UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
_________________________________________________________________________________________________
FORM 10-K
þ
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
¨
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: 001-36211
_____________________________________________________________________________________________________
Noble Corporation plc
(Exact name of registrant as specified in its charter)
England and Wales (Registered Number 08354954)
 
98-0619597
(State or other jurisdiction of
incorporation or organization)
 
(I.R.S. employer
identification number)
10 Brook Street, London, England, W1S1BG
(Address of principal executive offices) (Zip Code)
Registrant’s Telephone Number, Including Area Code: +44 20 3300 2300
Securities registered pursuant to Section 12(b) of the Act:
Title of each class
 
Name of each exchange on which registered
Shares, Nominal Value $0.01 per Share
 
New York Stock Exchange
Commission file number: 001-31306
_____________________________________________________________________________________________________
Noble Corporation
(Exact name of registrant as specified in its charter)
Cayman Islands
 
98-0366361
(State or other jurisdiction of
incorporation or organization)
 
(I.R.S. employer
identification number)
Suite 3D Landmark Square, 64 Earth Close, P.O. Box 31327 George Town, Grand Cayman, Cayman Islands, KY1-1206
(Address of principal executive offices) (Zip Code)
Registrant’s Telephone Number, Including Area Code: (345) 938-0293
Securities registered pursuant to Sections 12(b) and 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  þ   No  ¨
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  ¨    No  þ
Indicate by check mark whether each 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  þ    No  ¨
Indicate by check mark whether each registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).    Yes  þ    No  ¨
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K 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.   þ
Indicate by check mark whether each registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an 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):
Noble Corporation plc:
Large accelerated filer þ
Accelerated filer ¨
Non-accelerated filer ¨
Smaller reporting company ¨
Emerging growth company ¨
Noble Corporation:
Large accelerated filer ¨
Accelerated filer ¨
Non-accelerated filer þ
Smaller reporting company ¨
Emerging growth company ¨
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 each registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes  ¨    No  þ
As of June 30, 2018, the aggregate market value of the registered shares of Noble Corporation plc held by non-affiliates of the registrant was $1.5 billion based on the closing sale price on June 29, 2018 as reported on the New York Stock Exchange.
Number of shares outstanding and trading at February 19, 2019: Noble Corporation plc — 248,704,351
Number of shares outstanding: Noble Corporation — 261,245,693
DOCUMENTS INCORPORATED BY REFERENCE
The proxy statement for the 2019 annual general meeting of the shareholders of Noble Corporation plc will be incorporated by reference into Part III of this Form 10-K.
This Form 10-K is a combined annual report being filed separately by two registrants: Noble Corporation plc, a public limited company incorporated under the laws of England and Wales (“Noble-UK”), and its wholly-owned subsidiary, Noble Corporation, a Cayman Islands company (“Noble-Cayman”). Noble-Cayman meets the conditions set forth in General Instructions I(1)(a), (b) and (d) of Form 10-K and is therefore filing this Form 10-K with the reduced disclosure format contemplated by General Instructions I(2)(a) and (c) of Form 10-K.

1



TABLE OF CONTENTS
 
 
 
 
 
Page
PART I
 
 
 
 
Item 1.
 
 
4 
Item 1A.
 
 
11 
Item 1B.
 
 
Item 2.
 
 
Item 3.
 
 
Item 4.
 
 
 
 
 
 
 
PART II
 
 
 
 
Item 5.
 
 
25 
Item 6.
 
 
Item 7.
 
 
Item 7A.
 
 
Item 8.
 
 
Item 9.
 
 
Item 9A.
 
 
Item 9B.
 
 
 
 
 
 
 
PART III
 
 
 
 
Item 10.
 
 
Item 11.
 
 
Item 12.
 
 
110 
Item 13.
 
 
Item 14.
 
 
 
 
 
 
 
PART IV
 
 
 
 
Item 15.
 
 
Item 16.
 
 
 
 
 
 
 
 
 
 
This combined Annual Report on Form 10-K is separately filed by Noble Corporation plc, a public limited company incorporated under the laws of England and Wales (“Noble-UK”), and Noble Corporation, a Cayman Islands company (“Noble-Cayman”). Information in this filing relating to Noble-Cayman is filed by Noble-UK and separately by Noble-Cayman on its own behalf. Noble-Cayman makes no representation as to information relating to Noble-UK (except as it may relate to Noble-Cayman) or any other affiliate or subsidiary of Noble-UK.
This report should be read in its entirety as it pertains to each Registrant. Except where indicated, the Consolidated Financial Statements and the Notes to the Consolidated Financial Statements are combined. References in this Annual Report on Form 10-K to “Noble,” the “Company,” “we,” “us,” “our” and words of similar meaning refer collectively to Noble-UK and its consolidated subsidiaries, including Noble-Cayman.



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Forward-Looking Statements
This Annual Report on Form 10-K includes “forward-looking statements” within the meaning of Section 27A of the U.S. Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the U.S. Securities Exchange Act of 1934, as amended, (the “Exchange Act”). All statements other than statements of historical facts included in this report or in the documents incorporated by reference, including those regarding rig demand, the offshore drilling market, oil prices, contract backlog, fleet status, our future financial position, business strategy, impairments, repayment of debt, credit ratings, liquidity, borrowings under our Credit Facilities (as defined herein) or other instruments, sources of funds, future capital expenditures, contract commitments, dayrates, contract commencements, extension or renewals, contract tenders, the outcome of any dispute, litigation, audit or investigation, plans and objectives of management for future operations, foreign currency requirements, results of joint ventures, indemnity and other contract claims, reactivation, refurbishment, conversion and upgrade of rigs, shipyard risks and timing, delays in mobilization of rigs, industry conditions, access to financing, impact of competition, governmental regulations and permitting, availability of labor and spare parts, worldwide economic conditions, taxes and tax rates, indebtedness covenant compliance, dividends and distributable reserves, timing or results of acquisitions or dispositions, and timing for compliance with any new regulations are forward-looking statements. When used in this report or in the documents incorporated by reference, the words “anticipate,” “believe,” “estimate,” “expect,” “intend,” “may,” “plan,” “project,” “should” and similar expressions are intended to be among the statements that identify forward-looking statements. Although we believe that the expectations reflected in such forward-looking statements are reasonable, we cannot assure you that such expectations will prove to be correct. Actual results could differ materially from those expressed as a result of various factors. These factors include those referenced or described under “Risk Factors” included in this report, or in our other SEC filings, among others. Such risks and uncertainties are beyond our ability to control, and in many cases, we cannot predict the risks and uncertainties that could cause our actual results to differ materially from those indicated by the forward-looking statements. You should consider these risks when you are evaluating us.

3



PART I
Item 1. Business.
Overview
Noble Corporation plc, a public limited company incorporated under the laws of England and Wales (“Noble-UK”), is a leading offshore drilling contractor for the oil and gas industry. We provide contract drilling services to the international oil and gas industry with our global fleet of mobile offshore drilling units. We focus on a balanced, high-specification fleet of floating and jackup rigs and the deployment of our drilling rigs in oil and gas basins around the world. Noble and its predecessors have been engaged in the contract drilling of oil and gas wells since 1921.
We report our contract drilling operations as a single reportable segment, Contract Drilling Services, which reflects how we manage our business. The mobile offshore drilling units comprising our offshore rig fleet operate in a global market for contract drilling services and are often redeployed to different regions due to changing demands of our customers, which consist primarily of large, integrated, independent and government-owned or controlled oil and gas companies throughout the world. As of February 19, 2019, our fleet of 24 drilling rigs consisted of eight drillships, four semisubmersibles and 12 jackups. On February 14, 2019, we exercised an option to purchase an additional jackup and expect to complete the purchase in late February 2019.
Noble Corporation, a Cayman Islands company (“Noble-Cayman”), is an indirect, wholly-owned subsidiary of Noble-UK, our publicly-traded parent company. Noble-UK’s principal asset is all of the shares of Noble-Cayman. Noble-Cayman has no public equity outstanding. The consolidated financial statements of Noble-UK include the accounts of Noble-Cayman, and Noble-UK conducts substantially all its business through Noble-Cayman and its subsidiaries.
On August 1, 2014, Noble-UK completed the separation and spin-off of a majority of its standard specification offshore drilling business (the “Spin-off”) through a pro rata distribution of all the ordinary shares of its wholly-owned subsidiary, Paragon Offshore plc (“Paragon Offshore”), to the holders of Noble’s ordinary shares. The results of operations for Paragon Offshore prior to the Spin-off date and incremental Spin-off related costs have been classified as discontinued operations for all periods presented in this Annual Report on Form 10-K. For additional information regarding the Spin-off and certain matters relating to Paragon Offshore, see Part I, Item 1A, “Risk Factors” and Part II, Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations— Executive Overview— Spin-off of Paragon Offshore plc” and Part II, Item 8, “Financial Statements and Supplementary Data, Note 15— Commitments and Contingencies.”
Drilling Services
We typically provide contract drilling services under an individual contract, on a dayrate basis. Although the final terms of the contracts result from negotiations with our customers, many contracts are awarded based upon a competitive bidding process. Our drilling contracts generally contain the following terms:
contract duration extending over a specific period of time or a period necessary to drill a defined number wells;
payment of compensation to us (generally in U.S. Dollars although some customers, typically national oil companies, require a part of the compensation to be paid in local currency) on a “daywork” basis, so that we receive a fixed amount for each day (“dayrate”) that the drilling unit is operating under contract (a lower rate or no compensation is payable during periods of equipment breakdown and repair or adverse weather or in the event operations are interrupted by other conditions, some of which may be beyond our control);
provisions permitting early termination of the contract by the customer (i) if the unit is lost or destroyed or (ii) if operations are suspended for a specified period of time due to breakdown of equipment or breach of contract;
provisions allowing the impacted party to terminate the contract if specified “force majeure” events beyond the contracting parties’ control occur for a defined period of time;
payment by us of the operating expenses of the drilling unit, including labor costs and the cost of incidental supplies;
provisions that allow us to recover certain cost increases from our customers in certain long-term contracts; and
provisions that require us to lower dayrates for documented cost decreases in certain long-term contracts.
The terms of some of our drilling contracts permit the customer to terminate the contract after specified notice periods by tendering contractually specified termination amounts and, in certain cases, without any payment.
Generally, our contracts allow us to recover our mobilization and demobilization costs associated with moving a drilling unit from one regional location to another. When market conditions require us to assume these costs, our operating margins are reduced accordingly. For shorter moves, such as “field moves,” our customers have generally agreed to assume the costs of moving the unit in the form of a reduced dayrate or “move rate” while the unit is being moved. Under current market conditions, we are much less likely to receive full reimbursement of our mobilization and demobilization costs.

4



During periods of depressed market conditions, such as the one we are currently experiencing, our customers may attempt to renegotiate or repudiate their contracts with us although we seek to enforce our rights under our contracts. The renegotiations may include changes to key contract terms, such as pricing, termination and risk allocation. 
For a discussion of our backlog of commitments for contract drilling services, please read Part II, Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations— Contract Drilling Services Backlog.”
Drilling Fleet
Noble is a leading offshore drilling contractor for the oil and gas sector. Noble owns and operates one of the most modern, versatile and technically advanced fleets of mobile offshore drilling units in the offshore drilling industry. Noble provides, through its subsidiaries, contract drilling services with a fleet of 24 offshore drilling units, consisting of eight drillships, four semisubmersibles and 12 jackups, focused largely on ultra-deepwater and high-specification drilling opportunities in both established and emerging regions worldwide. Each type of drilling rig is described further below. Several factors determine the type of unit most suitable for a particular job, the most significant of which include the water depth and the environment of the intended drilling location, whether the drilling is being done over a platform or other structure, and the intended well depth. At December 31, 2018, our fleet was located in Canada, Far East Asia, the Middle East, the North Sea, Oceania, the Black Sea, South America and the U.S. Gulf of Mexico.
Drillships
A drillship is a type of floating drilling unit that is based on the ship-based hull of the vessel and equipped with modern drilling equipment that gives it the capability of easily transitioning from various worldwide locations and carrying high capacities of equipment while being able to drill ultra-deepwater oil and gas wells in up to 12,000 feet of water. Drillships can stay directly over the drilling location without anchors in open seas using a dynamic positioning system (“DPS”), which coordinates position references from satellite signals and acoustic seabed transponders with the drillship's six to eight thrusters to keep the ship directly over the well that is being drilled. Drillships are selected to drill oil and gas wells for programs that require a high level of simultaneous operations, where drilling loads are expected to be high, or where there are occurrences of high ocean currents, where the drillship's hull shape is the most efficient. There are currently eight drillships in Noble's fleet, capable of water depths from 8,200 feet to 12,000 feet.
Semisubmersibles
Semisubmersible drilling units are designed as a floating drilling platform incorporating one or several pontoon hulls, which are submerged in the water to lower the center of gravity and make this type of drilling unit exceptionally stable in the open sea. Semisubmersible drilling units are generally categorized in terms of the water depth in which they are capable of operating, from the mid-water range of 300 feet to 4,000 feet, the deepwater range of 4,000 feet to 7,500 feet, to the ultra-deepwater range of 7,500 feet to 12,000 feet as well as their generation, or date of construction. This type of drilling unit typically exhibits excellent stability characteristics, providing a stable platform for drilling in even rough seas. Semisubmersible drilling units hold their position over the drilling location using either an anchored mooring system or a DPS and may be self-propelled. Noble's fleet consists of four semisubmersible drilling units, two of which are equipped with mooring systems and two of which utilize DPS, with fleet diversity to operate in mid-water, deepwater and ultra-deepwater depth ranges with high levels of efficiency.
Jackups
Noble's fleet of modern, high-specification jackup drilling units give us the flexibility to provide drilling solutions to our customers who have drilling requirements in the shallower waters of the continental shelf, in depths ranging from less than 100 feet to as deep as 500 feet. Jackup rigs can be used in open water exploration locations, as well as over fixed, bottom-supported platforms. A jackup drilling unit is a towed mobile vessel consisting of a floating hull equipped with three or four legs, which are lowered to the seabed at the drilling location. The hull is then elevated out of the water by the jacking system using the legs to support weight of the hull and drilling equipment against the seabed. Once the hull is elevated to the desired level, or jacked up, the drilling package can be extended out over an existing production platform or the open water location and drilling can commence. Noble's fleet of 12 jackups varies from two standard units capable of drilling in up to 375 feet of water to premium and high-specification units capable of drilling in up to 500 feet of water with drilling hookloads greater than 2,500,000 pounds.

5



Offshore Fleet
The following table presents certain information concerning our offshore fleet at February 19, 2019. We own and operate all of the units included in the table.
Name
 
Make
 
Year Built or Rebuilt (1)
 
Water Depth Rating (feet)(2)
 
Drilling Depth Capacity (feet)
 
Location
 
Status (3)
Drillships—8
 
 
 
 
 
 
 
 
 
 
 
 
Noble Bob Douglas
 
GustoMSC P10000
 
2013 N
 
12,000
 
40,000
 
Guyana
 
Active
Noble Bully I (4)
 
GustoMSC Bully PRD 12000
 
2011 N
 
8,200
 
40,000
 
Curaçao
 
Stacked
Noble Bully II (4)
 
GustoMSC Bully PRD 12000
 
2011 N
 
10,000
 
40,000
 
Malaysia
 
Active
Noble Don Taylor
 
GustoMSC P10000
 
2013 N
 
12,000
 
40,000
 
U.S. Gulf of Mexico
 
Active
Noble Globetrotter I
 
Globetrotter Class
 
2011 N
 
10,000
 
30,000
 
Egypt
 
Active
Noble Globetrotter II
 
Globetrotter Class
 
2013 N
 
10,000
 
30,000
 
Bulgaria
 
Active
Noble Sam Croft
 
GustoMSC P10000
 
2014 N
 
12,000
 
40,000
 
U.S. Gulf of Mexico
 
Available
Noble Tom Madden
 
GustoMSC P10000
 
2014 N
 
12,000
 
40,000
 
Guyana
 
Active
Semisubmersibles—4
 
 
 
 
 
 
 
 
 
 
 
 
Noble Clyde Boudreaux
 
F&G 9500 Enhanced Pacesetter
 
2007 R/M
 
10,000
 
35,000
 
Myanmar
 
Active
Noble Danny Adkins
 
Bingo 9000-DP
 
2009 R
 
12,000
 
35,000
 
U.S. Gulf of Mexico
 
Stacked
Noble Jim Day
 
Bingo 9000-DP
 
2010 R
 
12,000
 
35,000
 
U.S. Gulf of Mexico
 
Stacked
Noble Paul Romano
 
Noble EVA-4000™
 
1998 R/ 2007 M/ 2013 R
 
6,000
 
25,000
 
U.S. Gulf of Mexico
 
Available
Independent Leg Cantilevered Jackups—12 (6)
 
 
 
 
 
 
 
 
 
 
Noble Hans Deul (5)
 
F&G JU-2000E
 
2009 N
 
400
 
30,000
 
U.K.
 
Active
Noble Houston Colbert (5)
 
F&G JU-3000N
 
2014 N
 
400
 
30,000
 
Qatar
 
Active
Noble Joe Beall
 
Modec 300C-38
 
2004 R
 
300
 
25,000
 
Saudi Arabia
 
Active
Noble Johnny Whitstine
 
GustoMSC CJ46-x100-D
 
2018 N
 
375
 
30,000
 
Singapore
 
Shipyard
Noble Lloyd Noble (5)
 
GustoMSC CJ70-x150-ST
 
2016 N
 
500
 
32,000
 
U.K.
 
Active
Noble Mick O’Brien (5)
 
F&G JU-3000N
 
2013 N
 
400
 
30,000
 
Qatar
 
Active
Noble Regina Allen (5)
 
F&G JU-3000N
 
2013 N
 
400
 
30,000
 
Canada
 
Active
Noble Roger Lewis (5)
 
F&G JU-2000E
 
2007 N
 
400
 
30,000
 
Saudi Arabia
 
Active
Noble Sam Hartley (5)
 
F&G JU-3000N
 
2014 N
 
400
 
30,000
 
U.K.
 
Active
Noble Sam Turner (5)
 
F&G JU-3000N
 
2014 N
 
400
 
30,000
 
Denmark
 
Active
Noble Scott Marks (5)
 
F&G JU-2000E
 
2009 N
 
400
 
30,000
 
Saudi Arabia
 
Active
Noble Tom Prosser (5)
 
F&G JU-3000N
 
2014 N
 
400
 
30,000
 
Australia
 
Available
(1) 
Rigs designated with an “R” were modified, refurbished or otherwise upgraded in the year indicated by capital expenditures in an amount deemed material by management. Rigs designated with an “N” are newbuilds. Rigs designated with an “M” have been upgraded to the Noble NC-5SM mooring standard.
(2) 
Rated water depth for drillships and semisubmersibles reflects the maximum water depth in which a floating rig has been designed for drilling operations.
(3) 
Rigs listed as “active” are operating, preparing to operate or under contract; rigs listed as “available” are actively seeking contracts and may include those that are idle or warm stacked; rigs listed as “shipyard” are in a shipyard for construction, repair, refurbishment or upgrade; rigs listed as “stacked” are idle without a contract and have reduced or no crew and are not actively marketed in present market conditions.
(4) 
We own and operate the Noble Bully I and Noble Bully II through joint ventures with a subsidiary of Shell. Under the terms of the joint venture agreements, each party has an equal 50 percent ownership stake in both vessels.
(5) 
Harsh environment capability.
(6) 
On February 14, 2019, we exercised our option to purchase another GustoMSC CJ46 rig, to be known as the Noble Joe Knight, and we expect to complete the purchase in late February 2019. The Jackups Rig list and rig counts shown do not include the Noble Joe Knight.

6




Market
The offshore contract drilling industry is a highly competitive and cyclical business characterized by large capital expenditures and large swings in pricing. Demand for offshore drilling equipment is driven by the exploration and development programs of oil and gas companies, which in turn are influenced by many factors, including the price of oil and gas, the availability and relative cost of onshore oil and gas resources, general global economic conditions, energy demand, environmental considerations and national oil and gas policy.
In the provision of offshore contract drilling services, competition is largely governed by price but involves numerous other factors as well. Rig availability, location, suitability and technical specifications are the primary factors in determining which rig is qualified for a job, and additional factors are considered when determining which contractor is awarded a job, including experience of the workforce, efficiency, safety performance record, condition of equipment, operating integrity, reputation, industry standing and client relations. In addition to having one of the newest fleets in the industry among our peer companies, we strive to keep our equipment well-maintained and technologically competitive.
We maintain a global operational presence and compete in most of the major offshore oil and gas basins worldwide. All of our drilling rigs are mobile, and we may mobilize our drilling rigs among regions for a variety of reasons, including to respond to customer requirements. We compete in both the jackup and floating rig market segments, each of which may have different supply and demand dynamics at a given period in time or in different regions.
Demand for our services is, in significant part, a function of the worldwide demand for oil and gas and the global supply of mobile offshore drilling units. Our industry experienced a significant increase in the number of drilling units prior to and during the period in which crude oil prices declined precipitously and were highly volatile and in which the supply of onshore oil and gas resources expanded greatly. This combination of increased supply of drilling rigs and reduced demand for such rigs has resulted in falling dayrates and heightened competition for opportunities to re-contract our rigs upon expiry of existing contracts.
We believe that improvements in market conditions will ultimately result from, among other things, improved oil prices, additional investment by our customers in offshore exploration and development, and attrition of rigs in the global offshore fleet. Our young and technologically advanced fleet is well positioned to compete now and in the future as market dynamics improve.
Significant Customers
Offshore contract drilling operations accounted for approximately 96 percent, 98 percent and 97 percent of our operating revenues for the years ended December 31, 2018, 2017 and 2016, respectively. During the three years ended December 31, 2018, we principally conducted our contract drilling operations in Canada, Far East Asia, the Middle East, the North Sea, Oceania, the Black Sea, Africa, South America and the U.S. Gulf of Mexico. Revenues from Royal Dutch Shell plc (“Shell”), Equinor ASA (“Equinor” formerly known as “Statoil ASA”) and Saudi Arabian Oil Company (“Saudi Aramco”) accounted for approximately 38.8 percent, 15.5 percent, and 14.5 percent, respectively, of our consolidated operating revenues for the year ended December 31, 2018. Revenues from Shell, Equinor and Saudi Aramco accounted for approximately 45.0 percent, 13.2 percent and 11.4 percent, respectively, of our consolidated operating revenues for the year ended December 31, 2017. Revenues from Shell and Freeport-McMoRan Inc. (“Freeport”) accounted for approximately 37.5 percent and 24.5 percent, respectively, of our consolidated operating revenues for the year ended December 31, 2016. No other customer accounted for more than 10 percent of our consolidated operating revenues in 2018, 2017 or 2016.
On May 10, 2016, Freeport, Freeport-McMoRan Oil & Gas LLC and one of our subsidiaries entered into an agreement terminating the contracts on the Noble Sam Croft and the Noble Tom Madden (“FCX Settlement”), which were scheduled to end in July 2017 and November 2017, respectively. During 2016, we recognized approximately $393.0 million in “Contract drilling services revenue” associated with the FCX Settlement. Excluding the $393.0 million of revenue attributable to the FCX Settlement our primary customers during 2016 would have been Shell, Anadarko Petroleum Corporation and Freeport, accounting for approximately 45.0 percent, 11.0 percent and 9.0 percent of our consolidated operation revenues, respectively.
Employees
At December 31, 2018, we had approximately 2,000 employees, excluding approximately 1,000 persons we engaged through labor contractors or agencies. Approximately 84 percent of our workforce is located offshore. We are not a party to any material collective bargaining agreements, and we consider our employee relations to be satisfactory.
We place considerable value on the involvement of our employees and maintain a practice of keeping them informed on matters affecting them, as well as on the performance of the Company. Accordingly, we conduct formal and informal meetings with employees, maintain a Company intranet website with matters of interest, issue periodic publications of Company activities and other matters of interest, and offer a variety of in-house training, including through Noble Advances, our state of the art training facility in Sugar Land, Texas.

7



We are committed to a policy of recruitment and promotion based upon merit without discrimination. Management actively pursues both the employment of disabled persons whenever a suitable vacancy arises and the continued employment and retraining of employees who become disabled while employed by the Company. Training and development is undertaken for all employees, including disabled persons.
Governmental Regulations and Environmental Matters
Political developments and numerous governmental regulations, which may relate directly or indirectly to the contract drilling industry, affect many aspects of our operations. Our contract drilling operations are subject to various laws and regulations in countries in which we operate, including laws and regulations relating to the equipping and operation of drilling units, environmental discharges and related recordkeeping, safety management systems, the reduction of greenhouse gas emissions to address climate change, currency conversions and repatriation, oil and gas exploration and development, taxation of offshore earnings and earnings of expatriate personnel and use of local employees, content and suppliers by foreign contractors. A number of countries actively regulate and control the ownership of concessions and companies holding concessions, the exportation of oil and gas and other aspects of the oil and gas industries in their countries. In addition, government actions, including initiatives by the Organization of Petroleum Exporting Countries (“OPEC”), may continue to contribute to oil price volatility. In some areas of the world, this government activity has adversely affected the amount of exploration and development work done by oil and gas companies and their need for offshore drilling services, and likely will continue to do so.
The regulations applicable to our operations include provisions that regulate the discharge of materials into the environment or require remediation of contamination under certain circumstances. Many of the countries in whose waters we operate from time to time regulate the discharge of oil and other contaminants in connection with drilling and marine operations. Failure to comply with these laws and regulations, or failure to obtain or comply with permits, may result in the assessment of administrative, civil and criminal penalties, imposition of remedial requirements and the imposition of injunctions to force future compliance. Although these requirements impact the oil and gas and energy services industries, generally they do not appear to affect us in any material respect that is different, or to any materially greater or lesser extent, than other companies in the energy services industry. However, our business and prospects could be adversely affected by regulatory activity that prohibits or restricts our customers’ exploration and production activities, results in reduced demand for our services or imposes environmental protection requirements that result in increased costs to us, our customers or the oil and natural gas industry in general.
The following is a summary of some of the existing laws and regulations that apply in the United States and Europe, which serves as an example of the various laws and regulations to which we are subject. While laws vary widely in each jurisdiction, each of the laws and regulations below addresses environmental issues similar to those in most of the other jurisdictions in which we operate.
Offshore Regulation and Safety. In response to the Macondo well blowout incident in April 2010, the U.S. Department of Interior, through the Bureau of Ocean Energy Management (“BOEM”) and the Bureau of Safety and Environmental Enforcement (“BSEE”), has undertaken an aggressive overhaul of the offshore oil and natural gas regulatory process that has significantly impacted oil and gas development in the U.S. Gulf of Mexico. From time to time, new rules, regulations and requirements have been proposed and implemented by BOEM, BSEE or the United States Congress that materially limit or prohibit, and increase the cost of, offshore drilling. We are also subject to the Ports and Waterways Safety Act (“PWSA”) and similar regulations, which impose certain operational requirements on offshore rigs operating in the U.S. and governs liability for vessel or cargo loss, or damage to life, property, or the marine environment. See Part I, Item 1A, “Risk Factors —Changes in, compliance with, or our failure to comply with the certain laws and regulations may negatively impact our operations and could have a material adverse effect on our results of operations” for additional information.
Spills and Releases. The U.S. Oil Pollution Act of 1990 (“OPA”), the Comprehensive Environmental Response, Compensation, and Liability Act in the U.S. (“CERCLA”), and similar regulations, including but not limited to the International Convention for the Prevention of Pollution from Ships (“MARPOL”), adopted by the International Maritime Organization (“IMO”), as enforced in the United States through the domestic implementing law called the Act to Prevent Pollution from Ships, impose certain operational requirements on offshore rigs operating in the U.S. and govern liability for leaks, spills and blowouts involving pollutants. OPA imposes strict, joint and several liabilities on “responsible parties” for damages, including natural resource damages, resulting from oil spills into or upon navigable waters, adjoining shorelines or in the exclusive economic zone of the United States. A “responsible party” includes the owner or operator of an onshore facility and the lessee or permit holder of the area in which an offshore facility is located. CERCLA and similar state and foreign laws and regulation, impose joint and several liabilities, without regard to fault or the legality of the original act, on certain classes of persons that contributed to the release of a “hazardous substance” into the environment. In the course of our ordinary operations, we may generate waste that may fall within the scope of CERCLA's definition of a “hazardous substance.” However, we have to-date not received any notification that we are, or may be, potentially responsible for cleanup costs under CERCLA.
Regulations under OPA require owners and operators of rigs in United States waters to maintain certain levels of financial responsibility. The failure to comply with OPA’s requirements may subject a responsible party to civil, criminal, or administrative enforcement actions. We are not aware of any action or event that would subject us to liability under OPA, and we believe that compliance with OPA’s financial assurance and other operating requirements will not have a material impact on our operations or financial condition.

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Waste Handling. The U.S. Resource Conservation and Recovery Act (“RCRA”), and similar state, local and foreign laws and regulations govern the management of wastes, including the treatment, storage and disposal of hazardous wastes. RCRA imposes stringent operating requirements, and liability for failure to meet such requirements, on a person who is either a “generator” or “transporter” of hazardous waste or an “owner” or “operator” of a hazardous waste treatment, storage or disposal facility. RCRA and many state counterparts specifically exclude from the definition of hazardous waste drilling fluids, produced waters, and other wastes associated with the exploration, development, or production of crude oil and natural gas. As a result, our operations generate minimal quantities of RCRA hazardous wastes. We do not believe the current costs of managing our wastes, as they are presently classified, to be significant. However, any repeal or modification of this or similar exemption in similar state statutes, would increase the volume of hazardous waste we are required to manage and dispose of, and would cause us, as well as our competitors, to incur increased operating expenses with respect to our U.S. operations.
Water Discharges. The U.S. Federal Water Pollution Control Act of 1972, as amended, also known as the “Clean Water Act,” and similar state laws and regulations impose restrictions and controls on the discharge of pollutants into federal and state waters. These laws also regulate the discharge of storm water in process areas. Pursuant to these laws and regulations, we are required to obtain and maintain approvals or permits for the discharge of wastewater and storm water. In addition, the U.S. Coast Guard has promulgated requirements for ballast water management as well as supplemental ballast water requirements, which includes limits and, in some cases, water treatment requirements applicable to specific discharge streams, such as deck runoff, bilge water and gray water. We do not anticipate that compliance with these laws will cause a material impact on our operations or financial condition.
Air Emissions. The U.S. Federal Clean Air Act and associated state laws and regulations restrict the emission of air pollutants from many sources, including oil and natural gas operations. New facilities may be required to obtain permits before operations can commence, and existing facilities may be required to obtain additional permits, and incur capital costs, in order to remain in compliance. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the Clean Air Act and associated state laws and regulations. In general, we believe that compliance with the Clean Air Act and similar state laws and regulations will not have a material impact on our operations or financial condition.
Climate Change. There is increasing attention concerning the issue of climate change and the effect of greenhouse gas (“GHG”) emissions. The United States Environmental Protection Agency (“EPA”) regulates the permitting of GHG emissions from stationary sources under the Clean Air Act’s Prevention of Significant Deterioration and Title V permitting programs, which require the use of “best available control technology” for GHG emissions from new and modified major stationary sources, which can sometimes include drillships. The EPA has also adopted rules requiring the monitoring and reporting of GHG emissions from specified sources in the United States, including, among other things, certain onshore and offshore oil and natural gas production facilities, on an annual basis.
Moreover, in 2005, the Kyoto Protocol to the 1992 United Nations Framework Convention on Climate Change, which establishes a binding set of emission targets for GHGs, became binding on all countries that had ratified it. In 2015, the United Nations (“U.N.”) Climate Change Conference in Paris resulted in the creation of the Paris Agreement. The Paris Agreement requires countries to review and “represent a progression” in their nationally determined contributions, which set emissions reduction goals, every five years beginning in 2020. Incentives to conserve energy or use alternative energy sources could have a negative impact on our business if such incentives reduce the worldwide demand for oil and gas. See Part I, Item1A, “Risk Factors— Governmental laws and regulations may add to our costs, result in delays, or limit our drilling activity” for additional information.
Countries in the European Union (“EU”) implement the U.N.’s Kyoto Protocol on GHG emissions through the Emissions Trading System (“ETS”). The ETS program establishes a GHG “cap and trade” system for certain industry sectors, including power generation at some offshore facilities. Total GHG from these sectors is capped, and the cap is reduced over time to achieve a 21 percent GHG reduction from these sectors between 2005 and 2020. The ETS program will continue to require GHG reductions in the future. Phase 4 of the ETS program (covering 2021 to 2030) was revised in 2018 to achieve emission reduction targets as part of the EU’s contribution to the Paris Agreement. Phase 4 targets a 43 percent GHG reduction between 2005 and 2030.
In addition, the United Kingdom (“UK”) government, which implements ETS in the UK North Sea, has introduced a carbon price floor mechanism to place an incrementally increasing minimum price on carbon. Thus, the cost of compliance with ETS can be expected to increase over time. Additional member state climate change legislation may result in potentially material capital expenditures.
We have determined that combustion of diesel fuel (Scope 1) aboard all of our vessels worldwide is the Company’s primary source of GHG emissions, including carbon dioxide, methane and nitrous oxide. The data necessary to report indirect emissions from generation of purchased power (Scope 2) has not been previously collected; however, procedures are being established to collect and report Scope 2 data.
For the year ended December 31, 2018, our estimated carbon dioxide equivalent (“CO2e”) gas emissions were 954,944 tonnes as compared to 918,439 tonnes for the year ended December 31, 2017. When expressed as an intensity measure of tonnes of CO2e gas emissions per dollar of contract drilling revenues from continuing operations, the intensity measure for December 31, 2018 and 2017 was .0009 and .0008, respectively.

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The increase in emissions is due to increases in operational activity from the Noble Tom Madden, Noble Sam Croft, Noble Lloyd Noble, Noble Tom Prosser and activation of the Noble Clyde Boudreaux.
Our Scope 1 CO2e gas emissions reporting has been prepared with reference to the requirements set out in the UK Companies Act 2006 Regulations 2013, the Environmental Reporting Guidelines (June 2013) issued by the Department for Environment Food & Rural Affairs, the World Resources Institute and World Business Council for Sustainable Development GHG Protocol Corporate Accounting and Reporting Standard Revised and the International Organization for Standardization (“ISO”) 14064-1, “Specification with guidance at the organizational level for quantification and reporting of greenhouse gas emissions and removals (2006).”
It is our intent to have the procedures related to GHG emissions independently assessed in the future.
Worker Safety. The U.S. Occupational Safety and Health Act (“OSHA”) and other similar laws and regulations govern the protection of the health and safety of employees. The OSHA hazard communication standard, EPA community right-to-know regulations under Title III of CERCLA and similar state statutes require that information be maintained about hazardous materials used or produced in our operations and that this information be provided to employees, state and local governments and citizens. EU member states have also adopted regulations pursuant to EU Directive 2013/30/EU, on the safety of offshore oil and gas operations within the exclusive economic zone (which can extend up to 200 nautical miles from a coast) or the continental shelf. We believe that we are in substantial compliance with OSHA requirements and EU directive 2013/30/EU (as well as the extensive current health and safety regimes implemented in the member states in which we operate), but future developments could require the Company to incur significant costs to comply with the directive's implementation.
International Regulatory Regime. The IMO provides international regulations governing shipping and international maritime trade. IMO regulations have been widely adopted by U.N. member countries, and in some jurisdictions in which we operate, these regulations have been expanded upon. The requirements contained in the International Management Code for the Safe Operation of Ships and for Pollution Prevention, or ISM Code, promulgated by the IMO, govern much of our drilling operations. Among other requirements, the ISM Code requires the party with operational control of a vessel to develop an extensive safety management system that includes, among other things, the adoption of a safety and environmental protection policy setting forth instructions and procedures for operating its vessels safely and describing procedures for responding to emergencies.
The IMO has also adopted MARPOL, including Annex VI to MARPOL which sets limits on sulfur dioxide and nitrogen oxide emissions from ship exhausts and prohibits deliberate emissions of ozone depleting substances. The IMO has also negotiated international conventions that impose liability for oil pollution in international waters and the territorial waters of the signatory to such conventions such as the Ballast Water Management Convention, (the “BWM Convention”) and the International Convention for Civil Liability for Bunker Oil Pollution Damage of 2001 (the “Bunker Convention”). The BWM Convention's implementing regulations call for a phased introduction of mandatory ballast of water exchange requirements (beginning in 2009), to be replaced in time with a requirement for mandatory ballast water treatment. The Bunker Convention provides a liability, compensation and compulsory insurance system for the victims of oil pollution damage caused by spills of bunker oil. We believe that all of our drilling rigs are currently compliant in all material respects with these regulations. However, the IMO continues to review and introduce new regulations. It is impossible to predict what additional regulations, if any, may be passed by the IMO and what effect, if any, such regulation may have on our operations.
Insurance and Indemnification Matters
Our operations are subject to many hazards inherent in the drilling business, including blowouts, fires, collisions, groundings, punch-throughs, and damage or loss from adverse weather and sea conditions. These hazards could cause personal injury or loss of life, loss of revenues, pollution and other environmental damage, damage to or destruction of property and equipment and oil and natural gas producing formations, and could result in claims by employees, customers or third parties and fines and penalties.
Our drilling contracts provide for varying levels of indemnification from our customers and in most cases also require us to indemnify our customers for certain losses. Under our drilling contracts, liability with respect to personnel and property is typically assigned on a “knock-for-knock” basis, which means that we and our customers assume liability for our respective personnel and property, generally irrespective of the fault or negligence of the party indemnified. In addition, our customers may indemnify us in certain instances for damage to our down-hole equipment and, in some cases, our subsea equipment. Also, we generally obtain a mutual waiver of consequential losses in our drilling contracts.
Our customers typically assume responsibility for and indemnify us from loss or liability resulting from pollution or contamination, including third-party damages and clean-up and removal, arising from operations under the contract and originating below the surface of the water. We are generally responsible for pollution originating above the surface of the water and emanating from our drilling units. Additionally, our customers typically indemnify us for liabilities incurred as a result of a blow-out or cratering of the well and underground reservoir loss or damage. In the current market, we are under increasing pressure to accept exceptions to the above-described allocations of risk and, as a result, take on more risk. In such cases where we agree, we generally limit the exposure with a monetary cap and other restrictions.

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In addition to the contractual indemnities described above, we also carry Protection and Indemnity (“P&I”) insurance, which is a comprehensive general liability insurance program covering liability resulting from offshore operations. Our P&I insurance includes coverage for liability resulting from personal injury or death of third parties and our offshore employees, third-party property damage, pollution, spill clean-up and containment and removal of wrecks or debris. Our P&I insurance program is renewed in April of each year and currently has a standard deductible of $10 million per occurrence, with maximum liability coverage of $750 million. We also carry hull and machinery insurance that protects us against physical loss or damage to our drilling rigs, subject to a deductible that is currently $10.0 million.
Our insurance policies and contractual rights to indemnity may not adequately cover our losses and liabilities in all cases. For additional information, please read “We may have difficulty obtaining or maintaining insurance in the future and our insurance coverage and contractual indemnity rights may not protect us against all the risks and hazards we face” included in Part I, Item 1A, “Risk Factors” of this Annual Report on Form 10-K.
The above description of our insurance program and the indemnification provisions of our drilling contracts is only a summary as of the time of preparation of this report, and is general in nature. Our insurance program and the terms of our drilling contracts may change in the future. In addition, the indemnification provisions of our drilling contracts may be subject to differing interpretations, and enforcement of those provisions may be limited by public policy and other considerations.
Available Information
Our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the U.S. Securities Exchange Act of 1934 are available free of charge at our website at http://www.noblecorp.com. The U.S. Securities and Exchange Commission (the “SEC”) maintains an internet site that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC at http://www.sec.gov.
You may also find information related to our corporate governance, board committees and company code of ethics (and any amendments or waivers of compliance) at our website. Among the documents you can find there are the following:
Articles of Association;
Code of Business Conduct and Ethics;
Corporate Governance Guidelines;
Audit Committee Charter;
Compensation Committee Charter;
Health, Safety, Environment and Engineering Committee Charter;
Nominating and Corporate Governance Committee Charter; and
Finance Committee Charter.
Item 1A. Risk Factors.
You should carefully consider the following risk factors in addition to the other information included in this Annual Report on Form 10-K. Each of these risk factors could affect our business, operating results and financial condition, as well as affect an investment in our shares.
Our business and results of operations have been materially and negatively impacted and our market value has substantially declined due to current depressed market conditions which are the result of the dramatic drop in the oil price, the development of additional onshore oil and gas resources and the oversupply of offshore drilling rigs.
After a period of sustained high crude oil prices, oil prices began a steep decline beginning in late 2014 and dropped to as low as approximately $30 per barrel in January 2016. Oil prices have recovered to a price of approximately $66 per barrel on February 19, 2019, but have been volatile and have never recovered to 2014 levels. As a result of the oil price environment prior to the drop in 2014, the offshore drilling business flourished with high utilization and high dayrates, and a large number of offshore drilling rigs were constructed to take advantage of the market. Also, many in our industry extended the lives of older rigs rather than retiring these rigs. These factors have led to a significant oversupply of drilling rigs at the same time that our customers have greatly reduced their planned offshore exploration and development spending in response to the depressed price of oil.
During the same period, crude oil production in the U.S. rose sharply. Production in the U.S. Permian Basin has increased from less than 1.5 million barrels of oil per day to nearly 4 million barrels per day. While, the cost of production in the Permian Basin (and many other onshore fields) varies, in some cases it may be significantly less than the cost of production in offshore fields where our rigs are designed to operate, especially deepwater fields. This increase in U.S. production has had a negative impact on the price of oil and the demand for our services. Further, given the reduced oil price and often the lower operating costs onshore, many of our customers have allocated more of their capital budgets to

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onshore exploration activities than offshore exploration activities, particularly deepwater exploration activities, which has also led to a decrease in the demand for offshore drilling services.
These factors have affected market conditions and led to a material decline in the demand for our services, the dayrates we are paid by our customers and the level of utilization of our drilling rigs. These poor market conditions, in turn, have led to a material deterioration in our results of operations. We have already experienced a substantial decline in the price of our shares, which has declined from $27 on August 4, 2014 post Spin-off to $3.15 at February 19, 2019. While the offshore contract drilling industry is highly cyclical and has experienced periods of low demand and higher demand, there can be no assurance as to when or to what extent the current depressed market conditions, and our business, results of operations or enterprise value, will improve. Further, even if the price of oil and gas were to increase dramatically, we cannot assure you that there would be any increase in demand for our services.
Our business depends on the level of activity in the oil and gas industry. Adverse developments affecting the industry, including a decline in the price of oil or gas, reduced demand for oil and gas products and increased regulation of drilling and production, could have a material adverse effect on our business, financial condition and results of operations.
Demand for drilling services depends on a variety of economic and political factors and the level of activity in offshore oil and gas exploration and development and production markets worldwide. As noted above, the price of oil and gas, and market expectations of potential changes in the price, significantly affect this level of activity, as well as dayrates which we can charge customers for our services. However, higher prices do not necessarily translate into increased drilling activity because our clients take into account a number of considerations when they decide to invest in offshore oil and gas resources, including expectations regarding future commodity prices. The price of oil and gas and the level of activity in offshore oil and gas exploration and development are extremely volatile and are affected by numerous factors beyond our control, including:
the cost of exploring for, developing, producing and delivering oil and gas;
the ability of OPEC to set and maintain production levels and pricing;
expectations regarding future energy prices;
increased supply of oil and gas resulting from onshore hydraulic fracturing activity and shale development;
the relative cost of offshore oil and gas exploration versus onshore oil and gas production;
worldwide production and demand for oil and gas, which are impacted by changes in the rate of economic growth in the global economy;
potential acceleration in the development, and the price and availability, of alternative fuels;
the level of production in non-OPEC countries;
worldwide financial instability or recessions;
regulatory restrictions or any moratorium on offshore drilling;
the discovery rate of new oil and gas reserves either onshore or offshore;
the rate of decline of existing and new oil and gas reserves;
available pipeline and other oil and gas transportation capacity;
oil refining capacity;
the ability of oil and gas companies to raise capital;
limitations on liquidity and available credit;
advances in exploration, development and production technology either onshore or offshore;
technical advances affecting energy consumption, including the displacement of hydrocarbons through increasing transportation fuel efficiencies;
merger and divestiture activity among oil and gas producers;
the availability of, and access to, suitable locations from which our customers can produce hydrocarbons;
adverse weather conditions, including hurricanes, typhoons, winter storms and rough seas;
tax laws, regulations and policies;
laws and regulations related to environmental matters, including those addressing alternative energy sources and the risks of global climate change;
the political environment of oil-producing regions, including uncertainty or instability resulting from civil disorder, an outbreak or escalation of armed hostilities or acts of war or terrorism; and
the laws and regulations of governments regarding exploration and development of their oil and gas reserves or speculation regarding future laws or regulations.
Adverse developments affecting the industry as a result of one or more of these factors, including any further decline in the price of oil and gas from their current levels or the failure of the price of oil and gas to recover to a level that encourages our clients to expand their capital spending, a global recession, reduced demand for oil and gas products, increased supply due to the development of new onshore drilling and production technologies, and increased regulation of drilling and production, particularly if several developments were to occur in a short period of time, would have a material adverse effect on our business, financial condition and results of operations. The current level of oil and gas prices has had

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a material adverse effect on demand for our services since 2015 and is expected to continue to have a material adverse effect on our business and results of operations.
The offshore contract drilling industry is a highly competitive and cyclical business with intense price competition. We have competitors who are larger and have more financial recourses than we do. If we are unable to compete successfully, our profitability may be materially reduced.
The offshore contract drilling industry is a highly competitive and cyclical business characterized by high capital and operating costs and evolving capability of newer rigs. Drilling contracts are traditionally awarded on a competitive bid basis. Price competition, rig availability, location and rig suitability and technical specifications are the primary factors in determining which rig is qualified for a job, and additional factors are considered when determining which contractor is awarded a job, including experience of the workforce, efficiency, safety performance record, condition of equipment, operating integrity, reputation, industry standing and client relations. Our future success and profitability will partly depend upon our ability to keep pace with our customers’ demands with respect to these factors. In the past several years, the pace of consolidation in our industry has increased, leading to the creation of a number of larger and financially stronger competitors. If we are unable, or our customers believe that we are unable, to compete with the scale and financial strength of these larger competitors, it could harm our competitiveness and our ability to secure new drilling contracts. If current competitors, or new market entrants, implement new technical capabilities, services or standards that are more attractive to our customers or price their product offerings more competitively, it could have a material adverse effect on our business, financial condition and results of operations.
In addition to intense competition, our industry has historically been cyclical. The offshore contract drilling industry is currently in a period characterized by low demand for drilling services and excess rig supply. Periods of low demand or excess rig supply intensify the competition in the industry and have resulted in, and are expected to continue to result in, many of our rigs earning substantially lower dayrates or being idle for long periods of time. We cannot provide you with any assurances as to when such period will end, and when there will be higher demand for contract drilling services or a meaningful reduction in the number of drilling rigs.
The over-supply of offshore rigs is contributing to a reduction in dayrates and demand for our rigs, which reduction may continue for some time and, therefore, is expected to further adversely impact our revenues and profitability.
Prior to the current downturn, we experienced an extended period of high utilization and high dayrates, and industry participants materially increased the supply of drilling rigs by building new drilling rigs, including some that have not yet entered service. This increase in supply, combined with the decrease in demand for drilling rigs resulting from the substantial decline in the price of oil that began in 2014, has resulted in an oversupply of drilling rigs, which has contributed to the decline in utilization and dayrates.
We are currently experiencing competition from newbuild rigs that have either already entered the market or are available to enter the market. The entry of these rigs into the market has resulted in lower dayrates for both newbuilds and existing rigs rolling off their current contracts. Lower utilization and dayrates have adversely affected our revenues and profitability and may continue to do so for some time in the future. In addition, our competitors may relocate rigs to geographic markets in which we operate, which could exacerbate excess rig supply and result in lower dayrates and utilization in those markets. To the extent that the drilling rigs currently under construction or on order do not have contracts upon their completion, there may be increased price competition as such vessels become operational, which could lead to a further reduction in dayrates and in utilization, and we may be required to idle additional drilling rigs. As a result, our business, financial condition and results of operations would be materially adversely affected.
We may record impairment charges on property and equipment, including rigs and related capital spares.
We evaluate the impairment of property and equipment, which include rigs and related capital spares, whenever events or changes in circumstances (including a decision to cold stack, retire or sell rigs) indicate that the carrying amount of an asset may not be recoverable. An impairment loss on our property and equipment may exist when the estimated undiscounted cash flows expected to result from the use of the asset and its eventual disposition are less than its carrying amount. Any impairment loss recognized represents the excess of the asset’s carrying value over the estimated fair value. As part of this analysis, we make assumptions and estimates regarding future market conditions. To the extent actual results do not meet our estimated assumptions, for a given rig or piece of equipment, we may take an impairment loss in the future. In addition, we may also take an impairment loss on capital spares and other capital equipment when we deem the value of those items has declined due to factors like obsolescence, deterioration or damage. Based upon our impairment analysis for the years ended December 31, 2018 and 2017, we decided that we would no longer market certain rigs. In connection with these decisions, we recorded impairment charges of $802.1 million and $121.6 million, respectively, on these rigs and certain capital spares during those periods. There can be no assurance that we will not have to take additional impairment charges in the future if current depressed market conditions persist.


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We may not be able to renew or replace expiring contracts, and our customers may terminate or seek to renegotiate or repudiate our drilling contracts or may have financial difficulties which prevents them from meeting their obligations under our drilling contracts.
Since the market downturn began at the end of 2014, the new customer contracts we have entered into have generally had less favorable terms, including dayrates, than contracts entered into prior to the downturn. In addition, for some of our older rigs we were unable to find replacement contracts at all. Our ability to renew contracts that expire or obtain new contracts and the terms of any such contracts will depend on market conditions and our customers' expectations and assumptions of future oil prices and other factors.
Our customers may generally terminate our term drilling contracts if a drilling rig is destroyed or lost or if we have to suspend drilling operations for a specified period of time as a result of a breakdown of major equipment or, in some cases, due to other events beyond the control of either party. In the case of nonperformance and under certain other conditions, our drilling contracts generally allow our customers to terminate without any payment to us. The terms of some of our drilling contracts permit the customer to terminate the contract after a specified notice period by tendering contractually specified termination amounts and, in some cases, without any payment. These termination payments, if any, may not fully compensate us for the loss of a contract. The early termination of a contract may result in a rig being idle for an extended period of time and a reduction in our contract backlog and associated revenue, which could have a material adverse effect on our business, financial condition and results of operations. Moreover, if any of our long-term contracts were to be terminated early, such termination could affect our future earnings flow and could have material adverse effect on our future financial condition and results of operations, even if we were to receive the contractually specified termination amount.
In addition, during periods of depressed market conditions, such as the one we are currently experiencing, we are subject to an increased risk of our customers seeking to renegotiate or repudiate their contracts. The ability of our customers to perform their obligations under drilling contracts with us may also be adversely affected by the financial condition of the customer, restricted credit markets, economic downturns and industry downturns. We may elect to renegotiate the rates we receive under our drilling contracts downward if we determine that to be a reasonable business solution. If our customers cancel or are unable to perform their obligations under their drilling contracts, including their payment obligations, and we are unable to secure new contracts on a timely basis on substantially similar terms or if we elect to renegotiate our drilling contracts and accept terms that are less favorable to us, it could have a material adverse effect on our business, financial condition and results of operations.
Our current backlog of contract drilling revenue may not be ultimately realized.
Generally, contract backlog only includes future revenues under firm commitments; however, from time to time, we may report anticipated commitments under letters of intent or award for which definitive agreements have not yet been, but are expected to be, executed. We may not be able to perform under these contracts as a result of operational or other breaches or due to events beyond our control, and we may not be able to ultimately execute a definitive agreement in cases where one does not currently exist. Moreover, we can provide no assurance that our customers will be able to or willing to fulfill their contractual commitments to us or that they will not seek to renegotiate or repudiate their contracts, especially during the current industry downturn. In estimating backlog, we make certain assumptions about applicable dayrates for our longer-term contracts with dayrate adjustment mechanisms (like certain of our contracts with Shell). While we believe these assumptions are appropriate, we cannot assure you that actual results will mirror these assumptions. Our inability to perform under our contractual obligations or to execute definitive agreements, our customers’ inability or unwillingness to fulfill their contractual commitments to us, including as a result of contract repudiations or our decision to accept less favorable terms on our drilling contracts, or the failure of actual results to reflect the assumptions we use to estimate backlog for certain contracts, may have a material adverse effect on our business, financial condition and results of operations.
We are substantially dependent on several of our customers, including Shell, Equinor and Saudi Aramco, and the loss of any of these customers would have a material adverse effect on our financial condition and results of operations.
Any concentration of customers increases the risks associated with any possible termination or nonperformance of drilling contracts, failure to renew contracts or award new contracts or reduction of their drilling programs. Shell, Equinor and Saudi Aramco accounted for approximately 38.8 percent, 15.5 percent and 14.5 percent, respectively, of our consolidated operating revenues and approximately 52.2 percent, 11.0 percent and 19.8 percent, respectively, of our backlog for the year ended December 31, 2018. This concentration of customers increases the risks associated with any possible termination or nonperformance of contracts, in addition to our exposure to credit risk. If any of these customers were to terminate or fail to perform their obligations under their contracts and we were not able to find other customers for the affected drilling units promptly, our financial condition and results of operations could be materially adversely affected.
A litigation trust was formed and funded as part of the Paragon Offshore bankruptcy proceedings and the litigation trust has filed claims against us and certain of our officers and directors. In addition, Paragon Offshore rejected in the bankruptcy proceedings certain separation agreements entered into with us, and as a result, we are responsible for those liabilities for which we would have otherwise sought indemnification under the separation agreements.
In August 2014, we completed the Spin-off of a majority of our standard specification offshore drilling business through a pro rata distribution of all of the ordinary shares of our wholly-owned subsidiary, Paragon Offshore, to the holders of our ordinary shares.

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In April 2017, Paragon Offshore filed a plan of reorganization (the “Plan”) in its bankruptcy proceeding. The Plan, which was modified in May 2017, provided for the creation of a litigation trust to which Paragon Offshore transferred its claims against us, including claims of alleged fraudulent conveyance in connection with the Spin-off and the funding of the trust by Paragon Offshore with $10.0 million. The litigation trust is entitled to pursue those claims against us. In June 2017, the Plan was approved by the bankruptcy court and Paragon Offshore emerged from bankruptcy on July 18, 2017.
On December 15, 2017, the litigation trust filed claims relating to the Spin-off against us and certain of our current and former officers and directors in the Delaware bankruptcy court that heard Paragon Offshore’s bankruptcy. The complaint alleges claims of alleged actual and constructive fraudulent conveyance, unjust enrichment and recharacterization of intercompany notes as equity claims against Noble and claims of breach of fiduciary duty and aiding and abetting breach of fiduciary duty against the officer and director defendants. The complaint states that the litigation trust is seeking damages of approximately $1.7 billion from the Company, an amount equal to the amount borrowed by Paragon Offshore immediately prior to the Spin-off, as well as unspecified amounts in respect of the claims against the officer and director defendants, all of whom have indemnification agreements with us. We requested that the court dismiss the claims of breach of fiduciary duty, aiding and abetting breach of fiduciary duty and unjust enrichment, and require such claims to be arbitrated under the master separation agreement (the “MSA”) entered into between Noble and Paragon Offshore at the time of the Spin-off, as well as stay the other proceedings during the pendency of the arbitration. The court ruled that the unjust enrichment claim be arbitrated and that the other claims proceed in bankruptcy court. We and the litigation trust have mutually agreed to drop our respective appeals of the arbitration ruling and now all matters will be heard in court, which will streamline the case. Discovery continues and the court has approved a litigation schedule, which could result in all pre-trial activity being completed by the end of 2019. A trial date has not yet been set.
We believe that Paragon Offshore, at the time of the Spin-off, was properly funded, solvent and had appropriate liquidity and that the claims brought by the litigation trust are without merit. We intend to defend ourselves vigorously. However, there is inherent risk and substantial expense in litigation, and the amount of damages the plaintiff is seeking is substantial. If any of the litigation trust’s claims are successful, or if we elect to settle any claims (in part to reduce or eliminate the ongoing cost of defending the litigation and eliminate any risk of a larger judgment against us), any damages or other amounts we would be required to or agree to pay could have a material adverse effect on our business, financial condition and results of operations. Because of our view of the merits of the claims and the significant discovery still to be conducted in the litigation, we are not currently able to make a reasonable estimation of the amount of possible loss we may incur, if any. Subsequent developments in the litigation may make such an estimation possible, in which case we may record a charge against our income when a loss is reasonably estimable. This may occur even though the litigation may still be ongoing. Any charge could be material and could have a material adverse effect on our financial condition and results of operations. It may also be materially different than any amount we are required to pay once the litigation is concluded.
We have directors’ and officers’ indemnification coverage for the officers and directors who have been sued by the litigation trust. The insurers have accepted coverage for the director and officer claims and we are continuing to discuss with them the scope of their reimbursement of litigation expenses. In addition, at the time of the Spin-off we had entity coverage, or “Side C” coverage, which was meant to cover certain litigation claims up to the coverage limit of $150.0 million, including litigation expenses. We have made a claim for coverage of the litigation trust’s claims against Noble under such entity insurance. The insurers have rejected coverage for these claims. We cannot predict the amount of claims and expenses we may incur, pay or settle in the Paragon Offshore litigation that such insurance will cover, if any.
We entered into certain separation agreements with Paragon Offshore at the time of the Spin-off (including the MSA, tax sharing agreement, transition services agreement and transition services agreement relating to our operations offshore Brazil) under which we agreed to indemnify Paragon Offshore for certain liabilities, and Paragon Offshore agreed to indemnify us for certain liabilities. As part of the Plan, Paragon Offshore rejected all of these contracts. Accordingly, we are no longer entitled to seek indemnity from Paragon Offshore under such agreements, and we would be responsible for those liabilities for which we would have otherwise sought indemnification. Such liabilities could have a material adverse effect on our business, financial condition and results of operations.
Our business involves numerous operating hazards.
Our operations are subject to many hazards inherent in the drilling business, including:
well blowouts;
fires;
collisions or groundings of offshore equipment and helicopter accidents;
punch-throughs;
mechanical or technological failures;
failure of our employees or third-party contractors to comply with our internal environmental, health and safety guidelines;
pipe or cement failures and casing collapses, which could release oil, gas or drilling fluids;
geological formations with abnormal pressures;
loop currents or eddies;
failure of critical equipment;

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toxic gas emanating from the well;
spillage handling and disposing of materials; and
adverse weather conditions, including hurricanes, typhoons, tsunamis, winter storms and rough seas.
These hazards could cause personal injury or loss of life, suspend drilling operations, result in regulatory investigation or penalties, seriously damage or destroy property and equipment, result in claims by employees, customers or third parties, cause environmental damage and cause substantial damage to oil and gas producing formations or facilities. Operations also may be suspended because of machinery breakdowns, abnormal drilling conditions, and failure of subcontractors to perform or supply goods or services or personnel shortages. The occurrence of any of the hazards we face could have a material adverse effect on our business, financial condition and results of operations.
We have substantial debt obligations that have significant covenant restrictions and could restrict our operations and prevent us from fulfilling our obligations with respect to our outstanding debt.
As of February 19, 2019, Noble-Cayman and its subsidiaries, including NHIL and its subsidiaries, had approximately $3.9 billion aggregate principal amount of unsecured long-term senior notes and seller loans (including current maturities) outstanding. At February 19, 2019, no amounts were currently outstanding under our 2015 Credit Facility or our 2017 Credit Facility (each as defined herein). We may also incur additional indebtedness in the future. If we do so, the risks related to our level of debt could intensify. Our substantial indebtedness could have adverse consequences, including:
making it more difficult for us to satisfy our financial obligations, including our obligations with respect to our outstanding debt;
increasing our vulnerability to adverse economic, regulatory and industry conditions, and placing us at a disadvantage compared to our competitors that are less leveraged;
limiting our ability to compete and our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate; and
limiting our ability to borrow additional funds for working capital, capital expenditures, acquisitions and general corporate or other purposes.
Our debt service obligations will require us to use a significant portion of our operating cash flow to pay interest and principal on indebtedness instead of for other corporate purposes, including funding future expansion of our business and ongoing capital expenditures, which could impede our growth. If our operating cash flow and capital resources are insufficient to comply with the financial covenants in our Credit Facilities or to service our debt obligations, we may be forced to sell assets, seek additional equity or debt financing or restructure our debt, which could harm our long-term business prospects. Our failure to comply with those covenants could result in an event of default which, if not cured or waived, could result in the acceleration of all of our debt. Our 2017 Credit Facility contains a covenant which limits our debt to total tangible capitalization (less noncontrolling interest) to a maximum 0.55 ratio. If we increase our indebtedness, including by borrowing under the 2017 Credit Facility, or incur further losses without reducing our indebtedness or increasing capital by an equivalent amount, our debt to total tangible capitalization ratio would increase.
To service our indebtedness, we will use a significant amount of cash. Our ability to generate cash to service our indebtedness depends on many factors beyond our control.
Our ability to make payments on our indebtedness and to fund planned capital expenditures will depend on our ability to generate cash in the future. This ability, to a certain extent, is subject to general economic, financial, competitive, legislative, regulatory and other factors that are beyond our control. We cannot assure you that cash flow generated from our business and other sources of cash, including future borrowings by Noble-Cayman and Noble International Finance Company, a Cayman Islands company and a wholly-owned indirect subsidiary of Noble-Cayman (“NIFCO”), under our 2015 Credit Facility or by Noble Cayman Limited, a Cayman Islands company and a wholly-owned indirect subsidiary of Noble-Cayman, and NIFCO under our 2017 Credit Facility, will be sufficient to enable us to pay our indebtedness and to fund our other liquidity needs.
As a result of our significant cash flow needs, we may be required to raise funds through the issuance of additional debt or equity, and in the event of lost market access, may have to delay or cancel discretionary capital expenditures.
Our cash flow needs, both in the short-term and long-term, may include the following:
normal recurring operating expenses;
planned and discretionary capital expenditures; and
repayment of debt and interest.
In the future, we may require funding for capital expenditures that is beyond the amount available to us from cash generated by our operations, cash on hand and borrowings under our existing Credit Facilities. We may raise such additional capital in a number of ways, including accessing

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capital markets, obtaining additional lines of credit or disposing of assets. However, we can provide no assurance that any of these options will be available to us on terms acceptable to us or at all.
We may delay or cancel discretionary capital expenditures, which could have certain adverse consequences, including delaying upgrades or equipment purchases that could make the affected rigs less competitive, adversely affect customer relationships and negatively impact our ability to contract such rigs.
We are exposed to risks relating to operations in international locations.
We operate in various regions throughout the world that may expose us to political and other uncertainties, including risks of:
seizure, nationalization or expropriation of property or equipment;
monetary policies, government credit rating downgrades and potential defaults, and foreign currency fluctuations and devaluations;
limitations on the ability to repatriate income or capital;
complications associated with repairing and replacing equipment in remote locations;
repudiation, nullification, modification or renegotiation of contracts;
limitations on insurance coverage, such as war risk coverage, in certain areas;
import-export quotas, wage and price controls, imposition of trade barriers and other forms of government regulation and economic conditions that are beyond our control;
delays in implementing private commercial arrangements as a result of government oversight;
financial or operational difficulties in complying with foreign bureaucratic actions;
changing taxation rules or policies;
other forms of government regulation and economic conditions that are beyond our control and that create operational uncertainty;
governmental corruption;
the occurrence or threat of epidemic or pandemic diseases or any government response to such occurrence or threat;
piracy; and
terrorist acts, war, revolution and civil disturbances.
Further, we operate or have operated in certain less-developed countries with legal systems that are not as mature or predictable as those in more developed countries, which can lead to greater uncertainty in legal matters and proceedings. Examples of challenges of operating in these countries include:
procedural requirements for temporary import permits, which may be difficult to obtain;
the effect of certain temporary import permit regimes, where the duration of the permit does not coincide with the general term of the drilling contract; and
ongoing claims in Brazil related to withholding taxes payable on our service contracts.
Our ability to do business in a number of jurisdictions is subject to maintaining required licenses and permits and complying with applicable laws and regulations. Changes in, compliance with, or our failure to comply with the laws and regulations of the countries where we operate may negatively impact our operations in those countries and could have a material adverse effect on our results of operations.
In addition, OPEC initiatives, as well as other governmental actions, may continue to cause oil price volatility. In some areas of the world, this governmental activity has adversely affected the amount of exploration and development work done by major oil companies, which may continue. In addition, some governments favor or effectively require the awarding of drilling contracts to local contractors, require use of a local agent, require partial local ownership or require foreign contractors to employ citizens of, or purchase supplies from, a particular jurisdiction. These practices may adversely affect our ability to compete and our results of operations.
In June 2016, the United Kingdom (“U.K.”) held a referendum in which voters approved an exit from the European Union (“E.U.”), commonly referred to as “Brexit” and in March 2017 the U.K. formally started the process for the U.K. to leave the E.U. Given the lack of comparable precedent, it is unclear how disruptive the withdrawal will be, including possible financial, trade, regulatory and legal implications. Brexit creates global political and economic uncertainty, which may cause, among other consequences, volatility in exchange rates and interest rates, and changes in regulations. The Company provides contract drilling services to the international oil and gas industry and our fleet operates globally across multiple locations. While our business is internationally diversified, the Company is incorporated and registered within the U.K. Based on our global operating model and the versatility and marketability of our fleet, we do not expect the impact of Brexit to be significant to the Company.

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Operating and maintenance costs of our rigs may be significant and may not correspond to revenue earned.
Our operating expenses and maintenance costs depend on a variety of factors including: crew costs, costs of provisions, equipment, insurance, maintenance and repairs, and shipyard costs, many of which are beyond our control. Our total operating costs are generally related to the number of drilling rigs in operation and the cost level in each country or region where such drilling rigs are located. Equipment maintenance costs fluctuate depending upon the type of activity that the drilling rig is performing and the age and condition of the equipment. Operating and maintenance costs will not necessarily fluctuate in proportion to changes in operating revenues. While operating revenues may fluctuate as a function of changes in dayrate, costs for operating a rig may not be proportional to the dayrate received and may vary based on a variety of factors, including the scope and length of required rig preparations and the duration of the contractual period over which such expenditures are amortized. Any investments in our rigs may not result in an increased dayrate for or income from such rigs. A disproportionate amount of operating and maintenance costs in comparison to dayrates could have a material adverse effect on our business, financial condition and results of operations.
Drilling contracts with national oil companies may expose us to greater risks than we normally assume in drilling contracts with non-governmental clients.
Contracts with national oil companies are often non-negotiable and may expose us to greater commercial, political and operational risks than we assume in other contracts, such as exposure to materially greater environmental liability and other claims for damages (including consequential damages) and personal injury related to our operations, or the risk that the contract may be terminated by our client without cause on short-term notice, contractually or by governmental action, under certain conditions that may not provide us an early termination payment, collection risks and political risks. In addition, our ability to resolve disputes or enforce contractual provisions may be negatively impacted with these contracts. While we believe that the financial, commercial and risk allocation terms of these contracts and our operating safeguards mitigate these risks, 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.
Governmental laws and regulations may add to our costs, result in delays, or limit our drilling activity.
Our business is affected by public policy and laws and regulations relating to the energy industry in the geographic areas where we operate.
The drilling industry is dependent on demand for services from the oil and gas exploration and production industry, and accordingly, we are directly affected by the adoption of laws and regulations that for economic, environmental or other policy reasons curtail exploration and development drilling for oil and gas. We may be required to make significant capital expenditures to comply with governmental laws and regulations. Governments in some foreign countries are increasingly active in regulating and controlling the ownership of concessions, the exploration for oil and gas, and other aspects of the oil and gas industries. There is increasing attention in the United States and worldwide concerning the issue of climate change and the effect of greenhouse gases, or GHGs. This increased attention may result in new environmental laws or regulations that may unfavorably impact us, our suppliers and our customers.
The modification of existing laws or regulations or the adoption of new laws or regulations that result in the curtailment of exploratory or developmental drilling for oil and gas could materially and adversely affect our operations by limiting drilling opportunities increasing our cost of doing business, discouraging our customers from drilling for hydrocarbons, disrupting revenue through permitting or similar delays, or subjecting us to liability.
Any violation of anti-bribery or anti-corruption laws, including the Foreign Corrupt Practices Act, the United Kingdom Bribery Act, or similar laws and regulations could result in significant expenses, divert management attention, and otherwise have a negative impact on us.
We operate in countries known to have a reputation for corruption. We are subject to the risk that we, our affiliated entities or their respective officers, directors, employees and agents may take action determined to be in violation of such anti-corruption laws, including the U.S. Foreign Corrupt Practices Act of 1977 (the FCPA), the United Kingdom Bribery Act 2010 (the U.K. Bribery Act) and similar laws in other countries. Any violation of the FCPA, U.K. Bribery Act or other applicable anti-corruption laws could result in substantial fines, sanctions, civil and/or criminal penalties and curtailment of operations in certain jurisdictions and might adversely affect our business, financial condition and results of operations. In addition, actual or alleged violations could damage our reputation and ability to do business. Further, detecting, investigating and resolving actual or alleged violations is expensive and can consume significant time and attention of our senior management.
Changes in, compliance with, or our failure to comply with the certain laws and regulations may negatively impact our operations and could have a material adverse effect on our results of operations.
Our operations are subject to various laws and regulations in countries in which we operate, including laws and regulations relating to:
the importing, exporting, equipping and operation of drilling rigs;
currency exchange controls;
oil and gas exploration and development;

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taxation of offshore earnings and earnings of expatriate personnel; and
use and compensation of local employees and suppliers by foreign contractors.
Public and regulatory scrutiny of the energy industry has resulted in increased regulations being either proposed or implemented. In addition, existing regulations might be revised or reinterpreted, new laws, regulations and permitting requirements might be adopted or become applicable to us, our rigs, our customers, our vendors or our service providers, and future changes in laws and regulations could significantly increase our costs and could have a material adverse effect on our business, financial condition and results of operations. In addition, we may be required to post additional surety bonds to secure performance, tax, customs and other obligations relating to our rigs in jurisdictions where bonding requirements are already in effect and in other jurisdictions where we may operate in the future. These requirements would increase the cost of operating in these countries, which could materially adversely affect our business, financial condition and results of operations.
From time to time, new rules, regulations and requirements regarding oil and gas development have been proposed and implemented by BOEM, BSEE or the United States Congress, as well as other jurisdictions outside the U.S., that could materially limit or prohibit, and increase the cost of, offshore drilling. For example, in July 2016, BOEM and BSEE finalized a rule revising and adding requirements for drilling on the U.S. Arctic Outer Continental Shelf. Similarly, in April 2016, BSEE announced a final blowout preventer systems and well control rule. BSEE also finalized a rule in September 2016 concerning production safety systems for oil and natural gas operations on the Outer Continental Shelf. However, in December 2017, BSEE published a proposed rule that would revise certain requirements from the September 2016 rule. The final rule implementing these revisions was published in September 2018. In addition, in May 2018, BSEE published a proposed rule that would revise several requirements of the blowout preventer systems and well control rule. A final rule has not yet been issued. BOEM also released a new Notice to Lessees and Operators in the Outer Continental Shelf (NTL) in September 2016 that updates offshore bonding requirements. This update eliminates waivers of supplemental bonding and prohibits a company from relying on the financial strength of co-lessees unless co-lessees agree to allocate BOEM-determined self-insurance to the lease. In January 2017, BOEM extended the implementation timeline for the NTL by six months. In May 2017, the Secretary of the Interior directed BOEM to review the NTL and provide a report describing the results of the review and options for revising or rescinding the NTL. BOEM again extended the implementation timeline for the NTL in June 2017. Implementation of the NTL is currently stayed pending further action by BOEM. However, these new bonding requirements may increase our customers’ operating costs and impact our customers’ ability to obtain leases, thereby reducing demand for our services. We are also subject to increasing regulatory requirements and scrutiny in the North Sea jurisdictions and other countries. These new rules, regulations and requirements, including the adoption of new safety requirements and policies relating to the approval of drilling permits, restrictions on oil and gas development and production activities in the U.S. Gulf of Mexico and elsewhere, implementation of safety and environmental management systems, mandatory third party compliance audits, and the promulgation of numerous Notices to Lessees or similar new regulatory requirements outside of the United States, have impacted and may continue to impact our operations by causing increased costs, delays and operational restrictions. In addition to these rules, regulations and requirements, the U.S. federal government is considering new legislation that could impose additional equipment and safety requirements on operators and drilling contractors in the United States, as well as regulations relating to the protection of the environment. If the new regulations, policies, operating procedures and possibility of increased legal liability resulting from the adoption or amendment of rules and regulations applicable to our operations in the United States or other jurisdictions are viewed by our current or future customers as a significant impairment to expected profitability on projects, then they could discontinue or curtail their offshore operations in the impacted region, thereby adversely affecting our operations by limiting drilling opportunities or imposing materially increased costs.
We could also be affected by challenges to offshore operations by environmental groups and coastal states. For example, in December 2018, environmental groups challenged incidental harassment authorizations issued by the National Marine Fisheries Service that allow companies to conduct air gun seismic surveys for oil and gas exploration off the Atlantic coast. The attorney generals for nine coastal states also sought to intervene as plaintiffs. Restrictions on authorizations needed to conduct seismic surveys could impact our customers’ ability to identify oil and gas reserves, thereby reducing demand for our services. Several coastal states have also taken steps to prohibit offshore drilling. For example, California passed laws in September 2018 barring the construction of new oil drilling-related infrastructure in state waters. Similarly, in November 2018, voters in Florida approved an amendment to the state constitution that would ban oil and gas drilling in offshore state waters. Such initiatives could reduce opportunities for our customers and thereby reduce demand for our services.
Adverse effects may continue as a result of the uncertainty of ongoing inquiries, investigations and court proceedings, or additional inquiries and proceedings by federal or state regulatory agencies or private plaintiffs. In addition, we cannot predict the outcome of any of these inquiries or whether these inquiries will lead to additional legal proceedings against us, civil or criminal fines or penalties, or other regulatory action, including legislation or increased permitting requirements. Legal proceedings or other matters against us, including environmental matters, suits, regulatory appeals, challenges to our permits by citizen groups and similar matters, might result in adverse decisions against us. The result of such adverse decisions, both individually or in the aggregate, could be material and may not be covered fully or at all by insurance.

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Operational interruptions or maintenance or repair work may cause our customers to suspend or reduce payment of dayrates until operation of the respective drilling rig is resumed, which may lead to loss of revenue or termination or renegotiation of the drilling contract.
If our drilling rigs are idle for reasons that are not related to the ability of the rig to operate, our customers are entitled to pay a waiting, or standby, rate lower than the full operational rate. In addition, if our drilling rigs are taken out of service for maintenance and repair for a period of time exceeding the scheduled maintenance periods set forth in our drilling contracts, we will not be entitled to payment of dayrates until the rig is able to work. Several factors could cause operational interruptions, including:
breakdowns of equipment and other unforeseen engineering problems;
work stoppages, including labor strikes;
shortages of material and skilled labor;
delays in repairs by suppliers;
surveys by government and maritime authorities;
periodic classification surveys;
inability to obtain permits;
severe weather, strong ocean currents or harsh operating conditions;
force majeure events; and
the occurrence or threat of epidemic or pandemic diseases or any government response to such occurrence or threat.
If the interruption of operations were to exceed a determined period due to an event of force majeure, our customers have the right to pay a rate that is significantly lower than the waiting rate for a period of time, and, thereafter, may terminate the drilling contracts related to the subject rig. Suspension of drilling contract payments, prolonged payment of reduced rates or termination of any drilling contract as a result of an interruption of operations as described herein could materially adversely affect our business, financial condition and results of operations.
We may have difficulty obtaining or maintaining insurance in the future and our insurance coverage and contractual indemnity rights may not protect us against all the risks and hazards we face.
We do not procure insurance coverage for all of the potential risks and hazards we may face. Furthermore, no assurance can be given that we will be able to obtain insurance against all of the risks and hazards we face or that we will be able to obtain or maintain adequate insurance at rates and with deductibles or retention amounts that we consider commercially reasonable.
Our insurance carriers may interpret our insurance policies such that they do not cover losses for which we make claims. Our insurance policies may also have exclusions of coverage for some losses. Uninsured exposures may include expatriate activities prohibited by U.S. laws, radiation hazards, certain loss or damage to property onboard our rigs and losses relating to shore-based terrorist acts or strikes. Furthermore, the damage sustained to offshore oil and gas assets in the United States as a result of hurricanes has negatively impacted certain aspects of the energy insurance market, resulting in more restrictive and expensive coverage for U.S. named windstorm perils due to the price or lack of availability of coverage. Accordingly, we have in the past self-insured the rigs in the U.S. Gulf of Mexico for named windstorm perils. We currently have U.S. windstorm coverage for most of our U.S. fleet subject to limit, but will continue to monitor the insurance market conditions in the future and may decide not to, or be unable to, purchase named windstorm coverage for some or all of the rigs operating in the U.S. Gulf of Mexico.
Under our drilling contracts, liability with respect to personnel and property is customarily assigned on a “knock-for-knock” basis, which means that we and our customers assume liability for our respective personnel and property, irrespective of the fault or negligence of the party indemnified. Although our drilling contracts generally provide for indemnification from our customers for certain liabilities, including liabilities resulting from pollution or contamination originating below the surface of the water, enforcement of these contractual rights to indemnity may be limited by public policy and other considerations and, in any event, may not adequately cover our losses from such incidents. There can also be no assurance that those parties with contractual obligations to indemnify us will necessarily be in a financial position to do so. During depressed market periods such as the one in which we currently operate, the contractual indemnity provisions we are able to negotiate in our drilling contracts may require us to assume more risk than we would during normal market periods.
Although we maintain insurance in the geographic areas in which we operate, pollution, reservoir damage and environmental risks generally are not fully insurable. Our insurance policies may not adequately cover our losses or may have exclusions of coverage for some losses. We do not have insurance coverage or rights to indemnity for all risks, including loss of hire insurance on most of the rigs in our fleet. Uninsured exposures may include expatriate activities prohibited by U.S. laws and regulations, radiation hazards, cyber risks, certain loss or damage to property onboard our rigs and losses relating to shore-based terrorist acts or strikes. If a significant accident or other event occurs and is not fully covered by insurance or contractual indemnity, it could adversely affect our business, financial condition and results of operations.
Our failure to adequately protect our sensitive information technology systems and critical data and our service providers’ failure to protect their systems and data could have a material adverse effect on our business, results of operations and financial condition.
We depend on information technology systems that we manage, and others that are managed by our third-party service and equipment providers, to conduct our day-to-day operations, including critical systems on our drilling units, and these systems are subject to risks associated

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with cyber incidents or attacks. It has been reported that unknown entities or groups have mounted cyber-attacks on businesses and other organizations solely to disable or disrupt computer systems, disrupt operations and, in some cases, steal data. Due to the nature of cyber-attacks, breaches to our systems or our service or equipment providers’ systems could go undetected for a prolonged period of time. While the Company has a cybersecurity program a significant cyber attack could disrupt our operations and result in downtime, loss of revenue, harm to the Company's reputation, or the loss, theft, corruption or unauthorized release of critical data of us or those with whom we do business as well as result in higher costs to correct and remedy the effects of such incidents. If our or our service or equipment providers’ systems for protecting against cyber incidents or attacks prove to be insufficient and an incident were to occur, it could have a material adverse effect on our business, financial condition and results of operations, along with our reputation. Currently, we do not carry insurance for losses related to cybersecurity attacks, and may elect to not obtain such insurance in the future.
In addition, laws and regulations governing data privacy and the unauthorized disclosure of confidential or protected information, including the European Union General Data Protection Regulation and recent legislation in various U.S. states, pose increasingly complex compliance challenges and potentially elevate costs, and any failure to comply with these laws and regulations could result in significant penalties and legal liability.
A loss of a major tax dispute or a successful tax challenge to our operating structure, intercompany pricing policies or the taxable presence of our subsidiaries in certain countries could result in a higher tax rate on our worldwide earnings, which could result in a material adverse effect on our financial condition and results of operations.
Income tax returns that we file will be subject to review and examination. We will not recognize the benefit of income tax positions we believe are more likely than not to be disallowed upon challenge by a tax authority. If any tax authority successfully challenges our operational structure, intercompany pricing policies or the taxable presence of our subsidiaries in certain countries, if the terms of certain income tax treaties are interpreted in a manner that is adverse to our structure, or if we lose a material tax dispute in any country, our effective tax rate on our worldwide earnings could increase substantially and result in a material adverse effect on our financial condition.
Our consolidated effective income tax rate may vary substantially from one reporting period to another.
We cannot provide any assurances as to what our consolidated effective income tax rate will be because of, among other matters, uncertainty regarding the nature and extent of our business activities in any particular jurisdiction in the future and the tax laws of such jurisdictions, as well as potential changes in UK, U.S. and other foreign tax laws, regulations or treaties or the interpretation or enforcement thereof, changes in the administrative practices and precedents of tax authorities or any reclassification or other matter (such as changes in applicable accounting rules) that increases the amounts we have provided for income taxes or deferred tax assets and liabilities in our consolidated financial statements. For example, 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 and/or cash flows.
In addition, as a result of frequent changes in the taxing jurisdictions in which our drilling rigs are operated and/or owned, changes in the overall level of our income and changes in tax laws, our consolidated effective income tax rate may vary substantially from one reporting period to another. Income tax rates imposed in the tax jurisdictions in which our subsidiaries conduct operations vary, as does the tax base to which the rates are applied. In some cases, tax rates may be applicable to gross revenues, statutory or negotiated deemed profits or other bases utilized under local tax laws, rather than to net income. Our drilling rigs frequently move from one taxing jurisdiction to another to perform contract drilling services. In some instances, the movement of drilling rigs among taxing jurisdictions will involve the transfer of ownership of the drilling rigs among our subsidiaries. If we are unable to mitigate the negative consequences of any change in law, audit, business activity or other matter, this could cause our consolidated effective income tax rate to increase and cause a material adverse effect on our financial position, operating results and/or cash flows.
Our operations are subject to numerous laws and regulations relating to the protection of the environment and of human health and safety, and compliance with these laws and regulations could impose significant costs and liabilities that exceed our current expectations.
Substantial costs, liabilities, delays and other significant issues could arise from environmental, health and safety laws and regulations covering our operations, and we may incur substantial costs and liabilities in maintaining compliance with such laws and regulations. Our operations are subject to extensive international conventions and treaties, and national or federal, state and local laws and regulations, governing environmental protection, including with respect to the discharge of materials into the environment and the security of chemical and industrial facilities. These laws govern a wide range of environmental issues, including:
the release of oil, drilling fluids, natural gas or other materials into the environment;
air emissions from our drilling rigs or our facilities;

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handling, cleanup and remediation of solid and hazardous wastes at our drilling rigs or our facilities or at locations to which we have sent wastes for disposal;
restrictions on chemicals and other hazardous substances; and
wildlife protection, including regulations that ensure our activities do not jeopardize endangered or threatened animals, fish and plant species, nor destroy or modify the critical habitat of such species.
Various governmental authorities have the power to enforce compliance with these laws and regulations and the permits issued under them, oftentimes requiring difficult and costly actions. Failure to comply with these laws, regulations and permits, or the release of oil or other materials into the environment, may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations, the imposition of stricter conditions on or revocation of permits, the issuance of moratoria or injunctions limiting or preventing some or all of our operations, delays in granting permits and cancellation of leases, or could affect our relationship with certain consumers.
There is an inherent risk of the incurrence of environmental costs and liabilities in our business, some of which may be material, due to the handling of our customers’ hydrocarbon products as they are gathered, transported, processed and stored, air emissions related to our operations, historical industry operations, and water and waste disposal practices. For example, we, as an operator of mobile offshore drilling units in navigable U.S. waters and certain offshore areas, including the U.S. Outer Continental Shelf, are liable for damages and for the cost of removing oil spills for which we may be held responsible, subject to certain limitations. Our operations may involve the use or handling of materials that are classified as environmentally hazardous. Environmental laws and regulations may expose us to liability for the conduct of or conditions caused by others or for acts that were in compliance with all applicable laws at the time they were performed. Joint, several or strict liability may be incurred without regard to fault under certain environmental laws and regulations for the remediation of contaminated areas and in connection with past, present or future spills or releases of natural gas, oil and wastes on, under, or from past, present or future facilities. Private parties may have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or property damage arising from our operations. In addition, increasingly strict laws, regulations and enforcement policies could materially increase our compliance costs and the cost of any remediation that may become necessary. Our insurance may not cover all environmental risks and costs or may not provide sufficient coverage if an environmental claim is made against us.
Our business may be adversely affected by increased costs due to stricter pollution control equipment requirements or liabilities resulting from non-compliance with required operating or other regulatory permits. Also, we might not be able to obtain or maintain from time to time all required environmental regulatory approvals for our operations. If there is a delay in obtaining any required environmental regulatory approvals, or if we fail to obtain and comply with them, the operation or construction of our facilities could be prevented or become subject to additional costs. In addition, the steps we could be required to take to bring certain facilities into regulatory compliance could be prohibitively expensive, and we might be required to shut down, divest or alter the operation of those facilities, which might cause us to incur losses.
We make assumptions and develop expectations about possible expenditures related to environmental conditions based on current laws and regulations and current interpretations of those laws and regulations. If the interpretation of laws or regulations, or the laws and regulations themselves, change, our assumptions may change, and new capital costs may be incurred to comply with such changes. In addition, new environmental laws and regulations might adversely affect our operations, as well as waste management and air emissions. For instance, governmental agencies could impose additional safety requirements, which could affect our profitability. Further, new environmental laws and regulations might adversely affect our customers, which in turn could affect our profitability.
Finally, although some of our drilling rigs will be separately owned by our subsidiaries, under certain circumstances a parent company and all of the unit-owning affiliates in a group under common control engaged in a joint venture could be held liable for damages or debts owed by one of the affiliates, including liabilities for oil spills under environmental laws. Therefore, it is possible that we could be subject to liability upon a judgment against us or any one of our subsidiaries.
Reactivation, refurbishment, conversion or upgrades of rigs are subject to risks, including delays and cost overruns, which could have an adverse impact on our available cash resources and results of operations.
We will continue to make upgrades, refurbishment and repair expenditures to our fleet from time to time, some of which may be unplanned. In addition, we may continue to reactivate rigs that have been cold or warm stacked and make selective purchases of rigs, such as the Noble Johnny Whitstine purchased in 2018 and the Noble Joe Knight, for which the purchase is expected to be completed in late February 2019. Our customers may also require certain shipyard reliability upgrade projects for our rigs. These projects and other efforts of this type are subject to risks of cost overruns or delays inherent in any large construction project as a result of numerous factors, including the following:
shortages of equipment, materials or skilled labor;
work stoppages and labor disputes;
unscheduled delays in the delivery of ordered materials and equipment;
local customs strikes or related work slowdowns that could delay importation of equipment or materials;
weather interferences;
difficulties in obtaining necessary permits or approvals or in meeting permit or approval conditions;

22



design and engineering problems;
inadequate regulatory support infrastructure in the local jurisdiction;
latent damages or deterioration to hull, equipment and machinery in excess of engineering estimates and assumptions;
unforeseen increases in the cost of equipment, labor and raw materials, particularly steel;
unanticipated actual or purported change orders;
client acceptance delays;
disputes with shipyards and suppliers;
delays in, or inability to obtain, access to funding;
shipyard availability, failures and difficulties, including as a result of financial problems of shipyards or their subcontractors; and
failure or delay of third-party equipment vendors or service providers.
The failure to complete a rig reactivation, repair, upgrade, refurbishment or new construction on time, or at all, or the inability to complete a rig conversion or new construction in accordance with its design specifications, may result in loss of revenues, penalties, or delay, renegotiation or cancellation of a drilling contract or the recognition of an asset impairment. Additionally, capital expenditures for rig reactivation, repair, upgrade, refurbishment and construction projects could materially exceed our planned capital expenditures. Moreover, when our rigs are undergoing upgrade, refurbishment and repair, they may not earn a dayrate during the period they are out of service. If we experience substantial delays and cost overruns in our shipyard projects, it could have a material adverse effect on our business, financial condition and results of operations. We currently have no new rigs under construction.
Failure to attract and retain skilled personnel or an increase in personnel costs could adversely affect our operations.
We require skilled personnel to operate and provide technical services and support for our drilling units. In the past, during periods of high demand for drilling services and increasing worldwide industry fleet size, shortages of qualified personnel have occurred. During the last few years of reduced demand, there were layoffs of qualified personnel, who often find work with competitors or leave the industry. As a result, as market conditions improve and we seek to reactivate warm or cold stacked rigs, upgrade our working rigs or purchase additional rigs, we may face shortages of qualified personnel, which would impair our ability to attract qualified personnel for our new or existing drilling units, impair the timeliness and quality of our work and create upward pressure on personnel costs, any of which could adversely affect our operations.
Supplier capacity constraints or shortages in parts or equipment, 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 used in our drilling operations exposes us to volatility in the quality, price and availability of such items. Certain specialized parts and equipment we use in our operations may be available only from a single or small number of suppliers. During the last few years of reduced demand, many of these third-party suppliers reduced their inventories of parts and equipment and, in some cases, reduced their production capacity. As the market for our services improves and we seek to reactivate warm or cold stacked rigs, upgrade our working rigs or purchase additional rigs, these reductions could make it more difficult for us to find equipment and parts for our rigs. A disruption or delay in the deliveries from such third-party suppliers, capacity constraints, production disruptions, price increases, defects or quality-control issues, recalls or other decreased availability or servicing of parts and equipment could adversely affect our ability to reactivate rigs, upgrade working rigs, purchase additional rigs or meet our commitments to customers on a timely basis, adversely impact our operations and revenues by resulting in uncompensated downtime, reduced dayrates, the incurrence of liquidated damages or other penalties or the cancellation or termination of contracts, or increase our operating costs.
Acts of terrorism, piracy and political and social unrest could affect the markets for drilling services, which may have a material adverse effect on our results of operations.
Acts of terrorism and social unrest, brought about by world political events or otherwise, have caused instability in the world’s financial and insurance markets in the past and may occur in the future. Such acts could be directed against companies such as ours. In addition, acts of terrorism, piracy and social unrest could lead to increased volatility in prices for crude oil and natural gas and could affect the markets for drilling services. Insurance premiums could increase and coverage may be unavailable in the future. Government regulations may effectively preclude us from engaging in business activities in certain countries. These regulations could be amended to cover countries where we currently operate or where we may wish to operate in the future.
Our drilling contracts do not generally provide indemnification against loss of capital assets or loss of revenues resulting from acts of terrorism, piracy or political or social unrest. We have limited insurance for our assets providing coverage for physical damage losses resulting from risks, such as terrorist acts, piracy, vandalism, sabotage, civil unrest, expropriation and acts of war, and we do not carry insurance for loss of revenues resulting from such risks.

23



Unionization efforts and labor regulations in certain countries in which we operate could materially increase our costs or limit our flexibility.
Certain of our employees and contractors in international markets are represented by labor unions or work under collective bargaining or similar agreements, which are subject to periodic renegotiation. Efforts may be made from time to time to unionize portions of our workforce. In addition, we may be subject to strikes or work stoppages and other labor disruptions in the future. Additional unionization efforts, new collective bargaining agreements or work stoppages could materially increase our costs, reduce our revenues or limit our operational flexibility.
Any failure to comply with the complex laws and regulations governing international trade could adversely affect our operations.
The shipment of goods, services and technology across international borders subjects our business to extensive trade laws and regulations. Import activities are governed by unique customs laws and regulations in each of the countries of operation. 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 economic sanctions against certain countries, persons and other entities that may restrict or prohibit transactions involving such countries, persons and entities. U.S. sanctions, in particular, are targeted against certain countries that are heavily involved in the petroleum and petrochemical industries, which includes drilling activities.
The laws and regulations concerning import activity, export recordkeeping and reporting, export control and economic sanctions are complex and constantly changing. These laws and regulations may be enacted, amended, enforced or interpreted in a manner materially impacting our operations. Shipments can be delayed and denied export or entry for a variety of reasons, some of which are outside our control and some of which may result from failure to comply with existing legal and regulatory regimes. Shipping delays or denials could cause unscheduled operational downtime. Any failure to comply with applicable legal and regulatory trading obligations could also result in criminal and civil penalties and sanctions, such as fines, imprisonment, debarment from government contracts, seizure of shipments and loss of import and export privileges.
Currently, we do not, nor do we intend to, operate in countries that are subject to significant sanctions and embargoes imposed by the U.S. government or identified by the U.S. government as state sponsors of terrorism, such as the Crimean region of the Ukraine, Cuba, Iran, North Korea, Sudan and Syria. The U.S. sanctions and embargo laws and regulations vary in their application, as they do not all apply to the same covered persons or proscribe the same activities, and such sanctions and embargo laws and regulations may be amended or strengthened over time. Although we believe that we will be in compliance with all applicable sanctions and embargo laws and regulations at the filing date, and intend to maintain such compliance, there can be no assurance that we will be in compliance in the future, particularly as the scope of certain laws may be unclear and may be subject to changing interpretations. Any such violation could result in fines or other penalties and could result in some investors deciding, or being required, to divest their interest, or not to invest, in us. In addition, certain institutional investors may have investment policies or restrictions that prevent them from holding securities of companies that have contracts with countries identified by the U.S. government as state sponsors of terrorism. In addition, our reputation and the market for our securities may be adversely affected if we engage in certain other activities, such as entering into drilling contracts with individuals or entities in countries subject to significant U.S. sanctions and embargo laws that are not controlled by the governments of those countries, or engaging in operations associated with those countries pursuant to contracts with third parties that are unrelated to those countries or entities controlled by their governments.
Pension expenses associated with our retirement benefit plans may fluctuate significantly depending upon changes in actuarial assumptions, future investment performance of plan assets and legislative or other regulatory actions.
A portion of our current and retired employee population is covered by pension and other post-retirement benefit plans, the costs of which are dependent upon various assumptions, including estimates of rates of return on benefit plan assets, discount rates for future payment obligations, mortality assumptions, rates of future cost growth and trends for future costs. In addition, funding requirements for benefit obligations of our pension and other post-retirement benefit plans are subject to legislative and other government regulatory actions. Future changes in estimates and assumptions associated with our pension and other post-retirement benefit plans could have a material adverse effect on our financial condition, results of operations, cash flows and/or financial disclosures.
Fluctuations in exchange rates and nonconvertibility of currencies could result in losses to us.
We may experience currency exchange losses when revenues are received or expenses are paid in nonconvertible currencies, when we do not hedge an exposure to a foreign currency, when the result of a hedge is a loss or if any counterparty to our hedge were to experience financial difficulties. We may also incur losses as a result of an inability to collect revenues due to a shortage of convertible currency available to the country of operation, controls over currency exchange or controls over the repatriation of income or capital.

24



We are subject to litigation that could have an adverse effect on us.
We are, from time to time, involved in various litigation matters. These matters may include, among other things, contract disputes, personal injury claims, asbestos and other toxic tort claims, environmental claims or proceedings, employment matters, issues related to employee or representative conduct, governmental claims for taxes or duties, and other litigation that arises in the ordinary course of our business. Although we intend to defend or pursue such matters vigorously, we cannot predict with certainty the outcome or effect of any claim or other litigation matter, and there can be no assurance as to the ultimate outcome of any litigation. Litigation may have an adverse effect on us because of potential negative outcomes, legal fees, the allocation of management’s time and attention, and other factors.
We are a holding company, and we are dependent upon cash flow from subsidiaries to meet our obligations.
We currently conduct our operations through our subsidiaries, and our operating income and cash flow are generated by our subsidiaries. As a result, cash we obtain from our subsidiaries is the principal source of funds necessary to meet our debt service obligations. Unless they are guarantors of our indebtedness, our subsidiaries do not have any obligation to pay amounts due on our indebtedness or to make funds available for that purpose. Contractual provisions or laws, as well as our subsidiaries’ financial condition and operating requirements, may also limit our ability to obtain the cash that we require from our subsidiaries to pay our debt service obligations. Applicable tax laws may also subject such payments to us by our subsidiaries to further taxation.
Item 1B. Unresolved Staff Comments.
None.
Item 2. Properties.
The description of our rig fleet included under “Part I, Item 1, Business” is incorporated by reference herein. Our corporate headquarters is located in London, England. We also maintain offices in Sugar Land, Texas, where significant worldwide global support activity occurs. In addition, we own and lease operational, administrative and marketing offices, as well as other sites used primarily for operations, storage and maintenance and repairs for drilling rigs and equipment in various locations worldwide.
Item 3. Legal Proceedings.
Information regarding legal proceedings is presented in “Note 15— Commitments and Contingencies” to our consolidated financial statements included in Part II, Item 8 of this Annual Report on Form 10-K.
Item 4. Mine Safety Disclosures.
Not applicable.

PART II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.
Market for Shares and Related Shareholder Information
Noble-UK shares are listed and traded on the New York Stock Exchange under the symbol “NE.”
The declaration and payment of dividends require the authorization of the Board of Directors of Noble-UK, provided that such dividends on issued share capital may be paid only out of Noble-UK’s “distributable reserves” on its statutory balance sheet in accordance with UK law. Therefore, Noble-UK is not permitted to pay dividends out of share capital, which includes share premium. Noble has not paid dividends since the third quarter of 2016. The payment of future dividends will depend on our results of operations, financial condition, cash requirements, future business prospects, contractual and indenture restrictions and other factors deemed relevant by our Board of Directors.
On February 19, 2019, there were 248,704,351 shares outstanding held by 167 shareholder accounts of record.
UK Tax Consequences to Shareholders of Noble-UK
The tax consequences discussed below do not reflect a complete analysis or listing of all the possible tax consequences that may be relevant to shareholders of Noble. Shareholders should consult their own tax advisors in respect of the tax consequences related to receipt, ownership, purchase or sale or other disposition of our shares.    

25



UK Income Tax on Dividends and Similar Distributions
A non-UK tax resident holder will not be subject to UK income taxes on dividend income and similar distributions in respect of our shares, unless the shares are attributable to a permanent establishment or a fixed place of business maintained in the UK by such non-UK holder.
Disposition of Noble—UK Shares
Shareholders who are neither UK tax residents nor holding their Noble-UK shares in connection with a trade carried on through a permanent establishment in the UK will not be subject to any UK taxes on chargeable gains as a result of any disposals of their shares. Noble-UK shares held outside the facilities of The Depository Trust Company (“DTC”) should be treated as UK situs assets for the purpose of UK inheritance tax.
UK Withholding Tax—Dividends to Shareholders
Payments of dividends by Noble-UK will not be subject to any withholding in respect of UK taxation, regardless of the tax residence of the recipient shareholder.
Stamp Duty and Stamp Duty Reserve Tax in Relation to the Transfer of Shares
Stamp duty and/or stamp duty reserve tax (“SDRT”) are imposed by the UK on certain transfers of chargeable securities (which include shares in companies incorporated in the UK) at a rate of 0.5 percent of the consideration paid for the transfers in question. Certain transfers of shares to depositaries or into clearance systems are charged at a higher rate of 1.5 percent. Her Majesty’s Revenue and Customs (“HMRC”) regard DTC as a clearance system for these purposes.
Transfers of the ordinary shares through the facilities of DTC will not attract a charge to stamp duty or SDRT in the UK. Any transfer of title to ordinary shares from within those facilities to a holder outside those facilities, and any subsequent transfers that occur entirely outside those facilities, will ordinarily attract stamp duty or SDRT at a rate of 0.5 percent. This duty must be paid (and, where relevant, the transfer document stamped by HMRC) before the transfer can be registered in the books of Noble-UK. However, if those ordinary shares of Noble-UK are redeposited into the facilities of DTC, that redeposit will attract stamp duty or SDRT at the rate of 1.5 percent.
Share Repurchases
Under UK law, the Company is only permitted to purchase its own shares by way of an “off-market purchase” in a plan approved by shareholders. We currently do not have shareholder authority to repurchase shares. During the years ended December 31, 2018, 2017 and 2016, we did not repurchase any of our shares.


26



Stock Performance Graph
The chart below presents a comparison of the five-year cumulative total return, assuming $100 was invested on December 31, 2013 for Noble-UK, the Standard & Poor's 500 Index, Dow Jones U.S. Oil Equipment and Services and a self-determined offshore drillers peer group. Total return assumes the reinvestment of dividends, if any, in the security on the ex-dividend date.
 
stockchartne26.jpg


 
 
INDEXED RETURNS
Year Ended December 31,
Company / Index
 
2014
 
2015
 
2016
 
2017
 
2018
Noble-UK
 
$
52.76

 
$
36.60

 
$
21.00

 
$
16.03

 
$
9.29

S&P 500 Index
 
113.69

 
115.26

 
129.05

 
157.22

 
150.33

Dow Jones U.S. Oil Equipment & Services
 
82.78

 
64.17

 
81.70

 
68.05

 
39.22

Offshore Drillers Peer Group (1)
 
53.21

 
33.16

 
29.95

 
21.05

 
12.16

 

(1) 
Our self-determined peer group is weighted according to market capitalization and consists of the Company and the following peer companies: Atwood Oceanics (through October 5, 2017), Diamond Offshore Drilling Inc., Ensco plc, Rowan Companies plc, Seadrill Ltd. and Transocean Ltd.
The above graph and related information shall not be deemed “soliciting material” or to be “filed” with the SEC, nor shall such information be incorporated by reference into any future filing under the Securities Act or the Exchange Act, except to the extent that we specifically incorporate it by reference into such filing.

27



Item 6. Selected Financial Data.
The following table presents selected financial data of us and our consolidated subsidiaries over the five-year period ended December 31, 2018, which information is derived from our audited financial statements. This information should be read in conjunction with, and is qualified in its entirety by, the more detailed information in our financial statements included in Part II, Item 8, “Financial Statements and Supplementary Data” in this Annual Report on Form 10-K.
 
 
Year Ended December 31,
 
 
2018
 
2017
 
2016
 
2015
 
2014
 
 
(In thousands, except per share amounts)
Statement of Income Data
 
 
 
 
 
 
 
 
 
 
Operating revenues from continuing operations
 
$
1,082,826

 
$
1,236,915

 
$
2,302,065

 
$
3,352,252

 
$
3,232,504

Net income (loss) from continuing operations attributable to Noble-UK (1)
 
(885,050
)
 
(516,511
)
 
(929,580
)
 
511,000

 
(152,011
)
Net income (loss) from continuing operations per share attributable to Noble-UK:
 
 
 
 
 
 
 
 
 
 
Basic
 
(3.59
)
 
(2.11
)
 
(3.82
)
 
2.06

 
(0.60
)
Diluted
 
(3.59
)
 
(2.11
)
 
(3.82
)
 
2.06

 
(0.60
)
Balance Sheet Data (at end of period)
 
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
 
375,232

 
662,829

 
725,722

 
512,245

 
68,510

Property and equipment, net
 
8,480,718

 
9,489,240

 
10,061,948

 
11,483,623

 
12,112,509

Total assets (2)
 
9,264,923

 
10,794,659

 
11,440,117

 
12,865,645

 
13,266,480

Long-term debt (2)
 
3,877,402

 
3,795,867

 
4,040,229

 
4,162,638

 
4,848,678

Total debt (3)
 
3,877,402

 
4,045,710

 
4,340,111

 
4,462,562

 
4,848,678

Total equity
 
4,654,574

 
5,950,628

 
6,467,445

 
7,422,230

 
7,287,034

Other Data
 
 
 
 
 
 
 
 
 
 
Net cash provided by operating activities
 
171,851

 
416,675

 
1,142,740

 
1,764,907

 
1,778,627

Net cash used in investing activities
 
(189,377
)
 
(118,325
)
 
(686,595
)
 
(432,537
)
 
(2,109,268
)
Net cash provided by (used in) financing activities
 
(269,396
)
 
(361,243
)
 
(242,668
)
 
(888,635
)
 
284,693

Net cash used for capital expenditures (4)
 
194,779

 
120,707

 
711,403

 
422,544

 
2,072,885

Working capital (2)(5)
 
293,599

 
445,951

 
559,321

 
377,034

 
259,888

Cash distributions declared per share
 

 

 
0.20

 
1.28

 
1.50

(1) 
Results for 2018, 2017, 2016, 2015 and 2014 include impairment charges of $802.1 million, $121.6 million, $1.5 billion, $418.3 million and $745.0 million, respectively.
(2) 
Certain amounts in prior periods have been reclassified to conform to the current year presentation. In accordance with our adoption of Accounting Standard Update No. 2015-3, unamortized debt issuance costs related to our senior notes are now shown as a direct reduction of the carrying amount of the related debt. See Part II, Item 8, “Financial Statements and Supplementary Data, Note 1— Organization and Significant Accounting Policies and Note 6— Loss on Impairment for more information.
(3) 
Consists of Long-term debt and Current maturities of long-term debt.
(4) 
Capital expenditures includes expenditures made for rigs that were ultimately transferred to Paragon Offshore as part of the Spin-off in August 2014.
(5) 
Working capital is calculated as current assets less current liabilities.
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.
The following discussion is intended to assist you in understanding our financial position at December 31, 2018 and 2017, and our results of operations for each of the years in the three-year period ended December 31, 2018. The following discussion should be read in conjunction with the consolidated financial statements and related notes contained in this Annual Report on Form 10-K for the year ended December 31, 2018 filed by Noble-UK and Noble-Cayman.

28



Executive Overview
We provide contract drilling services to the international oil and gas industry with our global fleet of mobile offshore drilling units. As of the filing date of this Annual Report on Form 10-K, our fleet of 24 drilling rigs consisted of eight drillships, four semisubmersibles and 12 jackups strategically deployed worldwide in both established and emerging ultra-deepwater and shallow water locations. We typically employ each drilling unit under an individual contract. Although the final terms of the contracts result from negotiations with our customers, many contracts are awarded based upon a competitive bidding process.
Our 2018 financial and operating results from continuing operations include:
operating revenues totaling $1.1 billion;
net loss of $885.1 million, or 3.59 per diluted share, which includes a $802.1 million before-tax impairment charge recognized on five of our rigs and certain capital spare equipment; and
net cash from operating activities totaling $171.9 million.
Our business strategy focuses on a balanced, high-specification fleet of both floating and jackup rigs and the deployment of our drilling rigs in established and emerging offshore oil and gas basins around the world.
Our floating and jackup drilling fleet is among the youngest, most modern and versatile in the industry. Our fleet consists predominately of technologically advanced units, equipped with sophisticated systems and components capable of executing our customers' increasingly complicated offshore drilling programs safely and with greater efficiency. A total of 15 of our drilling rigs have been delivered since 2011 following their construction in quality shipyards located primarily in Korea and Singapore. The last of our new rig additions was delivered in July 2016, and no further newbuild rig construction is in process. We have also retired or sold 11 drilling rigs since late 2014, due in part to advanced service lives, high cost of operation and limited customer appeal. Current market conditions could lead to us stacking or retiring additional rigs.
On September 21, 2018, we purchased the Noble Johnny Whitstine, a new GustoMSC CJ46 design jackup rig, from the PaxOcean Group (“PaxOcean”) in connection with a concurrently awarded drilling contract in the Middle East region. We paid $93.8 million for the rig, with $33.8 million paid in cash and the remaining $60.0 million of the purchase price financed by the seller. On February 14, 2019, we exercised our option to purchase a second newbuild CJ46 jackup from PaxOcean, to be known as the Noble Joe Knight, and we expect to complete the purchase in late February 2019. The purchase of the Noble Joe Knight will be funded with cash and seller financing on terms similar to the Noble Johnny Whitstine. See “Part II, Item 8, “Financial Statements and Supplementary Data, Note 7— Debt” for additional information.
Market Outlook
During 2018, higher average crude oil prices led to a slight improvement in customer activity, most notably across the jackup fleet. However, the challenging business environment for offshore drillers continued to persist due to an industry-wide rig supply imbalance that resulted from a multi-year period of investment in new offshore drilling capacity and the sustained drop in oil prices. Following the period of industry expansion, a period of oil price volatility compelled exploration and production companies to deemphasize offshore programs while focusing instead on land-based opportunities, such as unconventional land opportunities. A portion of the newbuild capacity ordered prior to the decline in industry activity continues to exit shipyards, while the delivery of other newbuild rigs has been delayed into the future. In either case, these rigs have added to the prevailing supply imbalance. Since 2015, the industry has experienced a higher level of fleet attrition, as rigs are removed from the global supply due to a number of factors, including advanced service life, high maintenance and reactivation costs and limited customer appeal, but the pace of attrition is significantly less than what would be required to remedy the capacity imbalance. Additionally, our customers have adopted a cautious approach to offshore spending due, in part, to volatility in crude oil prices over the past four years. We expect that the offshore drilling programs of operators will remain somewhat curtailed, as our customers continue to favor cash flow realization over long cycle investment in offshore production and exploration. During 2018, we recognized improvement in leading edge dayrates in the high specification jackup sector, especially in regions such as the North Sea and Middle East where approximately 80 percent of our fleet is located. We remain cautiously optimistic that this trend will continue into 2019. However, the floating sector did not enjoy the same pricing improvement as the jackup sector and additional customer activity will be required before dayrates move higher.
In spite of the gradual improvement in offshore activities in 2018, we expect the business environment for 2019 to remain challenging. The uncertainty of the viability and length of reductions in production agreed to by the Organization of Petroleum Exporting Countries (“OPEC”), the incremental production capacity in non-OPEC countries, including growing production from U.S. shale activity, the current U.S. political environment and fluid sentiment in oil markets are contributing to an uncertain oil price environment, leading to considerable uncertainty in our customers’ production spending plans. However, steady oil demand growth, the lack of production investments in various countries around the world and the production limits agreed to by OPEC and other significant oil producing countries should support higher sustained crude prices, and lead to improved offshore spending by our customers over time. In general, recent contract awards have been subject to an extremely competitive bidding process. As a result, the contracts have been for dayrates that are substantially lower than rates were for the same class of rigs before this period of imbalance.

29



We cannot give any assurances as to when conditions in the offshore drilling market will improve, or when the oversupply of available drilling rigs will end.
Due to numerous factors that influence our customers' annual global offshore spending patterns, including geopolitical events, we cannot predict the future level of demand or dayrates for our services, or future conditions in the offshore contract drilling industry. However, we believe the existence of certain factors should over time contribute to an improvement in the market for our services, driven in part by an acceleration in customers’ offshore spending. These factors include:
sustained crude oil prices;
improved geologic success with regard to our customers’ exploration efforts;
greater customer access to areas with promising offshore resource potential;
advances in offshore technological applications which reduce offshore costs and improve project economics;
high rate of natural depletion relating to land-based sources of crude oil production;
deteriorating annual production and poor reserve replacement metrics caused, in part, by a period of sustained under-investment by our customers; and
declining supply of rigs due to continued attrition.
We believe that we are strategically well positioned during this period of fundamental weakness for several reasons, including our substantial backlog, modern fleet of high-specification rigs and strong operational capability. We also believe that these strengths will help us take advantage of any future market upcycle. Although we plan to prioritize capital preservation and liquidity based on the challenging market conditions, from time to time we will also continue to evaluate opportunities to enhance our fleet of floating and jackup rigs, particularly focusing on higher specification rigs, to execute the increasingly complex drilling programs required by our customers.
Spin-off of Paragon Offshore plc
On August 1, 2014, Noble-UK completed the separation and spin-off of a majority of its standard specification offshore drilling business (the Spin-off) through a pro rata distribution of all of the ordinary shares of its wholly-owned subsidiary, Paragon Offshore plc (Paragon Offshore), to the holders of Noble’s ordinary shares. In February 2016, Paragon Offshore sought approval of a pre-negotiated plan of reorganization (the “Prior Plan”) by filing for voluntary relief under Chapter 11 of the United States Bankruptcy Code. As part of the Prior Plan, we entered into a settlement agreement with Paragon Offshore (the “Settlement Agreement”). The Prior Plan was rejected by the bankruptcy court in October 2016.
In April 2017, Paragon Offshore filed a revised plan of reorganization (the “New Plan”) in its bankruptcy proceeding. Under the New Plan, Paragon Offshore no longer need the Mexican tax bonding that Noble-UK was to provide under the Settlement Agreement. Consequently, Paragon Offshore abandoned the Settlement Agreement as part of the New Plan, and the Settlement Agreement was terminated at the time of the filing of the New Plan. On May 2, 2017, Paragon Offshore announced that it had reached an agreement in principle with both its secured and unsecured creditors to revise the New Plan to, among other things, create and fund a $10.0 million. litigation trust to pursue litigation against us. On June 7, 2017, the revised New Plan was approved by the bankruptcy court and Paragon Offshore emerged from bankruptcy on July 18, 2017.
On December 15, 2017, the litigation trust filed claims relating to the Spin-off against us and certain of our current and former officers and directors in the Delaware bankruptcy court that heard Paragon Offshore’s bankruptcy. The complaint alleges claims of alleged actual and constructive fraudulent conveyance, unjust enrichment and recharacterization of intercompany notes as equity claims against Noble and claims of breach of fiduciary duty and aiding and abetting breach of fiduciary duty against the officer and director defendants. The complaint states that the litigation trust is seeking damages of approximately $1.7 billion from the Company, an amount equal to the amount borrowed by Paragon Offshore immediately prior to the Spin-off, as well as unspecified amounts in respect of the claims against the officer and director defendants, all of whom have indemnification agreements with us. We requested that the court dismiss the claims of breach of fiduciary duty, aiding and abetting breach of fiduciary duty and unjust enrichment, and require such claims to be arbitrated under the master separation agreement (the “MSA”) entered into between Noble and Paragon Offshore at the time of the Spin-off, as well as stay the other proceedings during the pendency of the arbitration. The court ruled that the unjust enrichment claim be arbitrated and that the other claims proceed in bankruptcy court. We and the litigation trust have mutually agreed to drop our respective appeals of the arbitration ruling and now all matters will be heard in court, which will streamline the case. Discovery continues and the court has approved a litigation schedule, which could result in all pre-trial activity being completed by the end of 2019. A trial date has not yet been set.
We believe that Paragon Offshore, at the time of the Spin-off, was properly funded, solvent and had appropriate liquidity and that the claims brought by the litigation trust are without merit. We intend to defend ourselves vigorously. However, there is inherent risk and substantial expense in litigation, and the amount of damages the plaintiff is seeking is substantial. If any of the litigation trust’s claims are successful, or if we elect

30



to settle any claims (in part to reduce or eliminate the ongoing cost of defending the litigation and eliminate any risk of a larger judgment against us), any damages or other amounts we would be required to or agree to pay could have a material adverse effect on our business, financial condition and results of operations. Because of our view of the merits of the claims and the significant discovery still to be conducted in the litigation, we are not currently able to make a reasonable estimation of the amount of possible loss we may incur, if any. Subsequent developments in the litigation may make such an estimation possible, in which case we may record a charge against our income when a loss is reasonably estimable. This may occur even though the litigation may still be ongoing. Any charge could be material and could have a material adverse effect on our financial condition and results of operations. It may also be materially different than any amount we are required to pay once the litigation is concluded.
We have directors’ and officers’ indemnification coverage for the officers and directors who have been sued by the litigation trust. The insurers have accepted coverage for the director and officer claims and we are continuing to discuss with them the scope of their reimbursement of litigation expenses. In addition, at the time of the Spin-off, we had entity coverage, or “Side C” coverage, which was meant to cover certain litigation claims up to the coverage limit of $150.0 million, including litigation expenses. We have made a claim for coverage of the litigation trust’s claims against Noble under such entity insurance. The insurers have rejected coverage for these claims. We cannot predict the amount of claims and expenses we may incur, pay or settle in the Paragon Offshore litigation that such insurance will cover, if any.
Prior to the completion of the Spin-off, Noble-UK and Paragon Offshore entered into a series of agreements to effect the separation and Spin-off and govern the relationship between the parties after the Spin-off (the Separation Agreements), including the MSA and a Tax Sharing Agreement (the TSA).
As part of its final bankruptcy plan, Paragon Offshore rejected the Separation Agreements. Accordingly, the indemnity obligations that Paragon Offshore potentially would have owed us under the Separation Agreements have now terminated, including indemnities arising under the MSA and the TSA in respect of obligations related to Paragon Offshore’s business that were incurred through Noble-retained entities prior to the Spin-off. Likewise, any potential indemnity obligations that we would have owed Paragon Offshore under the Separation Agreements, including those under the MSA and the TSA in respect of Noble-UK’s business that was conducted prior to the Spin-off through Paragon Offshore-retained entities, are now also extinguished. In the absence of the Separation Agreements, liabilities relating to the respective parties will be borne by the owner of the legal entity or asset at issue and neither party will look to an allocation based on the historic relationship of an entity or asset to one of the party’s business, as had been the case under the Separation Agreements.
The rejection and ultimate termination of the indemnity and related obligations under the Separation Agreements resulted in a number of accounting charges and benefits during the year ended December 31, 2017, and such termination may continue to affect us in the future as liabilities arise for which we would have been indemnified by Paragon Offshore or would have had to indemnify Paragon Offshore. We do not expect that, overall, the rejection of the Separation Agreements by Paragon Offshore will have a material adverse effect on our financial condition or liquidity. However, any loss we experience with respect to which we would have been able to secure indemnification from Paragon Offshore under one or more of the Separation Agreements could have an adverse impact on our results of operations in any period, which impact may be material depending on our results of operations during this down-cycle.
During the year ended December 31, 2017, we recognized net charges of $15.9 million, with a non-cash loss of $1.5 million recorded in “Net loss from discontinued operations, net of tax” on our Consolidated Statement of Operations relating to Paragon Offshore’s emergence from bankruptcy.”
U.S. Federal Income Tax Reform
On December 22, 2017, the President of the United States signed into law legislation informally known as the Tax Cuts and Jobs Act (the “Act”). The Act represents major tax reform legislation that, among other provisions, reduces the U.S. corporate tax rate. For more information on the Act and its effect on our consolidated financial statements, see “—Critical Accounting Policies” and Part II, Item 8, “Financial Statements and Supplementary Data, Note 11— Income Taxes.”
Impairment
As more thoroughly described in “Note 6— Loss on Impairment” to our consolidated financial statements, included in Part II, Item 8 of this Annual Report on Form 10-K, we evaluate our property and equipment for impairment whenever there are changes in facts which suggest that the value of the asset is not recoverable. An impairment loss is recognized when and to the extent that an asset's carrying value exceeds its estimated fair value. As part of this analysis, we make assumptions and estimates regarding future market conditions. To the extent actual results do not meet our estimated assumptions for a given rig or piece of equipment, we may take an impairment loss in the future.
During the years ended December 31, 2018, 2017 and 2016, we recognized non-cash, before-tax impairment charges of $802.1 million, $121.6 million and $1.5 billion, respectively, related to certain rigs and related capital spares. These impairments were driven by factors such as customer suspensions of drilling programs, contract cancellations, a further reduction in the number of new contract opportunities, capital spare equipment obsolescence, and our belief that a drilling unit is no longer marketable and is unlikely to return to service.

31



There can be no assurance that we will not have to take additional impairment charges in the future if current depressed market conditions persist.
Contract Drilling Services Backlog
We maintain a backlog of commitments for contract drilling services. Our contract drilling services backlog reflects estimated future revenues attributable to signed drilling contracts. While backlog did not include any letters of intent as of December 31, 2018, in the past we have included in backlog certain letters of intent that we expect to result in binding drilling contracts.
We calculate backlog for any given unit and period by multiplying the full contractual operating dayrate for such unit by the number of days remaining in the period, and for the three rigs contracted with Royal Dutch Shell plc (“Shell”) mentioned below, we utilize the idle period and floor rates as described in footnote (2) to the backlog table below. The reported contract drilling services backlog does not include amounts representing revenues for mobilization, demobilization and contract preparation, which are not expected to be significant to our contract drilling services revenues, amounts constituting reimbursables from customers or amounts attributable to uncommitted option periods under drilling contracts or letters of intent.
The table below presents the amount of our contract drilling services backlog and the percent of available operating days committed for the periods indicated:
 
 
 
 
Year Ending December 31, (1)
 
 
Total
 
2019
 
2020
 
2021
 
2022
 
2023
 
 
(In thousands)
Contract Drilling Services Backlog
 
 
 
 
 
 
 
 
 
 
 
 
Semisubmersibles/Drillships (2)(3)
 
$
1,475,792

 
$
492,077

 
$
388,860

 
$
338,025

 
$
187,255

 
$
69,575

Jackups
 
927,739

 
453,275

 
286,710

 
141,438

 
46,316

 

Total (4)
 
$
2,403,531

 
$
945,352

 
$
675,570

 
$
479,463

 
$
233,571

 
$
69,575

Percent of Available Days Committed (5)
 
 
 
 
 
 
 
 
 
 
 
 
Semisubmersibles/Drillships
 
 
 
49
%
 
34
%
 
27
%
 
15
%
 
6
%
Jackups
 
 
 
75
%
 
38
%
 
25
%
 
7
%
 
%
Total
 
 
 
62
%
 
36
%
 
26
%
 
11
%
 
3
%

(1) 
Represents a twelve-month period beginning January 1, 2019.
(2) 
As previously reported, three of our long-term drilling contracts with Shell, the Noble Bully II, Noble Globetrotter I and Noble Globetrotter II, contain a dayrate adjustment mechanism that utilizes an average of market rates that match a set of distinct technical attributes and is subject to a modest discount, beginning on the fifth-year anniversary of the contract and continuing every six months thereafter. On December 12, 2016, we amended those drilling contracts with Shell. As a result of the amendments, each of the contracts now has a contractual dayrate floor. The contract amendments for the Noble Globetrotter I and Noble Globetrotter II provide a dayrate floor of $275,000 per day. The Noble Bully II contract contains a dayrate floor of $200,000 per day plus daily operating expenses. The amendment also provided Shell the right to idle the Noble Bully II for up to one year at a special stacking rate. The Noble Bully II was idled at a rate of $200,000 per day, effective April 3, 2017. In April 2018, we agreed with Shell to extend the idle period for the Noble Bully II through December 31, 2018 at a revised rate of $230,000 per day. Once the dayrate adjustment mechanism becomes effective and following any idle periods, the dayrate for these rigs will not be lower than the higher of (i) the contractual dayrate floor or (ii) the market rate as calculated under the adjustment mechanism. The impact to contract backlog from these amendments has been reflected in the table above and the backlog calculation assumes that, after any idle period at the contractual stacking rate, each rig will work at their respective dayrate floor for the remaining contract term.
(3) 
Noble and a subsidiary of Shell are involved in joint ventures that own and operate both the Noble Bully I and Noble Bully II. Pursuant to these agreements, each party has an equal 50 percent share in both vessels. As of December 31, 2018, the backlog for the Noble Bully II totaled $405.6 million, all of which is included in backlog. As of the same date, the Noble Bully I had no backlog. Noble’s proportional interest in the backlog for these rigs totaled $202.8 million.
(4) 
Some of our drilling contracts provide customers with certain early termination rights and, in limited cases, those termination rights require minimal or no notice and minimal financial penalties.
(5) 
Percent of available days committed is calculated by dividing the total number of days our rigs are operating under contract for such period by the product of the number of our rigs and the number of calendar days in such period.

32



The amount of actual revenues earned and the actual periods during which revenues are earned may be materially different than the backlog amounts and backlog periods presented in the table above due to various factors, including, but not limited to, shipyard and maintenance projects, unplanned downtime, the operation of market benchmarks for dayrate resets, achievement of bonuses, weather conditions, reduced standby or mobilization rates and other factors that result in applicable dayrates lower than the full contractual operating dayrate. In addition, amounts included in the backlog may change because drilling contracts may be varied or modified by mutual consent or customers may exercise early termination rights contained in some of our drilling contracts or decline to enter into a drilling contract after executing a letter of intent. As a result, our backlog as of any particular date may not be indicative of our actual operating results for the periods for which the backlog is calculated. See Part I, Item 1A, “Risk Factors— Our current backlog of contract drilling revenue may not be ultimately realized.”
For the year ended December 31, 2018, Shell, Saudi Arabian Oil Company and Equinor ASA represented approximately 52.2 percent, 19.8 percent and 11 percent of our backlog, respectively.
Results of Operations
2018 Compared to 2017
Net loss from continuing operations attributable to Noble-UK for the year ended December 31, 2018 was $885.1 million, or $3.59 per diluted share, on operating revenues of $1.1 billion, compared to a net loss from continuing operations for the year ended December 31, 2017 of $515.0 million, or $2.10 per diluted share, on operating revenues of $1.2 billion.
As a result of Noble-UK conducting all of its business through Noble-Cayman and its subsidiaries, the financial position and results of operations for Noble-Cayman, and the reasons for material changes in the amount of revenue and expense items between December 31, 2018 and December 31, 2017, would be the same as the information presented below regarding Noble-UK in all material respects, with the exception of operating income (loss). During the years ended December 31, 2018 and 2017, Noble-Cayman's operating loss was $40.7 million and $37.9 million lower, respectively, than that of Noble-UK. The operating loss difference is primarily a result of administration and other costs directly attributable to Noble-UK for operations support and stewardship-related services.
Key Operating Metrics
Operating results for our contract drilling services segment are dependent on three primary metrics: operating days, dayrates and operating costs. We also track rig utilization, which is a function of operating days and the number of rigs in our fleet. For more information on operating costs, see “—Contract Drilling Services” below. The following table presents the average rig utilization, operating days and average dayrates for our rig fleet for the years ended December 31, 2018 and 2017:
 
 
Average Rig Utilization (1)
 
Operating Days (2)
 
Average Dayrates (3)
 
 
December 31,
 
December 31,
 
 
 
December 31,
 
 
 
 
2018
 
2017
 
2018
 
2017
 
% Change
 
2018
 
2017
 
% Change
Jackups
 
77
%
 
85
%
 
3,642

 
4,367

 
(17
)%
 
$
130,217

 
$
126,109

 
3
 %
Semisubmersibles
 
15
%
 
17
%
 
268

 
365

 
(27
)%
 
108,111

 
155,919

 
(31
)%
Drillships
 
62
%
 
59
%
 
1,817

 
1,716

 
6
 %
 
293,265

 
349,244

 
(16
)%
Total
 
61
%
 
63
%
 
5,727

 
6,448

 
(11
)%
 
$
180,909

 
$
187,181

 
(3
)%
(1) 
We define utilization for a specific period as the total number of days our rigs are operating under contract, divided by the product of the total number of our rigs, including cold stacked rigs, and the number of calendar days in such period. Information reflects our policy of reporting on the basis of the number of available rigs in our fleet, excluding newbuild rigs under construction.
(2) 
Information reflects the number of days that our rigs were operating under contract.
(3) 
Average dayrates for the year ended December 31, 2017 include the impact of the valuation of certain contingent payments for the Noble Sam Croft and Noble Tom Madden contract settlement and termination by and among Freeport-McMoRan Inc., Freeport-McMoRan Oil & Gas LLC and one of our subsidiaries (“FCX Settlement”). We recognized a $14.4 million loss to the termination date valuation of certain contingent payments for the Noble Sam Croft and Noble Tom Madden related to the FCX Settlement. The loss in 2017 had a negative impact on the drillships’ average dayrates.

33



Contract Drilling Services
The following table presents the operating results for our contract drilling services segment for the years ended December 31, 2018 and 2017 (dollars in thousands):
 
 
Year Ended December 31,
 
Change
 
 
2018
 
2017
 
$
 
%
Operating revenues:
 
 
 
 
 
 
 
 
Contract drilling services
 
$
1,036,082

 
$
1,207,026

 
$
(170,944
)
 
(14
)%
Reimbursables and other (1)
 
46,744

 
29,889

 
16,855

 
56
 %
 
 
$
1,082,826

 
$
1,236,915

 
$
(154,089
)
 
(12
)%
Operating costs and expenses:
 
 
 
 
 
 
 
 
Contract drilling services
 
$
629,937

 
$
642,937

 
$
(13,000
)
 
(2
)%
Reimbursables (1)
 
37,084

 
18,435

 
18,649

 
101
 %
Depreciation and amortization
 
467,302

 
524,752

 
(57,450
)
 
(11
)%
General and administrative
 
73,216

 
71,634

 
1,582

 
2
 %
Loss on impairment
 
802,133

 
121,639

 
$
680,494

 
559
 %
 
 
2,009,672

 
1,379,397

 
630,275

 
46
 %
Operating loss
 
$
(926,846
)
 
$
(142,482
)
 
$
(784,364
)
 
551
 %
(1) 
We record reimbursements from customers for out-of-pocket expenses as operating revenues and the related direct costs as operating expenses. Changes in the amount of these reimbursables generally do not have a material effect on our financial position, results of operations or cash flows.
Operating Revenues. The $170.9 million decline in contract drilling services revenues for the year ended December 31, 2018 as compared to the same period of 2017 was composed of a $135.0 million decline due to fewer operating days and a $35.9 million decline due to lower dayrates. The decline in revenue was primarily due to our drillship and jackup fleet, which experienced declines in revenues of $66.5 million and $76.5 million, respectively. Our semisubmersible fleet also experienced a decline in revenue of $27.9 million.
The $66.5 million revenue decline in our drillship fleet consists of a $101.7 million decline from lower dayrates, which was partially offset by a $35.2 million increase due to higher operating days for the year ended December 31, 2018 compared to the same period of 2017. The decline in average dayrates was primarily related to the Noble Bully II, which remained idle during the current period but operated for a portion of the prior period. The increase in operating days was primarily related to the reactivation of the Noble Tom Madden in the fourth quarter of 2018, offset by the stacking of the Noble Bully I in the second quarter of 2017.
The $76.5 million revenue decline in our jackup fleet is primarily attributable to a $91.5 million decline in revenues due to certain of our jackup rigs not operating for the year ended December 31, 2018, which was partially offset by a $15.0 million increase in revenues associated with favorable dayrate changes across the jackup fleet. The decrease in operating days during the current period was the result of the retirement and subsequent sale of the Noble David Tinsley, the retirement of the Noble Alan Hay and a decrease in operating days for the Noble Mick O'Brien and for the Noble Sam Hartley, which was stacked in early 2018 and reactivated in late 2018. The $27.9 million decline in semisubmersible revenues was primarily due to a decrease in both dayrate and operating days on the Noble Paul Romano, which was warm stacked in early 2018.
Operating Costs and Expenses. Contract drilling services costs decreased $13.0 million for the year ended December 31, 2018 as compared to the same period of 2017. Rigs that were operating in the prior period, but were idle or stacked most of the current period contributed $20.5 million to the decrease in operating costs, and rigs that operated in the prior period but were subsequently retired contributed $18.7 million to the decrease in operating costs. In addition to these rig costs declines, operations support costs decreased $9.2 million for the year ended December 31, 2018, of which $7.6 million related to reduction of employee-related expenses. These decreases were offset by $64.1 million of cost increases as certain rigs prepared and returned to operations and experienced higher operating days in the current period. Operating costs increases were recognized across all costs categories, but were primarily attributable to crew-related expenses ($48.4 million) and repairs, maintenance, and other rig-related costs ($15.7 million). Contract Drilling Services costs in 2017 included non-recurring charges of $28.7 million related to damages sustained by two rigs during Hurricane Harvey in the U.S. Gulf of Mexico region along with a charge related to the write-off an uncollectible receivable held by a Paragon Offshore entity in Mexico that is expected to be liquidated.
Depreciation and amortization decreased $57.5 million for the year ended December 31, 2018 as compared to the same period of 2017. The decline was due to the effect of rig impairments recorded during the second quarter of 2018 and the fourth quarter of 2017.
Loss on Impairments. We recorded a loss on impairment of $802.1 million for the year ended December 31, 2018 as compared to a loss on impairment of $121.6 million for the same period of 2017. We evaluate our property and equipment for impairment whenever there are changes

34



in facts which suggest that the value of the asset is not recoverable. In connection with the preparation of our financial statements for the second quarter of 2018 and the year ended December 31, 2018, we conducted a review of our fleet. The review included an assessment of certain assumptions, including future marketability of each unit in light of its current technical specifications. Based upon our impairment analysis, we impaired the carrying values to estimated fair values for the Noble Bully I, Noble Dave Beard, Noble Gene House, Noble Joe Beall, Noble Paul Romano, and certain capital spare equipment. For additional information, see Part II, Item 8, “Financial Statements and Supplementary Data, Note 6— Loss on Impairment.”
Other Income and Expenses
General and Administrative Expenses. General and administrative expenses increased $1.6 million during the year ended December 31, 2018 as compared to the same period of 2017, primarily due to higher employee-related costs.
Interest Expense. Interest expense increased $5.6 million during the year ended December 31, 2018 as compared to the same period of 2017. This increase was primarily due to the issuance of our Senior Notes due 2026 (the “2026 Notes”) in January 2018, an increase in interest rates on certain of our senior notes due to the downgrading of our credit rating, the entry into the 2017 Credit Facility (as defined herein) on December 21, 2017, and the entry into the seller-financed secured loan for the purchase of the Noble Johnny Whitstine. These increases were partially offset by the retirement of a portion of various tranches of our senior notes as a result of tender offers and open market repurchases throughout 2018, the maturity of our Senior Notes due 2018 (the “2018 Notes”) and the redemption of our remaining Senior Notes due 2019 (the “2019 Notes”). For additional information, see Part II, Item 8, “Financial Statements and Supplementary Data, Note 7— Debt.”
Income Tax Provision. Our income tax provision decreased by $149.3 million for the year ended December 31, 2018 as compared to the same period of 2017. The decrease was primarily due to prior period discrete tax items of $151.2 million related to tax restructuring and the impact of the Act and to various tax benefits in the current period including the tax impact on asset impairments of $35.6 million, U.S. return-to-provision adjustment of $24.9 million, UK return-to-provision adjustment of $9.1 million and a U.S. disallowed interest carryover of $51.4 million. These decreases were partially offset by an $84.2 million increase in tax expense in the current period attributable to a higher pre-tax loss and a lower worldwide effective tax rate as compared to the prior period. The increase in the current period pre-tax loss generated a $19.6 million tax benefit and the lower current period worldwide effective tax rate reduced the tax benefit by $103.7 million. The decrease in the worldwide effective tax rate in the current period is primarily a result of the geographic mix of income and sources of revenue.
2017 Compared to 2016
Net loss from continuing operations attributable to Noble-UK for the year ended December 31, 2017 was $515.0 million, or $2.10 per diluted share, on operating revenues of $1.2 billion, compared to a net loss from continuing operations for the year ended December 31, 2016 of $929.6 million, or $3.82 per diluted share, on operating revenues of $2.3 billion.
As a result of Noble-UK conducting all of its business through Noble-Cayman and its subsidiaries, the financial position and results of operations for Noble-Cayman, and the reasons for material changes in the amount of revenue and expense items between December 31, 2017 and December 31, 2016, would be the same as the information presented below regarding Noble-UK in all material respects, with the exception of operating income (loss). During the years ended December 31, 2017 and 2016, Noble-Cayman’s operating loss was $37.9 million and $29.7 million lower, respectively, than that of Noble-UK. The operating loss difference is primarily a result of administration and other costs directly attributable to Noble-UK for operations support and stewardship-related services.
Key Operating Metrics
Operating results for our contract drilling services segment are dependent on three primary metrics: operating days, dayrates and operating costs. We also track rig utilization, which is a function of operating days and the number of rigs in our fleet. For more information on operating costs, see “—Contract Drilling Services” below. The following table presents the average rig utilization, operating days and average dayrates for our rig fleet for the years ended December 31, 2017 and 2016:
 
 
Average Rig Utilization (1)
 
Operating Days (2)
 
 
 
Average Dayrates
 
 
 
 
December 31,
 
December 31,
 
 
 
December 31,
 
 
 
 
2017
 
2016
 
2017
 
2016
 
% Change
 
2017
 
2016
 
% Change
Jackups
 
85
%
 
83
%
 
4,367

 
3,966

 
10
 %
 
$
126,109

 
$
126,279

(3) 
 %
Semisubmersibles
 
17
%
 
22
%
 
365

 
649

 
(44
)%
 
155,919

 
256,122

 
(39
)%
Drillships
 
59
%
 
82
%
 
1,716

 
2,408

 
(29
)%
 
349,244

(4) 
654,074

(4) 
(47
)%
Total
 
63
%
 
66
%
 
6,448

 
7,023

 
(8
)%
 
$
187,181

 
$
319,256

 
(41
)%
 

35



(1) 
We define utilization for a specific period as the total number of days our rigs are operating under contract, divided by the product of the total number of our rigs, including cold stacked rigs, and the number of calendar days in such period. Information reflects our policy of reporting on the basis of the number of available rigs in our fleet, excluding newbuild rigs under construction.
(2) 
Information reflects the number of days that our rigs were operating under contract.
(3) 
Average dayrate for the year ended December 31, 2016 includes $16.4 million in contract drilling services revenue related to the Noble Tom Prosser contract cancellation with Quadrant Energy Australia Limited. The additional contract drilling services revenue in 2016 had a positive impact on the jackups’ average dayrates.
(4) 
Average dayrates include a $14.4 million loss in the year ended December 31, 2017 and a $14.4 million gain in the year ended December 31, 2016, in respect of the termination date valuation of certain contingent payments for the Noble Sam Croft and Noble Tom Madden related to the FCX Settlement. The loss in 2017 had a negative impact and the gain in 2016 had a positive impact on the drillships’ average dayrates.
Contract Drilling Services
The following table presents the operating results for our contract drilling services segment for the years ended December 31, 2017 and 2016 (dollars in thousands):
 
 
Year Ended December 31,
 
Change
 
 
2017
 
2016
 
$
 
%
Operating revenues:
 
 
 
 
 
 
 
 
Contract drilling services
 
$
1,207,026

 
$
2,242,200

 
$
(1,035,174
)
 
(46
)%
Reimbursables and other (1)
 
29,889

 
59,865

 
(29,976
)
 
(50
)%
 
 
$
1,236,915

 
$
2,302,065

 
$
(1,065,150
)
 
(46
)%
Operating costs and expenses:
 
 
 
 
 
 
 
 
Contract drilling services
 
$
642,937

 
$
877,689

 
$
(234,752
)
 
(27
)%
Reimbursables (1)
 
18,435

 
45,608

 
(27,173
)
 
(60
)%
Depreciation and amortization
 
524,752

 
587,999

 
(63,247
)
 
(11
)%
General and administrative
 
71,634

 
69,258

 
2,376

 
3
 %
Loss on impairment
 
121,639

 
1,458,749

 
(1,337,110
)
 
(92
)%
 
 
1,379,397

 
3,039,303

 
(1,659,906
)
 
(55
)%
Operating income (loss)
 
$
(142,482
)
 
$
(737,238
)
 
$
594,756

 
(81
)%
(1) 
We record reimbursements from customers for out-of-pocket expenses as operating revenues and the related direct costs as operating expenses. Changes in the amount of these reimbursables generally do not have a material effect on our financial position, results of operations or cash flows.
Operating Revenues. The $1.0 billion decline in contract drilling services revenues for the year ended December 31, 2017 as compared to the same period of 2016 was composed of an $851.6 million decline from lower dayrates and a $183.6 million decline due to fewer operating days. The contract drilling services revenues decline was primarily due to our drillship and semisubmersible fleets, which experienced declines in revenues of $975.7 million and $109.3 million, respectively, and was partially offset by revenue increases in our jackup fleet of $49.8 million.
The $975.7 million revenue decline in our drillship fleet for the year ended December 31, 2017 as compared to the same period of 2016 consists of a $523.1 million decline from lower dayrates and a $452.6 million decline due to fewer operating days. The decline in average dayrates was primarily related to the payment of the $393.0 million FCX Settlement in 2016. Of the decline in revenue attributable to operating days, $281.5 million is related to the Noble Bully I and Noble Bob Douglas operating for all of 2016, but being idle for the majority of 2017. The remainder of the decline in operating days and the decline in average dayrates was attributable to the Noble Tom Madden and Noble Sam Croft, whose contracts were terminated in May 2016.
The $109.3 million revenue decline in our semisubmersible fleet for the year ended December 31, 2017 as compared to the same period of 2016 consists of a $36.6 million decline from lower dayrates and a $72.7 million decline due to fewer operating days. The decline in both average dayrates and operating days as compared to 2016 was attributable to contract completions for the Noble Clyde Boudreaux, Noble Jim Day, Noble Dave Beard, Noble Danny Adkins and Noble Amos Runner, none of which have returned to work since their respective contract completions.
The $49.8 million revenue increase in our jackup fleet is primarily attributable to an increase in operating days on the Noble Mick O'Brien and Noble Regina Allen as well as the startup of the newbuild Noble Lloyd Noble.

36



Operating Costs and Expenses. Contract drilling services costs decreased $234.8 million for the year ended December 31, 2017 as compared to the same period of 2016. Of the decrease, $179.0 million was due to rigs that operated during 2016 being idle during 2017. An additional $113.1 million decrease in cost was due to continuing cost control measures, yielding reductions in labor and training related costs of approximately $53.8 million, operations support costs of $29.7 million, repair and maintenance costs of $28.1 million, and rig mobilization costs of $3.0 million. These cost decreases were partially offset by the startup of the Noble Lloyd Noble, a greater number of operating days for contracted rigs during 2017 and the write-off of a $14.4 million customer receivable during 2017.

Depreciation and amortization decreased $63.2 million for the year ended December 31, 2017 as compared to the same period of 2016. The decline was due to the effect of rig retirements and impairments during 2016, partially offset by the effect of the Noble Lloyd Noble being placed into service during November 2016.
Other Income and Expenses
General and Administrative Expenses. General and administrative expenses increased $2.4 million during the year ended December 31, 2017 as compared to the same period of 2016, primarily due to higher professional fees.
Interest Expense, net of amount capitalized. Interest expense, net of amount capitalized, increased $69.1 million during the year ended December 31, 2017 as compared to the same period of 2016. This increase was primarily due to the interest incurred during 2017 on the senior notes issued in December 2016, the absence of capitalized interest during 2017 and an increase in interest rates on certain of our senior notes due to the downgrading of our credit rating. These increases were partially offset by the retirement of a portion of our Senior Notes due 2020 (the “2020 Notes”), Senior Notes due 2021 (the “2021 Notes”) and Senior Notes due 2022 (the “2022 Notes”) as a result of tender offers in 2016 and the maturity of our Senior Notes due 2017 (the “2017 Notes). For additional information see, Part II, Item 8, “Financial Statements and Supplementary Data, Note 7— Debt.
Income Tax Provision. Our income tax provision increased $151.8 million for the year ended December 31, 2017 as compared to the same period of 2016. The increase was primarily due to a $260.7 million non-cash discrete tax item resulting from a tax restructuring in 2017. The effect of this tax restructuring was to lower current tax expense. This increase was partially offset by the tax effect of the FCX Settlement of $27.2 million in 2016. Excluding the impact of these items, taxes decreased by $86.0 million as a result of lower pre-tax income in 2017, primarily from our geographical mix of pre-tax income.
Liquidity and Capital Resources
Overview
Net cash provided by operating activities was $171.9 million for the year ended December 31, 2018 and $416.7 million for the year ended December 31, 2017. The decrease in net cash provided by operating activities for the year ended December 31, 2018 was primarily attributable to a reduction in operating activity during 2018. We had working capital of $293.6 million and $446.0 million at December 31, 2018 and December 31, 2017, respectively.
Net cash used in investing activities for the year ended December 31, 2018 was $189.4 million as compared to $118.3 million for the year ended December 31, 2017. The variance primarily relates to the purchase of the Noble Johnny Whitstine, the reactivation of the Noble Clyde Boudreaux, Noble Tom Madden, and Noble Sam Croft and various major projects in the current period.
Net cash used in financing activities for the year ended December 31, 2018 was $269.4 million as compared to $361.2 million for the year ended December 31, 2017. During the current period, our primary uses of cash included retirement of a portion of the 2020 Notes, 2021 Notes, 2022 Notes, Senior Notes due 2024 (the “2024 Notes”), Senior Notes due 2040 (the “2040 Notes”), Senior Notes due 2041 (the “2041 Notes”), and Senior Notes due 2042 (the “2042 Notes”) in tender offers and open market purchases, repayment at maturity of the 2018 Notes and redemption of the 2019 Notes, which amounts were partially offset by the issuance of the 2026 Notes.
Our principal source of capital in the current period was cash generated from operating activities coupled with the $750.0 million 2026 Notes offering in January 2018. Cash on hand during the current period was primarily used for the following:
normal recurring operating expenses;
retirement of a portion of various tranches of our senior notes in tender offers, repayment at maturity of the 2018 Notes and redemption of the 2019 Notes; and
capital expenditures.
Our currently anticipated cash flow needs, both in the short-term and long-term, may include the following:
normal recurring operating expenses;
planned and discretionary capital expenditures; and
repayments of debt and interest.

37



We currently expect to fund these cash flow needs with cash generated by our operations, cash on hand, borrowings under our Credit Facilities (as defined herein) and potential issuances of equity or long-term debt. However, to adequately cover our expected cash flow needs, we may require capital in excess of the amount available from these sources, and we may seek additional sources of liquidity and/or delay or cancel certain discretionary capital expenditures or other payments as necessary.
At December 31, 2018, we had a total contract drilling services backlog of approximately $2.4 billion, which includes a commitment of 62.0 percent of available days for 2019. For additional information regarding our backlog, see “—Contract Drilling Services Backlog.”
Capital Expenditures
Capital expenditures totaled $281.3 million, $111.1 million and $659.9 million for the years ended December 31, 2018, 2017 and 2016, respectively. Capital expenditures during 2018 consisted of the following:
$82.7 million for sustaining capital;
$75.6 million in major projects, including reactivations;
$29.2 million in subsea and other related projects; and
$93.8 million to purchase the Noble Johnny Whitstine (inclusive of cash paid and seller financing).
Our total capital expenditure estimate for 2019 is approximately $303.9 million, which is currently anticipated to be spent as follows:
$90.3 million for sustaining capital;
$96.4 million in major projects, including reactivations;
$33.4 million in subsea and other related projects; and
$83.8 million to purchase the Noble Joe Knight (inclusive of cash paid and seller financing).
From time to time we consider possible projects that would require expenditures that are not included in our capital budget, and such unbudgeted expenditures could be significant. In addition, we will continue to evaluate acquisitions of drilling units from time to time. Other factors that could cause actual capital expenditures to materially exceed plan include delays and cost overruns in shipyards (including costs attributable to labor shortages), shortages of equipment, latent damage or deterioration to hull, equipment and machinery in excess of engineering estimates and assumptions, changes in governmental regulations and requirements, possible refurbishment and reactivation of rigs and changes in design criteria or specifications during repair or construction.
Share Capital
The declaration and payment of dividends require the authorization of the Board of Directors of Noble-UK, provided that such dividends on issued share capital may be paid only out of Noble-UK’s “distributable reserves” on its statutory balance sheet in accordance with UK law. Therefore, Noble-UK is not permitted to pay dividends out of share capital, which includes share premium. Noble has not paid dividends since the third quarter of 2016. The payment of future dividends will depend on our results of operations, financial condition, cash requirements, future business prospects, contractual and indenture restrictions and other factors deemed relevant by our Board of Directors.
At our 2018 Annual General Meeting, shareholders approved a proposal to allow our Board of Directors to increase share capital through the issuance of up to 82.2 million ordinary shares (at current nominal value of $0.01 per share). The right of our directors to allot shares will expire at the end of our 2019 Annual General Meeting unless we seek an extension from shareholders at that time. No shares were allotted during the year ended December 31, 2018.
Share Repurchases
Under UK law, the Company is only permitted to purchase its own shares by way of an “off-market purchase” in a plan approved by shareholders. We currently do not have shareholder authority to repurchase shares. During the years ended December 31, 2018, 2017 and 2016, we did not repurchase any of our shares.
Credit Facilities
2015 Credit Facility
At December 31, 2017, we had a five-year $2.4 billion senior unsecured credit facility that matures in January 2020 and is guaranteed by our indirect, wholly-owned subsidiaries, Noble Holding (U.S.) LLC (“NHUS”) and Noble Holding International Limited (“NHIL”) (the “2015 Credit Facility”). At December 31, 2017, the 2015 Credit Facility also provided us with the ability to issue up to $500.0 million in letters of credit.
On December 19, 2017, we entered into the First Amendment and Consent and Successor Agent Agreement (the “Amendment”) amending the 2015 Credit Facility. On January 3, 2018, the Amendment to the 2015 Credit Facility became fully effective. The Amendment caused, among other things, a reduction in the aggregate principal amount of commitments under the 2015 Credit Facility to $300.0 million and the termination of the 2015 Credit Facility's letter of credit sub-facility. The maturity of the 2015 Credit Facility remains January 2020. As a result of the 2015

38



Credit Facility's reduction in the aggregate principal amount of commitments, we recognized a net loss of approximately $2.3 million in the year ended December 31, 2018. At December 31, 2018, we had no borrowings outstanding or letters of credit issued under the 2015 Credit Facility.
2017 Credit Facility
On December 21, 2017, Noble Cayman Limited, a Cayman Islands company and a wholly-owned indirect subsidiary of Noble-Cayman (“NCL”); Noble International Finance Company, a Cayman Islands company and a wholly-owned indirect subsidiary of Noble-Cayman (“NIFCO”); and Noble Holding UK Limited, a company incorporated under the laws of England and Wales and a wholly-owned direct subsidiary of Noble-UK (“NHUK”), as parent guarantor, entered into a new senior unsecured credit agreement (the “2017 Credit Facility” and, together with the 2015 Credit Facility, the “Credit Facilities”). The maximum aggregate amount of commitments under the 2017 Credit Facility is approximately $1.5 billion. Borrowings under the 2017 Credit Facility are subject to certain conditions precedent, including that there be no unused commitments to advance loans under the 2015 Credit Facility. The 2017 Credit Facility will mature in January 2023. Borrowings may be used for working capital and other general corporate purposes. The 2017 Credit Facility provides for a letter of credit sub-facility currently in the amount of $15.0 million, with the ability to increase such amount up to $500.0 million with the approval of the lenders. At December 31, 2018, we had $3.4 million of performance letters of credit outstanding under the 2017 Credit Facility. At December 31, 2018, other than the performance letters of credit, we had no borrowings outstanding under the 2017 Credit Facility.
Both of our Credit Facilities have provisions which vary the applicable interest rates for borrowings based upon our debt ratings. We also pay a facility fee under the 2015 Credit Facility on the full commitments thereunder (used or unused) and a commitment fee under the 2017 Credit Facility on the daily unused amount of the underlying commitments, in each case which varies depending on our credit ratings. At December 31, 2018, the interest rates in effect under our Credit Facilities were the highest permitted interest rates under those agreements.
Debt Issuance
In January 2018, we issued $750.0 million aggregate principal amount of the 2026 Notes through our indirect wholly-owned subsidiary, NHIL. The net proceeds of the offering of approximately $737.4 million, after expenses, were used to retire a portion of our near-term senior notes in a related tender offer.
The indenture for the 2026 Notes contains certain covenants and restrictions, including, among others, restrictions on our subsidiaries’ ability to incur certain additional indebtedness. Additionally, the subsidiary guarantors must own, directly or indirectly, (i) assets comprising at least 85% of the revenue of Noble-Cayman and its subsidiaries on a consolidated basis and (ii) jackups, semisubmersibles, drillships, submersibles or other mobile offshore drilling units of material importance, the combined book value of which comprises at least 85% of the combined book value of all such assets of Noble-Cayman and its subsidiaries on a consolidated basis, in each case, with respect to the most recently completed fiscal year.
Seller Financing of Rig
In September 2018, we purchased the Noble Johnny Whitstine for $93.8 million with a $60.0 million seller-financed secured loan (the “Seller Loan”). The Seller Loan has a term of four years and requires a 5% principal payment at the end of the third year with the remainder of the principal due at the end of the term. The Seller Loan bears a cash interest rate of 4.25% and the equivalent of a 1.25% interest rate paid-in-kind over the four-year term of the Seller Loan. Based on the terms of the Seller Loan, the 1.25% paid-in-kind interest rate is accelerated into the first year, resulting in an overall first year interest rate of 8.91%, of which only 4.25% is payable in cash. Thereafter, the paid-in-kind interest ends and the cash interest rate of 4.25% is payable for the remainder of the term.
The Seller Loan is guaranteed by Noble-Cayman and is secured by a mortgage on the Noble Johnny Whitstine and by the pledge of the shares of the single-purpose entity that owns the rig. The Seller Loan contains debt to total capitalization ratio and minimum liquidity financial covenants substantially similar to the 2017 Credit Facility, and an asset and revenue covenant substantially similar to the 2026 Notes as well as other covenants and provisions customarily found in secured transactions. The Seller Loan requires immediate repayment on the occurrence of certain events, including the termination of the drilling contract entered into at the time of the purchase of the rig.
On February 14, 2019, we exercised our option to purchase a new jackup rig, to be known as the Noble Joe Knight, and we expect to complete the purchase in late February 2019. The purchase of the Noble Joe Knight will be partially funded with cash and a seller loan on terms similar to the Noble Johnny Whitstine.
Senior Notes Interest Rate Adjustments
During 2016 and 2017, we experienced debt rating downgrades by Moody’s Investors Service and S&P Global Ratings, which reduced our debt ratings below investment grade. As a result of these downgrades, we experienced interest rate increases during 2016 and 2017 on the 2018 Notes, our Senior Notes due 2025 (the “2025 Notes”) and our Senior Notes due 2045 (the “2045 Notes”), all of which are subject to provisions that vary the applicable interest rates based on our debt rating. On October 18, 2017, S&P Global Ratings further reduced our debt rating, which

39



increased the interest rates on the 2025 Notes and the 2045 Notes to 7.95% and 8.95%, respectively, effective April 2018. These senior notes have reached the contractually defined maximum interest rate set for each rating agency and no further interest rate increases are possible. The interest rates on these senior notes may be decreased if our debt ratings were to be raised by either rating agency above specified levels. Our other outstanding senior notes do not contain provisions varying applicable interest rates based upon our credit ratings.
Debt Tender Offers, Repayments and Open Market Repurchases
In January 2018, we commenced cash tender offers for the 2018 Notes, 2019 Notes, 2020 Notes, 2021 Notes, 2022 Notes and 2024 Notes. In February 2018, we purchased $754.2 million aggregate principal amount of these senior notes for $750.0 million, plus accrued interest, using the net proceeds of the 2026 Notes issuance and cash on hand. As a result of this transaction, we recognized a net loss of approximately $3.5 million.
In February 2018, we redeemed the remaining principal amount of $61.9 million of the 2019 Notes for approximately $65.3 million, plus accrued interest. As a result of this transaction, we recognized a net loss of approximately $3.5 million.
In March 2018, we repaid the remaining aggregate principal amount of $126.6 million of the 2018 Notes at maturity using cash on hand.
In March 2018, we purchased $9.5 million aggregate principal amount of various tranches of our senior notes for approximately $8.7 million, plus accrued interest, as open market repurchases and recognized a net gain of approximately $0.5 million.
In August 2018, we purchased $0.4 million aggregate principal amount of the 2042 Notes for approximately $0.3 million, plus accrued interest, as open market repurchases and recognized a net gain of approximately $0.1 million.
In October 2018, we purchased $27.4 million aggregate principal amount of various tranches of our senior notes for approximately $20.2 million, plus accrued interest, as open market repurchases and recognized a net gain of approximately $6.9 million.
Covenants
The 2015 Credit Facility is guaranteed by NHUS and NHIL. The 2015 Credit Facility contains a covenant that limits our ratio of debt to total tangible capitalization, as defined in the 2015 Credit Facility, to 0.60 at the end of each fiscal quarter.
The 2017 Credit Facility contains certain financial covenants applicable to NHUK and its subsidiaries, including (i) a covenant restricting debt to total tangible capitalization to not greater than 0.55 at the end of each fiscal quarter, (ii) a minimum Liquidity requirement of $300.0 million, (iii) a covenant that, beginning with the fiscal quarter ending March 31, 2018, the ratio of the Rig Value (as defined in the 2017 Credit Facility) of Marketed Rigs (as defined in the 2017 Credit Facility) to the sum of commitments under the 2017 Credit Facility plus indebtedness for borrowed money of the borrowers and guarantors, in each case, that directly own Marketed Rigs, is not less than 3:00 to 1:00 at the end of each fiscal quarter and (iv) a covenant that, beginning with the fiscal quarter ending March 31, 2018, the ratio of (A) the Rig Value of the Closing Date Rigs (as defined in the 2017 Credit Facility) that are directly wholly owned by the borrowers and guarantors to (B) the Rig Value of the Closing Date Rigs owned by NHUK, subsidiaries of NHUK and certain local content affiliates, is not less than 80% at the end of each fiscal quarter (such covenants described in (iii) and (iv) of this paragraph, the “Guarantor Ratio Covenants”). The 2017 Credit Facility also includes restrictions on borrowings if, after giving effect to any such borrowings and the application of the proceeds thereof, the aggregate amount of Available Cash (as defined in the 2017 Credit Facility) would exceed $200.0 million.
NHUK has guaranteed the obligations of the borrowers under the 2017 Credit Facility. In addition, on January 19, 2018, certain indirect subsidiaries of Noble-UK became guarantors under the 2017 Credit Facility, including Noble Dave Beard Limited, Noble Drilling (TVL) Ltd., Noble Resources Limited, Noble SA Limited, Noble BD LLC, Noble Drilling Holding LLC, Noble Drilling International GmbH, Noble Leasing (Switzerland) GmbH, and Noble Leasing III (Switzerland) GmbH. Certain other subsidiaries of Noble-UK may be required from time to time to guarantee the obligations of the borrowers under the 2017 Credit Facility in order maintain compliance with the Guarantor Ratio Covenants.
The 2017 Credit Facility contains additional restrictive covenants generally applicable to NHUK and its subsidiaries, including restrictions on the incurrence of liens and indebtedness, mergers and other fundamental changes, restricted payments, repurchases and redemptions of indebtedness with maturities outside of the maturity of the 2017 Credit Facility, sale and leaseback transactions and transactions with affiliates.
In addition to the covenants from the Credit Facilities noted above, the covenants from the 2026 Notes described under “—Debt Issuance” above and the covenants from the Seller Loan described under “—Seller Financing of Rig” above, the indentures governing our outstanding senior unsecured notes contain covenants that place restrictions on certain merger and consolidation transactions, unless we are the surviving entity or the other party assumes the obligations under the indenture, and on the ability to sell or transfer all or substantially all of our assets. There are also restrictions on incurring or assuming certain liens and on entering into sale and lease-back transactions.
At December 31, 2018, our debt to total tangible capitalization ratio under our 2017 Credit Facility was approximately 0.48 and we were in compliance with all applicable debt covenants. We continually monitor compliance with the covenants under our Credit Facilities, senior notes and Seller Loan, and expect to remain in compliance throughout 2019.

40



Summary of Contractual Cash Obligations and Commitments
The following table summarizes our contractual cash obligations and commitments (in thousands):
 
 
 
 
Payments Due by Period
 
 
 
 
 
 
For the Years Ending December 31,
 
 
 
 
Total
 
2019
 
2020
 
2021
 
2022
 
2023
 
Thereafter
 
Other
Contractual Cash Obligations
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Debt obligations
 
$
3,934,553

 

 
$
65,890

 
$
96,142

 
$
99,481

 
$

 
$
3,673,040

 
$

Interest payments
 
3,613,160

 
289,752

 
287,497

 
281,905

 
279,083

 
266,831

 
2,208,092

 

Operating leases (2)
 
36,888

 
15,213

 
7,913

 
5,522

 
1,821

 
695

 
5,724

 

Pension plan contributions
 
147,609

 
12,128

 
12,692

 
17,054

 
13,371

 
14,098

 
78,266

 

Tax reserves (1)
 
183,786

 

 

 

 

 

 

 
183,786

Total contractual cash obligations
 
$
7,915,996

 
$
317,093

 
$
373,992

 
$
400,623

 
$
393,756

 
$
281,624

 
$
5,965,122

 
$
183,786

(1) 
Tax reserves are included in “Other” due to the difficulty in making reasonably reliable estimates of the timing of cash settlements to taxing authorities. See Part II, Item 8, “Financial Statements and Supplementary Data, Note 11— Income Taxes.”
(2) 
In February 2019, we amended the lease for our Sugar Land office to extend the lease for an additional ten years and to reduce the rented space. The above table does not include this lease amendment.
At December 31, 2018, we had other commitments that we are contractually obligated to fulfill with cash if the obligations are called. These obligations include letters of credit that guarantee our performance as it relates to our drilling contracts, tax and other obligations in various jurisdictions. These letters of credit obligations are not normally called, as we typically comply with the underlying performance requirement.
The following table summarizes our other commercial commitments at December 31, 2018 (in thousands):
 
 
 

 
Amount of Commitment Expiration Per Period
 
 
Total
 
2019
 
2020
 
2021
 
2022
 
2023
 
Thereafter
Total letters of credit and commercial commitments
 
$
14,655

 
$
9,437

 
$
1,535

 
$

 
$

 
$
8

 
$
3,675

Critical Accounting Policies
We consider the following to be our critical accounting policies and estimates since they are very important to the understanding of our financial condition and results and require our most subjective and complex judgments. We have discussed the development, selection and disclosure of such policies and estimates with the Audit Committee of our Board of Directors. For a discussion of our significant accounting policies, refer to Part II, Item 8, “Financial Statements and Supplementary Data, Note 1— Organization and Significant Accounting Policies.”
We prepare our consolidated financial statements in accordance with accounting principles generally accepted in the U.S. (“GAAP”), which require us to make estimates that affect the reported amounts of assets, liabilities, revenues, expenses and related disclosures of contingent assets and liabilities. These estimates require significant judgments and assumptions. We base our estimates on historical experience and on various other assumptions that we believe are reasonable under the circumstances, the results of which form the basis for making judgments about the carrying amounts of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates.
Principles of Consolidation
The consolidated financial statements include our accounts, those of our wholly-owned subsidiaries and entities in which we hold a controlling financial interest. Our consolidated financial statements include the accounts of two joint ventures, in each of which we own a 50 percent interest. Our ownership interest meets the definition of variable interest under Financial Accounting Standards Board (“FASB”) codification and we have determined that we are the primary beneficiary. Intercompany balances and transactions have been eliminated in consolidation.
The combined carrying amount of the Bully-class drillships at December 31, 2018 and 2017 totaled $0.7 billion and $1.3 billion, respectively. These assets were primarily funded through partner equity contributions. Cash held by the Bully joint ventures totaled approximately $45.2 million at December 31, 2018 as compared to approximately $41.6 million at December 31, 2017.

41



Basis of Presentation-U.K. Companies Act 2006 Section 435 Statement
The accompanying consolidated financial statements have been prepared in accordance with US GAAP, which the Board of Directors considers to be the most meaningful presentation of our results of operations and financial position. The accompanying consolidated financial statements do not constitute statutory accounts required by the UK Companies Act 2006 (“Companies Act”), which will be prepared in accordance with International Financial Reporting Standards, as adopted by the European Union and delivered to the Registrar of Companies in the UK following the annual general meeting of shareholders.
Property and Equipment
Property and equipment is stated at cost, reduced by provisions to recognize economic impairment in value whenever events or changes in circumstances indicate an asset’s carrying value may not be recoverable. At December 31, 2018 and 2017, we had $209.1 million and $83.5 million of construction-in-progress, respectively. Such amounts are included in “Property and equipment, at cost” in the accompanying Consolidated Balance Sheets. Major replacements and improvements are capitalized. When assets are sold, retired or otherwise disposed of, the cost and related accumulated depreciation are eliminated from the accounts and the gain or loss is recognized. Drilling equipment and facilities are depreciated using the straight-line method over their estimated useful lives as of the date placed in service or date of major refurbishment. Estimated useful lives of our drilling equipment range from three to thirty years. Other property and equipment is depreciated using the straight-line method over useful lives ranging from two to forty years.
Interest is capitalized on construction-in-progress using the weighted average cost of debt outstanding during the period of construction. During the years ended December 31, 2018, 2017 and 2016, there was $2.9 million, zero and $22.4 million capitalized interest, respectively.
Scheduled maintenance of equipment is performed based on the number of hours operated in accordance with our preventative maintenance program. Routine repair and maintenance costs are charged to expense as incurred; however, the costs of the overhauls and asset replacement projects that benefit future periods and which typically occur every three to five years are capitalized when incurred and depreciated over an equivalent period. These overhauls and asset replacement projects are included in “Property and equipment, at cost” in the Consolidated Balance Sheets. Such amounts, net of accumulated depreciation, totaled $146.3 million and $149.3 million at December 31, 2018 and 2017, respectively. Depreciation expense from continuing operations related to overhauls and asset replacement totaled $66.9 million, $79.2 million and $86.0 million for the years ended December 31, 2018, 2017 and 2016, respectively.
We evaluate the impairment of property and equipment whenever events or changes in circumstances (including the decision to cold stack, retire or sell a rig) indicate that the carrying amount of an asset may not be recoverable. An impairment loss on our property and equipment may exist when the estimated undiscounted cash flows expected to result from the use of the asset and its eventual disposition are less than its carrying amount. Any impairment loss recognized represents the excess of the asset's carrying value over the estimated fair value. As part of this analysis, we make assumptions and estimates regarding future market conditions. To the extent actual results do not meet our estimated assumptions, for a given rig or piece of equipment, we may take an impairment loss in the future.
During the years ended December 31, 2018, 2017 and 2016, we recognized a non-cash loss on impairment of $802.1 million, $121.6 million, and $1.5 billion, respectively, related to our long-lived assets. See Part II, Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations— Executive Overview,” and Part II, Item 8, “Financial Statements and Supplementary Data, Note 6— Loss on Impairment” for additional information.

Revenue Recognition
The activities that primarily drive the revenue earned in our drilling contracts include (i) providing a drilling rig and the crew and supplies necessary to operate the rig, (ii) mobilizing and demobilizing the rig to and from the drill site, and (iii) performing rig preparation activities and/or modifications required for the contract. Consideration received for performing these activities may consist of dayrate drilling revenue, mobilization and demobilization revenue, contract preparation revenue and reimbursement revenue. We account for these integrated services provided within our drilling contracts as a single performance obligation satisfied over time and comprised of a series of distinct time increments in which we provide drilling services.
Our standard drilling contracts require that we operate the rig at the direction of the customer throughout the contract term (which is the period we estimate to benefit from the corresponding activities and generally ranges from two to 60 months). The activities performed and the level of service provided can vary hour to hour. Our obligation under a standard contract is to provide whatever level of service is required by the operator, or customer, over the term of the contract. We are, therefore, under a stand-ready obligation throughout the entire contract duration. Consideration for our stand-ready obligation corresponds to distinct time increments, though the rate may be variable depending on various factors, and is recognized in the period in which the services are performed. The total transaction price is determined for each individual contract by estimating both fixed and variable consideration expected to be earned over the term of the contract. We have elected to exclude from the transaction

42



price measurement all taxes assessed by a governmental authority. See further discussion regarding the allocation of the transaction price to the remaining performance obligations below.
The amount estimated for variable consideration may be subject to interrupted or restricted rates and is only included in the transaction price to the extent that it is probable that a significant reversal of previously recognized revenue will not occur throughout the term of the contract (“constrained revenue”). When determining if variable consideration should be constrained, management considers whether there are factors outside the Company’s control that could result in a significant reversal of revenue as well as the likelihood and magnitude of a potential reversal of revenue. These estimates are re-assessed each reporting period as required.
Dayrate Drilling Revenue. Our drilling contracts generally provide for payment on a dayrate basis, with higher rates for periods when the drilling unit is operating and lower rates or zero rates for periods when drilling operations are interrupted or restricted. The dayrate invoices billed to the customer are typically determined based on the varying rates applicable to the specific activities performed on an hourly basis. Such dayrate consideration is allocated to the distinct hourly increment it relates to within the contract term, and therefore, recognized in line with the contractual rate billed for the services provided for any given hour.
Mobilization/Demobilization Revenue. We may receive fees (on either a fixed lump-sum or variable dayrate basis) for the mobilization and demobilization of our rigs. These activities are not considered to be distinct within the context of the contract and, therefore, the associated revenue is allocated to the overall performance obligation and the associated pre-operating costs are deferred. We record a contract liability for mobilization fees received and a deferred asset for costs. Both revenue and pre-operating costs are recognized ratably over the initial term of the related drilling contract.
In most contracts, there is uncertainty as to the amount of expected demobilization revenue due to contractual provisions that stipulate that certain conditions must be present at contract completion for such revenue to be received and as to the amount thereof, if any. For example, contractual provisions may require that a rig demobilize a certain distance before the demobilization revenue is payable or the amount may vary dependent upon whether or not the rig has additional contracted work within a certain distance from the wellsite. Therefore, the estimate for such revenue may be constrained, as described earlier, depending on the facts and circumstances pertaining to the specific contract. We assess the likelihood of receiving such revenue based on past experience and knowledge of the market conditions. In cases where demobilization revenue is expected to be received upon contract completion, it is estimated as part of the overall transaction price at contract inception and recognized in earnings ratably over the initial term of the contract with an offset to an accretive contract asset.
Contract Preparation Revenue. Some of our drilling contracts require downtime before the start of the contract to prepare the rig to meet customer requirements. At times, we may be compensated by the customer for such work (on either a fixed lump-sum or variable dayrate basis). These activities are not considered to be distinct within the context of the contract and, therefore, the related revenue is allocated to the overall performance obligation and recognized ratably over the initial term of the related drilling contract. We record a contract liability for contract preparation fees received, which is amortized ratably to contract drilling revenue over the initial term of the related drilling contract.
Bonuses, Penalties and Other Variable Consideration. We may receive bonus increases to revenue or penalty decreases to revenue. Based on historical data and ongoing communication with the operator/customer, we are able to reasonably estimate this variable consideration. We will record such estimated variable consideration and re-measure our estimates at each reporting date. For revenue estimated, but not received, we will record to “Prepaid expenses and other current assets” on our Consolidated Balance Sheets.
Capital Modification Revenue. From time to time, we may receive fees from our customers for capital improvements to our rigs to meet contractual requirements (on either a fixed lump-sum or variable dayrate basis). Such revenue is allocated to the overall performance obligation and recognized ratably over the initial term of the related drilling contract as these activities are integral to our drilling activities and are not considered to be a stand-alone service provided to the customer within the context of our contracts. We record a contract liability for such fees and recognize them ratably as contract drilling revenue over the initial term of the related drilling contract.
Revenues Related to Reimbursable Expenses. We generally receive reimbursements from our customers for the purchase of supplies, equipment, personnel services and other services provided at their request in accordance with a drilling contract or other agreement. Such reimbursable revenue is variable and subject to uncertainty, as the amounts received and timing thereof is highly dependent on factors outside of our influence. Accordingly, reimbursable revenue is constrained revenue and not included in the total transaction price until the uncertainty is resolved, which typically occurs when the related costs are incurred on behalf of a customer. We are generally considered a principal in such transactions and record the associated revenue at the gross amount billed to the customer as “Reimbursables and other” in our Consolidated Statements of Operations. Such amounts are recognized ratably over the period within the contract term during which the corresponding goods and services are to be consumed.
Deferred revenues from drilling contracts totaled $80.8 million and $114.3 million at December 31, 2018 and 2017, respectively. Such amounts are included in either “Other current liabilities” or “Other liabilities” in the accompanying Consolidated Balance Sheets, based upon our expected time of recognition. Related expenses deferred under drilling contracts totaled $47.7 million at December 31, 2018 as compared to $55.7

43



million at December 31, 2017 and are included in either “Prepaid expenses and other current assets,” “Other assets,” or “Property and equipment, net” in the accompanying Consolidated Balance Sheets, based upon our expected time of recognition.
We record reimbursements from customers for “out-of-pocket” expenses as revenues and the related direct cost as operating expenses.
Income Taxes
We operate in a number of countries throughout the world and our tax returns filed in those jurisdictions are subject to review and examination by tax authorities within those jurisdictions. We recognize uncertain tax positions that we believe have a greater than 50 percent likelihood of being sustained. We cannot predict or provide assurance as to the ultimate outcome of any existing or future assessments. Our net deferred tax asset balance at year-end reflects the application of our income tax accounting policies and is based on management’s estimates, judgments and assumptions regarding realizability. If it is more likely than not that a portion of the deferred tax assets will not be realized in a future period, the deferred tax assets will be reduced by a valuation allowance based on management’s estimates. The Company has adopted an accounting policy to look through the outside basis of partnerships and all other flow-through entities and exclude these from the computation of deferred taxes.
During 2014, the Internal Revenue Service (“IRS”) began its examination of our tax reporting in the U.S. for the taxable years ended December 31, 2010 and 2011. The IRS examination team has completed its examination of our 2010 and 2011 U.S. tax returns and proposed adjustments and deficiencies with respect to certain items that were reported by us for the 2010 and 2011 tax years. On December 19, 2016, we received the Revenue Agent Report from the IRS. We believe that we have accurately reported all amounts in our tax returns, and have submitted administrative protests with the IRS Office of Appeals contesting the examination team’s proposed adjustments. We intend to vigorously defend our reported positions, and believe the ultimate resolution of the adjustments proposed by the IRS examination team will not have a material adverse effect on our consolidated financial statements. During the third quarter of 2017, the IRS initiated its examination of our 2012, 2013, 2014 and 2015 tax returns.
Audit claims of approximately $50.7 million attributable to income and other business taxes were assessed against Noble entities in Mexico related to tax years 2005 and 2007. We intend to vigorously defend our reported positions, and believe the ultimate resolution of the audit claims will not have a material adverse effect on our consolidated financial statements.
On December 22, 2017, the President of the United States signed the into law legislation informally known as the Tax Cuts and Jobs Act (the “Act”). The Act represents major tax reform legislation that, among other provisions, reduces the U.S. corporate tax rate. The Company recognized the income tax effects of the Act in its 2017 financial statements, including $109.0 million of tax benefit related to the write-down of our net deferred tax liabilities, in accordance with Accounting Standards Codification (“ASC”) Topic 740, Income Taxes, in the reporting period in which the Act was enacted. During the fourth quarter of 2017, the Act resulted in the write-down of our U.S. net deferred tax liabilities. In accordance with the guidance issued in Staff Accounting Bulletin No. 118, during the third quarter of 2018, we finalized our provisional amounts recorded as we completed our technical analysis, computations and tax law interpretations and filed our 2017 U.S. tax return. As a result, we recognized an additional tax benefit of $24.9 million.
The Act introduces a new anti-deferral provision, which subjects a U.S. parent shareholder to current tax on certain income referred to as Global Intangible Low-Taxed Income, of its foreign subsidiaries. The Company has adopted a policy to treat tax due on future U.S. inclusions in taxable income as period costs when incurred.
Insurance Reserves
We maintain various levels of self-insured retention for certain losses including property damage, loss of hire, employment practices liability, employers’ liability and general liability, among others. We accrue for property damage and loss of hire charges on a per event basis.
Employment practices liability claims are accrued based on actual claims during the year. Maritime employer’s liability claims are generally estimated using actuarial determinations. General liability claims are estimated by our internal claims department by evaluating the facts and circumstances of each claim (including incurred but not reported claims) and making estimates based upon historical experience with similar claims. At December 31, 2018 and 2017, loss reserves for personal injury and protection claims totaled $22.4 million and $22.0 million, respectively, and such amounts are included in “Other current liabilities” in the accompanying Consolidated Balance Sheets.
Certain Significant Estimates and Contingent Liabilities
The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amount of revenues and expenses during the reporting period. Certain accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. We evaluate our estimates and assumptions on a regular basis. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about carrying

44



values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates and assumptions used in preparation of our consolidated financial statements. We follow FASB standards regarding contingent liabilities, which are discussed in Part II, Item 8, “Financial Statements and Supplementary Data, Note 15— Commitments and Contingencies.”
Off-Balance Sheet Arrangements
We have no off-balance sheet arrangements as that term is defined in Item 303(a)(4)(ii) of Regulation S-K.
New Accounting Pronouncements
See Part II, Item 8, “Financial Statements and Supplementary Data, Note 1— Organization and Significant Accounting Policies” for a description of the recent accounting pronouncements.
Item 7A. Quantitative and Qualitative Disclosures about Market Risk.
Market risk is the potential for loss due to a change in the value of a financial instrument as a result of fluctuations in interest rates, currency exchange rates or equity prices, as further described below.
Interest Rate Risk
We are subject to market risk exposure related to changes in interest rates on borrowings under the Credit Facilities. Interest on borrowings under our Credit Facilities is at an agreed upon percentage point spread over LIBOR, or a base rate stated in the agreements. At December 31, 2018, we had no borrowings outstanding or letters of credit issued under the 2015 Credit Facility. At December 31, 2018, we had $3.4 million of performance letters of credit outstanding under the 2017 Credit Facility. At December 31, 2018, other than the performance letters of credit, we had no borrowings outstanding under the 2017 Credit Facility.
During 2016 and 2017, we experienced debt rating downgrades by Moody’s Investors Service and S&P Global Ratings, which reduced our debt ratings below investment grade. As a result of these downgrades, we experienced interest rate increases during 2016 and 2017 on our Senior Notes due 2018, our Senior Notes due 2025 (the “2025 Notes”) and our Senior Notes due 2045 (the “2045 Notes”), all of which are subject to provisions that vary the applicable interest rates based on our debt rating. On October 18, 2017, S&P Global Ratings further reduced our debt rating, which increased the interest rates on the 2025 Notes and the 2045 Notes to 7.95% and 8.95%, respectively, effective April 2018. These senior notes have reached the contractually defined maximum interest rate set for each rating agency and no further interest rate increases are possible. The interest rates on these senior notes may be decreased if our debt ratings were to be raised by either rating agency above specified levels. Our other outstanding senior notes do not contain provisions varying applicable interest rates based upon our credit ratings.
We maintain certain debt instruments at a fixed rate whose fair value will fluctuate based on changes in market expectations for interest rates and perceptions of our credit risk. The fair value of our total debt was $2.9 billion and $3.4 billion at December 31, 2018 and December 31, 2017, respectively. The decrease in the fair value of debt relates to a reduction in total principal amount outstanding due to our debt repayments during 2018, partially offset by our debt issuance and changes in market expectations for interest rates and perceptions of our credit risk.
Foreign Currency Risk
Although we are a UK company, we define foreign currency as any non-U.S. denominated currency. Our functional currency is the U.S. Dollar. However, outside the United States, a portion of our expenses are incurred in local currencies. Therefore, when the U.S. Dollar weakens (strengthens) in relation to the currencies of the countries in which we operate, our expenses reported in U.S. Dollars will increase (decrease).
We are exposed to risks on future cash flows to the extent that local currency expenses exceed revenues denominated in local currency that are other than the functional currency. To help manage this potential risk, we periodically enter into derivative instruments to manage our exposure to fluctuations in currency exchange rates, and we may conduct hedging activities in future periods to mitigate such exposure. These contracts are primarily accounted for as cash flow hedges, with the effective portion of changes in the fair value of the hedge recorded on the Consolidated Balance Sheets and in “Accumulated other comprehensive income (loss)” (“AOCI”). Amounts recorded in AOCI are reclassified into earnings in the same period or periods that the hedged item is recognized in earnings. The ineffective portion of changes in the fair value of the hedged item is recorded directly to earnings. We have documented policies and procedures to monitor and control the use of derivative instruments. We do not engage in derivative transactions for speculative or trading purposes, nor are we a party to leveraged derivatives.
Several of our regional shorebases have a significant amount of their cash operating expenses payable in local currencies. To limit the potential risk of currency fluctuations, we periodically enter into forward contracts, which have historically settled monthly in the operations’ respective local currencies. All of these contracts had a maturity of less than 12 months. There were no foreign currency forward contracts outstanding or entered into during the year ended December 31, 2018.

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Market Risk
We have a U.S. noncontributory defined benefit pension plan that covers certain salaried employees and a U.S. noncontributory defined benefit pension plan that covers certain hourly employees, whose initial date of employment is prior to August 1, 2004 (collectively referred to as our “qualified U.S. plans”). These plans are governed by the Noble Drilling Employees’ Retirement Trust. The benefits from these plans are based primarily on years of service and, for the salaried plan, employees’ compensation near retirement. These plans are designed to qualify under the Employee Retirement Income Security Act of 1974 (“ERISA”), and our funding policy is consistent with funding requirements of ERISA and other applicable laws and regulations. We make cash contributions, or utilize credits available to us, for the qualified U.S. plans when required. The benefit amount that can be covered by the qualified U.S. plans is limited under ERISA and the Internal Revenue Code of 1986. Therefore, we maintain an unfunded, nonqualified excess benefit plan designed to maintain benefits for specified employees at the formula level in the qualified salary U.S. plan. We refer to the qualified U.S. plans and the excess benefit plan collectively as the “U.S. plans.”
In addition to the U.S. plans, Noble Drilling (Land Support) Limited, an indirect, wholly-owned subsidiary of Noble-UK, maintains a pension plan that covers all of its salaried, non-union employees, whose most recent date of employment is prior to April 1, 2014 (referred to as our “non-U.S. plan”). Benefits are based on credited service and employees’ compensation, as defined by the non-U.S. plan.
Changes in market asset values related to the pension plans noted above could have a material impact upon our Consolidated Statements of Comprehensive Income (Loss) and could result in material cash expenditures in future periods.


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Item 8. Financial Statements and Supplementary Data.
The following financial statements are filed in this Item 8: 
 
 
Page
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 


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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and
Shareholders of Noble Corporation plc

Opinions on the Financial Statements and Internal Control over Financial Reporting

We have audited the accompanying consolidated balance sheets of Noble Corporation plc and its subsidiaries (the “Company”) as of December 31, 2018 and 2017, and the related consolidated statements of operations, comprehensive income (loss), cash flows, and equity for each of the three years in the period ended December 31, 2018, including the related notes (collectively referred to as the “consolidated financial statements”). We also have audited the Company's internal control over financial reporting as of December 31, 2018, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2018 and 2017 and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2018 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2018, based on criteria established in Internal Control - Integrated Framework (2013) issued by the COSO.

Basis for Opinions

The Company's management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in Management's Annual Report on Internal Control over Financial Reporting as appearing under Item 9A. Our responsibility is to express opinions on the Company’s consolidated financial statements and on the Company's internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.

Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

Definition and Limitations of Internal Control over Financial Reporting

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


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


 
/s/ PricewaterhouseCoopers LLP
 
Houston, Texas
February 21, 2019

We have served as the Company’s auditor since 1994.  


49




NOBLE CORPORATION PLC AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Unless otherwise indicated, dollar amounts in tables are in thousands, except per share data)

 
 
December 31,
2018
 
December 31,
2017
ASSETS
Current assets
 
 
 
 
Cash and cash equivalents
 
$
375,232

 
$
662,829

Accounts receivable, net
 
200,722

 
204,696

Taxes receivable
 
20,498

 
105,345

Prepaid expenses and other current assets
 
62,604

 
66,105

Total current assets
 
659,056

 
1,038,975

Property and equipment, at cost
 
10,956,412

 
12,034,331

Accumulated depreciation
 
(2,475,694
)
 
(2,545,091
)
Property and equipment, net
 
8,480,718

 
9,489,240

Other assets
 
125,149

 
266,444

Total assets
 
$
9,264,923

 
$
10,794,659

LIABILITIES AND EQUITY
Current liabilities
 
 
 
 
Current maturities of long-term debt
 
$

 
$
249,843

Accounts payable
 
125,557

 
84,032

Accrued payroll and related costs
 
50,284

 
54,904

Taxes payable
 
29,386

 
34,391

Interest payable
 
100,100

 
98,189

Other current liabilities