapping and cold-stacking to accelerate during 2017 and into 2018.

When demand for offshore drilling ultimately improves, we expect that newer, more capable rigs will be the first to obtain contract awards, increasing the likelihood that older stacked rigs do not return to the active fleet.

There are approximately 45 competitive newbuild drillships and semisubmersibles reported to be under construction, of which approximately 30 are scheduled to be delivered before the end of 2017. Most newbuild floaters are uncontracted. Several newbuild deliveries have already been delayed into future years, and we expect that more uncontracted newbuilds will be delayed or cancelled.

There are approximately 100 competitive newbuild jackups reported to be under construction, of which approximately 70 are scheduled to be delivered before the end of 2017. Most newbuild jackups are uncontracted. Over the past year, some 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.


52



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, 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. During 2016, we executed several transactions to maximize our liquidity in the near term.

Equity Transactions

In April 2016, we closed an underwritten public offering of 65,550,000 Class A ordinary shares at $9.25 per share, inclusive of shares purchased under an underwriters' option. We received net proceeds from the offering of $585.5 million.

In October 2016, we entered into a privately-negotiated exchange agreement whereby we issued 1,822,432 Class A ordinary shares in exchange for $24.5 million principal amount of our 5.75% senior notes due 2044. The exchange resulted in a gain on debt extinguishment of $8.8 million.

Cash and Debt

Throughout 2016, we used proceeds from the April 2016 equity offering and cash on hand to repurchase $1.1 billion of outstanding debt for $863.9 million through tender offers and open market repurchases. We recognized a gain on debt extinguishment of $279.0 million net of discounts, premiums, debt issuance costs and transaction costs.

In December 2016, we completed a private placement of $849.5 million of 3.00% exchangeable senior notes due 2024 for net proceeds of $822.8 million.

In January 2017, through a private-exchange transaction, we repurchased $649.5 million of outstanding debt with $332.5 million of net proceeds from the December 2016 exchangeable senior notes offering and $332.0 million of newly issued 8.00% senior notes due 2024.

As of December 31, 2016, we had $5.3 billion in total debt outstanding, representing 39.0% of our total capitalization. Following the settlement of the exchange transaction in January 2017, our outstanding debt declined to $4.9 billion, representing 37.5% of our total capitalization. Our next debt maturity is in 2019 with an aggregate principal amount of $292.2 million, followed by additional maturities in 2020, 2021 and 2024 with aggregate principal amounts of $551.0 million, $309.1 million and $1.8 billion, respectively.

As of December 31, 2016, we have $2.6 billion in cash and cash equivalents and short-term investments and a $2.25 billion senior unsecured revolving credit facility (the “Credit Facility”) to be used for general corporate purposes with a term that expires in September 2019. In October 2016, we extended the maturity of $1.13 billion of the $2.25 billion Credit Facility commitment for one year to September 2020. The Credit Facility requires us to maintain a total debt to total capitalization ratio that is less than or equal to 60%.

Backlog

As of December 31, 2016, our backlog was $3.6 billion as compared to $5.8 billion as of December 31, 2015. Our backlog declined primarily due to revenues realized during the year and various contract day rate concessions and terminations, partially offset by new contract awards and contract extensions. As current contracts expire, we will likely experience further declines in backlog, which will result in a decline in revenues and operating cash flows during 2017.

53




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, 2016, we invested approximately $2.1 billion in the construction of new drilling rigs.

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.

Floaters

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 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. During 2015, we agreed with the shipyard to delay delivery of ENSCO DS-10 until the first quarter of 2017. In January 2017, we agreed to further delay delivery of ENSCO DS-10 and $75.0 million of the final milestone payment until the first quarter of 2019 or such earlier date that we elect to take delivery. ENSCO DS-9 and ENSCO DS-10 are being actively marketed.

Jackups

During 2014, we entered into an agreement with Lamprell to construct two premium jackup rigs. ENSCO 140 and ENSCO 141 are significantly enhanced versions of the LeTourneau Super 116E jackup design and will incorporate our patented Canti-Leverage AdvantageSM technology. ENSCO 140 and ENSCO 141 were delivered during the third and fourth quarters of 2016, respectively. Both rigs are currently uncontracted and are being actively marketed. As part of our agreement with Lamprell, these rigs will be warm stacked in the shipyard at no additional cost to us for up to two years.

We previously entered into agreements with KFELS to construct four ultra-premium harsh environment jackup rigs (ENSCO 120, ENSCO 121, ENSCO 122 and ENSCO 123) and a premium jackup rig (ENSCO 110). ENSCO 120 was delivered during the third quarter of 2013, ENSCO 121 was delivered during the fourth quarter of 2013, ENSCO 122 was delivered during the third quarter of 2014 and ENSCO 110 was delivered during the second quarter of 2015. During the first quarter of 2016, we agreed with the shipyard to delay delivery of ENSCO 123 until the first quarter of 2018. ENSCO 123 is currently uncontracted.

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 11 jackup rigs, three dynamically positioned semisubmersible rigs, three moored semisubmersible rigs and two drillships during the three-year period ended December 31, 2016. We are marketing for sale two rigs, which were classified as held-for-sale in our consolidated financial statements as of December 31, 2016.


54



BUSINESS ENVIRONMENT

Floaters

Excluding the impact of lump-sum termination payments, floater revenues declined by $770.9 million, or 33%, primarily due to fewer days under contract across our floater fleet, contract terminations and sale of ENSCO 6003, ENSCO 6004 and ENSCO DS-1, lower average day rates and lower revenues from ENSCO DS-5. The decline in revenue was partially offset by a $327.8 million, or 31%, decline in contract drilling expense primarily due to rig stackings and other cost control initiatives that reduced personnel costs and other daily rig operating costs.
    
During the year, we executed contract extensions for ENSCO 5004 and ENSCO 5006 at lower rates. We agreed to reduce the ENSCO 6001 contracted rate and early terminate ENSCO 6003 and ENSCO 6004 in exchange for an extension of the ENSCO 6002 contract term at a reduced rate.

We received an early termination notice on ENSCO 8505 and agreed to lump-sum settlements of ongoing obligations for ENSCO DS-9 and ENSCO 8503. We also received an early termination notice on ENSCO DS-7 whereby the drilling contract obligates the customer to pay us termination fees at 75% of the operating rate through November 2017. These fees will be defrayed should we re-contract the rig over the remainder of the original contract term. In addition, we sold five floaters for scrap value resulting in insignificant pre-tax gains and losses, two of which were included in discontinued operations, net, in our consolidated statements of operations.

Jackups

     Jackup revenues declined by $516.1 million, or 36%, primarily due to fewer days under contract across our jackup fleet and lower average day rates. This decline in revenue was partially offset by a $176.7 million, or 25%, decline in contract drilling expense due to rig stackings and other cost control initiatives that reduced personnel costs and other daily rig operating expenses.

During the year, we agreed to reduced rates on our jackups contracted with Saudi Aramco and received early termination notices on ENSCO 72, ENSCO 75, ENSCO 83 and ENSCO 110. In addition, we sold four jackups for scrap value resulting in insignificant pre-tax gains, one of which was included in discontinued operations, net, in our consolidated statements of operations.

We reached an agreement with our ENSCO 54, ENSCO 88 and ENSCO 94 customer to extend the terms of these contracts for five, three and five years, respectively. We subsequently reached an agreement with our customer to substitute ENSCO 84 for ENSCO 94 for the duration of the contract. Additionally, we executed a five-year contract for ENSCO 106 and executed several contracts with various customers for ENSCO 67, ENSCO 72, ENSCO 80 and ENSCO 101 with terms ranging from six to 18 months.


55



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, 2016 (in millions):
 
 
2016
 
2015
 
2014
Revenues
 
$
2,776.4

 
$
4,063.4

 
$
4,564.5

Operating expenses
 
 

 
 

 
 

Contract drilling (exclusive of depreciation)
 
1,301.0

 
1,869.6

 
2,076.9

Loss on impairment
 

 
2,746.4

 
4,218.7

Depreciation
 
445.3

 
572.5

 
537.9

General and administrative 
 
100.8

 
118.4

 
131.9

Operating income (loss)
 
929.3

 
(1,243.5
)
 
(2,400.9
)
Other income (expense), net 
 
68.2

 
(227.7
)
 
(147.9
)
Provision for income taxes 
 
108.5

 
(13.9
)
 
140.5

Income (loss) from continuing operations 
 
889.0

 
(1,457.3
)
 
(2,689.3
)
Income (loss) from discontinued operations, net 
 
8.1

 
(128.6
)
 
(1,199.2
)
Net income (loss)
 
897.1

 
(1,585.9
)
 
(3,888.5
)
Net income attributable to noncontrolling interests
 
(6.9
)
 
(8.9
)
 
(14.1
)
Net income (loss) attributable to Ensco
 
$
890.2

 
$
(1,594.8
)
 
$
(3,902.6
)
    
During 2016, excluding the impact of ENSCO DS-9 and ENSCO 8503 lump-sum termination payments totaling $205.0 million received during the year and ENSCO DS-4 and ENSCO DS-9 lump-sum termination payments totaling $129.0 million received during 2015, revenues declined by $1,363.0 million, or 35%, as compared to the prior year. The decline was primarily due to fewer days under contract across our fleet, lower average day rates, contract terminations and sale of ENSCO 6003, ENSCO 6004 and ENSCO DS-1, and lower revenues from ENSCO DS-5. The decline in revenues was partially offset by the commencement of ENSCO DS-8 drilling operations and revenue generated from semisubmersible rigs that were undergoing shipyard projects during 2015.

Contract drilling expenses declined by $568.6 million, or 30%, as compared to the prior year primarily due to rig stackings and other cost control initiatives that reduced personnel costs and other daily rig operating expenses as well as contract terminations and sale of ENSCO 6003, ENSCO 6004 and ENSCO DS-1. This decline was partially offset by ENSCO DS-8 contract drilling expense.

During 2015, excluding the impact of ENSCO DS-4 and DS-9 lump-sum termination payments totaling $129.0 million received during the year, revenues and contract drilling expense declined by $630.1 million, or 14%, and $207.3 million, or 10%, respectively, 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. The decline in contract drilling expense was due to rig stackings and other cost control initiatives that reduced personnel costs and other daily rig operating expenses.

During 2015, we recorded a non-cash loss on impairment totaling $2,746.4 million, of which $2,470.3 million 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 $4,218.7 million, of which $2,997.9 million related to impairment of our floater goodwill and $1,220.8 million related to impairment of certain floaters and jackups.

General and administrative expenses declined by $17.6 million, or 15%, in 2016 as compared to 2015 and $13.5 million, or 10%, in 2015 as compared to 2014 primarily due to lower shore-based headcount levels and various other cost control initiatives.

56




Other income (expense), net, included pre-tax gains on debt extinguishment of $287.8 million related to debt repurchases and the exchange of equity for debt, and losses of $33.5 million related to make-whole premiums on our 2015 debt redemption during the years ended December 31, 2016 and 2015, respectively.

Rig Counts, Utilization and Average Day Rates
   
The following table summarizes our offshore drilling rigs by reportable segment, rigs under construction and rigs held-for-sale as of December 31, 2016, 2015 and 2014:
 
2016
 
2015
 
2014
Floaters(1)(2)
19
 
22
 
20
Jackups(2)(3)
36
 
36
 
36
Under construction(2)
2
 
4
 
7
Held-for-sale(3)(4)
2
 
6
 
7
Total
59
 
68
 
70

(1) 
During 2016, we sold ENSCO DS-1, ENSCO 6003 and ENSCO 6004.

(2) 
During 2016, we accepted delivery of two high-specification jackup rigs (ENSCO 140 and ENSCO 141). Both of these rigs are uncontracted.

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.

(3) 
During 2016, we classified ENSCO 53 and ENSCO 94 as held-for-sale. During 2015, we classified ENSCO 91 as held-for-sale.

(4) 
During 2016, we sold ENSCO DS-2, ENSCO 6000, ENSCO 53, ENSCO 58, ENSCO 91 and ENSCO 94. During 2015, we sold ENSCO 5001 and ENSCO 5002.

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, 2016:
 
 
2016
 
2015
 
2014
Rig Utilization(1)
 
 

 
 

 
 

Floaters
 
54%
 
69%
 
79%
Jackups
 
60%
 
73%
 
89%
Total
 
58%
 
72%
 
85%
Average Day Rates(2)
 
 
 
 

 
 
Floaters
 
$
359,758

 
$
416,346

 
$
456,023

Jackups
 
110,682

 
136,451

 
140,033

Total
 
$
192,427

 
$
233,325

 
$
242,884


(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

57



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, 2016 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 (loss) and were included in "Reconciling Items." 
 
Year Ended December 31, 2016
 
Floaters
 
Jackups
 
Other
 
Operating Segments Total
 
Reconciling Items
 
Consolidated Total
 
 
 
 
 
 
 
 
 
 
 
 
Revenues
$
1,771.1

 
$
929.5

 
$
75.8

 
$
2,776.4

 
$

 
$
2,776.4

Operating expenses
 
 
 
 
 
 
 
 
 
 
 
  Contract drilling
  (exclusive of depreciation)
725.0

 
516.8

 
59.2

 
1,301.0

 

 
1,301.0

  Depreciation
304.1

 
123.7

 

 
427.8

 
17.5

 
445.3

  General and administrative

 

 

 

 
100.8

 
100.8

Operating income
$
742.0

 
$
289.0

 
$
16.6

 
$
1,047.6

 
$
(118.3
)
 
$
929.3

 

58



Year Ended December 31, 2015
 
Floaters
 
Jackups
 
Other
 
Operating Segments Total
 
Reconciling Items