Company Quick10K Filing
Quick10K
Ensco
Closing Price ($) Shares Out (MM) Market Cap ($MM)
$15.26 109 $1,670
10-K 2018-12-31 Annual: 2018-12-31
10-Q 2018-09-30 Quarter: 2018-09-30
10-Q 2018-06-30 Quarter: 2018-06-30
10-Q 2018-03-31 Quarter: 2018-03-31
10-K 2017-12-31 Annual: 2017-12-31
10-Q 2017-09-30 Quarter: 2017-09-30
10-Q 2017-06-30 Quarter: 2017-06-30
10-Q 2017-03-31 Quarter: 2017-03-31
10-K 2016-12-31 Annual: 2016-12-31
10-Q 2016-09-30 Quarter: 2016-09-30
10-Q 2016-06-30 Quarter: 2016-06-30
10-Q 2016-03-31 Quarter: 2016-03-31
10-K 2015-12-31 Annual: 2015-12-31
10-Q 2015-09-30 Quarter: 2015-09-30
10-Q 2015-06-30 Quarter: 2015-06-30
10-Q 2015-03-31 Quarter: 2015-03-31
10-K 2014-12-31 Annual: 2014-12-31
10-Q 2014-09-30 Quarter: 2014-09-30
10-Q 2014-06-30 Quarter: 2014-06-30
10-Q 2014-03-31 Quarter: 2014-03-31
10-K 2013-12-31 Annual: 2013-12-31
8-K 2019-04-09 Enter Agreement, M&A, Off-BS Arrangement, Sale of Shares, Officers, Regulation FD, Other Events, Exhibits
8-K 2019-03-06 Officers, Exhibits
8-K 2019-02-21 Shareholder Vote, Regulation FD, Exhibits
8-K 2019-02-20 Regulation FD, Exhibits
8-K 2019-01-28 Enter Agreement, Regulation FD, Exhibits
8-K 2019-01-02 Regulation FD, Exhibits
8-K 2018-10-29 Regulation FD, Exhibits
8-K 2018-10-29 Earnings, Other Events, Exhibits
8-K 2018-10-23 Other Events, Exhibits
8-K 2018-10-07 Enter Agreement, Officers, Regulation FD, Other Events, Exhibits
8-K 2018-09-04 Other Events
8-K 2018-07-25 Earnings, Exhibits
8-K 2018-07-19 Regulation FD, Exhibits
8-K 2018-05-21 Officers, Shareholder Vote, Exhibits
8-K 2018-04-23 Regulation FD, Exhibits
8-K 2018-02-22 Other Events
8-K 2018-02-20 Officers, Exhibits
8-K 2018-02-08 Other Events, Exhibits
8-K 2018-01-26 Other Events, Exhibits
8-K 2018-01-25 Other Events, Exhibits
8-K 2018-01-11 Other Events, Exhibits
8-K 2018-01-10 Other Events, Exhibits
BAX Baxter 39,670
ERII Energy Recovery 508
YRIV Yangtze River Port & Logistics 240
APTO Aptose Biosciences 74
OBAS Optibase 54
FPP Fieldpoint Petroleum 0
BLMT BSB Bancorp 0
ETCK Enerteck 0
OHGI One Horizon Group 0
NTWN Newtown Lane Marketing 0
ESV 2018-12-31
Part I
Item 1. Business
Item 1A. Risk Factors
Item 1B. Unresolved Staff Comments
Item 2. Properties
Item 3. Legal Proceedings
Item 4. Mine Safety Disclosures
Part II
Item 5. Market for Registrant's Common Equity, Related Shareholder Matters and Issuer Purchases of Equity Securities
Item 6. Selected Financial Data
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Item 8. Financial Statements and Supplementary Data
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
Item 9A. Controls and Procedures
Item 9B. Other Information
Part III
Item 10. Directors, Executive Officers and Corporate Governance
Item 11. Executive Compensation
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters
Item 13. Certain Relationships and Related Transactions, and Director Independence
Item 14. Principal Accounting Fees and Services
Part IV
Item 15. Exhibits, Financial Statement Schedules
Item 16. Form 10-K Summary
EX-21.1 esv-ex211x12312018.htm
EX-23.1 esv-ex231x12312018.htm
EX-31.1 esv-ex311x12312018.htm
EX-31.2 esv-ex312x12312018.htm
EX-32.1 esv-ex321x12312018.htm
EX-32.2 esv-ex322x12312018.htm

Ensco Earnings 2018-12-31

ESV 10K Annual Report

Balance SheetIncome StatementCash Flow

10-K 1 esv-20181231x10k.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, 2018
 
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
8.00% Senior Notes due 2024
7.75% Senior Notes due 2026
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 every Interactive Data File required to be submitted 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 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.  ý
 
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or emerging growth company. See the definitions of "large accelerated filer," "accelerated filer," "smaller reporting company," and "emerging growth company" in Rule 12b-2 of the Exchange Act (Check one):

Large accelerated filer
 
x
 
  
Accelerated filer
 
o
 
 
 
 
 
 
 
 
Non-Accelerated filer
 
o
 
  
Smaller reporting company
 
o
 
 
 
 
 
 
 
 
 
 
 
 
 
Emerging growth company
 
o
 
o If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.

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, 2018 of $7.26) of Ensco plc held by non-affiliates of Ensco plc at that date was approximately $3,149,586,000.
 
As of February 22, 2019, there were 437,071,204 Class A ordinary shares of Ensco plc issued and outstanding.
 
DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Company's Proxy Statement for the 2019 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.
 
 
ITEM 16.
 
 
 
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 (the "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," "likely," "plan," "project," "could," "may," "might," "should," "will" and similar words and specifically include statements regarding expected financial performance; the proposed transaction with Rowan Companies plc ("Rowan") dividends; expected utilization, day rates, revenues, operating expenses, contract terms, contract backlog, capital expenditures, insurance, financing and funding; expected work commitments, awards and contracts; the timing of availability, delivery, mobilization, contract commencement or relocation or other movement of rigs and the timing thereof; future rig construction (including work-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; expected divestitures of assets; 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:
 
our ability to complete the combination with Rowan;

failure, difficulties and delays in meeting conditions required for closing set forth in the Transaction Agreement (as defined herein);

our ability to obtain requisite regulatory approval and satisfy the other conditions to consummate the transaction with Rowan;

the potential impact of the pendency or implementation of the transaction with Rowan on relationships, including with employees, suppliers, customers, competitors, lenders and credit rating agencies;

our ability to successfully integrate Rowan's operations and employees and to realize synergies and cost savings in connection with the Rowan Transaction (as defined herein);

changes in future levels of drilling activity and capital 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 the U.K.'s planned withdrawal from the European Union, civil unrest, political demonstrations, mass strikes, or an escalation or additional outbreak of armed hostilities or other

2



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 and acquired rigs, for rigs currently idled and for rigs whose contracts are expiring;

any failure to execute definitive contracts following announcements of letters of intent, letters of award or other expected work commitments;

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, service our indebtedness 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;

the adequacy of sources of liquidity for us and our customers;

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;

the occurrence of cybersecurity incidents, attacks or other breaches to our information technology systems;


3



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.

4



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 56 rigs, with drilling operations in most of the strategic markets around the globe. We also have three rigs under construction. Inclusive of rigs under construction, our fleet includes12 drillships, 9 dynamically positioned semisubmersible rigs, three moored semisubmersible rigs and 35 jackup rigs.  We operate the world's 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 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 an integrated service that includes the provision of a drilling rig and rig crews for which we receive a daily rate that may vary between the full rate and zero rate throughout the duration of the contractual term, depending on the operations of the rig. We also may receive lump-sum fees or similar compensation for the mobilization, demobilization and capital upgrades of our rigs. 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.

Ensco plc is a public limited company incorporated under the laws of England and Wales in 2009. 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.

Proposed Rowan Transaction

On October 7, 2018, Ensco plc and Rowan Companies plc ("Rowan") entered into an agreement that provides for the combination of the two companies (as amended the "Transaction Agreement"). Ensco has agreed to acquire the entire issued and to be issued share capital of Rowan in an all-stock transaction (the "Rowan Transaction") by way of a scheme of arrangement to be undertaken by Rowan under Part 26 of the UK Companies Act 2006. On January 29, 2019, the Transaction Agreement was amended to increase the exchange ratio in connection with the Rowan Transaction from 2.215 to 2.750.

Subject to the terms and conditions of the Transaction Agreement, each Class A ordinary share of Rowan will be converted into the right to receive 2.750 Class A ordinary shares of Ensco plc. We estimate the total consideration to be delivered in the Rowan Transaction to be approximately $1.5 billion, consisting of approximately 351.3 million of our shares based on the closing price of $4.41 on February 22, 2019. The value of the Rowan Transaction consideration will fluctuate until the closing date based on changes in the price of our shares and the number of shares of Rowan ordinary shares outstanding.

The completion of the Rowan Transaction is subject to various closing conditions, including, among others, (i) the sanction of the Rowan Transaction by the High Court of Justice of England and Wales, (ii) the receipt of certain required regulatory approvals or lapse of certain review periods with respect thereto, including in the Kingdom of Saudi Arabia, (iii) the absence of legal restraints prohibiting or restraining the Rowan Transaction and (iv) the absence of any law or order reasonably expected to result in the dissolution of the Saudi Aramco Offshore Drilling Company,

5



Rowan’s joint venture with Saudi Aramco (the “ARO JV”), or the sale, disposition, forfeiture or nationalization of Rowan’s interest in the ARO JV. Shareholders of Rowan and Ensco approved the Rowan Transaction on February 21, 2019. The Rowan Transaction is expected to close during the first half of 2019, subject to satisfaction of all conditions to closing. Upon closing of the Rowan Transaction, we intend to complete a reverse split of our ordinary shares under which every four existing Ensco ordinary shares will be consolidated into one Ensco ordinary share.

Atwood Merger
    
On October 6, 2017 (the "Merger Date"), we completed a merger transaction (the "Atwood Merger") with Atwood Oceanics, Inc. ("Atwood") and Echo Merger Sub, LLC, a wholly-owned subsidiary of Ensco plc. Pursuant to the merger agreement, Echo Merger Sub, LLC, merged with and into Atwood, with Atwood as the surviving entity and an indirect, wholly-owned subsidiary of Ensco plc. Total consideration delivered in the Atwood Merger consisted of 132.2 million of our Class A ordinary shares and $11.1 million of cash in settlement of certain share-based payment awards. The total aggregate value of consideration transferred was $781.8 million. Additionally, upon closing of the Atwood Merger, we utilized cash acquired of $445.4 million and cash on hand to extinguish Atwood's revolving credit facility, outstanding senior notes and accrued interest totaling $1.3 billion. The estimated fair values assigned to assets acquired net of liabilities assumed exceeded the consideration transferred, resulting in a bargain purchase gain of $140.2 million that was recognized during the fourth quarter of 2017. During 2018, we recognized measurement period adjustments as we completed our fair value assessments resulting in additional bargain purchase gain of $1.8 million.

Drilling Rig Construction and Delivery

We remain focused on our long-established strategy of high-grading our fleet and expanding the scale of our operations, as evidenced by the recently completed Atwood Merger and proposed Rowan Transaction. During the three-year period ended December 31, 2018, we invested approximately $1.0 billion in the construction of new drilling rigs. We will continue to invest in the expansion and high-grading of our fleet or execute other strategic transactions to optimize our asset portfolio when we believe attractive opportunities exist.

We believe our remaining capital commitments will primarily be funded from cash and short-term investments, and, if necessary, funds borrowed under our Credit Facility or other future financing arrangements, including available shipyard financing options for our two drillships under construction. We may decide to access debt and/or equity markets to raise additional capital or increase liquidity as necessary.

Floaters

We previously entered into an agreement with Samsung Heavy Industries to construct ENSCO DS-10, an ultra deepwater drillship. During 2017, we took delivery of ENSCO DS-10 and made the final milestone payment of $75.0 million. ENSCO DS-10 commenced drilling operations offshore Nigeria in March 2018.

In connection with the Atwood Merger, we acquired two ultra-deepwater drillships, ENSCO DS-13 and ENSCO DS-14, which are currently under construction in the Daewoo Shipbuilding & Marine Engineering Co. Ltd. yard in South Korea. ENSCO DS-13 and ENSCO DS-14 are scheduled for delivery during the third quarter of 2019 and second quarter of 2020, respectively. Upon delivery, the remaining milestone payments and accrued interest thereon may be financed through a promissory note with the shipyard for each rig. The promissory notes will bear interest at a rate of 5.0% per annum with a maturity date of December 30, 2022 and will be secured by a mortgage on each respective rig.

Jackups

During 2014, we entered into an agreement with Lamprell Energy Limited to construct two premium jackup rigs, ENSCO 140 and ENSCO 141, which are significantly enhanced versions of the LeTourneau Super 116E jackup design and incorporate Ensco's patented Canti-Leverage AdvantageTM technology. ENSCO 140 and ENSCO 141 were

6



delivered during 2016 and commenced drilling operations offshore Saudi Arabia during July and August 2018, respectively.

We previously entered into an agreement with Keppel FELS to construct an ultra-premium harsh environment jackup, ENSCO 123. In December 2017, we agreed to delay delivery of ENSCO 123 until 2019, and in January 2018, we made a $207.4 million milestone payment. The remaining unpaid balance of $9.0 million is due upon delivery. ENSCO 123 was designed to incorporate Ensco's patented Continuous Tripping Technology™, a new proprietary solution that provides safer and more efficient pipe tripping and helps to lower customers’ offshore project costs. We expect ENSCO 123 to commence drilling operations in the North Sea in July 2019.
 
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 12 jackup rigs, five dynamically positioned semisubmersible rigs, one moored semisubmersible rig and two drillships during the three-year period ended December 31, 2018.

We continue to focus on our fleet management strategy in light of the composition of our rig fleet. As part of this strategy, we may act opportunistically from time to time to monetize assets to enhance shareholder value and improve our liquidity profile, in addition to selling or disposing of older, lower-specification or non-core assets.

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.

Of our 59 rigs, 29 are located in the Middle East, Africa and Asia Pacific (including three rigs under construction), 12 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.”

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 various events, including damage or 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),


7



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 rate basis such that we receive a fixed amount for each day that the drilling unit is under contract (lower day rates generally apply for limited periods when operations are suspended due to various events, including during delays that are beyond our reasonable control, during repair of equipment damage or breakdown and during periods of re-drilling damaged portions of the well, and no day rate, or zero rate, generally applies when these limited periods are exceeded until the event is remediated, and during periods to remediate unsatisfactory performance or other specified conditions), 

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

mobilization and demobilization requirements of us to move the drilling unit to and from the planned drilling site, and may include reimbursement of a portion of these moving costs by the customer in the form of an 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 for contracts with terms in excess of one year.    

In general, recent contract awards have been subject to an extremely competitive bidding process. The intense pressure on operating day rates has resulted in lower margin contracts that also contain less favorable contractual and commercial terms, including reduced or no mobilization and/or demobilization fees; reduced day rates or zero day rates during downtime due to damage or failure of our equipment; reduced standby, redrill and moving rates and reduced periods in which such rates are payable; reduced caps on reimbursements for lost or damaged downhole tools; reduced periods to remediate downtime due to equipment breakdowns or failure to perform in accordance with the contractual standards of performance before the operator may terminate the contract; certain limitations on our ability to be indemnified from operator and third party damages caused by our fault, resulting in increases in the nature and amounts of liability allocated to us; and reduced or no early termination fees and/or termination notice periods.

Backlog Information

Our contract drilling backlog reflects commitments, represented by signed drilling contracts, and is 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 is 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, 2019 and February 27, 2018, respectively.

The following table summarizes our contract backlog of business as of December 31, 2018 and 2017 (in millions):
 
2018
 
2017
Floaters
$
941.5

 
$
1,578.3

Jackups
1,071.0

 
1,013.0

Other
169.9

 
229.7

Total
$
2,182.4

 
$
2,821.0



8



As of December 31, 2018, our backlog was $2.2 billion as compared to $2.8 billion as of December 31, 2017. Our floater backlog declined $636.8 million primarily due to revenues realized during 2018, partially offset by new contract awards and contract extensions. While our floater utilization increased marginally in 2018 to 46% from 45% in 2017, our floater backlog declined as revenues were realized on above-market, longer-term contracts and new contracts were executed a lower rates for shorter terms. Our jackup backlog increased $58.0 million primarily due to new contract awards as utilization increased to 63% in 2018 from 60% in 2017, partially offset by revenues realized during 2018. Our other segment backlog declined $59.8 million due to revenues realized during 2018.
    
The following table summarizes our contract backlog of business as of December 31, 2018 and the periods in which such revenues are expected to be realized (in millions):
 
2019
 
2020
 
2021
 
2022
and Beyond
 
 Total
Floaters
$
716.5

 
$
225.0

 
$

 
$

 
$
941.5

Jackups
503.4

 
272.0

 
191.8

 
103.8

 
1,071.0

Other
55.8

 
55.9

 
55.7

 
2.5

 
169.9

Total
$
1,275.7

 
$
552.9

 
$
247.5

 
$
106.3

 
$
2,182.4


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 and cash flows” and “Item 1A. Risk Factors - We may suffer losses if our customers terminate or seek to renegotiate our contracts, if operations are suspended or interrupted or if a rig becomes a total loss.”

Drilling Contracts and Insurance Program

Our drilling contracts provide for varying levels of allocation of responsibility for liability between our customer and us for loss or damage to each party's property and third-party property, personal injuries and other claims arising out of our drilling operations. We also maintain insurance for personal injuries, damage to or loss of property and certain business risks.
 
Our insurance policies typically consist of 12-month policy periods, and the next renewal date for a substantial portion of our insurance program is scheduled for May 31, 2019. Our insurance program provides coverage, subject to the policies' terms and conditions and 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.

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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 four jackups and five 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, although in some cases we assume responsibility for all damages due to our negligence.  In addition, our drilling contracts typically provide for our customers to indemnify us, generally based on replacement cost minus some level of depreciation, for loss or 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 our 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 most drilling contracts, we assume liability for third-party damages resulting from such pollution and contamination caused by our negligence, usually subject to negotiated caps on a per occurrence or per event basis. In addition, in substantially all of our contracts, the customer assumes responsibility and indemnifies us for loss or damage to the reservoir, for loss of hydrocarbons escaping from the reservoir and for the costs of bringing the well under control.  Further, subject to the exceptions noted below, most of our contracts provide that the customer assumes responsibility and indemnifies us for loss or damage to the well, except when the loss or damage to the well is due to our negligence, in which case most of our contracts provide that the customer's sole remedy is to require us to redrill the lost or damaged portion of the well at a substantially reduced rate 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 would otherwise 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 we are able to negotiate 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 some or 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

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limit our liability in the event of our gross negligence or willful misconduct are deemed to be unenforceable as being contrary to public policy, and we are exposed to unlimited liability for losses and damages that result from our gross negligence or willful misconduct, regardless of any 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 injury or death to the operator's personnel, 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 fault based 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 may 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.

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 2018, our five largest customers accounted for 48% of consolidated revenues. Total and Saudi Aramco, our customers who account for 10% or more of consolidated revenues, accounted for 15% and 11% of consolidated revenues, respectively.




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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 and Environmental Matters

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."

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. These laws and regulations may, among other things:

require the acquisition of various permits before drilling commences;

require notice to stakeholders of proposed and ongoing operations;

require the installation of expensive pollution control equipment;

restrict the types, quantities and concentration of various substances that can be released into the environment in connection with drilling; and

restrict the production rate of natural resources below the rate that would otherwise be possible.

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-control 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.

Additionally, environmental laws and regulations are revised frequently, and any changes, including changes in implementation or interpretation, that result in more stringent and costly waste handling, disposal and cleanup requirements for our industry could have a significant impact on our operating costs.

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

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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 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 and 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 an Interim Policy Document ("IPD") stating that it would begin issuing Incidents of Non-Compliance ("INC's") to contractors as well as operators for serious violations of BSEE regulations. Following federal court decisions successfully challenging the scope of BSEE’s jurisdiction over offshore contractors, this IPD has been removed from the list of IPDs on the BSEE website. If this judicial precedent stands, it may reduce regulatory and civil litigation liability exposures.

In late 2014, the United States Coast Guard ("USCG") proposed new regulations that would impose GPS equipment and positioning requirements for mobile offshore drilling units ("MODUs") and jackup rigs operating in the U.S. Gulf of Mexico and issued notices regarding the development of guidelines 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 ("MTSA"), including our rigs. The regulations imposing GPS equipment and positioning requirements have not yet been issued.  On July 12, 2017, the USCG announced the availability of and requested comments on draft guidelines for addressing cyber risks at MTSA-regulated facilities.

On July 28, 2016, BSEE adopted a new well-control rule that will be implemented in phases over the next several years (the "2016 Well Control Rule"). This new rule includes more stringent design requirements for well-control equipment used in offshore drilling operations. In May 2018, BSEE proposed revisions to the 2016 Well Control Rule. This proposed rule would revise requirements for well design, well control, casing, cementing, real-time monitoring and subsea containment. The revisions are targeted to ensure safety and environmental protection while correcting errors in the 2016 rule and reducing certain unnecessary regulatory burdens imposed under the existing regulations. The proposed revisions have not yet been finalized. 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 2016 Well Control Rule.
 
The continuing and evolving threat of cyber attacks will likely require increased expenditures to strengthen cyber risk management systems for MODUs and onshore facilities. For example, on May 11, 2017, President Trump issued EO 13800, entitled Strengthening the Cybersecurity of Federal Networks and Critical Infrastructure, which is intended to improve the nation's ability to defend against increasing and evolving cyber attacks, and in July 2017 the USCG issued proposed cybersecurity guidelines for port facilities and offshore facilities, including MODUs, that could be impacted by cyber attacks. We cannot currently estimate the future expenditures associated with increased regulatory requirements, which may be material, and we continue to monitor regulatory changes as they occur.

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Additionally, climate change is receiving increasing attention from scientists and legislators, and significant focus is being put on companies that are active producers of depleting natural resources. Globally, there are a number of legislative and regulatory proposals at various levels of government to address the greenhouse gas emissions that contribute to climate change. Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address greenhouse gas emissions would impact our business, any such future laws and regulations could require us or our customers to incur increased operating costs. Any such legislation or regulatory programs could also increase the cost of consuming oil, and thereby reduce demand for oil, which could reduce our customers’ demand for our services. Consequently, legislation and regulatory programs to reduce greenhouse gas emissions could have an adverse effect on our financial position, operating results and cash flows.
    
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." 

Non-U.S. Operations

Revenues from non-U.S. operations were 87%, 92% and 81% of our total consolidated revenues during 2018, 2017 and 2016, 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 or our customer's property, 

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, 


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limitations on our ability to recover amounts due, 

increased risk of government and vendor/supplier corruption, 

increased local content requirements,

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

changes in political conditions, and 

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

See "Item 1A. Risk Factors - Our non-U.S. operations involve additional risks not associated with U.S. operations."
Executive Officers
Officers generally serve for a one-year term or until successors are elected and qualified to serve. The table below sets forth certain information regarding our executive officers:
Name
 
Age
 
Position         
Carl G. Trowell
 
50
 
President and Chief Executive Officer
P. Carey Lowe
 
60
 
Executive Vice President - Chief Operating Officer
Jonathan Baksht
 
44
 
Senior Vice President and Chief Financial Officer
Steven J. Brady
 
59
 
Senior Vice President - Eastern Hemisphere
John S. Knowlton
 
59
 
Senior Vice President - Technical
Gilles Luca
 
47
 
Senior Vice President - Western Hemisphere
Michael T. McGuinty
 
56
 
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

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to 2007. Mr. Lowe held various drilling-related management positions with Sedco Forex and Schlumberger Oilfield Services from 1980 to 2000, including Business Manager - Drilling, North and South America and General Manager - Oilfield Services, Saudi Arabia, Bahrain and Kuwait. Following Schlumberger, he was associated with a business-to-business e-procurement company until he joined Occidental during 2001. Mr. Lowe holds a Bachelor of Science Degree in Civil Engineering from Tulane University.

Jonathan Baksht joined Ensco in 2013 and was appointed to his current position of Senior Vice President - Chief Financial Officer in 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 a Senior Vice President at Goldman Sachs & Co. within the Investment Banking Division where he served as a financial advisor to energy clients, oilfield services lead and a member of the Merger & Acquisitions Group.  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 with High Honors 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. In 2018, Mr. Brady was elected the Chairman of the Executive Committee for the International Association of Drilling Contractors. 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. 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

Excluding contract employees, we employed approximately 4,400 personnel worldwide as of December 31, 2018.  The majority of our personnel work on rig crews and are compensated on an hourly basis.

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Available Information

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

Item 1A.  Risk Factors
 
Risks Related to the Rowan Transaction

The following risk factors relate to the Rowan Transaction. For more information on the Rowan Transaction, please read the joint proxy statement we filed with the SEC on December 11, 2018, the supplement to the joint proxy statement we filed with the SEC on January 31, 2019, as well as any other related information on the Rowan Transaction that we have filed with the SEC.

We and Rowan will be subject to various uncertainties and contractual restrictions while the Rowan Transaction is pending that could adversely affect each party’s business and operations.

In connection with the Rowan Transaction, it is possible that some customers, suppliers and other persons with whom we or Rowan have business relationships may delay or defer certain business decisions, or might decide to seek to terminate, change or renegotiate their relationship with us or Rowan as a result of the Rowan Transaction, which could negatively affect our or Rowan’s respective financial positions, operating results or cash flows, as well as the market price of our shares and Rowan shares, regardless of whether the Rowan Transaction is completed.

Under the terms of the Rowan Transaction Agreement, we and Rowan are subject to certain restrictions on the conduct of our businesses prior to completing the Rowan Transaction, which may adversely affect our and Rowan's ability to execute certain business strategies. Such limitations could negatively affect each party’s businesses and operations prior to the completion of the Rowan Transaction. Furthermore, the process of planning to integrate two businesses and organizations for the post-transaction period may divert management’s attention and resources and could ultimately have an adverse effect on each party. These uncertainties could cause customers, suppliers and others that deal with us or Rowan to seek to change existing business relationships with such party, which in turn could have an adverse effect on the combined company’s ability to realize the anticipated benefits of the Rowan Transaction.

We or Rowan may have difficulty attracting, motivating and retaining executives and other employees in light of the Rowan Transaction.

Uncertainty about the effect of the Rowan Transaction on our employees or Rowan’s employees may impair the companies' ability to attract, retain and motivate personnel until the Rowan Transaction is completed. Employee retention may be particularly challenging during the pendency of the Rowan Transaction, as employees may feel uncertain about their future roles with the combined organization. In addition, we or Rowan may have to provide additional compensation in order to retain employees. If our employees or Rowan's employees depart because of issues relating to the uncertainty and difficulty of integration or a desire not to become employees of the combined company, the combined company’s ability to realize the anticipated benefits of the Rowan Transaction could be adversely affected.

The Rowan Transaction is subject to conditions, including certain conditions that may not be satisfied, and may not be completed on a timely basis, if at all. Failure to complete the Rowan Transaction, or significant delays in completing the Rowan Transaction, could negatively affect the trading price of our shares and our future business and financial results.

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The completion of the Rowan Transaction remains subject to a number of conditions beyond our and Rowan’s control that may prevent, delay or otherwise materially adversely affect its completion, including among others the receipt of antitrust clearance in Saudi Arabia. Neither we nor Rowan can predict whether and when these conditions will be satisfied. Any delay in completing the Rowan Transaction could cause the combined company not to realize some or all of the synergies expected to be achieved if the Rowan Transaction is successfully completed within its expected time frame.

If the Rowan Transaction is not completed, we will be subject to several risks and consequences, including the following:

certain damages for which we may be liable to Rowan under the terms and conditions of the Rowan Transaction Agreement;

negative reactions from the financial markets, including declines in the price of our shares due to the fact that current prices may reflect a market assumption that the Rowan Transaction will be completed;

certain significant costs relating to the Rowan Transaction, including, in certain circumstances, the payment by us of $15 million for Rowan’s expenses and a termination fee payable by us of $24 million less any previous expense reimbursements; and

diverted attention of our management to the Rowan Transaction rather than our own operations and pursuit of other opportunities that could have been beneficial to us.

In addition, completion of the Rowan Transaction remains subject to antitrust clearance in Saudi Arabia. Under the terms of the Rowan Transaction Agreement, either we and/or Rowan could be required to effect or commit to effecting the divestiture or disposition of certain of our or their respective businesses, assets, equity interests, product lines or properties in order to obtain approvals and consents needed from the antitrust authorities in the relevant jurisdictions in order to complete the Rowan Transaction. If we or Rowan takes such actions, it could be detrimental to us or to the combined company following the consummation of the Rowan Transaction.

We and Rowan will incur substantial transaction fees and costs in connection with the Rowan Transaction.

We and Rowan expect to incur a number of non-recurring transaction-related costs associated with completing the Rowan Transaction, combining the operations of the two organizations and achieving desired synergies. These fees and costs will be substantial. Non-recurring transaction costs include, but are not limited to, fees paid to legal, financial and accounting advisors, retention, severance, change in control and other integration-related costs, filing fees and printing costs. Additional unanticipated costs may be incurred in the integration of our business and Rowan's business. There can be no assurance that the elimination of certain duplicative costs, as well as the realization of other efficiencies related to the integration of the two businesses, will offset the incremental transaction-related costs over time. Thus, any net benefit may not be achieved in the near term, the long term or at all.

Completion of the Rowan Transaction will trigger change of control or other provisions in certain agreements to which Rowan is a party.

The completion of the Rowan Transaction will trigger change of control or other provisions in certain agreements to which Rowan is a party. In particular, pursuant to the indenture governing Rowan’s 7.375% senior notes due 2025, Rowan will be required to make an offer to purchase all or any part of each holder’s notes at an amount equal to 101% of the aggregate principal amount of such holder’s notes, plus accrued and unpaid interest, if any, if there is a ratings downgrade by both Moody’s Investors Service, Inc. (“Moody’s”) and S&P Global Ratings (“S&P”) between the public notice of the Rowan Transaction and 60 days after the consummation of the Rowan Transaction (or any extended period if either Moody’s or S&P publicly announces a possible downgrade). As a result, we could be required to repay up to an aggregate $500.0 million principal amount of senior notes plus $5.0 million in associated premiums.

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In addition, the completion of the Rowan Transaction will constitute a change of control under Rowan’s 2018 and 2014 revolving credit facilities. As a result, at the direction of the lenders holding a majority of the unfunded commitments and outstanding loans under a revolving credit facility, the commitments under such revolving credit facility may be terminated and the outstanding balance under such revolving credit facilities may be accelerated and become due and payable by Rowan in connection with the completion of the Rowan Transaction. As of December 31, 2018, Rowan had no outstanding borrowings under its revolving credit facilities.

If a governmental authority asserts objections to the Rowan Transaction, we and Rowan may be unable to complete the Rowan Transaction or, in order to do so, we and Rowan may be required to comply with material restrictions or satisfy material conditions.

The completion of the Rowan Transaction is subject to the condition that there is no order, injunction, decree or other legal restraint by a governmental authority in effect restraining, preventing or prohibiting the Rowan Transaction contemplated by the Transaction Agreement. If a governmental authority asserts objections to the Rowan Transaction, we or Rowan may be required to divest assets or accept other remedies in order to complete the Rowan Transaction. There can be no assurance as to the cost, scope or impact of the actions that may be required to address any governmental authority objections to the Rowan Transaction. If we or Rowan takes such actions, it could be detrimental to us or to the combined company following the consummation of the Rowan Transaction. Furthermore, these actions could have the effect of delaying or preventing completion of the Rowan Transaction or imposing additional costs on or limiting the operating results or cash flows of the combined company following the consummation of the Rowan Transaction.

In addition, in some circumstances, a third party could initiate a private action under antitrust laws challenging or seeking to enjoin the Rowan Transaction, before or after it is completed. We or Rowan may not prevail and may incur significant costs in defending or settling any action under the antitrust laws.

If completed, the Rowan Transaction may not achieve its intended results, and we and Rowan may be unable to successfully integrate our operations. Failure to successfully combine our business and Rowan's business in the expected time frame may adversely affect the future results of the combined organization, and, consequently, the value of our shares that Rowan shareholders receive as the Rowan Transaction consideration.

We and Rowan entered into the Transaction Agreement with the expectation that the Rowan Transaction will result in various benefits, including, among other things, expanding our geographic presence and customer base and creating synergies. Achieving the anticipated benefits of the Rowan Transaction is subject to a number of uncertainties, including whether the businesses of us and Rowan can be integrated in an efficient and effective manner.

It is possible that the integration process could take longer than anticipated and could result in the loss of valuable employees, the disruption of each company’s ongoing businesses, processes and systems or inconsistencies in standards, controls, procedures, practices, policies and compensation arrangements, any of which could adversely affect the combined company’s ability to achieve the anticipated benefits of the Rowan Transaction. The combined company’s results of operations could also be adversely affected by any issues attributable to either company’s operations that arise or are based on events or actions that occur prior to the completion of the Rowan Transaction. The companies may have difficulty addressing possible differences in corporate cultures and management philosophies. The integration process is subject to a number of uncertainties, and no assurance can be given that the anticipated benefits will be realized or, if realized, the timing of their realization. Failure to achieve these anticipated benefits could result in increased costs or decreases in the amount of expected revenues and could adversely affect the combined company’s future business, financial condition, operating results and cash flows.

A downgrade in our or our subsidiaries’ credit ratings following the Rowan Transaction could impact the combined company’s access to capital and cost of doing business.

Following the Rowan Transaction, rating agencies may re-evaluate our and our subsidiaries’ ratings, and any additional actual or anticipated downgrades in such credit ratings could limit our ability to access credit and capital markets, or to restructure or refinance our indebtedness. As a result of any such downgrades, future financings or

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refinancings may result in higher borrowing costs and require more restrictive terms and covenants, including obligations to post collateral with third parties, which may further restrict operations and negatively impact liquidity.

Credit rating agencies perform independent analysis when assigning credit ratings. The analysis includes a number of criteria including, but not limited to, business composition, market and operational risks, as well as various financial tests. Credit rating agencies continue to review the criteria for industry sectors and various debt ratings and may make changes to those criteria from time to time. Credit ratings are not recommendations to buy, sell or hold investments in the rated entity. Ratings are subject to revision or withdrawal at any time by the rating agencies, and we cannot assure you that we will maintain our current credit ratings.

The Rowan Transaction may be completed even though material adverse changes subsequent to the announcement of the Rowan Transaction, such as industry-wide changes or other events, may occur.

In general, either party can refuse to complete the Rowan Transaction if there is a material adverse change affecting the other party. However, some types of changes do not permit either party to refuse to complete the Rowan Transaction, even if such changes would have a material adverse effect on either of the parties. For example, a worsening of our or Rowan's financial condition or results of operations due to a decrease in commodity prices or general economic conditions would not give the other party the right to refuse to complete the Rowan Transaction. If adverse changes occur that affect either party but the parties are still required to complete the Rowan Transaction, our share price, business and financial results after the Rowan Transaction may suffer.

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 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 causing operators to reduce capital spending and cancel or defer existing programs, substantially reducing the opportunities for new drilling contracts. More recently, oil prices have increased meaningfully from the decade lows reached during 2016, with Brent crude averaging nearly $55 per barrel in 2017 and more than $70 per barrel through the first nine months of 2018, leading to signs of a gradual recovery in demand for offshore drilling services. However, macroeconomic and geopolitical headwinds triggered a market correction during the fourth quarter of 2018, resulting in a decline in Brent crude prices from more than $85 per barrel at the beginning of the quarter to approximately $50 per barrel at year-end. Commodity prices have not improved to a level that supports increased rig demand sufficient to absorb existing rig supply and generate meaningful increases in day rates. We expect these trends to continue as long as commodity prices and rig supply 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,


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oil and natural gas supply and demand,

expectations regarding future energy prices, 

the ability of the Organization of Petroleum Exporting Countries ("OPEC") to reach further agreements to set and maintain production levels and pricing and to implement existing and future 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, 

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

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

the development and exploitation of alternative fuels or energy sources, 

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 2014, 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 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, 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.


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

Our industry is highly competitive, and our contracts are traditionally awarded on a competitive bid basis. Pricing, safety records and competency are key factors in determining which qualified contractor is awarded a job. Rig availability, location and technical capabilities also can be significant factors in the determination. 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 105 competitive newbuild drillships, semisubmersibles and jackup rigs reported to be on order or under construction with delivery expected by the end of 2020.  Approximately 71 of these rigs are scheduled for delivery during 2019, representing an approximate 9% increase in the total worldwide fleet of competitive offshore drilling rigs since year-end 2018. Many of these offshore drilling rigs do not have drilling contracts in place. In addition, the supply of marketed offshore drilling rigs could further increase due to depressed market conditions resulting in 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 has required us, and may in the future require us, to idle or scrap 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 or 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.

Two of our three rigs under construction, which are scheduled for delivery between 2019 and 2020, are currently uncontracted. There is no assurance that we will secure drilling contracts for these rigs, or future rigs we construct or acquire, 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 or cash flows.


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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 allocated so that we and our customers each assume liability for our respective personnel and property. Our customers have historically assumed most of the responsibility for and indemnified 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. However, we regularly are required to assume a limited amount of liability for pollution damage caused by our negligence, which liability generally has caps for ordinary negligence, with much higher caps or unlimited liability where the damage is caused by our gross negligence. Notwithstanding a contractual indemnity from a customer, there can be no assurance that our customers will be financially able to assume their responsibility and 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 in excess of those agreed in our contracts due to customer balance sheet or liquidity issues or applicable law.

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

In market downturns similar to the current environment, our customers may not be able to honor the terms of existing contracts, 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. Often, 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 fee 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 all of the lost revenue. Certain of our contracts permit termination by the customer without an early termination fee. Furthermore, financially distressed customers may seek to negotiate reduced termination fees 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 or 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

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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 2017, we recognized a pre-tax, non-cash loss on impairment of $182.9 million related to two floaters and one jackup rig, all of which were older, less capable, non-core assets in our fleet. During 2018, we recognized a pre-tax, non-cash loss on impairment of $40.3 million related to an older, non-core jackup rig. During the three years ended December 31, 2018, we have recorded pre-tax, non-cash losses on impairment of long-lived assets totaling $223.2 million. Further asset impairments may be necessary if market conditions remain depressed for longer than we expect. See Note 5 to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" for additional information.

The loss of a significant customer or customer contract could adversely affect us.

We provide our services to major international, government-owned and independent oil and gas companies.  During 2018, our five largest customers accounted for 48% of our consolidated revenues in the aggregate, with our largest customer representing 15% of our consolidated revenues. In addition, our largest customer contract represents a significant percentage of our operating cash flows.  Our financial position, operating results or cash flows may be materially adversely affected if any of our higher day rate contracts were terminated or renegotiated on less favorable terms or 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, 2018, our contract backlog was approximately $2.2 billion, which represents a decline of $638.6 million since December 31, 2017. This amount reflects the remaining contractual terms multiplied by the applicable contractual day rate. The contractual revenue may be higher than the actual revenue we ultimately 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 or 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.

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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 punch-throughs, capsizing, sinking, grounding, collision, damage from severe weather and marine life infestations.  Additionally, a cyber attack or other 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 rights 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. 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 or our clients are unable to meet their indemnification obligation), it could adversely affect our financial position, operating results or cash flows.


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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 four jackup rigs and five 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 in the past, including the total loss of drilling rigs, 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 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. It is likely that the tight insurance market for windstorm damage, liabilities and removal of wreckage and debris will 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 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 four jackups and five 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, and these procedures may, on occasion, 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 MODU 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, 2019, 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 or cash flows if we sustain significant uninsured or underinsured losses or liabilities as a result of these storms or hurricanes.


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

Revenues from non-U.S. operations were 87%, 92% and 81% of our total revenues during 2018, 2017 and 2016, 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 or our customer's property, 

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,

changes in political conditions, and 

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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 or cash flows.

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

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

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

A portion of the costs and expenditures incurred by our non-U.S. operations, including 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.
    

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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, reduced day rates during such downtime and contract cancellations. 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.

The results of the U.K.'s referendum on withdrawal from the E.U. may have a negative effect on global economic conditions, financial markets and our business.

In June 2016, a referendum was held in the U.K. which resulted in a majority voting in favor of the U.K. withdrawing from the E.U. (commonly referred to as “Brexit”). The U.K. will continue to be a member of the E.U. until the expiration of a two-year notice period, following the U.K.’s formal notification to the European Council under Article 50 of the Treaty on European Union (which occurred on March 29, 2017), or until such other date as is agreed by all 28 member states of the E.U., unless prior to any such date the U.K. elects to revoke its formal Article 50 notification to the European Council. While the U.K. government and the European Commission have agreed to the terms of a withdrawal agreement, on January 16, 2019, the U.K. Parliament voted against the withdrawal agreement in its current form. There is currently no certainty that the withdrawal agreement will be ratified by, in particular, the U.K. Parliament or the European Parliament or the European Council. Consequently, the terms on which, and the date on which, the U.K. will withdraw from the E.U. (if at all) remain difficult to predict. In addition, it is expected that, if and when the U.K. withdraws from the E.U., the U.K. and the E.U. will hold further negotiations seeking to establish the terms of the long-term trading relationship between the U.K. and the E.U.

The referendum and the political negotiation surrounding the terms of the U.K.’s withdrawal from the E.U. have created significant uncertainty about the future relationship between the U.K. and the E.U., including with respect to the laws and regulations that will apply. This is because if the U.K. withdraws from the E.U. (and subject to the terms of any withdrawal agreement), the U.K. will determine which E.U.-derived laws to replace or replicate in the event of a withdrawal. The referendum has also given rise to calls for the governments of other E.U. member states to consider withdrawal, while the U.K.’s withdrawal negotiation process has increased the risk of governmental change in the U.K. as well as the possibility of a further referendum concerning Scotland’s independence from the rest of the U.K.

If no withdrawal agreement is reached by March 29, 2019, the U.K.’s membership of the E.U. could terminate under a so-called “hard Brexit.” Under this scenario, there could be increased costs from the imposition of tariffs on trade or non-tariff barriers between the U.K. and E.U., shipping delays because of the need for customs inspections and temporary shortages of certain goods. Any of the foregoing might cause our U.K. suppliers to pass along these increased costs, if realized, to us in the U.K. In addition, trade and investment between the U.K., the E.U. and other countries would be impacted by the fact that the U.K. currently operates under tax and trade treaties concluded between the E.U. and other countries. Following a “hard Brexit”, the U.K. would need to negotiate its own tax and trade treaties with other countries, as well as with the E.U. Any new, or changes to existing, U.K. tax laws could make the U.K. a

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less desirable jurisdiction of incorporation for our parent company, Ensco plc. In addition, one of our U.K. subsidiaries owns two jackup rigs, and following a “hard Brexit,” the E.U. might require some form of importation fee or guarantee on certain U.K. owned rigs that operate outside U.K. waters.

These developments, or the perception that any of them could occur, have had and may continue to have a material adverse effect on global, regional and/or national economic conditions and the stability of global financial markets, and may significantly reduce global market liquidity and restrict the ability of key market participants to operate in certain financial markets. Any of these factors could depress economic activity, result in changes to currency exchange rates, tariffs, treaties, taxes, import/export regulations, laws and other regulatory matters, and/or restrict our access to capital and the free movement of our employees, which could have a material adverse effect on our financial position, operating results or cash flows. Approximately 11% of our total revenues were generated in the U.K. for the year ended December 31, 2018.

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 15 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, personal injury and other claims for damages (including consequential damages), 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, 2017 and 2018. In the future, our Board of Directors may, without advance notice, 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, restrictions and limitations in our credit facility and other debt documents 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 adversely affect us.

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 International LLC ("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

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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.

On August 29, 2018, we received a letter from the Division of Enforcement of the SEC informing us that the Division had concluded its investigation into alleged irregularities related to the drilling services agreement with Petrobras for ENSCO DS-5 (the “DSA”) and does not intend to recommend any enforcement action against us. On August 31, 2018, we received a letter from the DOJ stating that it had closed the inquiry into this matter and acknowledging our full cooperation with the investigation. See Item 1 “Legal Proceedings” in our quarterly report on Form 10-Q for the quarter ended June 30, 2018, for further information on the investigation.
    
In August 2017, one of our Brazilian subsidiaries was contacted by the Office of the Attorney General for the Brazilian state of Paraná in connection with a criminal investigation procedure initiated against agents of both Samsung Heavy Industries, a shipyard in South Korea (“SHI”), and Pride in relation to the DSA. The Brazilian authorities requested information regarding our compliance program and the findings of our internal investigations. We cooperated with the Office of the Attorney General and provided documents in response to its request. We cannot predict the scope or ultimate outcome of this procedure or whether any Brazilian governmental authority will open an investigation into Pride’s involvement in 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 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 2010 Macondo well incident in the U.S. Gulf of Mexico, the U.S. Department of the Interior issued Notices to Lessees, implementing new requirements and/or guidelines that are applicable to drilling operations in the U.S. Gulf of Mexico. Current or future Notice to Lessees 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. In 2016, BSEE promulgated the 2016 Well Control Rule imposing 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. In May 2018, BSEE proposed revisions to the 2016 Well Control Rule. This proposed rule would revise requirements for well design, well control, casing, cementing, real-time monitoring and subsea containment. The revisions are targeted to ensure safety and environmental protection while correcting errors in the 2016 rule and reducing certain unnecessary regulatory burdens imposed under the existing regulations. The proposed revisions have not yet been finalized.

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Also, as a result of the Macondo well incident, BSEE and its predecessor agency promulgated regulations regarding SEMS. 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 in the past 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 issued an IPD for use by BSEE inspectors in 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 was 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 indicated that BSEE’s enforcement actions would continue to focus primarily on lessees and operators, but that “in appropriate circumstances” BSEE also would issue INCs to contractors for “serious violations” of BSEE regulations. Following federal court decisions successfully challenging the scope of BSEE’s jurisdiction over offshore contractors, this IPD has been removed from the list of IPDs on the BSEE website. If this judicial precedent stands, it may reduce regulatory and civil litigation liability exposures.

Since 2014, the United States Coast Guard has proposed new regulations that would impose GPS equipment and positioning requirements for MODUs and jackup rigs operating in the U.S. Gulf of Mexico and issued notices regarding the development of guidelines for cybersecurity measures used in the marine and offshore energy sectors for all vessels and facilities that are subject to the MTSA, including our rigs. In 2016, BSEE adopted the 2016 Well Control Rule, which 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. As described above, revisions to this rule have been proposed by BSEE, which could reduce the regulatory burden of the rule. We are continuing to evaluate the cost and effect that these new rules will have on our operations. However, 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.

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

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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 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. Although 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 or cash flows. Further, remedies under the Clean Water Act and related legislation and 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, 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 or cash flows could be materially adversely affected.

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. 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. 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.

Regulation of greenhouse gases and climate change could have a negative impact on our business.

Governments around the world are increasingly focused on enacting laws and regulations regarding climate change and regulation of greenhouse gases. Lawmakers and regulators in the jurisdictions where we operate have proposed or enacted regulations requiring reporting of greenhouse gas emissions and the restriction thereof, including increased fuel efficiency standards, carbon taxes or cap and trade systems, restrictive permitting, and incentives for renewable energy. In addition, efforts have been made and continue to be made in the international community toward the adoption of international treaties or protocols that would address global climate change issues and impose reductions

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of hydrocarbon-based fuels, including plans developed in connection with the Paris climate conference in December 2015 and the Katowice climate conference in December 2018. Laws or regulations incentivizing or mandating the use of alternative energy sources such as wind power and solar energy have also been enacted in certain jurisdictions. Additionally, numerous large cities globally and several countries have adopted programs to mandate or incentivize the conversion from internal combustion engine powered vehicles to electric-powered vehicles and placed restrictions on non-public transportation. Such policies or other laws, regulations, treaties and international agreements related to greenhouse gases and climate change may negatively impact the price of oil relative to other energy sources, reduce demand for hydrocarbons, limit drilling in the offshore oil and gas industry, or otherwise unfavorably impact our business, our suppliers and our customers, and result in increased compliance costs and additional operating restrictions, all of which would have a material adverse impact on our business. In addition, there have also been efforts in recent years to influence the investment community, including investment advisors and certain sovereign wealth, pension and endowment funds promoting divestment of fossil fuel equities and pressuring lenders to limit funding to companies engaged in the extraction of fossil fuel reserves. Such environmental activism and initiatives aimed at limiting climate change and reducing air pollution could ultimately interfere with our business activities and operations.

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 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.

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 two ultra-deepwater drillships 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. We agreed with the shipyard constructing ENSCO 123 to delay the delivery of the rig until 2019 and, prior to the closing of the Atwood Merger, Atwood agreed to delay the delivery of two ultra deepwater drillships, ENSCO DS-13 and ENSCO DS-14, into 2019 and 2020, respectively. 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, 


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

unanticipated actual or purported change orders, 

strikes, labor disputes or work stoppages, 

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

unanticipated cost increases, 

foreign currency exchange rate fluctuations impacting overall cost, 

inability to obtain the requisite permits or approvals, 

client acceptance delays, 

disputes with shipyards and suppliers, 

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

claims of force majeure events, and 

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

With respect to ENSCO DS-13 and ENSCO DS-14, 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 or cash flows. The same risks apply to ENSCO 123 which was recently contracted and is expected to commence operations in July 2019 in the North Sea.

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 was intense 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. The recent prolonged industry downturn may further reduce the number of qualified personnel available. 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.


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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.

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, 2018, we had $5.0 billion in total debt outstanding, representing approximately 38.2% of our total capitalization. Our current indebtedness may have several important effects on our future operations, including:
 
a substantial portion of our cash flows from operations will be dedicated to the payment of principal and interest,
 
covenants contained in our debt arrangements require us to meet certain financial tests, which may affect our flexibility in planning for, and reacting to, changes in our business and may limit our ability to dispose of assets or place restrictions on the use of proceeds from such dispositions, withstand current or future economic or industry downturns and compete with others in our industry for strategic opportunities, and 

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

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

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

Our revolving credit facility places restrictions on us and certain of our subsidiaries with respect to incurring additional indebtedness and liens, paying dividends and other payments to shareholders, repurchasing our ordinary shares, repurchasing or redeeming certain other indebtedness which matures after the revolving credit facility, entering into mergers and other matters. Our revolving credit facility also requires compliance with covenants to maintain specified financial and guarantee coverage ratios. These restrictions may limit our flexibility in obtaining additional financing and in pursuing various business opportunities.

In addition, our access to credit and capital markets depends on the credit ratings assigned to our credit facility and our notes by independent credit rating agencies. In recent years, we have experienced downgrades in our corporate credit rating and the credit rating of our senior notes. Our access to credit and capital markets may be more limited because we no longer have an investment grade credit rating. Any additional actual or anticipated downgrades in our corporate credit rating or the credit rating of our notes could further limit our ability to access credit and capital markets, or to restructure or refinance our indebtedness. Furthermore, 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. Limitations on our ability to access credit and capital markets could have a material adverse impact on our financial position, operating results or cash flows.

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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 or 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 useful 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 proceeds from sales of non-core assets, we may be required to either incur additional borrowings or raise capital through the sale of debt or equity securities. Our ability to access the capital markets may be limited by our financial condition at the time, by changes in laws and regulations (or interpretation thereof) and by adverse market conditions resulting from, among others, general economic conditions, contingencies and uncertainties that are beyond our control. Similarly, when lenders and institutional investors reduce, and in some cases cease to provide, funding to corporate and other industrial borrowers, the liquidity and financial condition of us and our customers can be adversely impacted. 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 or cash flows.

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Significant part or equipment shortages, supplier capacity constraints, supplier production disruptions, supplier quality and sourcing issues or price increases could increase our operating costs, decrease our revenues and adversely impact our operations.

Our reliance on third-party suppliers, manufacturers and service providers to secure equipment, parts, components and sub-systems used in our operations exposes us to potential volatility in the quality, prices and availability of such items. Certain high-specification parts and equipment that we use in our operations may be available only from a small number of suppliers, manufacturers or service providers, or in some cases must be sourced through a single supplier, manufacturer or service provider. Recent industry consolidation has reduced the number of available suppliers. A disruption in the deliveries from such third-party suppliers, manufacturers or service providers, capacity constraints, production disruptions, price increases, quality control issues, recalls or other decreased availability of parts and equipment could adversely affect our ability to meet our commitments to customers, thus adversely impacting our operations and revenues 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 on 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 and vendor data; disruption of our or our customers' operations; and increased costs to prevent, respond to or mitigate cybersecurity events.  Despite our security measures, our information technology and infrastructure may be vulnerable to attacks by hackers or breached due to employee error, malfeasance or other disruptions. Any such breach could compromise our networks or our customers' and vendors' networks and the information stored there could be accessed, publicly disclosed, lost or stolen. Any such access, disclosure or other loss of information could result in legal claims or proceedings, including under data privacy laws and regulations such as the European Union General Data Protection Regulation, disrupt our operations and damage our reputation, which could adversely affect our financial position, operating results or cash flows. In the past, we have experienced data security breaches resulting from unauthorized access to our systems, which to date have not had a material impact on our operations; however, there is no assurance that such impacts will not be material in the future.

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

38



classification under U.S. GAAP, including maintaining the ability to settle the 2024 Convertible Notes entirely in 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 6 to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" for additional information on our 2024 Convertible Notes.

The IRS may not agree with the conclusion that we should be treated as a foreign corporation for U.S. federal tax purposes following the Atwood Merger.

Although Ensco plc is incorporated in the United Kingdom, the U.S. Internal Revenue Service (“IRS”) may assert that we should be treated as a U.S. corporation (and, therefore, a U.S. tax resident) for U.S. federal income tax purposes following the Atwood Merger pursuant to Section 7874 of the Internal Revenue Code. For U.S. federal income tax purposes, a corporation is generally considered a U.S. “domestic” corporation (or U.S. tax resident) if it is organized in the United States, and a corporation is generally considered a “foreign” corporation (or non-U.S. tax resident) if it is not a U.S. domestic corporation. Because Ensco plc is an entity incorporated in England and Wales, it would generally be classified as a foreign corporation (or non-U.S. tax resident) under these rules. Section 7874 of the Internal Revenue Code provides an exception under which a foreign incorporated entity may, in certain circumstances, be treated as a U.S. domestic corporation for U.S. federal income tax purposes.

We would be treated as a U.S. domestic corporation (that is, as a U.S. tax resident) for U.S. federal income tax purposes following the Atwood Merger pursuant to Section 7874 of the Internal Revenue Code if the percentage (by vote or value) of our shares considered to be held by former holders of shares of Atwood common stock after the acquisition by reason of holding shares of Atwood common stock for purposes of Section 7874 of the Internal Revenue Code (the “Section 7874 Percentage”) was 80% or more.

The Section 7874 Percentage at the time of the acquisition was less than 60%. The calculation of the Section 7874 Percentage, however, is complex, is subject to detailed regulations and is subject to factual uncertainties. As a result, the IRS could assert that the Section 7874 Percentage was greater than 80% and that we therefore are treated for U.S. federal income tax purposes as a U.S. domestic corporation (that is, as a U.S. tax resident) following the acquisition. If the IRS successfully challenged our status as a foreign corporation, significant adverse tax consequences would result for us and for certain of our shareholders.

U.S. tax laws and IRS guidance could affect our ability to engage in certain acquisition strategies and certain internal restructurings.

Even if we are treated as a foreign corporation for U.S. federal income tax purposes, Section 7874 of the Internal Revenue Code and U.S. Treasury Regulations promulgated thereunder, including temporary Treasury Regulations, may adversely affect our ability to engage in certain future acquisitions of U.S. businesses in exchange for our equity, which may affect the tax efficiencies that otherwise might be achieved in such potential future transactions.


39



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 or 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. 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 jurisdictions with high tax rates to jurisdictions with lower tax rates. Certain countries within which we operate have recently enacted changes to their tax laws in response to the OECD recommendations or otherwise and these and other countries may enact changes to their tax laws or practices in the future (prospectively or retroactively), which may have a material adverse effect on our financial position, operating results or cash flows. U.S. federal income tax reform legislation enacted in late 2017, formally known as the Tax Cuts and Jobs Act of 2017, introduced significant changes to U.S. income tax law, including a reduction in the statutory income tax rate from 35% to 21% effective January 1, 2018, a one-time transition tax on deemed repatriation of deferred foreign income, a base erosion anti-abuse tax that effectively imposes a minimum tax on certain payments to non-U.S. affiliates, new and revised rules relating to the current taxation of certain income of foreign subsidiaries and revised rules associated with limitations on the deduction of interest.

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 income taxes 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 income taxes to increase and cause a material adverse effect on our financial position, operating results or cash flows.

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

We cannot provide any assurances as to what our 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 increase the amounts we have provided for income taxes or deferred tax assets and liabilities in our consolidated financial statements. In addition, as a result of frequent changes in the taxing jurisdictions in which our drilling rigs are operated and/or owned, changes in the overall level of our income and changes in tax laws, our consolidated effective income tax rate may vary substantially from one reporting period to another. 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 net income. 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 or cash flows.


40



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.

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 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 we are a public limited company incorporated under the Laws of England and Wales, investors could experience difficulty enforcing judgments obtained against us in U.S. courts. In addition, it may be more difficult (or

41



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 general meeting in 2018 to authorize the allotment of up to a prescribed amount of additional shares until the conclusion of the next annual general meeting or the close of business on August 21, 2019 (whichever is earlier). This authority was further increased by shareholders at an additional general meeting on February 21, 2019, expiring at the next annual shareholder meeting or at the close of business on April 22, 2020 (whichever is earlier). 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 up to a prescribed amount of shares for an additional 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 general meeting in 2018, to disapply pre-emption rights in respect of new shares up to a prescribed amount until the conclusion of the next annual general meeting or the close of business on August 21, 2019 (whichever is earlier). This authority was further increased by shareholders at an additional general meeting on February 21, 2019, expiring at the next annual shareholder meeting or at the close of business on April 22, 2020 (whichever is earlier). Special resolutions will be put to shareholders at our next annual shareholder meeting seeking their approval to renew the board's authority to disapply pre-emption rights in respect of new shares up to a prescribed amount for an additional 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 our annual shareholder meeting in May 2018 to permit us to make "off-market" purchases of our own shares pursuant to certain purchase agreements for a five-year term.

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

Our articles of association contain anti-takeover provisions.

Certain provisions of our articles of association have anti-takeover effects, such as the ability to issue shares under the Rights Plan (as defined therein). These provisions are intended to ensure that any takeover or change of control of the Company is conducted in an orderly manner, all shareholders 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.


42



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 (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 Code is different from that used by the U.K. tax authorities. Under the Code, the Takeover Panel will look to where the majority of the directors of the company are residents for the purposes of determining where the company has its place of central management and control. Accordingly, the Takeover Panel has previously indicated that the Code does not apply to the Company and the Company's shareholders therefore do 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 declaring dividends and returning 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 a general 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.

43



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 20, 2019:
 
 
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'
 
Nigeria
Under contract
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'
 
Spain
Available
ENSCO DS-7
Drillship
 
2013
 
Dynamically Positioned
 
10,000'/40,000'
 
Cyprus
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'
 
French Guiana
Under contract
ENSCO DS-10
Drillship
 
2018
 
Dynamically Positioned
 
10,000'/40,000'
 
Nigeria
Under contract
ENSCO DS-11
Drillship
 
2013
 
Dynamically Positioned
 
12,000'/40,000'
 
Spain
Available
ENSCO DS-12
Drillship
 
2013
 
Dynamically Positioned
 
12,000'/40,000'
 
Spain
Under contract
ENSCO DS-13
Drillship
 
2019
 
Dynamically Positioned
 
12,000'/40,000'
 
South Korea
Under construction(2)
ENSCO DS-14
Drillship
 
2020
 
Dynamically Positioned
 
12,000'/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 5006
Semisubmersible
 
1999/2014
 
Bingo 8000
 
7,000'/25,000'
 
Australia
Under contract
ENSCO 6002
Semisubmersible
 
2001/2009/2015
 
Megathyst
 
5,600'/25,000'
 
Brazil
Under contract
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'
 
Mexico
Under contract
ENSCO 8504
Semisubmersible
 
2011
 
Dynamically Positioned
 
8,500'/35,000'
 
Japan
Under contract
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)
ENSCO DPS-1
Semisubmersible
 
2012
 
Dynamically Positioned
 
10,000'/35,000'
 
Australia
Under contract
ENSCO MS-1
Semisubmersible
 
2011
 
F&G ExD Millennium
 
8200'/32,000'
 
Malaysia
Available
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Jackups
 
 
 
 
 
 
 
 
 
 
ENSCO 54
Jackup
 
1982/1997/2014
 
F&G L-780 MOD II-C
 
300'/25,000'
 
Saudi Arabia
Under contract
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
Preservation stacked(1)
ENSCO 71
Jackup
 
1982/1995/2012
 
Hitachi K1032N
 
225'/25,000'
 
United Kingdom
Preservation stacked(1)
ENSCO 72
Jackup
 
1981/1996
 
Hitachi K1025N
 
225'/25,000'
 
United Kingdom
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 84
Jackup
 
1981/2005/2012
 
MLT 82-SD-C
 
250'/25,000'
 
Saudi Arabia
Under contract
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 92
Jackup
 
1982/1996
 
MLT 116-C
 
225'/25,000'
 
United Kingdom
Under contract
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 100
Jackup
 
1987/2009
 
MLT 150-88-C
 
350'/30,000
 
United Kingdom
Available

44



 
 
Rig Name
 
 
  Rig Type
 
 
Year Built/
Rebuilt
 
 
 
Design      
 
   Maximum
 Water Depth/
Drilling Depth
 
 
  Location   
 
 
Status    
Jackups
 
 
 
 
 
 
 
 
 
 
ENSCO 101
Jackup
 
2000
 
KFELS MOD V-A
 
400'/30,000'
 
United Kingdom
Under contract
ENSCO 102
Jackup
 
2002
 
KFELS MOD V-A
 
400'/30,000'
 
Gulf of Mexico
Under contract
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
Preservation stacked(1)
ENSCO 106
Jackup
 
2005
 
KFELS MOD V-B
 
400'/30,000'
 
Indonesia
Under contract
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'
 
Saudi Arabia
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'
 
Qatar
Under contract
ENSCO 111
Jackup
 
2003
 
KFELS MOD V-B
 
400'/36,000'
 
Malta
Cold stacked
ENSCO 112
Jackup
 
2008
 
MLT Super 116-E
 
350'/30,000'
 
Malta
Cold stacked
ENSCO 113
Jackup
 
2012
 
Pacific Class 400
 
400'/30,000'
 
Philippines
Cold stacked
ENSCO 114
Jackup
 
2012
 
Pacific Class 400
 
400'/30,000'
 
Philippines
Cold stacked
ENSCO 115
Jackup
 
2013
 
Pacific Class 400
 
400'/30,000'
 
Malaysia
Under contract
ENSCO 120
Jackup
 
2013
 
KFELS Super A
 
400'/40,000'
 
United Kingdom
Under contract
ENSCO 121
Jackup
 
2013
 
KFELS Super A
 
400'/40,000'
 
United Kingdom
Under contract
ENSCO 122
Jackup
 
2014
 
KFELS Super A
 
400'/40,000'
 
United Kingdom
Under contract
ENSCO 123
Jackup
 
2019
 
KFELS Super A
 
400'/40,000'
 
Singapore
Under construction(3)
ENSCO 140
Jackup
 
2016
 
Cameron Letourneau Super 116E
 
400'/30,000'
 
Saudi Arabia
Under contract
ENSCO 141
Jackup
 
2016
 
Cameron Letourneau Super 116E
 
400'/30,000'
 
Saudi Arabia
Under contract

(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.

(3) 
Rig is currently under construction but is contracted to commence operations in July 2019 in the North Sea. 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 purpose-built maritime vessels 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 systems.  Our drillships are capable of drilling in water depths of up to 12,000 feet and are suitable for deepwater drilling in remote locations because of their superior 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 MODUs 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 or dynamically positioned by computer-controlled

45



propellers or "thrusters" 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 and ENSCO MS-1, which are moored semisubmersibles, are capable of deepwater drilling in water depths greater than 5,000 feet.  Dynamically positioned semisubmersibles generally are outfitted for drilling in deeper water depths and are well-suited for deepwater development and exploratory well drilling. Further, we have three hybrid semisubmersibles, ENSCO 8503, ENSCO 8504 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, 2019, 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, Aberdeen, Abu Dhabi, Australia, Dubai, Indonesia, Malaysia, Malta, Mexico, Nigeria, The Netherlands, Saudi Arabia, Singapore, Thailand, Vietnam and Qatar. We own offices and other facilities in Louisiana, Angola, Australia and Brazil.

Item 3.  Legal Proceedings
  
DSA Dispute

On January 4, 2016, Petrobras sent a notice to us declaring the drilling services agreement with Petrobras (the "DSA") for ENSCO DS-5, a drillship ordered from Samsung Heavy Industries, a shipyard in South Korea ("SHI"), void effective immediately, reserving its rights and stating its intention to seek any restitution to which it may be entitled. The previously disclosed arbitral hearing on liability related to the matter was held in March 2018. Prior to the arbitration tribunal issuing its decision, we and Petrobras agreed in August 2018 to a settlement of all claims relating to the DSA. No payments were made by either party in connection with the settlement agreement. The parties agreed to normalize business relations and the settlement agreement provides for our participation in current and future Petrobras tenders on the same basis as all other companies invited to these tenders. No losses were recognized during 2018 with respect to this settlement as all disputed receivables with Petrobras related to the DSA were fully reserved in 2015.  See Item 1 “Legal Proceedings” in our quarterly report on Form 10-Q for the quarter ended June 30, 2018 for further information about the DSA dispute.

In November 2016, we initiated separate arbitration proceedings in the U.K. against SHI for the losses incurred in connection with the foregoing Petrobras arbitration and certain other losses relating to the DSA. SHI subsequently filed a statement of defense disputing our claim. In January 2018, the arbitration tribunal for the SHI matter issued an award on liability fully in our favor. In August 2018, the tribunal awarded us approximately $2.8 million in costs and legal fees incurred to date, plus interest, which was collected during the fourth quarter.

The January 2018 arbitration award provides that SHI is liable to us for $10 million or damages that we can prove. We have submitted to the tribunal our claim for damages. The arbitral hearing on damages owed to us by SHI is scheduled to take place in the first quarter of 2019. We are unable to estimate the ultimate outcome of recovery for damages at this time. 



46



Pride FCPA Investigation

During 2010, Pride and its subsidiaries resolved their previously disclosed investigations into potential violations of the U.S. Foreign Corrupt Practices Act of 1977 (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 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 2017, 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 and cash flows, there can be no assurance as to the ultimate outcome of these assessments. A $180,000 liability related to these matters was included in accrued liabilities and other on our consolidated balance sheet as of December 31, 2018.
 
We currently are subject to a pending administrative proceeding initiated during 2009 by a Spanish government authority seeking payment in an aggregate amount of approximately $3.0 million for an alleged environmental spill originating from ENSCO 5006 while it was operating offshore Spain. Our customer has posted guarantees with the Spanish government to cover potential penalties. Additionally, we expect to be indemnified for any payments resulting from this incident by our customer under the terms of the drilling contract. A criminal investigation of the incident was initiated during 2010 by a prosecutor in Tarragona, Spain, and the administrative proceeding has 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 and cash flows, there can be no assurance as to the ultimate outcome of the proceedings.


47



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 and cash flows.

Item 4.  Mine Safety Disclosures
 
    Not applicable.

48



PART II


Item 5.
Market for Registrant's Common Equity, Related Shareholder Matters and Issuer Purchases of Equity Securities
Market Information
Our Class A ordinary shares are traded on the NYSE under the ticker symbol "ESV." Many of our shareholders hold shares electronically, all of which are owned by a nominee of DTC. We had 77 shareholders of record on February 1, 2019.
Dividends
 
Our Board of Directors declared a $0.01 quarterly cash dividend for the first quarter of 2019. In October 2017, we amended our revolving credit facility, which prohibits us from paying dividends in excess of $0.01 per share per fiscal quarter. Dividends in excess of this amount would require the amendment or waiver of such provision.

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.

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.

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.


49



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, self-invested personal 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 £2,000 of taxable dividend income received by an individual shareholder in the tax year 2018/2019 (the "Nil Rate Amount"), regardless of what tax rate would otherwise apply to that dividend income,

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

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

Where a shareholder’s taxable dividend income for a tax year exceeds the Nil Rate Amount, the excess amount will, subject to the availability of any income tax personal allowance, be subject to income tax at the following rates for the tax year 2018/2019:

at the rate of 7.5%, to the extent that the excess amount falls below the threshold for the higher rate of income tax,

at the rate of 32.5%, to the extent that the excess amount 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 excess amount 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 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,

50



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 2018 is 19%, and will be 19% for the financial year 2019. 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.

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 in the U.K. for a period of five years or less 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 2018/2019 is:

10%, to the extent that the shareholder's total taxable gains and taxable income in a given year, including any chargeable gains arising from a disposal of his or her shares ("Total Taxable Gains and Income"), are less than or equal to the upper limit of the income tax basic rate band applicable to that shareholder in respect of that tax year (the "Band Limit"), and

20%, to the extent that the shareholder's Total Taxable Gains and Income are more than the Band Limit.

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

51



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 19% in the financial year 2018 and 19% in the financial year 2019. Corporate shareholders may be entitled to an indexation allowance in computing the amount of a chargeable gain accruing on a disposal of the shares, which provides relief for the effects of inflation by reference to movements in the U.K. retail price index. Such indexation allowance is calculated only up to and including December 2017.

If the conditions of the substantial 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 12-month period beginning not more than six 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) 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 system will not be subject to U.K. stamp duty or SDRT.

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

We have put in place arrangements to require that shares held outside the facilities of DTC cannot be transferred into such facilities (including where shares are re-deposited into DTC by an existing shareholder) until the transferor of the shares has first delivered the shares to a depository we specify, so that stamp duty and/or 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 the depository in funds to settle the resultant liability for stamp duty and/or 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.
    

52



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."

Issuer Repurchases of Equity Securities
 
The following table provides a summary of our repurchases of our equity securities during the quarter ended December 31, 2018.

Issuer Repurchases of Equity Securities
 
  
 
 
Period
 
Total Number of Securities Repurchased(1)
 
Average Price Paid per Security
 
Total Number of Securities Repurchased as Part of Publicly Announced Plans or Programs (2)   
 
Approximate Dollar Value of Securities that May Yet Be Repurchased Under Plans or Programs
October 1 - October 31 
 
2,602

 
$
8.50

 

 
$
500,000,000

November 1 - November 30
 
4,858

 
$
6.53

 

 
$
500,000,000

December 1 - December 31
 
1,914

 
$
5.11

 

 
$
500,000,000

Total 
 
9,374

 
$
6.79

 

 
 


(1)
During the quarter ended December 31, 2018, 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) 
Our shareholders approved a new repurchase program at our annual shareholder meeting held in May 2018. 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 $500.0 million in the aggregate from one or more financial intermediaries under the program, but in no case more than 65.0 million shares. The program terminates in May 2023. Our prior share repurchase program approved by our shareholders in 2013, under which we could purchase up to a maximum of $2.0 billion in the aggregate, but in no case more than 35.0 million shares, expired in May 2018. As of December 31, 2018, there had been no share repurchases under this program.


53



Performance Chart    
    
The chart below presents a comparison of the five-year cumulative total return, assuming $100 invested on December 31, 2013 for Ensco plc, the Standard & Poor's MidCap 400 Index, and a self-determined peer group. Total return assumes the reinvestment of dividends, if any, in the security on the ex-dividend date. The Standard & Poor's MidCap 400 Index includes Ensco and has been included as a comparison. Since Ensco operates exclusively as an offshore drilling company, a self-determined peer group composed exclusively of major offshore drilling companies has been included as a comparison.* 

COMPARISON OF 5 YEAR CUMULATIVE TOTAL RETURN(1) 
Among Ensco plc, the S&P MidCap 400 Index and Peer Group
comparisonof5yearcumulat.jpg

(1)100 invested on 12/31/2013 in stock or index, including reinvestment of dividends.
Fiscal year ending December 31.

Copyright© 2019 S&P, a division of The McGraw-Hill Companies Inc. All rights reserved.
 
Fiscal Year Ended December 31,
 
2013
 
2014
 
2015
 
2016
 
2017
 
2018
Ensco plc
100.0

 
56.1

 
29.7

 
18.8

 
11.5

 
7.0

S&P MidCap 400
100.0

 
109.8

 
107.4

 
129.7

 
150.7

 
134.0

Peer Group
100.0

 
45.2

 
26.5

 
25.6

 
18.5

 
10.6

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

54



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,
 
2018
 
2017
 
2016
 
2015
 
2014
  
(in millions, except per share amounts)
Consolidated Statement of Operations Data
 
 
 

 
 

 
 

 
 

Revenues
$
1,705.4

 
$
1,843.0

 
$
2,776.4

 
$
4,063.4

 
$
4,564.5

Operating expenses
 

 
 

 
 

 
 

 
 

Contract drilling (exclusive of depreciation)
1,319.4

 
1,189.5

 
1,301.0

 
1,869.6

 
2,076.9

Loss on impairment
40.3

 
182.9

 

 
2,746.4

 
4,218.7

Depreciation
478.9

 
444.8

 
445.3

 
572.5

 
537.9

General and administrative
102.7

 
157.8

 
100.8

 
118.4

 
131.9

Operating income (loss)
(235.9
)

(132.0
)

929.3


(1,243.5
)

(2,400.9
)
Other income (expense), net
(303.0
)
 
(64.0
)
 
68.2

 
(227.7
)
 
(147.9
)
Income tax expense (benefit)
89.6

 
109.2

 
108.5

 
(13.9
)
 
140.5

Income (loss) from continuing operations
(628.5
)
 
(305.2
)

889.0


(1,457.3
)

(2,689.3
)
Income (loss) from discontinued operations, net(1)
(8.1
)
 
1.0

 
8.1

 
(128.6
)
 
(1,199.2
)
Net income (loss)
(636.6
)
 
(304.2
)

897.1


(1,585.9
)

(3,888.5
)
Net (income) loss attributable to noncontrolling interests
(3.1
)
 
.5

 
(6.9
)
 
(8.9
)
 
(14.1
)
Net income (loss) attributable to Ensco
$
(639.7
)
 
$
(303.7
)

$
890.2


$
(1,594.8
)

$
(3,902.6
)
Earnings (loss) per share – basic and diluted
 

 
 

 
 

 
 

 
 

Continuing operations
$
(1.45
)
 
$
(0.91
)
 
$
3.10

 
$
(6.33
)
 
$
(11.70
)
Discontinued operations
(0.02
)
 

 
0.03

 
(0.55
)
 
(5.18
)
 
$
(1.47
)
 
$
(0.91
)

$
3.13


$
(6.88
)

$
(16.88
)
Weighted-average shares outstanding
 

 
 

 
 

 
 

 
 

Basic and diluted
434.1

 
332.5

 
279.1

 
232.2

 
231.6

(1) 
See Note 11 to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" for information on discontinued operations.

 
Year Ended December 31,
 
2018
 
2017
 
2016
 
2015
 
2014
  
(in millions)
Consolidated Balance Sheet and Cash Flow Statement Data
 
 
 
 
 
 
 
 
 
Working capital
$
781.2

 
$
853.5

 
$
2,424.9

 
$
1,509.6

 
$
1,788.9

Total assets
$
14,023.7

 
$
14,625.9

 
$
14,374.5

 
$
13,610.5

 
$
16,023.3

Long-term debt
$
5,010.4

 
$
4,750.7

 
$
4,942.6

 
$
5,868.6

 
$
5,868.1

Ensco shareholders' equity
$
8,091.4

 
$
8,732.1

 
$
8,250.6

 
$
6,512.9

 
$
8,215.0

Cash flows from operating activities of continuing operations
$
(55.7
)
 
$
259.4

 
$
1,077.4

 
$
1,697.9

 
$
2,057.9

 

55




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 56 rigs, with drilling operations in most of the strategic markets around the globe. We also have three rigs under construction. Inclusive of our rigs under construction, our fleet includes 12 drillships, nine dynamically positioned semisubmersible rigs, three moored semisubmersible rigs and 35 jackup rigs.  We operate the world's 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 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 an integrated service that includes the provision of a drilling rig and rig crews for which we receive a daily rate that may vary between the full rate and zero rate throughout the duration of the contractual term, depending on the operations of the rig. We also may receive lump-sum fees or similar compensation for the mobilization, demobilization and capital upgrades of our rigs. 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.

Proposed Rowan Transaction

On October 7, 2018, Ensco plc and Rowan Companies plc ("Rowan") entered into an agreement that provides for the combination of the two companies (as amended the "Transaction Agreement"). Ensco has agreed to acquire the entire issued and to be issued share capital of Rowan in an all-stock transaction (the "Rowan Transaction") by way of a scheme of arrangement to be undertaken by Rowan under Part 26 of the UK Companies Act 2006. On January 29, 2019, the Transaction Agreement was amended to increase the exchange ratio in connection with the Rowan Transaction from 2.215 to 2.750.

Subject to the terms and conditions of the Transaction Agreement, each Class A ordinary share of Rowan will be converted into the right to receive 2.750 Class A ordinary shares of Ensco plc. We estimate the total consideration to be delivered in the Rowan Transaction to be approximately $1.5 billion, consisting of approximately 351.3 million of our shares based on the closing price of $4.41 on February 22, 2019. The value of the Rowan Transaction consideration will fluctuate until the closing date based on changes in the price of our shares and the number of Rowan ordinary shares outstanding.

The completion of the Rowan Transaction is subject to various closing conditions, including, among others, (i) the sanction of the Rowan Transaction by the High Court of Justice of England and Wales, (ii) the receipt of certain required regulatory approvals or lapse of certain review periods with respect thereto, including in the Kingdom of Saudi Arabia, (iii) the absence of legal restraints prohibiting or restraining the Rowan Transaction and (iv) the absence of any law or order reasonably expected to result in the dissolution of the Saudi Aramco Offshore Drilling Company, Rowan’s joint venture with Saudi Aramco (the “ARO JV”), or the sale, disposition, forfeiture or nationalization of Rowan’s interest in the ARO JV. Shareholders of Rowan and Ensco approved the Rowan Transaction and related proposals on February 21, 2019. The Rowan Transaction is expected to close during the first half of 2019, subject to satisfaction of all conditions to closing. Upon closing of the Rowan Transaction, we intend to complete a reverse split of our ordinary shares under which every four existing Ensco ordinary shares will be consolidated into one Ensco ordinary share.


56



Atwood Merger
    
On October 6, 2017 (the "Merger Date"), we completed a merger transaction (the "Atwood Merger") with Atwood Oceanics, Inc. ("Atwood") and Echo Merger Sub, LLC, a wholly-owned subsidiary of Ensco plc. Pursuant to the merger agreement, Echo Merger Sub, LLC, merged with and into Atwood, with Atwood as the surviving entity and an indirect, wholly-owned subsidiary of Ensco plc. Total consideration delivered in the Atwood Merger consisted of 132.2 million of our Class A ordinary shares and $11.1 million of cash in settlement of certain share-based payment awards. The total aggregate value of consideration transferred was $781.8 million. Additionally, upon closing of the Atwood Merger, we utilized cash acquired of $445.4 million and cash on hand to extinguish Atwood's revolving credit facility, outstanding senior notes and accrued interest totaling $1.3 billion. The estimated fair values assigned to assets acquired net of liabilities assumed exceeded the consideration transferred, resulting in a bargain purchase gain of $140.2 million that was recognized during the fourth quarter of 2017. During 2018, we recognized measurement period adjustments as we completed our fair value assessments resulting in additional bargain purchase gain of $1.8 million.

Our Industry

Operating results in the offshore contract drilling industry are highly cyclical and are 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 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

The decline in oil prices from 2014 highs led to a significant reduction in demand for offshore drilling services in recent years as many projects became uneconomic for customers at lower commodity prices. Customers significantly reduced their capital spending budgets, including the cancellation or deferral of existing programs, resulting in fewer contracting opportunities for offshore drilling rigs. Declines in capital spending levels, together with the oversupply of rigs, resulted in significantly reduced day rates and utilization.

More recently, oil prices have increased meaningfully from the decade lows reached during 2016, with Brent crude averaging nearly $55 per barrel in 2017 and more than $70 per barrel through the first nine months of 2018, leading to signs of a gradual recovery in demand for offshore drilling services. However, macroeconomic and geopolitical headwinds triggered a market correction during the fourth quarter of 2018, resulting in a decline in Brent crude prices from more than $85 per barrel at the beginning of the quarter to approximately $50 per barrel at year-end.
While market volatility may continue over the near-term, we expect long-term oil prices to remain at levels sufficient to result in more offshore projects that are economic for our customers. Therefore, we expect that near-term market conditions will remain challenging while demand for contract drilling services continues its gradual recovery with different segments of the market recovering more quickly than others.
Although oil prices have declined from the recent highs reached in 2018, we continue to observe improvements in the shallow-water market as higher levels of customer demand and rig retirements have led to gradually increasing jackup utilization over the past year. Moreover, new floater contracts and open tenders have increased as compared to a year ago due to improving economics for deepwater projects.
Despite the increase in customer activity, contract awards remain subject to an extremely competitive bidding process, and the corresponding pressure on operating day rates in recent periods has resulted in low margin contracts, particularly for floaters. Therefore, we expect our results from operations to continue to decline over the near-term as current contracts with above market rates expire and new contracts are executed at lower rates. We believe further improvements in demand coupled with a reduction in rig supply are necessary to improve the commercial landscape for day rates.

57



Drilling Rig Supply

Drilling rig supply continues to exceed drilling rig demand for both floaters and jackups. However, the decline in customer capital expenditure budgets over the past several years has led to a lack of contracting opportunities resulting in meaningful global fleet attrition. Since the beginning of the downturn, drilling contractors have retired approximately 120 floaters and 90 jackups. As 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, less capable rigs do not return to the global active fleet.

Approximately 20 floaters older than 30 years are idle, 10 additional floaters older than 30 years have contracts expiring by the end of 2019 without follow-on work and a further 10 floaters aged between 15 and 30 years have been idle for more than two years. 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.

Approximately 100 jackups older than 30 years are idle, and 60 jackups that are 30 years or older have contracts expiring by the end of 2019 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 continue during 2019.

There are 41 newbuild drillships and semisubmersibles reported to be under construction, of which 20 are scheduled to be delivered before the end of 2019. Most newbuild floaters are uncontracted. Several newbuild deliveries have been delayed into future years, and we expect that more uncontracted newbuilds will be delayed or cancelled.

There are 77 newbuild jackups reported to be under construction, of which 51 are scheduled to be delivered before the end of 2019. 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.

Liquidity, Backlog and Debt Maturities

We remain focused on our liquidity and over the past several years have executed a number of financing transactions to improve our financial position and manage our debt maturities. Based on our balance sheet, our contractual backlog and $2.0 billion available under our Credit Facility, we expect to fund our liquidity needs, including contractual obligations and anticipated capital expenditures, as well as working capital requirements, from cash and short-term investments and, if necessary, funds borrowed under our Credit Facility or other future financing arrangements, including available shipyard financing options for our two drillships under construction. We may rely on the issuance of debt and/or equity securities in the future to supplement our liquidity needs.

Cash and Debt

As of December 31, 2018, we had $5.0 billion in total debt outstanding, representing 38.2% of our total capitalization. We also had $604.1 million in cash and short-term investments and $2.0 billion undrawn capacity under our Credit Facility.

In January 2018, we issued $1.0 billion aggregate principal amount of unsecured 7.75% senior notes due 2026 (the "2026 Notes"), net of debt issuance costs of $16.5 million. Net proceeds of $983.5 million from the 2026 Notes were partially used to fund the repurchase and redemption of $237.6 million principal amount of our 8.50% senior notes due 2019, $328.0 million principal amount of our 6.875% senior notes due 2020 and $156.2 million principal amount of our 4.70% senior notes due 2021. We recognized a pre-tax loss on debt extinguishment of $19.0 million during the first quarter of 2018.

Following the January 2018 debt offering, repurchases and redemption, our only debt maturities until 2024 are $122.9 million during 2020 and $113.5 million during 2021.

58



        
Backlog

As of December 31, 2018, our backlog was $2.2 billion as compared to $2.8 billion as of December 31, 2017. Our floater backlog declined $636.8 million primarily due to revenues realized during 2018, partially offset by new contract awards and contract extensions. While our floater utilization increased marginally in 2018 to 46% from 45% in 2017, our floater backlog declined as revenues were realized on above-market, longer-term contracts and new contracts were executed a lower rates for shorter terms. Our jackup backlog increased $58.0 million primarily due to new contract awards as utilization increased to 63% in 2018 from 60% in 2017, partially offset by revenues realized during 2018. Our other segment backlog declined $59.8 million due to revenues realized during 2018.
    
As current contracts expire, we may experience further declines in backlog, which could result in a decline in revenues and operating cash flows during 2019. Contract backlog includes the impact of drilling contracts signed or terminated after each respective balance sheet date but prior to filing our annual reports on February 28, 2019 and February 27, 2018, respectively.

Drilling Rig Construction and Delivery

We remain focused on our long-established strategy of high-grading our fleet, as evidenced by the recently completed Atwood Merger and proposed Rowan Transaction. During the three-year period ended December 31, 2018, we invested approximately $1.0 billion in the construction of new drilling rigs. We will continue to invest in the expansion and high-grading of our fleet or execute other strategic transactions to optimize our asset portfolio when we believe attractive opportunities exist.

We believe our remaining capital commitments will primarily be funded from cash and short-term investments, and, if necessary, funds borrowed under our Credit Facility or other future financing arrangements, including available shipyard financing options for our two drillships under construction. We may decide to access debt and/or equity markets to raise additional capital or increase liquidity as necessary.

Floaters

We previously entered into an agreement with Samsung Heavy Industries to construct ENSCO DS-10, an ultra deepwater drillship. During 2017, we took delivery of ENSCO DS-10 and made the final milestone payment of $75.0 million. ENSCO DS-10 commenced drilling operations offshore Nigeria in March 2018.
    
In connection with the Atwood Merger, we acquired two ultra-deepwater drillships, ENSCO DS-13 and ENSCO DS-14, which are currently under construction in the Daewoo Shipbuilding & Marine Engineering Co. Ltd. yard in South Korea. ENSCO DS-13 and ENSCO DS-14 are scheduled for delivery during the third quarter of 2019 and second quarter of 2020, respectively. Upon delivery, the remaining milestone payments and accrued interest thereon may be financed through a promissory note with the shipyard for each rig. The promissory notes will bear interest at a rate of 5.0% per annum with a maturity date of December 30, 2022 and will be secured by a mortgage on each respective rig.
 
Jackups

During 2014, we entered into an agreement with Lamprell Energy Limited to construct two premium jackup rigs, ENSCO 140 and ENSCO 141, which are significantly enhanced versions of the LeTourneau Super 116E jackup design and incorporate Ensco's patented Canti-Leverage AdvantageTM technology. ENSCO 140 and ENSCO 141 were delivered during 2016 and commenced drilling operations offshore Saudi Arabia in July and August 2018, respectively.

We previously entered into an agreement with Keppel FELS to construct an ultra-premium harsh environment jackup, ENSCO 123. In December 2017, we agreed to delay delivery of ENSCO 123 until 2019, and in January 2018, we made a $207.4 million milestone payment. The remaining unpaid balance of $9.0 million is due upon delivery.

59



ENSCO 123 was designed to incorporate Ensco's patented Continuous Tripping Technology™, a new proprietary solution that provides safer and more efficient pipe tripping and helps to lower customers’ offshore project costs. We expect ENSCO 123 to commence drilling operations in the North Sea in July 2019.

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 12 jackup rigs, five dynamically positioned semisubmersible rigs, one moored semisubmersible rig and two drillships during the three-year period ended December 31, 2018.

We continue to focus on our fleet management strategy in light of the composition of our rig fleet. As part of this strategy, we may act opportunistically from time to time to monetize assets to enhance shareholder value and improve our liquidity profile, in addition to selling or disposing of older, lower-specification or non-core rigs.

BUSINESS ENVIRONMENT

Floaters

The floater contracting environment continues to be challenged due to limited demand and excess newbuild supply. Floater demand declined significantly since the beginning of the current market downturn due to lower commodity prices that have caused our customers to reduce capital expenditures. More recently, we have observed increased activity that has translated into marginal improvements in near-term utilization of our floater fleet; however, further improvements in demand and/or reductions in supply will be necessary before meaningful increases in utilization and day rates are realized.
    
During first quarter 2018, we executed two short-term contracts and a contract extension for ENSCO 8503, as well as a short-term contract for ENSCO 8505, in the U.S Gulf of Mexico.

During second quarter 2018, we executed a short-term contract extension for ENSCO DS-12 offshore Suriname as well as a short-term contract and contract extension for ENSCO 8505 and ENSCO 8503, respectively, in the U.S. Gulf of Mexico.  Additionally, our customer terminated the contract for ENSCO 8504 offshore Vietnam due to force majeure.

During third quarter 2018, we executed a one-well contract for ENSCO DS-9 that commenced in December 2018 offshore French Guiana, a two-well contract for ENSCO DS-12 that is expected to commence in April 2019 offshore Senegal, an eight-well contract for ENSCO 8505 that commenced in January 2019, a100-day contract for ENSCO 8503 that commenced in November 2018 offshore Mexico and a one-well contract for ENSCO 8504 that is expected to commence in April 2019 offshore Japan.

During fourth quarter 2018, we executed a one-year contract extension for ENSCO DS-10 offshore Nigeria and a two-well contract extension for ENSCO 5004 in the Mediterranean.

During first quarter 2019, we executed a four-well contract in the U.S. Gulf of Mexico for ENSCO 8503 that is expected to commence in June 2019 and a two-well contract offshore Australia for ENSCO DPS-1 that is expected to commence in February 2020.

During 2018, we sold three floaters for scrap value resulting in insignificant pre-tax gains.


60



Jackups

Demand for jackups has improved with increased tendering activity observed in recent periods; however, day rates remain depressed due to the oversupply of rigs.
During first quarter 2018, we executed a 16-month contract for ENSCO 104 offshore UAE.  We also executed short-term contracts or extensions for ENSCO 72, ENSCO 101 and ENSCO 122 in the North Sea as well as for ENSCO 68, ENSCO 75 and ENSCO 87 in the U.S. Gulf of Mexico.

During second quarter 2018, we executed three-year contracts for ENSCO 140, ENSCO 141 and ENSCO 108 offshore Saudi Arabia. ENSCO 140 and ENSCO 141 commenced operations during July 2018 and August 2018, respectively, and ENSCO 108 commenced operations during the fourth quarter. We also executed a 10-month contract for ENSCO 115 offshore Thailand that is expected to commence during first quarter 2019 and short-term contracts or extensions for ENSCO 101 and ENSCO 122 in the North Sea as well as for ENSCO 68 and ENSCO 75 in the U.S. Gulf of Mexico.

During third quarter 2018, we executed a nine-month contract extension for ENSCO 75 and short-term contracts or extensions for ENSCO 72, ENSCO 121 and ENSCO 122 in the North Sea as well as for ENSCO 68, ENSCO 87 and ENSCO 102 in the U.S. Gulf of Mexico.

During fourth quarter 2018, we executed a four-year contract extension for ENSCO 76 offshore Saudi Arabia and a 500-day contract extension for ENSCO 67 offshore Indonesia. We also executed a contract with a customer in the North Sea comprising three campaigns scheduled to commence in July 2019, March 2020 and June 2020. ENSCO 123 is contracted to perform the first and third campaigns and ENSCO 100 is contracted to perform the second campaign. However, the contract allows for us to provide any ENSCO 120 Series rig to perform the second and third campaigns.  Additionally, we executed short-term contracts for ENSCO 87 and ENSCO 102 in the U.S. Gulf of Mexico.

During first quarter 2019, we executed short-term contracts or extensions for ENSCO 72, ENSCO 100 and ENSCO 121 in the North Sea, ENSCO 96 offshore Saudi Arabia and ENSCO 107 offshore Australia.

During 2018, we sold three jackups for scrap value resulting in insignificant pre-tax gains.


61



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, 2018 (in millions):
 
 
2018
 
2017
 
2016
Revenues
 
$
1,705.4

 
$
1,843.0

 
$
2,776.4

Operating expenses
 
 

 
 

 
 

Contract drilling (exclusive of depreciation)
 
1,319.4

 
1,189.5

 
1,301.0

Loss on impairment
 
40.3

 
182.9

 

Depreciation
 
478.9

 
444.8

 
445.3

General and administrative 
 
102.7

 
157.8

 
100.8

Operating income (loss)
 
(235.9
)
 
(132.0
)
 
929.3

Other income (expense), net
 
(303.0
)
 
(64.0
)
 
68.2

Provision for income taxes 
 
89.6

 
109.2

 
108.5

Income (loss) from continuing operations
 
(628.5
)
 
(305.2
)
 
889.0

Income (loss) from discontinued operations, net
 
(8.1
)
 
1.0

 
8.1

Net income (loss)
 
(636.6
)
 
(304.2
)
 
897.1

Net (income) loss attributable to noncontrolling interests
 
(3.1
)
 
.5

 
(6.9
)
Net income (loss) attributable to Ensco
 
$
(639.7
)
 
$
(303.7
)
 
$
890.2

    
Overview

Year Ended December 31, 2018

Revenues declined by $137.6 million, or 7%, as compared to the prior year. The decline was primarily due to a decline in average day rates in both our floater and jackup fleets and the sale of several rigs during the year that operated in the year-ago period, partially offset by increased utilization and the addition of Atwood rigs to the fleet.

Contract drilling expense increased by $129.9 million, or 11%, as compared to the prior year. The increase was primarily due to addition of Atwood rigs to the fleet and the commencement of drilling operations for several of our newbuild rigs. This increase was partially offset by the sale of several rigs during the year that operated in the year-ago period and cost incurred during the prior year to settle a previously disclosed legal contingency.

Excluding the impact of $7.5 million and $51.6 million of transaction costs recognized during 2018 and 2017 respectively, general and administrative expenses declined by $11.0 million, or 10%, as compared to the prior year. The decline was primarily due to lower compensation costs and the recovery of certain legal costs awarded to us in connection with the SHI litigation.

Year Ended December 31, 2017

Excluding the impact of ENSCO DS-9 and ENSCO 8503 lump-sum termination payments totaling $205.0 million received during 2016, revenues declined by $728.4 million, or 28%, as compared to the prior year. The decline was primarily due to a decline in average day rates in both our floater and jackup segments and the sale of several rigs during the year that operated in the year-ago period. The decline was partially offset by the addition of Atwood rigs to the fleet during the fourth quarter of 2017.

    Contract drilling expense declined by $111.5 million, or 9%, as compared to the prior year. The decline was primarily due to lower fleet-wide utilization and the sale of several rigs that operated in the year-ago period. This decline was partially offset by the addition of Atwood rigs to the fleet during the fourth quarter of 2017.

62




Excluding the impact of $51.6 million of transaction costs associated with the Atwood Merger, general and administrative expenses increased by $5.4 million, or 5%, as compared to the prior year primarily due to increased compensation costs for certain performance-based awards.

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, 2018, 2017 and 2016:
 
 
2018
 
2017
 
2016
Floaters(1)(2)
 
22
 
24
 
19
Jackups(3)
 
34
 
37
 
36
Under construction(2)(4)
 
3
 
3
 
2
Held-for-sale(5)
 
 
1
 
2
Total
 
59
 
65
 
59

(1) 
During 2018, we sold ENSCO 5005 and ENSCO 6001. During 2017, we added ENSCO DS-11, ENSCO DS-12, ENSCO DPS-1 and ENSCO MS-1 from the Atwood Merger.

(2) 
During 2017, we accepted delivery of ENSCO DS-10.

(3) 
During 2018, we sold ENSCO 80, ENSCO 81 and ENSCO 82. During 2017, we added ENSCO 111, ENSCO 112, ENSCO 113, ENSCO 114 and ENSCO 115 from the Atwood Merger and sold ENSCO 86, ENSCO 99, ENSCO 52 and ENSCO 56.

(4) 
During 2017, we added ENSCO DS-13 and ENSCO DS-14 from the Atwood Merger, both of which are under construction.

(5)    During 2018, we sold ENSCO 7500. During 2017, we sold ENSCO 90.

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, 2018:
 
 
2018
 
2017
 
2016
Rig Utilization(1)
 
 

 
 

 
 

Floaters
 
46%
 
45%
 
54%
Jackups
 
63%
 
60%
 
60%
Total
 
56%
 
55%
 
58%
Average Day Rates(2)
 
 
 
 

 
 
Floaters
 
$
248,395

 
$
327,736

 
$
359,758