Document


UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
_____________________________________________________________________________________
FORM 10-K
_____________________________________________________________________________________
x
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2016
¨
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)
Devonshire House, 1 Mayfair Place, London, England, W1J 8AJ
(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  x   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  x
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months, and (2) has been subject to such filing requirements for the past 90 days.    Yes  x   No  ¨
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months.    Yes  x    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.   x
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
Noble Corporation plc:
 
Large accelerated filer  x
 
Accelerated filer ¨
 
Non-accelerated filer  ¨
 
Smaller reporting company  ¨
Noble Corporation:
 
Large accelerated filer  ¨
 
Accelerated filer  ¨
 
Non-accelerated filer  x
 
Smaller reporting company ¨ 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes  ¨    No   x
As of June 30, 2016, the aggregate market value of the registered shares of Noble Corporation plc held by non-affiliates of the registrant was $2.0 billion based on the closing sale price as reported on the New York Stock Exchange.
Number of shares outstanding and trading at February 15, 2017: Noble Corporation plc – 244,676,954
Number of shares outstanding: Noble Corporation – 261,245,693

DOCUMENTS INCORPORATED BY REFERENCE
The proxy statement for the 2017 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) of Form 10-K and is therefore filing this Form 10-K with the reduced disclosure format contemplated by paragraphs (a) and (c) of General Instruction I(2) of Form 10-K.




TABLE OF CONTENTS
 
 
 
 
 
PAGE
PART I
 
 
 
 
Item 1.
 
 
Item 1A.
 
 
Item 1B.
 
 
Item 2.
 
 
Item 3.
 
 
Item 4.
 
 
 
 
 
 
 
PART II
 
 
 
 
Item 5.
 
 
Item 6.
 
 
Item 7.
 
 
Item 7A.
 
 
Item 8.
 
 
Item 9.
 
 
Item 9A.
 
 
Item 9B.
 
 
 
 
 
 
 
PART III
 
 
 
 
Item 10.
 
 
Item 11.
 
 
Item 12.
 
 
Item 13.
 
 
Item 14.
 
 
 
 
 
 
 
PART IV
 
 
 
 
Item 15.
 
 
Item 16.
 
 
 
 
 
 
 
 
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 after November 20, 2013 and to Noble Corporation, a Swiss corporation (“Noble-Swiss”), and its consolidated subsidiaries for periods through November 20, 2013. Noble-UK became a successor registrant to Noble-Swiss under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), pursuant to Rule 12g-3 of the Exchange Act as a result of the consummation of the Transaction described in Part I, Item 1 of this Annual Report on Form 10-K.




PART I
Item 1.
Business.
General
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 perform contract drilling services 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 28 drilling rigs consisted of 14 jackups, eight drillships and six semisubmersibles.
For additional information on the specifications of our fleet, see Part I, Item 2, “Properties—Drilling Fleet.” At December 31, 2016, our fleet was located in the United States, the North Sea, South Africa, the Middle East and Asia. Noble and its predecessors have been engaged in the contract drilling of oil and gas wells since 1921.
Spin-off of Paragon Offshore plc (“Paragon Offshore”)
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, to the holders of Noble’s ordinary shares. Our shareholders received one share of Paragon Offshore for every three shares of Noble owned as of July 23, 2014, the record date for the distribution. Through the Spin-off, we disposed of most of our standard specification drilling units and related assets, liabilities and business. Prior to the Spin-off, Paragon Offshore issued approximately $1.7 billion of long-term debt. We used the proceeds from this debt to repay certain amounts outstanding under our commercial paper program. 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 our current relationship with Paragon Offshore, see Part II, Item 8, “Financial Statements and Supplementary Data, Note 2Spin-off of Paragon Offshore plc ("Paragon Offshore")” and Part II, Item 8, “Financial Statements and Supplementary Data, Note 17Commitments and Contingencies.”
Consummation of Merger and Redomiciliation
On November 20, 2013, pursuant to the Merger Agreement dated as of June 30, 2013 between Noble Corporation, a Swiss corporation (“Noble-Swiss”), and Noble-UK, Noble-Swiss merged with and into Noble-UK, with Noble-UK as the surviving company (the “Transaction”). In the Transaction, all of the outstanding ordinary shares of Noble-Swiss were cancelled, and Noble-UK issued, through an exchange agent, one ordinary share of Noble-UK in exchange for each ordinary share of Noble-Swiss. The Transaction effectively changed the place of incorporation of our publicly traded parent holding company from Switzerland to the United Kingdom.
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 of its business through Noble-Cayman and its subsidiaries.
Business Strategy
Our goal is to be the preferred offshore drilling contractor for the oil and gas industry based upon the following core principles:
operate in a manner that provides a safe working environment for our employees while protecting the environment and our assets;
provide an attractive investment vehicle; and
deliver superior customer service through a diverse and technically advanced fleet operated by proficient crews.
Our business strategy focuses on a balanced fleet of both deepwater and high-specification jackup assets and the deployment of our drilling rigs in important oil and gas basins around the world.
Over the past five years, we have expanded our drilling and fleet through our newbuild program. We took delivery of our remaining newbuild, the heavy-duty, harsh environment jackup, Noble Lloyd Noble, in July 2016. The Noble Lloyd Noble commenced operations in November 2016 under a four-year contract in the North Sea. Although we plan to focus on capital preservation and liquidity based on current market conditions, we also continue to evaluate opportunities to enhance our fleet, particularly focusing on higher specification rigs, to execute the increasingly complex drilling programs required of our customers.

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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. In recent years, there has been a significant increase in the number of jackups and ultra-deepwater drilling units. Brent crude has declined from approximately $112 per barrel on June 30, 2014 to as low as approximately $30 per barrel in January 2016, before improving to $56 per barrel on February 15, 2017. As a result, our customers have greatly reduced their exploration and development spending and the number of rigs they have under contract. This combination of increased supply of drilling rigs and reduced demand for such rigs has resulted in falling dayrates and significantly reduced opportunities to re-contract our rigs upon expiry of existing contracts.
Drilling Contracts
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 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, although in the current depressed market, we may not recover some or all of these costs. 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.
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 “Management’s Discussion and Analysis of Financial Condition and Results of Operations–Contract Drilling Services Backlog.”
Offshore Drilling Operations
Contract Drilling Services
We conduct offshore contract drilling operations, which accounted for over 99 percent of our operating revenues for the years ended December 31, 2016, 2015 and 2014. During the three years ended December 31, 2016, we principally conducted our contract drilling operations in the United States, the North Sea, the Middle East, Asia, Australia, and Brazil. Revenues from Royal Dutch Shell plc (“Shell”) and its affiliates accounted for approximately 38 percent, 49 percent and 55 percent of our consolidated operating revenues in 2016, 2015 and 2014, respectively. Revenues from Freeport-McMoRan Inc. (“Freeport”) accounted for approximately 25 percent and 14 percent of our consolidated operating revenues in 2016 and 2015, respectively. Freeport did not account for more than 10 percent of our consolidated operating revenues in 2014. No other customer accounted for more than 10 percent of our consolidated operating revenues in 2016, 2015 or 2014.
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 million in “Contract drilling

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services revenue” associated with the FCX Settlement. Our primary customers would have been Shell, Anadarko, and Freeport, accounting for approximately 45 percent, 11 percent, and 9 percent, respectively, of our consolidated operation revenues, excluding the $393 million of revenue attributable to the FCX Settlement. See Part II, Item 8, “Financial Statements and Supplementary Data, Note 3 Contract Settlement and Termination Agreement with Freeport-McMoRan Inc." for further information.
Competition
The offshore contract drilling industry is a highly competitive and cyclical business characterized by large capital expenditures and high operating and maintenance costs. We compete with other providers of offshore drilling rigs. Some of our competitors may have access to greater financial resources than we do.
In the provision of contract drilling services, competition involves numerous factors, including price, rig availability and technical specification, experience of the workforce, efficiency, safety performance record, condition and age of equipment, operating integrity, reputation, financial strength, industry standing and client relations although price and technical specification are among the most important factors. We believe that we compete favorably with respect to all of these factors. In addition to having one of the newest fleets in the industry among our peer companies, we follow a policy of keeping our equipment well-maintained and technologically competitive. However, our rigs could be made obsolete by the development of new techniques and equipment, regulations or customer preferences.
We compete on a worldwide basis, but competition may vary by region. Demand for offshore drilling equipment also depends on 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 financial condition of such companies, general global economic conditions, energy demand, political considerations and national oil and gas policy, many of which are beyond our control. In addition, industry-wide shortages of supplies, services, skilled personnel and equipment necessary to conduct our business have historically occurred. While we do not anticipate this being an issue in the current market environment, we cannot assure that any such shortages experienced in the past will not happen again in the future.
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. We are also subject to a plea agreement with the U.S. Department of Justice (“DOJ”) in connection with prior operations in Alaska, and any future environmental incidents could have an impact on the plea agreement or related actions that the DOJ or other regulatory agencies may take against us as a result of such an incident. We have made, and will continue to make, expenditures to comply with environmental requirements. We do not believe that our compliance with such requirements will have a material adverse effect on our results of operations, our competitive position or materially increase our capital expenditures. 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.

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Spills and Releases. The Comprehensive Environmental Response, Compensation, and Liability Act in the U.S. (“CERCLA”), and similar state and foreign laws and regulations, 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. These persons include the “owner” and “operator” of the site where the release occurred, past owners and operators of the site, and companies that disposed or arranged for the disposal of the hazardous substances found at the site. Responsible parties under CERCLA may be liable for the costs of cleaning up hazardous substances that have been released into the environment and for damages to natural resources. In the course of our ordinary operations, we may generate waste that may fall within 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.
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. For example, in July 2016, BOEM and BSEE finalized a rule revising and adding planning and operational requirements for drilling on the U.S. Arctic Outer Continental Shelf. The final rule became effective September 13, 2016. Similarly, in April 2016, BSEE published a final blowout preventer systems and well control rule. This rule focuses on blowout preventer requirements and includes reforms in well design, well control, casing, cementing, real-time well monitoring and subsea containment, among other things. Additionally, in December 2016, President Obama withdrew 115 million acres in the U.S. Arctic Ocean and 3.8 million acres off the U.S. North and Mid-Atlantic coasts from future oil and gas activity under the Outer Continental Shelf Lands Act (“OCSLA”). This withdrawal follows a March 2016 decision by BOEM to not include the Mid- and South Atlantic Program Areas from the proposed Leasing Program from 2017 to 2022. BOEM also released a new Notice to Lessees and Operators in the Outer Continental Shelf in September 2016 that updates offshore bonding requirements. BOEM also recently proposed a rule that would update identification, modeling, measuring, and tracking of air emissions from oil and gas activity in federal waters of the Western and Central Gulf of Mexico and the Arctic Ocean.
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 the Arctic, implementation of safety and environmental management systems, mandatory third party compliance audits, and the promulgation of numerous Notices to Lessees have impacted and may continue to impact our operations. 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 U.S. Gulf of Mexico, as well as regulations relating to the protection of the environment. If the new regulations, policies, operating procedures and possibility of increased legal liability 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 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.
The Oil Pollution Act. The U.S. Oil Pollution Act of 1990 (“OPA”) 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. OPA initially established a liability limit for onshore facilities of $350 million, which was subsequently increased to $633.85 million by a U.S. Coast Guard final rule in November 2015. Liability for offshore facilities was initially limited to all removal costs plus up to $75 million in other damages; however, BOEM increased this liability limit to $133.65 million in December 2014. These liability limits may not apply if a spill is caused by a party’s gross negligence or willful misconduct, if the spill resulted from violation of a federal safety, construction or operating regulation, or if a party fails to report a spill or to cooperate fully in a clean-up.
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. However, these wastes may be regulated by the United States Environmental Protection Agency (“EPA”) or state agencies as solid waste. In addition, ordinary industrial wastes, such as paint wastes, waste solvents, laboratory wastes, and waste compressor oils may be regulated under RCRA as hazardous waste. 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 include limits 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. The EPA is responsible for regulating air emissions on the Outer Continental Shelf apart from the Western and Central Gulf of Mexico and the Arctic Ocean, which are regulated by BOEM under OCSLA. In April 2016, BOEM proposed a rule that would impose new requirements for the identification, modeling, measuring, and tracking of air emissions from oil and gas activities in these regions. The proposed rule is aimed at updating BOEM’s air quality regulations to be more consistent with EPA’s current regulation of the national ambient air quality standards (“NAAQS”). 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 EPA regulates the permitting of GHG emissions from stationary sources under the Clean Air Act’s Prevention of Significant Deterioration (“PSD”) 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. Facilities containing petroleum and natural gas systems that emit 25,000 metric tons or more of CO2 equivalent per year are now required to report annual GHG emissions to the EPA.
Further, proposed legislation has been introduced in Congress that would establish an economy-wide cap on emissions of GHG’s in the United States and would require most sources of GHG emissions to obtain GHG emission “allowances” corresponding to their annual emissions of GHG’s. 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 Climate Change Conference in Paris resulted in the creation of the Paris Agreement. The Paris Agreement was signed on April 22, 2016 and requires countries to review and “represent a progression” in their nationally determined contributions, which set emissions reduction goals, every five years beginning in 2020. While it is not possible at this time to predict how new treaties and legislation that may be enacted to address GHG emissions would impact our business, the modification of existing laws or regulations or the adoption of new laws or regulations curtailing exploratory or developmental drilling for oil and gas could materially and adversely affect our operations by limiting drilling opportunities or imposing materially increased costs. Moreover, 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.
Countries in the European Union ("EU") implement the U.N.’s Kyoto Protocol on GHG emissions through the Emissions Trading System (“ETS”), though ETS will continue to require GHG reductions in the future that are not currently prescribed by the Kyoto Protocol or related agreements. 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. In July 2015, the European Commission presented a legislative proposal to revise the European Union ETS for the period after 2020 that includes a more rapid reduction

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in emission allowances, among other suggestions. This revision would also increase the 21 percent GHG reduction target for ETS sectors discussed above to 43 percent by 2030. The European Parliament and Council have yet to adopt legislation relating to this proposal. More generally, the EU Commission has proposed a roadmap for reducing emissions by 80 percent by 2050 compared to 1990 levels. Some EU member states have enacted additional and more long-term legally binding targets. For example, the UK has committed to reduce GHG emissions by 80 percent by 2050. These reduction targets may also be affected by future negotiations under the United Nations Framework Convention on Climate Change and its Kyoto Protocol and Paris Agreement.
Entities operating over the cap must either reduce their GHG emissions or purchase tradable emissions allowances, or EUAs, from other program participants, or purchase international GHG offset credits generated under the Kyoto Protocol’s Clean Development Mechanisms or Joint Implementation for international carbon trading after 2020. However, the Paris Agreement provides for the creation of a new market-based mechanism that could replace the Clean Development Mechanisms and Joint Implementation. As the cap declines, prices for emissions allowances or GHG offset credits may rise. However, due to the over-allocation of EUAs by EU member states in earlier phases and the impact of the recession in the EU, there has been a general over-supply of EUAs. The EU has recently approved amending legislation to withhold the auction of EUAs in a process known as “back-loading.” EU proposals for wider structural reform of the EU ETS may follow the enactment of the back-loading legislation. For example, in July and October 2015, the European Parliament and Council, respectively, approved a Market Stability Reserve. The Market Stability Reserve will start operating in January 2019 and is intended as a long-term solution to the oversupply. Both back-loading and wider structural reforms are aimed at reviving the EU carbon price.
In addition, the 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. We will establish the necessary procedures to collect and report Scope 2 data.
For the year ended December 31, 2016, our estimated carbon dioxide equivalent (“CO2e”) gas emissions were 483,111 tonnes as compared to 625,829 tonnes for the year ended December 31, 2015. The decline in emissions was mostly due to a decrease in drillship engine use. When expressed as an intensity measure of tonnes of CO2e gas emissions per dollar of contract drilling revenues from continuing operations, both the 2016 and 2015 intensity measure was .0002.
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).” We have used SANGEA™ Emissions Estimation Software to estimate CO2e gas of Scope 1 emissions based on diesel fuel consumption.
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. We believe that we are in substantial compliance with these requirements and with other applicable OSHA requirements.
On June 10, 2013, the European Union adopted a new directive, 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 of any of its member states. The directive establishes minimum requirements for preventing major accidents in offshore oil and gas operations, and aims to limit the consequences of such accidents. All European Union member states were required to adopt national legislation or regulations by July 19, 2015 to implement the new directive’s requirements, which also include reporting requirements related to major safety and environmental hazards that must be satisfied before drilling can take place, as well as the use of “all suitable measures” to both prevent major accidents and limit the human health and environmental consequences of such a major accident should one occur. We believe that our operations are in substantial compliance with the requirements of the directive (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 its implementation.
International Regulatory Regime. The International Maritime Organization (“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

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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. Annex VI, which applies to all ships, fixed and floating drilling rigs and other floating platforms, imposes a global cap on the sulfur content of fuel oil and allows for specialized areas to be established internationally with even more stringent controls on sulfur emissions. For vessels 400 gross tons and greater, platforms and drilling rigs, Annex VI imposes various survey and certification requirements. On July 15, 2011, the IMO approved mandatory measures to reduce emissions of GHGs from international shipping, requiring energy efficiency and survey and certification measures. These amendments to Annex VI apply to all ships of 400 gross tonnage and above and entered into force on January 1, 2013, affecting the operations of vessels that are registered in countries that are signatories to MARPOL Annex VI or vessels that call upon ports located within such countries. Moreover, 2008 amendments to Annex VI require the imposition of progressively stricter limitations on sulfur emissions from ships. These amendments required that, as of January 1, 2015, the sulfur content of marine fuel in SOx Emission Control Areas (“ECAs”) be limited to 0.10 percent m/m (mass by mass). The North American ECA became effective in August 2012. The North Sea and Baltic Sea ECAs have been in place since July 1, 2010. The North Sea ECA encompasses all of the North Sea and the full length of the English Channel. These regulations also established a global cap on the marine fuel sulfur content of 3.50 percent m/m in non-ECA areas that will decrease progressively to a 0.5 percent m/m cap by January 1, 2020. The amendments also establish new tiers of stringent nitrogen oxide emissions standards for new marine engines, depending on their date of installation.
The IMO has 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, or BWM Convention. The BWM Convention’s implementing regulations call for a phased introduction of mandatory ballast water exchange requirements (beginning in 2009), to be replaced in time with a requirement for mandatory ballast water treatment. The BWM Convention will enter into force on September 8, 2017, after having reached its 35 percent ratification trigger in September 2016. Upon the BWM Convention’s entry into force, all vessels in international traffic are to comply with the ballast water exchange standard. Thereafter, vessels will be required to meet the more stringent ballast water performance standard no later than the first intermediate or renewal survey following the Convention’s entry into force. All of our drilling rigs are in substantial compliance with the proposed terms of the BWM Convention.
The IMO has also adopted the International Convention for Civil Liability for Bunker Oil Pollution Damage of 2001, or Bunker Convention. The Bunker Convention provides a liability, compensation and compulsory insurance system for the victims of oil pollution damage caused by spills of bunker oil. Under the Bunker Convention, ship owners must pay compensation for pollution damage (including the cost of preventive measures) caused in the territory, including the territorial sea of a State Party, as well as its exclusive economic zone or equivalent area. Registered owners of any seagoing vessel and seaborne craft over 1,000 gross tons, of any type whatsoever, and registered in a State Party, or entering or leaving a port in the territory of a State Party, must maintain insurance which meets the requirements of the Bunker Convention and to obtain a certificate issued by a State Party attesting that such insurance is in force. The State issued certificate must be carried on board at all times. We believe that all of our drilling rigs are currently compliant in all material respects with these regulations.
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

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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 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 again physical loss or damage to our drilling rigs, subject to a deductible.
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 of 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.
Employees
At December 31, 2016, we had approximately 2,100 employees, excluding approximately 700 persons we engaged through labor contractors or agencies. Approximately 84 percent of our workforce is located offshore. Of our shorebased employees, approximately 70 percent are male. 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.
We are committed to a policy of recruitment and promotion on the basis of aptitude and ability without discrimination of any kind. 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.
Financial Information about Segments and Geographic Areas
Information regarding our revenues from external customers, segment profit or loss and total assets attributable to each segment for the last three fiscal years is presented in Part II, Item 8, “Financial Statements and Supplementary Data, Note 18Segment and Related Information.”
Information regarding our operating revenues and identifiable assets attributable to each of our geographic areas of operations for the last three fiscal years is presented in Part II, Item 8, “Financial Statements and Supplementary Data, Note 18Segment and Related Information.”
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. These filings are also available to the public at the U.S. Securities and Exchange Commission’s (the “SEC”) Public Reference Room at 100 F Street, NE, Room 1580, Washington, DC 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. Electronic filings with the SEC are also available on the SEC’s website 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;

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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.
Risk Factors Relating to Our Business
Our business and results of operations have been materially hurt and our enterprise value has substantially declined due to current depressed market conditions which are the result of the dramatic drop in the oil price and the oversupply of offshore drilling rigs.
Brent crude has declined from approximately $112 per barrel on June 30, 2014 to as low as approximately $30 per barrel in January 2016, before improving to $56 per barrel on February 15, 2017. In addition, a large number of offshore drilling rigs were constructed and added to the global fleet in the last few years, and a substantial number of additional rigs, including rigs built on speculation, are currently scheduled to enter the market in 2017. 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 exploration and development spending in response to the depressed price of oil. 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 $27.00 on August 4, 2014 post Spin-off to $7.32 at February 15, 2017. 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 these 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’ expectations of future commodity prices typically drive demand for our rigs. 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;
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;

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worldwide instability in the financial and credit sectors and a reduction in the availability of liquidity and credit;
the relative cost of offshore drilling versus onshore oil and gas production;
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 depressed 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 downturn has already had a material adverse effect on demand for our services and is expected to have a material adverse effect on our business and results of operations.
The contract drilling industry is a highly competitive and cyclical business with intense price competition. 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. Intense price competition, rig availability, location and suitability are the primary factors in determining which contractor is awarded a job, although other factors are important, including experience of the workforce, efficiency, safety performance record, technical capability and 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. 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 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 may result in some of our rigs being idle or earning substantially lower dayrates for long periods of times. We cannot provide you with any assurances as to when such period will end, or when there will be higher demand for contract drilling services or a reduction in the number of drilling rigs.
The over-supply of 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 recent 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 since mid-2014, has resulted in an oversupply of drilling rigs, which has contributed to the recent decline in utilization and dayrates.
We are currently experiencing competition from newbuild rigs that have either already entered the market or are scheduled 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.

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We may record additional losses or impairment charges related to rigs to be sold or cold stacked or other capital equipment.
We evaluate the impairment of property and equipment 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. In addition, on an annual basis, we complete an impairment analysis on our rig fleet and capital spares. 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. For example, based upon our annual impairment analysis as of the end of 2016 and 2015, we decided that we would no longer market certain rigs. In connection with these decisions, we recorded impairment charges of $285 million and $372 million, respectively, on these rigs during those periods. In addition, based upon our annual impairment analysis as of the end of 2016, we partially impaired the carrying value of three rigs to the estimated fair value and recorded an impairment charge of $1 billion. There can be no assurance that we will not have to take additional impairment charges in the future if current depressed market conditions persist.
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.
We had a number of customer contracts that expired in 2016 and will expire in 2017 and 2018. Our ability to renew these contracts 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. During 2016, a number of oil and gas companies, including some of our customers, have publicly announced significant reductions in their planned exploration and development spending during 2017 and beyond. These reductions in spending by our customers could further reduce the demand for contract drilling services and as a result, our business, financial condition and results of operations would be materially adversely affected.
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.
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, such as the one we are currently experiencing. 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

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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 and Statoil ASA, and the loss 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 accounted for approximately 38 percent of our consolidated operating revenues in 2016 and represents approximately 69 percent of our backlog at December 31, 2016. While Statoil ASA (“Statoil”) only represented one percent of our consolidated operating revenues for the year ended December 31, 2016, we expect Statoil to represent a more significant portion of our contract drilling revenue in the next few years due to the commencement of a four-year North Sea drilling contract by the Noble Lloyd Noble in November 2016. As a result of this contract commencement, Statoil now represents 18 percent of our backlog at December 31, 2016. 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 either 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.
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. A disruption 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 meet our commitments to customers, adversely impact our operations and revenues by resulting in uncompensated downtime, reduced day rates or the cancellation or termination of contracts, or increase our operating costs.
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;
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.
As part of our recent agreement with Paragon Offshore, we agreed to assume certain Mexican tax liabilities and bonding obligations.  These tax liabilities could cost more than we expect, and the bonding requirements could be greater than anticipated and also could affect our liquidity.  There can be no assurance that Paragon Offshore will satisfy its tax payment, cost reimbursement or other obligations when they become due.  If the bankruptcy court does not approve our settlement agreement with Paragon Offshore, we could be sued by Paragon Offshore or its creditors.

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In February 2016, we entered into an agreement in principle (followed by a definitive settlement agreement entered into in April 2016 and still subject to approval of the bankruptcy court having jurisdiction over Paragon Offshore’s bankruptcy proceeding as discussed below) for a settlement with Paragon Offshore under which, in exchange for a full and unconditional release of any claims by Paragon Offshore in connection with the Spin-off (including fraudulent conveyance claims that could be brought on behalf of Paragon Offshore’s creditors), we agreed to assume the administration of Mexican tax claims for specified years up to and including 2010, as well as the related bonding obligations and certain of the related tax liabilities. We cannot make any assurances regarding the outcome of the tax assessments and claims, and the cost of these liabilities and the amount of bonding required could be greater than we anticipate.
We expect that we will be able to bond amounts required in Mexico using our current bonding facility. If the amount of bonding is greater than we anticipate, or we are required to maintain such bonds longer than we anticipate, then our current bonding facility may not be sufficient, and we would be required to use other sources for the bonding, including our credit facility, which could affect our liquidity and reduce the availability of credit for uses other than bonding Mexican tax liabilities.
In addition, Paragon Offshore is required under the terms of the settlement agreement to share equally in the payment of certain of the Mexican tax liabilities and the costs of administering the tax claims. If Paragon Offshore is unable or unwilling to pay its share of these tax liabilities or the costs to administer the tax claims, we could be forced to pay these amounts ourselves and seek reimbursement from Paragon Offshore. There can be no assurance that Paragon Offshore will be able to satisfy its share of the tax liabilities, reimburse us when such payments would be due or comply with other obligations under the settlement agreement or our tax sharing agreement. If Paragon Offshore is unable to satisfy these obligations, the underlying liabilities could have a material adverse effect on our business, financial condition and results of operations. See Part II, Item 8, “Financial Statements and Supplementary Data, Note 17Commitments and Contingencies.”
Paragon Offshore sought approval of a pre-negotiated plan of reorganization by filing for voluntary relief under Chapter 11 of the United States Bankruptcy Code in February 2016. Our settlement agreement with Paragon Offshore is subject to approval of Paragon Offshore’s bankruptcy plan. On October 28, 2016, the bankruptcy court having jurisdiction over the Paragon Offshore bankruptcy denied confirmation of Paragon Offshore’s bankruptcy plan. On January 18, 2017, Paragon Offshore announced that it had reached an agreement in principle with an ad hoc committee of secured debt holders on a term sheet to support a new bankruptcy plan. The term sheet contemplates that the existing settlement agreement between Noble and Paragon Offshore will be adopted under the new bankruptcy plan. Paragon Offshore also stated that it will seek to obtain court approval of the new bankruptcy plan as soon as possible in the first half of 2017. Paragon Offshore’s unsecured creditors are not parties to the agreement in principle, and have formed an ad hoc committee which we expect to oppose Paragon's new bankruptcy plan, including our settlement agreement. There can be no assurance that the bankruptcy court will ultimately approve our settlement agreement with Paragon Offshore or Paragon Offshore’s bankruptcy plan or that our settlement agreement will continue to be a part of their bankruptcy plan. If for any reason the agreement is not approved by the bankruptcy court or included in their plan or Paragon Offshore fails to exit bankruptcy, Paragon Offshore or its creditors could become adverse to us in any potential litigation relating to the Spin-off, including any alleged fraudulent conveyance claim in connection with the creation of Paragon Offshore as a stand-alone entity.
In connection with the Spin-off, we agreed to indemnify Paragon Offshore for certain liabilities, and Paragon Offshore agreed to indemnify us for certain liabilities. We have significant exposure to losses resulting from this obligation, and there can be no assurance that the Paragon Offshore indemnities will be sufficient to insure us against the full amount of the related liabilities, or that Paragon Offshore will be able or willing to satisfy its indemnification and other obligations in the future.
We entered into certain agreements with Paragon Offshore in connection with the Spin-off, including a master separation agreement, tax sharing agreement, transition services agreement and transition services agreement relating to our operations offshore Brazil. Pursuant to the agreements, we agreed to indemnify Paragon Offshore for certain liabilities, and Paragon Offshore agreed to indemnify us for certain liabilities. We could have significant exposure to losses resulting from our obligations under these agreements.
Third parties could seek to hold us responsible for any of the liabilities that Paragon Offshore has agreed to retain, and there can be no assurance that the indemnity from Paragon Offshore will be sufficient to protect us against the full amount of such liabilities, or that Paragon Offshore will be able or willing to fully satisfy its indemnification or performance obligations. Moreover, even if we ultimately succeed in recovering from Paragon Offshore any amounts for which we are held liable, we may be temporarily required to bear these losses. If Paragon Offshore is unable or unwilling to satisfy its indemnification and other obligations, the underlying liabilities could have a material adverse effect on our business, financial condition and results of operations.
We may experience downgrades in our credit ratings, which would increase our borrowing costs and potentially reduce our access to additional liquidity.
As a result of the decline in our credit ratings below investment grade in 2016, access to the commercial paper market became closed to us and we have terminated our commercial paper program. So long as such access is closed, any future borrowings

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would have to be made under our revolving credit facility. Our revolving credit facility has a provision which changes the applicable interest rate based upon our credit ratings, and these reduced credit ratings increase our interest expense for borrowings under our revolving credit facility.
In February 2016 Moody’s Investors Service downgraded our debt rating below investment grade, resulting in an interest rate increase of 1.00% on each of certain notes. Effective March 16, 2016, the interest rate on our Senior Notes due 2018 increased to 5.00% as a result of the downgrade. Effective April 1, 2016, the interest rates on our Senior Notes due 2025 and Senior Notes due 2045 increased to 6.95% and 7.95%, respectively, as a result of the downgrade.
In July 2016, S&P Global Ratings issued an additional downgrade, resulting in an interest rate increase of 0.25% each, of the same notes. Effective September 16, 2016, the interest rate on our Senior Notes due 2018 increased to 5.25%. Effective October 1, 2016, the interest rates on our Senior Notes due 2025 and Senior Notes due 2045 increased to 7.20% and 8.20%, respectively. The weighted average coupon of all three tranches is now 7.12%.
In December 2016, S&P Global Ratings issued an additional downgrade, resulting in an interest rate increase of 0.5% each, of the same notes. Effective March 16, 2017, the interest rate on our Senior Notes due 2018 is scheduled to increase to 5.75% as a result of the downgrade. Effective April 1, 2017, the interest rates on our Senior Notes due 2025 and Senior Notes due 2045 are scheduled to increase to 7.70% and 8.70%, respectively, as a result of this downgrade.
The interest rates on these Senior Notes may be further increased if our debt ratings were to be downgraded further (up to a maximum of an additional 25 basis points). Our other outstanding senior notes, including the Senior Notes due 2024 issued in December 2016, do not contain provisions varying applicable interest rates based upon our credit ratings.
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;
piracy; and
terrorist acts, war, revolution and civil disturbances.
Further, we operate 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, other governmental actions, including initiatives by OPEC, 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

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citizens of, or purchase supplies from, a particular jurisdiction. These practices may adversely affect our ability to compete and our results of operations.
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, including environmental 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 and the environment 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.
Our operations are also subject to numerous laws and regulations controlling the discharge of materials into the environment or otherwise relating to the protection of the environment. 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. 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. Laws and regulations protecting the environment have generally become more stringent and in certain circumstances impose “strict liability,” rendering a person liable for environmental damage without regard to negligence or fault. 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.
As disclosed in Part II, Item 8, “Financial Statements and Supplementary Data, Note 17Commitments and Contingencies,” in November 2012, the U.S. Coast Guard in Alaska conducted an inspection and investigation of the Noble Discoverer and the Kulluk, a rig we were providing contract labor services for, and referred the matters to the DOJ for further investigation. In December 2014, a subsidiary reached a settlement with the DOJ regarding its investigation of the Noble Discoverer and the Kulluk. Under the terms of the plea agreement, the subsidiary pled guilty to violations relating to maintaining proper oil

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record books for the Noble Discoverer and Kulluk, maintaining proper ballast records for the Noble Discoverer and notification of hazardous conditions with respect to the Noble Discoverer. The subsidiary paid $8.2 million in fines and $4 million in community service payments and implemented a comprehensive environmental compliance plan. Under the plea agreement, we were also placed on probation for four years. If during the term of probation, the subsidiary fails to adhere to the terms of the plea agreement, the DOJ may withdraw from the plea agreement and would be free to prosecute the subsidiary on all charges arising out of its investigation, including any charges dismissed pursuant to the terms of the plea agreement, as well as potentially other charges.
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, or FCPA, the United Kingdom Bribery Act 2010, or U.K. Bribery Act, and similar laws in other countries. Any violation of the FCPA, the 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, results of operations or financial condition. 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;
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.
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”), began an overhaul of the offshore oil and natural gas regulatory process that significantly impacted oil and gas development regulated by the United States. From time to time, new rules, regulations and requirements have been proposed and implemented by BOEM, BSEE or the United States Congress 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. BOEM also released a new Notice to Lessees and Operators in the Outer Continental Shelf 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. 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 U.S., 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 U.S., 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 U.S. or other jurisdictions are viewed by our

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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.
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.
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; and
force majeure events.
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.
As a result of our significant cash flow needs, we may be required to incur additional indebtedness, 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;
repayment of debt and interest; and
payments of dividends.
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 bank credit facility. We may raise such additional capital in a number of ways, including accessing 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.
Our debt instruments could limit our operations and our debt level may limit our flexibility to obtain financing and pursue business opportunities. Our ability to obtain financing or to access the capital markets may be limited by our financial condition and our credit ratings at the time of any such financing and the covenants in our existing debt agreements, as well as by adverse market conditions resulting from, among other things, a depressed oil price, general economic conditions and uncertainties that are beyond our control. Even if we are successful in obtaining additional capital through debt financings, incurring additional indebtedness may significantly increase our interest expense and may reduce our flexibility to respond to changing business and economic conditions or to fund working capital needs, because we will require additional funds to service our outstanding indebtedness.

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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 may have difficulty obtaining or maintaining insurance in the future and our insurance coverage and contractual indemnity rights may not protect us against all of 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 U.S. 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.
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.
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 U.K., U.S. and other foreign tax laws, regulations or treaties or the interpretation or enforcement thereof, changes in the administrative practices and precedents of tax authorities or any reclassification or other matter (such as changes in applicable accounting rules) that increases the amounts we have provided for income taxes or deferred tax assets and liabilities in our consolidated financial statements. In addition, as a result of frequent changes in the taxing jurisdictions in which our drilling rigs are operated and/or owned, changes in the overall level of our income and changes in tax laws, our consolidated effective income tax rate may vary substantially from one reporting period to another. Income tax rates imposed in the tax jurisdictions in which our subsidiaries conduct operations vary, as does the tax base to which the rates are applied. In some cases, tax rates may be applicable to gross revenues, statutory or negotiated deemed profits or other bases utilized under local tax laws, rather than to net income. Our drilling rigs frequently move from one taxing jurisdiction to another to perform contract drilling services. In some instances, the movement of drilling rigs among taxing jurisdictions will involve the transfer of

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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;
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. 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.

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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. 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;
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 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 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.
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.
Our information technology systems and those of our service providers are subject to cybersecurity risks and threats.
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 operations, including critical systems on our drilling units, and these systems are subject to risks associated 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 or our service or equipment providers’ systems could go unnoticed for a prolonged period of time. These cybersecurity risks could disrupt our operations and result in downtime, loss of revenue, or the loss of critical data 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, results of operations or cash flows. Currently, we do not carry insurance for losses related to cybersecurity attacks, and may elect to not obtain such insurance in the future.

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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 periods of low demand, such as the one we are currently experiencing, there are layoffs of qualified personnel, who often find work with competitors or leave the industry.  As a result, once market conditions improve, 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.
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 Cuba, Iran, 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-

22



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 or when the result of a hedge is a loss. 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.
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, governmental claims for taxes or duties, and other litigation that arises in the ordinary course of our business. Although we intend to defend these 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, costs of attorneys, 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. Contractual provisions or laws, as well as our subsidiaries’ financial condition and operating requirements, may 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.
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 regarding rig demand, the offshore drilling market, oil prices, contract backlog, fleet status, our financial position, business strategy, impairments, repayment of debt, credit ratings, borrowings under our credit facilities 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, industry conditions, access to financing, impact of competition, governmental regulations and permitting, availability of labor, 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, 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. These factors include those described in “Risk Factors” above, 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.
Item 1B.
Unresolved Staff Comments.
None.
Item 2.
Properties.
Drilling Fleet
Our drilling fleet is composed of the following types of units: drillships, semisubmersibles, and jackups. 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.

23



Drillships
Our drillships are self-propelled vessels. These units maintain their position over the well through the use of a computer-controlled dynamic positioning system. Certain of our drillships are capable of drilling in water depths up to 12,000 feet.
As of the filing date of this Annual Report on Form 10-K, our drillship fleet consisted of the following eight units:
four dynamically positioned Gusto Engineering Class drillships;
two dynamically positioned Bully-class drillships operated by us through a 50 percent joint venture with a subsidiary of Shell; and
two dynamically positioned Globetrotter-class drillships.
Semisubmersibles
Semisubmersibles are floating platforms which, by means of a water ballasting system, can be submerged to a predetermined depth so that a substantial portion of the hull is below the water surface during drilling operations in order to improve stability. These units maintain their position over the well through the use of either a fixed mooring system or a computer controlled dynamic positioning system and can drill in many areas where jackups cannot drill. Semisubmersibles normally require water depths of at least 200 feet in order to conduct operations. Certain of our semisubmersibles are capable of drilling in water depths of up to 12,000 feet.
As of the filing date of this Annual Report on Form 10-K, our semisubmersible fleet consisted of the following six units:
two Noble EVA-4000™ semisubmersibles;
two modified Friede & Goldman 9500 Enhanced Pacesetter semisubmersibles; and
two modified Bingo 9000 design unit, dynamically positioned semisubmersibles.
Jackups
Jackups are mobile, self-elevating drilling platforms equipped with legs that can be lowered to the ocean floor until a foundation is established for support. The rig hull includes the drilling rig, jacking system, crew quarters, loading and unloading facilities, storage areas for bulk and liquid materials, helicopter landing deck and other related equipment. All of our jackups are independent leg (i.e., the legs can be raised or lowered independently of each other) and cantilevered. A cantilevered jackup has a feature that permits the drilling platform to be extended out from the hull, allowing it to perform drilling or workover operations over pre-existing platforms or structures. Moving a rig to the drill site involves jacking up its legs until the hull is floating on the surface of the water. The hull is then towed to the drill site by tugs and the legs are jacked down to the ocean floor. The jacking operation continues until the hull is raised out of the water, and drilling operations are conducted with the hull in its raised position. Our jackups are capable of drilling in maximum water depths from approximately 300-500 feet. As of the filing date of this Annual Report on Form 10-K, we had 14 jackups in our fleet, including one high-specification, harsh environment jackup.

24



Offshore Fleet Table
The following table sets forth certain information concerning our offshore fleet at February 23, 2017. We operate and own all of the units included in the table.
Name
 
Make
 
Year Built
or Rebuilt (1)
 
Water
Depth
Rating
(feet)
 
Drilling
Depth
Capacity
(feet)
 
Location
 
Status (2)
Drillships—8
 
 
 
 
 
 
 
 
 
 
 
 
Noble Bob Douglas
 
GustoMSC P10000
 
2013 N
 
12,000
 
40,000
 
U.S. Gulf of Mexico
 
Active
Noble Bully I (4)
 
GustoMSC Bully PRD 12000
 
2011 N
 
8,200
 
40,000
 
U.S. Gulf of Mexico
 
Active
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
 
U.S. Gulf of Mexico
 
Active
Noble Globetrotter II
 
Globetrotter Class
 
2013 N
 
10,000
 
30,000
 
South Africa
 
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
 
U.S. Gulf of Mexico
 
Available
Semisubmersibles—6
 
 
 
 
 
 
 
 
 
 
 
 
Noble Amos Runner
 
Noble EVA-4000™
 
1999 R/2008 M
 
8,000
 
32,500
 
U.S. Gulf of Mexico
 
Stacked
Noble Clyde Boudreaux
 
F&G 9500 Enhanced Pacesetter
 
2007 R/M
 
10,000
 
35,000
 
Singapore
 
Available
Noble Danny Adkins
 
Bingo 9000-DP
 
2009 R
 
12,000
 
35,000
 
U.S. Gulf of Mexico
 
Stacked
Noble Dave Beard
 
F&G 9500 Enhanced Pacesetter-DP
 
2009 R
 
10,000
 
35,000
 
Singapore
 
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
 
6,000
 
32,500
 
U.S. Gulf of Mexico
 
Active
Independent Leg Cantilevered Jackups—14
 
 
 
 
 
 
 
 
 
 
Noble Alan Hay
 
Levingston Class 111-C
 
2005 R
 
300
 
25,000
 
U.A.E.
 
Active
Noble David Tinsley
 
Modec 300C-38
 
2010 R
 
300
 
25,000
 
U.A.E.
 
Active
Noble Gene House
 
Modec 300C-38
 
1998 R
 
300
 
25,000
 
Saudi Arabia
 
Active
Noble Hans Deul (3)
 
F&G JU-2000E
 
2009 N
 
400
 
30,000
 
U.K.
 
Active
Noble Houston Colbert (3)
 
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 Lloyd Noble (3)
 
GustoMSC CJ70-x150-ST
 
2016 N
 
500
 
32,000
 
U.K.
 
Active
Noble Mick O’Brien (3)
 
F&G JU-3000N
 
2013 N
 
400
 
30,000
 
U.A.E.
 
Active
Noble Regina Allen (3)
 
F&G JU-3000N
 
2013 N
 
400
 
30,000
 
U.K.
 
Active
Noble Roger Lewis (3)
 
F&G JU-2000E
 
2007 N
 
400
 
30,000
 
Saudi Arabia
 
Active
Noble Sam Hartley (3)
 
F&G JU-3000N
 
2014 N
 
400
 
30,000
 
Brunei
 
Active
Noble Sam Turner (3)
 
F&G JU-3000N
 
2014 N
 
400
 
30,000
 
Denmark
 
Active
Noble Scott Marks (3)
 
F&G JU-2000E
 
2009 N
 
400
 
30,000
 
Saudi Arabia
 
Active
Noble Tom Prosser (3)
 
F&G JU-3000N
 
2014 N
 
400
 
30,000
 
U.A.E.
 
Available
Footnotes to Drilling Fleet Table
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.
Rigs listed as “active” are operating, or preparing to operate, 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.
3.
Harsh environment capability.
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.

25



Facilities
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 set forth in Note 17 to our consolidated financial statements included in 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 following table sets forth for the periods indicated the high and low sales prices and dividends or returns of capital declared and paid in U.S. Dollars per share:
 
 
High
 
Low
 
Cash
Dividends
Declared and
Paid
2016
 
 

 
 

 
 

Fourth quarter
 
$
7.64

 
$
4.64

 
$

Third quarter
 
8.94

 
5.12

 
0.020

Second quarter
 
11.98

 
8.07

 
0.020

First quarter
 
13.56

 
6.91

 
0.150

 
 
 
 
 
 
 
2015
 
 

 
 

 
 

Fourth quarter
 
$
14.22

 
$
10.55

 
$
0.150

Third quarter
 
15.27

 
10.46

 
0.375

Second quarter
 
18.16

 
14.45

 
0.375

First quarter
 
19.51

 
13.55

 
0.375

Our most recent quarterly dividend payment to shareholders, totaling approximately $5 million (or $0.02 per share), was declared on July 22, 2016 and paid on August 8, 2016 to holders of record on August 1, 2016.
Our Board of Directors eliminated our quarterly cash dividend of $0.02 per share, beginning in the fourth quarter of 2016.
The declaration and payment of dividends requires 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. Noble-UK is not permitted to pay dividends out of share capital, which includes share premiums. The resumption of the payment of future dividends will depend on our results of operations, financial condition, cash requirements, future business prospects, contractual restrictions and other factors deemed relevant by our Board of Directors.
On February 15, 2017, there were 244,676,954 shares outstanding held by 341 shareholder accounts of record.

26



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.
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 resident 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. In December 2014, we received shareholder approval to repurchase up to 37 million ordinary shares, or approximately 15 percent of our outstanding ordinary shares at the time of such shareholder approval. The authority to make such repurchases expired at the end of the Company’s 2016 annual general meeting of shareholders, which was held on April 22, 2016. During 2015, we repurchased 6.2 million of our ordinary shares covered by this authorization at an average price of $16.10 per share, excluding commissions and stamp tax, for a total cost of approximately $101 million. All share repurchases were made in the open market and were pursuant to the share repurchase program discussed above. All shares repurchased during 2015 were immediately cancelled. During the year ended December 31, 2016, we did not repurchase any of our shares.

27



Stock Performance Graph
This graph shows the cumulative total shareholder return of our shares over the five-year period ending December 31, 2016. The graph also shows the cumulative total returns for the same five-year period of the S&P 500 Index and the Dow Jones U.S. Oil Equipment & Services Index. The graph assumes that $100 was invested in our shares and the two indices on January 1, 2012 and that all dividends or distributions and returns of capital were reinvested on the date of payment.
https://cdn.kscope.io/700ec20eea143d63be87a9b65038e44b-performancechart.jpg 

 
 
INDEXED RETURNS
Year Ended December 31,
Company / Index
 
2012
 
2013
 
2014
 
2015
 
2016
Noble-UK
 
$
116.98

 
$
128.45

 
$
67.77

 
$
47.01

 
$
26.98

S&P 500 Index
 
116.00

 
153.57

 
174.60

 
177.01

 
198.18

Dow Jones U.S. Oil Equipment & Services
 
100.33

 
128.83

 
106.64

 
82.67

 
105.26

 
Investors are cautioned against drawing any conclusions from the data contained in the graph, as past results are not necessarily indicative of future performance.
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.

28



Item 6.
Selected Financial Data.
The following table sets forth selected financial data of us and our consolidated subsidiaries over the five-year period ended December 31, 2016, which information is derived from our audited financial statements. This information should be read in connection with, and is qualified in its entirety by, the more detailed information in our financial statements included in Item 8 of this Annual Report on Form 10-K.
 
 
Year Ended December 31,
 
 
2016
 
2015
 
2014
 
2013
 
2012
 
 
(In thousands, except per share amounts)
Statement of Income Data
 
 

 
 

 
 

 
 

 
 

Operating revenues from continuing operations
 
$
2,302,065

 
$
3,352,252

 
$
3,232,504

 
$
2,538,143

 
$
2,200,699

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

 
(152,011
)
 
478,595

 
414,389

Net income (loss) from continuing operations per share attributable to Noble-UK:
 
 

 
 

 
 

 
 

 
 

Basic
 
(3.82
)
 
2.06

 
(0.60
)
 
1.86

 
1.63

Diluted
 
(3.82
)
 
2.06

 
(0.60
)
 
1.86

 
1.63

Balance Sheet Data (at end of period)
 
 

 
 

 
 

 
 

 
 

Cash and marketable securities
 
$
725,722

 
$
512,245

 
$
68,510

 
$
114,458

 
$
282,092

Property and equipment, net
 
10,061,948

 
11,483,623

 
12,112,509

 
14,558,090

 
13,025,972

Total assets (5)
 
11,440,117

 
12,865,645

 
13,266,480

 
16,194,639

 
14,580,886

Long-term debt (5)
 
4,040,229

 
4,162,638

 
4,848,678

 
5,532,933

 
4,607,487

Total debt (2) (5)
 
4,340,111

 
4,462,562

 
4,848,678

 
5,532,933

 
4,607,487

Total equity
 
6,467,445

 
7,422,230

 
7,287,034

 
9,050,028

 
8,488,290

Other Data
 
 

 
 

 
 

 
 

 
 

Net cash from operating activities
 
$
1,128,282

 
$
1,762,351

 
$
1,778,208

 
$
1,702,317

 
$
1,381,693

Net cash from investing activities
 
(669,931
)
 
(432,537
)
 
(2,109,268
)
 
(2,485,107
)
 
(1,790,888
)
Net cash from financing activities
 
(244,874
)
 
(886,079
)
 
285,112

 
615,156

 
452,091

Capital expenditures (3)
 
659,925

 
422,544

 
2,072,885

 
2,487,520

 
1,669,811

Working capital (4) (5)
 
$
559,321

 
377,034

 
259,888

 
339,020

 
393,876

Cash distributions declared per share
 
0.20

 
1.28

 
1.50

 
0.76

 
0.54

(1)
Results for 2016, 2015, 2014, 2013 and 2012 include impairment charges of $1.5 billion, $418 million, $745 million, $4 million and $20 million, respectively.
(2)
Consists of Long-term debt and Current maturities of long-term debt.
(3)
Capital expenditures includes expenditures made for rigs that were ultimately transferred to Paragon Offshore as part of the Spin-off.
(4)
Working capital is calculated as current assets less current liabilities.
(5)
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 and Note 9 for more information.
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, 2016 and 2015, and our results of operations for each of the years in the three-year period ended December 31, 2016. 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, 2016 filed by Noble-UK and Noble-Cayman.
The results of operations for Paragon Offshore prior to August 1, 2014, the Spin-off date, and non-recurring costs related to the Spin-off have been classified as discontinued operations for all periods presented in this report. The terms “earnings” and “loss” as used in this “Management’s Discussion and Analysis of Financial Condition and Results of Operations” refer to income

29



or loss from continuing operations. Income or loss from continuing operations is representative of the Company’s current business operations and focus.
Executive Overview
Our 2016 financial and operating results from continuing operations include:
operating revenues totaling $2.3 billion;
net loss of $930 million, or $3.82 per diluted share, which includes a $1.3 billion after-tax impairment charge recognized on five of our rigs and certain capital spare equipment; and
net cash from operating activities totaling $1.1 billion.
The business environment for offshore drillers during 2016 remained challenging. A rig supply imbalance expanded throughout 2016, primarily due to reduced offshore spending by customers, leaving a growing number of rigs without follow-on drilling programs as contracts expired. In addition, newbuild rigs ordered prior to the decline in industry activity continue to exit shipyards, adding to the supply imbalance. Our customers have adopted a cautious approach to offshore spending as crude oil prices declined from approximately $112 per barrel on June 30, 2014 to as low as approximately $30 per barrel in January 2016, before improving to $56 per barrel on February 15, 2017. We expect that the offshore drilling programs of operators will remain curtailed, especially exploration activity, until higher, sustained crude oil prices are achieved. Until then, further deterioration in rig utilization and dayrates is possible.
We expect the business environment for 2017 to remain weak and it could potentially deteriorate further. The present subdued level of global economic activity, the uncertainty of the viability and length of reductions in production agreed to by the Organization of Petroleum Exporting Countries (“OPEC”) in November 2016, the incremental production capacity in non-OPEC countries, including the current U.S. political environment, and the Brexit vote in the UK are contributing to an uncertain oil price environment, leading to considerable uncertainity in our customers’ exploration and production spending plans. However, the production limits recently agreed to by OPEC could help to establish market conditions supporting higher, sustained crude prices in 2017. In general, recent contract awards have been short-term in nature and 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. 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. While current market conditions persist, we will continue to focus on operating efficiency, cost control and managing liquidity and could stack or retire additional drilling rigs.
While we cannot predict the future level of demand or dayrates for our services, or future conditions in the offshore contract drilling industry, we believe we are strategically well positioned.
We believe in the long-term fundamentals for the industry, especially for those contractors with a modern fleet of high-specification rigs like ours. We expect the persistent rig supply imbalance to improve over time, with the combination of further fleet attrition and a rebound in offshore spending by our customers. Also, we believe the ultimate market recovery will benefit from any sustained under-investment by customers during the current phase of the market cycle.
Our business strategy focuses on a balanced fleet of both deepwater drilling and high-specification jackup assets and the deployment of our drilling rigs in important oil and gas basins around the world. 
Over the past five years, we have expanded our drilling fleet through our newbuild program. We took delivery of our remaining newbuild, the heavy-duty, harsh environment jackup, Noble Lloyd Noble, in July 2016. The Noble Lloyd Noble has commenced operations in November 2016 under a four-year contract in the North Sea. Although we plan to focus on capital preservation and liquidity based on current market conditions, we also continue to evaluate opportunities to enhance our fleet, particularly focusing on higher specification rigs, to execute the increasingly complex drilling programs required by our customers.
Impairment
We evaluate the impairment of property and equipment whenever events or changes in circumstances (including the decision to cold stack, retire or sale a rig) indicate that the carrying amount of an asset may not be recoverable. In addition, on an annual basis in the fourth quarter, we complete an impairment analysis on our rig fleet. 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 connection with our annual impairment analysis as of the end of 2016, we identified indicators that certain assets in our fleet might not be recoverable. Such indicators included the significant supply/demand rig imbalance, additional customer

30



suspensions of drilling programs, contract cancellations and a further reduction in the number of new contract opportunities, resulting in a reduced number of overall drilling contracts. As a result of our year-end testing, we determined that the carrying amounts of certain drilling units were impaired. We estimated the fair values of these units by applying the income valuation approach utilizing significant unobservable inputs, representative of a Level 3 fair value measurement. Assumptions used in our assessment included, but were not limited to, timing of future contract awards and expected operating day rates, operating costs, utilization rates, capital expenditures, reactivation costs and estimated economic useful lives. Based upon our annual impairment analysis, we impaired the carrying values to estimated fair values for the Noble Amos Runner, the Noble Clyde Boudreaux and the Noble Dave Beard. The impairment charge related to these units was approximately $1 billion.
If we believe that one of our drilling units is no longer marketable or is otherwise unlikely to return to active service, we may elect to retire the unit and/or sell the unit at a value that may be substantially below its book value, and recognize an impairment charge that reduces the asset’s carrying value to the estimated fair value. In late December 2016, we decided to retire from service and sell for scrap our semisubmersible, the Noble Max Smith, which we sold in December for approximately $1 million, and we recognized an impairment charge of approximately $165 million. We will continue to analyze the market and our expectations for our fleet, and we may retire and/or sell other units (which may be at a substantial loss compared to book value) if we conclude that it is appropriate to do so.
Also in the fourth quarter of 2016, in connection with our annual impairment analysis, we concluded that the semisubmersible, the Noble Homer Ferrington and certain capital spare equipment would not be utilized in the foreseeable future, and we recognized an impairment charge of $120 million and $154 million, respectively. In the second quarter of 2016, we recognized a charge of approximately $17 million for the impairment of certain capital spare equipment based upon our decision to dispose of this equipment.
In connection with our 2015 annual impairment analysis, we decided that we would no longer market one of our drillships, the Noble Discoverer. The decision was a result of the termination of the contract for this rig by Shell in December 2015 and the decreased opportunities for rigs of this type in the current marketplace. We also reviewed assumptions on the future marketability of one of our jackups, the Noble Charles Copeland, after its contract completion in late September 2015, with consideration given to its years in service, limited technical features and anticipated capital requirements in light of the current market conditions. As a result of this analysis, we decided to discontinue marketing this unit. Additionally, as a result of a year-end 2015 review of capital spare equipment, we elected to retire certain capital spare equipment. We evaluated these units and capital spare equipment for impairment and recorded an impairment charge of $406 million for the year ended December 31, 2015.
Also in 2015, we determined that certain corporate assets were partially impaired due to a declining market for, and the potential disposal of, the assets. We estimated the fair value of the assets based on quotes from brokers of similar assets (Level 2). Based on these estimates, we recorded an impairment charge of approximately $13 million for the year ended December 31, 2015.
In connection with our 2014 annual impairment analysis, we decided to discontinue marketing three of our semisubmersibles, the Noble Driller, the Noble Jim Thompson and the Noble Paul Wolff, because of then current market conditions. We evaluated these units for impairments and recorded an impairment charge of $685 million on these units. Additionally, we fully impaired the $60 million of goodwill on our books, which originated from the acquisition of FDR Holdings Limited (“Frontier”) in 2010, as a result of a significant decline in the market value of our stock, a decrease in oil and gas prices, significant reductions in the projected dayrates for new contracts and reduced utilization forecasts.
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 through a pro rata distribution of all of the ordinary shares of its wholly-owned subsidiary, Paragon Offshore, to the holders of Noble’s ordinary shares. Our shareholders received one share of Paragon Offshore for every three shares of Noble owned as of July 23, 2014, the record date for the distribution. Through the Spin-off, we disposed of most of our standard specification drilling units and related assets, liabilities and business. Prior to the Spin-off, Paragon Offshore issued approximately $1.7 billion of long-term debt. We used the proceeds from this debt to repay certain amounts outstanding under our commercial paper program. 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 the year ended December 31, 2014. There were no discontinued operations in 2016 or 2015.
In April 2016, we entered into a settlement agreement with Paragon Offshore (following the execution of an agreement in principle in February 2016) under which, in exchange for a full and unconditional release of any claims by Paragon Offshore in connection with the Spin-off (including fraudulent conveyance claims that could be brought on behalf of Paragon Offshore’s creditors), we agreed to assume the administration of Mexican tax claims for specified years up to and including 2010, as well as the related bonding obligations and certain of the related tax liabilities. The settlement agreement with Paragon Offshore is subject to the approval of Paragon Offshore's bankruptcy plan by the bankruptcy court. On October 28, 2016, the bankruptcy court having

31



jurisdiction over the Paragon Offshore bankruptcy denied confirmation of Paragon Offshore’s bankruptcy plan. On January 18, 2017, Paragon Offshore announced that it had reached an agreement in principle with an ad hoc committee of secured debt holders on a term sheet to support a new bankruptcy plan. The term sheet contemplates that the existing settlement agreement between Noble and Paragon Offshore will be adopted under the new bankruptcy plan. Paragon Offshore also stated that it will seek to obtain court approval of the new bankruptcy plan as soon as possible in the first half of 2017. Paragon Offshore’s unsecured creditors are not parties to the agreement in principle, and have formed an ad hoc committee which we expect to oppose Paragon's new bankruptcy plan, including our settlement. There can be no assurance that the bankruptcy court will ultimately approve our settlement agreement with Paragon Offshore or Paragon Offshore’s bankruptcy plan. If for any reason the agreement is not approved by the bankruptcy court or included as part of an approved plan or Paragon Offshore fails to exit bankruptcy, Paragon Offshore or its creditors could become adverse to us in any potential litigation relating to the Spin-off, including any alleged fraudulent conveyance claim in connection with the creation of Paragon Offshore as a stand-alone entity. For additional information regarding the Spin-off, see Part II, Item 8, “Financial Statements and Supplementary Data, Note 2Spin-off of Paragon Offshore plc ("Paragon Offshore")” and Part II, Item 8, “Financial Statements and Supplementary Data, Note 17Commitments and Contingencies.”
Prior to the completion of the Spin-off, Noble 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.
Master Separation Agreement (“MSA”)
The general terms and conditions relating to the separation and Spin-off are set forth in the MSA. The MSA identifies the assets transferred, liabilities assumed and contracts assigned either to Paragon Offshore by us or by Paragon Offshore to us in the separation and describes when and how these transfers, assumptions and assignments would occur. The MSA provides for, among other things, Paragon Offshore’s responsibility for liabilities relating to its business and the responsibility of Noble for liabilities related to our, and in certain limited cases, Paragon Offshore’s business, in each case irrespective of when the liability arose. The MSA also contains indemnification obligations and ongoing commitments by us and Paragon Offshore.
Employee Matters Agreement (“EMA”)
The EMA allocates liabilities and responsibilities between us and Paragon Offshore relating to employment, compensation and benefits and other employment related matters.
Tax Sharing Agreement
The tax sharing agreement provides for the allocation of tax liabilities and benefits between us and Paragon Offshore and governs the parties’ assistance with tax-related claims.
Transition Services Agreements
Under two transition services agreements, we agreed to continue, for a limited period of time, to provide various interim support services to Paragon Offshore, and Paragon Offshore agreed to provide various interim support services to us, including providing operational and administrative support for our remaining Brazilian operations. As of May 2016, we no longer had any rigs operating in Brazil.

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Contract Drilling Services Backlog
We maintain a backlog (as defined below) of commitments for contract drilling services. The following table sets forth, as of December 31, 2016, the amount of our contract drilling services backlog and the percent of available operating days committed for the periods indicated:
 
 
 

 
Year Ending December 31,
 
 
Total
 
2017
 
2018
 
2019
 
2020
 
2021-2023
 
 
(In millions)
Contract Drilling Services Backlog
 
 

 
 

 
 

 
 

 
 

 
 

Semisubmersibles/Drillships (3)(5)
 
$
2,252

 
$
537

 
$
459

 
$
348

 
$
326

 
$
582

Jackups (2)
 
1,027

 
468

 
285

 
159

 
115

 

Total (1)
 
$
3,279

 
$
1,005

 
$
744

 
$
507

 
$
441

 
$
582

Percent of Available Days Committed (4)
 
 

 
 

 
 

 
 

 
 

 
 

Semisubmersibles/Drillships
 
 

 
33
%
 
29
%
 
22
%
 
21
%
 
13
%
Jackups
 
 

 
71
%
 
36
%
 
7
%
 
5
%
 
%
Total
 
 

 
52
%
 
32
%
 
15
%
 
13
%
 
7
%
(1)
Some of our drilling contracts provide the customer with certain early termination rights and, in very limited cases, these termination rights require minimal or no notice or financial penalties. No notifications of contract terminations have been received as of February 24, 2017.
(2)
Our Saudi Aramco contract rates were adjusted downward for 2016. Given current market conditions and based on discussions with the customer, we do not expect the rates to return to the original contract rates. Instead, we expect the contract rates to be in the general range of the amended rates for 2016 through the end of each respective contract and the 2017 rates for the Noble Joe Beall and Noble Gene House were recently confirmed within this range. This December 31, 2016 backlog has been prepared assuming the reduced rates for 2016 apply for the remainder of the contract.
(3)
As previously reported, three of our 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 long-term 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 and the Noble Globetrotter II for up to two years, each at a special stacking rate. Shell has exercised its right and beginning late December 2016 we idled the Noble Globetrotter II at a rate of $185,000 per day. We expect the Noble Bully II will be idled at a rate of $200,000 per day before May 1, 2017. 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.
(4)
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. Percentages take into account additional capacity from our newbuild rig that commenced operations during 2016.
(5)
Noble and a subsidiary of Shell are involved in joint ventures that own and operate both the Noble Bully I and the Noble Bully II. Pursuant to these agreements, each party has an equal 50 percent share in both vessels. As of December 31, 2016, the combined amount of backlog for these rigs totals $646 million, all of which is included in backlog. Noble’s proportional interest in the backlog for these rigs totals $323 million.
Our contract drilling services backlog reflects estimated future revenues attributable to both signed drilling contracts and letters of intent that we expect to result in binding drilling contracts.  A letter of intent is generally subject to customary conditions, including the execution of a definitive drilling contract. It is possible that some customers that have entered into letters of intent will not enter into signed drilling contracts. As of December 31, 2016, our contract drilling services backlog did not include any letters of intent.
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 Shell mentioned above, utilize the idle period and floor rates as described in Footnote (3) to the Backlog table above. The reported contract drilling services backlog does not include amounts representing revenues for mobilization, demobilization and contract preparation, which are not expected to be

33



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 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 set forth 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. Please read Part I, Item 1A, “Risk Factors—We can provide no assurance that our current backlog of contract drilling revenue will be ultimately realized.”
As of December 31, 2016, Shell and Statoil represented approximately 69 percent and 18 percent of our backlog, respectively.
RESULTS OF OPERATIONS
2016 Compared to 2015
Net loss from continuing operations attributable to Noble-UK for 2016 was $930 million, or $3.82 per diluted share, on operating revenues of $2.3 billion, compared to net income from continuing operations for 2015 of $511 million, or $2.06 per diluted share, on operating revenues of $3.4 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 2016 and 2015, would be the same as the information presented below regarding Noble-UK in all material respects, except operating loss for Noble-Cayman for the year ended December 31, 2016 and operating income for the year ended December 31, 2015 was $30 million lower and $29 million higher, respectively, than operating loss and income for Noble-UK for the same periods. The operating income or loss difference is primarily a result of executive costs directly attributable to Noble-UK for operations support and stewardship related services.
Rig Utilization, Operating Days and Average Dayrates
Operating results for our contract drilling services segment are dependent on three primary metrics: rig utilization, operating days and dayrates. The following table sets forth the average rig utilization, operating days and average dayrates for our rig fleet for 2016 and 2015:
 
 
Average Rig
Utilization (1)
 
Operating
Days (2)
 
Average
Dayrates
 
 
2016
 
2015
 
2016
 
2015
 
% Change
 
2016
 
2015
 
% Change
Jackups
 
83
%
 
85
%
 
3,966

 
3,967

 
 %
 
$
126,279

(3) 
$
162,348

 
(22
)%
Semisubmersibles
 
22
%
 
63
%
 
649

 
1,876

 
(65
)%
 
256,122

 
445,320

(6) 
(42
)%
Drillships
 
82
%
 
100
%
 
2,408

 
3,257

 
(26
)%
 
654,074

(4) 
547,265

(5) 
20
 %
Total
 
66
%
 
84
%
 
7,023

 
9,100

 
(23
)%
 
$
319,256

(7) 
$
358,423

(7) 
(11
)%
 
(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)
Includes the contract drilling services revenue portion of the Noble Tom Prosser contract cancellation with Quadrant Energy Australia Limited ("Quadrant") during the current year. Exclusive of the cancellation agreement, the average dayrate for the year ended December 31, 2016 would have been $122,151 for jackups.
(4)
Includes the impact of the FCX Settlement during the current year. Exclusive of this item, the average dayrate for the year ended December 31, 2016 would have been $490,868 for drillships.
(5)
Includes the contract drilling services revenue portion of the Noble Discoverer contract cancellation with Shell during 2015. Exclusive of the cancellation agreement, the average dayrate for the year ended December 31, 2015 would have been $502,878 for drillships.

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(6)
Includes the contract drilling services revenue portion of the Noble Homer Ferrington arbitration award during 2015. Exclusive of the arbitration award, the average dayrate for the year ended December 31, 2015 would have been $372,512 for semisubmersibles.
(7)
Exclusive of the items listed above, the total average dayrates would have been $260,962 and $327,547 for the years ended December 31, 2016 and 2015, respectively.
Contract Drilling Services
The following table sets forth the operating results for our contract drilling services segment for 2016 and 2015 (dollars in thousands):
 
 
 
 
Change
 
 
2016
 
2015
 
$
 
%
Operating revenues:
 
 
 
 
 
 
 
 
Contract drilling services
 
$
2,242,200

 
$
3,261,610

 
$
(1,019,410
)
 
(31
)%
Reimbursables (1)
 
59,432

 
88,597

 
(29,165
)
 
(33
)%
Other
 
433

 

 
433

 
**

 
 
$
2,302,065

 
$
3,350,207

 
$
(1,048,142
)
 
(31
)%
Operating costs and expenses:
 
 
 
 
 
 
 
 
Contract drilling services
 
$
879,438

 
$
1,232,529

 
$
(353,091
)
 
(29
)%
Reimbursables (1)
 
45,608

 
68,182

 
(22,574
)
 
(33
)%
Depreciation and amortization
 
587,999

 
611,748

 
(23,749
)
 
(4
)%
General and administrative
 
69,258

 
76,843

 
(7,585
)
 
(10
)%
Loss on impairment
 
1,458,749

 
405,512

 
1,053,237

 
**

 
 
3,041,052

 
2,394,814

 
646,238

 
27
 %
Operating income (loss)
 
$
(738,987
)
 
$
955,393

 
$
(1,694,380
)
 
(177
)%
(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.
**
Not a meaningful percentage.
Operating Revenues. Changes in contract drilling services revenues for the current year as compared to the prior year were driven by a 23 percent decrease in operating days, which reduced revenues by $744 million, as well as an 11 percent decrease in average dayrates, which decreased revenues by $275 million. Contract drilling services revenues decreased for the current year as compared to the prior year by $669 million, $207 million and $143 million on our semisubmersibles, drillships and jackups, respectively.
During the prior year, we recognized $137 million of dayrate revenues related to the Noble Homer Ferrington arbitration award. Excluding the arbitration award in the prior year, semisubmersible revenues decreased by $533 million, driven by a 65 percent decline in operating days and a 31 percent decline in average dayrates, resulting in a $457 million and a $76 million decline in revenues, respectively, from the prior year. The decrease in both operating days and average dayrates was primarily attributable to contract completions during the current year for the Noble Jim Day, Noble Clyde Boudreaux, Noble Amos Runner, Noble Danny Adkins and Noble Dave Beard. The decrease in revenue was partially offset by the Noble Paul Romano, which operated in the majority of the current year but was off contract the majority of the prior year.
During the current year, we recognized $393 million of dayrate revenues related to the FCX Settlement, of which $14 million related to the termination date (May 10, 2016) valuation of the contingent payments, and during the prior year, we recognized $145 million of dayrate revenues related to the Noble Discoverer cancellation agreement with Shell. Excluding these items in the current year and prior year, drillship revenues decreased by $456 million driven by a 26 percent decrease in operating days and a 2 percent decrease in average dayrates, resulting in a $427 million and a $29 million decrease in revenues, respectively, from the prior year. The decrease in both operating days and average dayrates was the result of the retirement and subsequent sale of the Noble Discoverer, which operated in the prior year, the contract cancellations of the Noble Sam Croft and the Noble Tom Madden in the current year and increased shipyard days on the Noble Globetrotter I in the current year. Additionally, decreases in dayrates on contracts across the drillship fleet contributed to the decrease in average dayrates.
During the current year, we recognized $16 million of dayrate revenues related to the Noble Tom Prosser cancellation agreement with Quadrant. Excluding the cancellation agreement in the current year, jackup revenues decreased by $159 million

35



driven by a 25 percent decrease in average dayrates from the prior year, while operating days remained consistent in the current year as compared to the prior year. The decrease in average dayrates was primarily driven by the Noble Regina Allen, which was off contract during a majority of the current year but operated during the prior year, the retirement and subsequent sale of the Noble Charles Copeland, which operated in the prior year and the Noble Houston Colbert, which completed its contract during the current year. Additionally, unfavorable dayrate changes on contracts across the jackup fleet contributed to the decrease in average dayrates. This was partially offset by the commencement of the newbuilds, the Noble Sam Hartley and the Noble Lloyd Noble, which commenced their contracts in January 2016 and November 2016, respectively, the Noble Mick O'Brien which commenced its contract in July 2016, but was off contract during the prior year and the Noble Tom Prosser, which commenced operations in October 2015 and operated through October 2016.
Operating Costs and Expenses. Contract drilling services operating costs and expenses decreased $353 million for the current year as compared to the prior year. Rigs that were operating in the prior period, but were idle or stacked most of the current period contributed $255 million to the decrease in operating costs. These decreases were recognized across all cost categories, but primarily attributable to labor ($125 million), repairs and maintenance ($53 million), and other-rig related costs. There was also a $95 million decrease in operating costs primarily related to the retirement of the Noble Discoverer, Noble Charles Copeland, and Noble Max Smith. Additional cost control measures led to a decrease of $62 million across rigs with comparable operating days in the periods. This decrease was primarily recognized in repair and maintenance cost ($21 million), labor costs ($12 million), as well as savings realized in training fees ($8 million), operations support ($8 million), and other-rig related costs. This was partially offset by a $59 million increase related to rigs that had additional operating days during 2016, including two newbuilds, which commenced operations during the current year.
The $24 million decrease in depreciation and amortization in the current year from the prior year was primarily attributable to the retirement and subsequent sale of the Noble Discoverer and Noble Charles Copeland and certain capital spare equipment, partially offset by the newbuild rigs and other drilling equipment placed in service.
Loss on impairment during the current year of $1.5 billion was recognized after we identified indicators that the carrying value of certain assets in our fleet may not be recoverable. As a result of our testing, we determined that the carrying amounts of certain drilling units were impaired. In connection with our annual analysis, we impaired the carrying values for the Noble Amos Runner, the Noble Clyde Boudreaux and the Noble Dave Beard to the fair value. The impairment charge related to these units was approximately $1 billion. We also decided to retire from service our semisubmersible, the Noble Max Smith, which we sold during the fourth quarter for approximately $1 million, and we recognized an impairment charge of approximately $165 million.
Also in the fourth quarter of 2016, in connection with our impairment analysis, we concluded that the semisubmersible, the Noble Homer Ferrington and certain capital spare equipment would not be utilized in the foreseeable future and we recognized an impairment charge of approximately $120 million and $154 million, respectively. In the second quarter of 2016, we recognized a charge of approximately $17 million for the impairment of certain capital spare equipment based upon our decision to dispose of this equipment.
Other Income and Expenses
General and administrative expenses. Overall, general and administrative expenses decreased $8 million in the current year as compared to the prior year primarily as a result of decreased employee related costs.
Interest Expense, net of amount capitalized. Interest expense, net of amount capitalized, increased $9 million in the current year as compared to the prior year. The increase is a result of a full period of interest in respect of the senior notes issued in March 2015, an increase in applicable interest rates on those senior notes due to the downgrading of our credit rating below investment grade during 2016 and lower capitalized interest in 2016 as compared to 2015, due to the completion of construction of two newbuild jackups, the Noble Sam Hartley and the Noble Lloyd Noble, which commenced their respective contracts in January 2016 and November 2016. During the current year, we capitalized approximately 9 percent of total interest charges versus approximately 10 percent during the prior year. These expense increases were partially offset by the repayment of our maturing $350 million 3.45% Senior Notes and our $300 million 3.05% Senior Notes in August 2015 and March 2016, respectively, the current year retirement of a portion of our 2020, 2021 and 2022 Senior Notes as a result of two different tender offers in the current year as compared to the prior year.
Interest Income and Other, Net. Interest income and other, net has decreased $36 million in the current year as compared to the prior year. The decrease is primarily the result of the prior year including $30 million of interest income recognized in connection with the Noble Homer Ferrington arbitration award and $5 million of interest received on a U.S. Internal Revenue Service (“IRS”) tax refund for the years 2006 and 2007.
Gain on extinguishment of debt, net. Gain on debt extinguishment increased $18 million in the current year compared to the prior year. This increase is due to the completion of cash tender offers on our 4.9% Senior Notes due 2020 (the “4.9% Senior Notes”), 4.625% Senior Notes due 2021 (the “4.625% Senior Notes”), and 3.95% Senior Notes due 2022 (the “3.95% Senior

36



Notes”) in the current year. During the year ended December 31, 2016, we purchased $798 million of these Senior Notes for $774 million, plus accrued interest.
Income Tax Benefit (Provision). Our income tax provision decreased $268 million in the current year, of which $126 million related to the impact of impairment charges recognized in 2016, the Quadrant contract cancellation payment, the FCX Settlement, retirement of a portion of our 2020, 2021 and 2022 Senior Notes as a result of tender offers and discrete tax items in the current year and $27 million related to the Noble Homer Ferrington arbitration award in the prior year. Excluding the impact of these items, taxes decreased by $115 million as a result of lower pre-tax income partially offset by a higher effective tax rate in the current year, primarily from our geographical mix of pre-tax income.
2015 Compared to 2014
General
Net income from continuing operations attributable to Noble-UK for 2015 was $511 million, or $2.06 per diluted share, on operating revenues of $3.4 billion, compared to net loss from continuing operations for 2014 of $152 million, or $0.60 per diluted share, on operating revenues of $3.2 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 2015 and 2014, would be the same as the information presented below regarding Noble-UK in all material respects, except operating income for Noble-Cayman for the years ended December 31, 2015 and 2014 was $29 million and $50 million higher, respectively, than operating income for Noble-UK for the same periods. The operating income difference is primarily a result of executive costs directly attributable to Noble-UK for operations support and stewardship related services. In addition, we had non-recurring costs of $63 million in 2014 related to the Spin-off, which we recognized as part of discontinued operations at the Noble-UK level.
Rig Utilization, Operating Days and Average Dayrates
Operating results from continuing operations for our contract drilling services segment are dependent on three primary metrics: rig utilization, operating days and dayrates. The following table sets forth the average rig utilization, operating days and average dayrates for our rig fleet for 2015 and 2014: 
 
 
Average Rig
Utilization (1)
 
Operating
Days (2)
 
Average
Dayrates
 
 
2015
 
2014
 
2015
 
2014
 
% Change
 
2015
 
2014
 
% Change
Jackups
 
85
%
 
91
%
 
3,967

 
3,682

 
8
 %
 
$
162,348

 
$
177,345

 
(8
)%
Semisubmersibles (3)
 
63
%
 
71
%
 
1,876

 
2,844

 
(34
)%
 
445,230

 
409,848

 
9
 %
Drillships (4)
 
100
%
 
100
%
 
3,257

 
2,756

 
18
 %
 
547,265

 
482,426

 
13
 %
Other
 
N/A

 
%
 
N/A

 

 
**

 
N/A

 

 
**

Total
 
84
%
 
86
%
 
9,100

 
9,282

 
(2
)%
 
$
358,423

 
$
339,154

 
6
 %
(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)
Includes the contract drilling services revenue portion of the Noble Homer Ferrington arbitration award during the current year. Exclusive of the arbitration award, the average dayrate for the year ended December 31, 2015 was $372,512.
(4)
Includes the contract drilling services revenue portion of the Noble Discoverer contraction cancellation with Shell during the current year. Exclusive of the cancellation agreement, the average dayrate for the year ended December 31, 2015 was $502,878.
**
Not a meaningful percentage.


37



Contract Drilling Services
The following table sets forth the operating results from continuing operations for our contract drilling services segment for 2015 and 2014 (dollars in thousands):
 
 
 
 
 
 
Change
 
 
2015
 
2014
 
$
 
%
Operating revenues:
 
 

 
 

 
 

 
 

Contract drilling services
 
$
3,261,610

 
$
3,147,859

 
$
113,751

 
4
 %
Reimbursables (1)
 
88,597

 
82,393

 
6,204

 
8
 %
Other
 

 
1

 
(1
)
 
**

 
 
$
3,350,207

 
$
3,230,253

 
$
119,954

 
4
 %
Operating costs and expenses:
 
 

 
 

 
 

 
 

Contract drilling services
 
$
1,232,529

 
$
1,500,512

 
$
(267,983
)
 
(18
)%
Reimbursables (1)
 
68,182

 
65,080

 
3,102

 
5
 %
Depreciation and amortization
 
611,748

 
608,590

 
3,158

 
1
 %
General and administrative
 
76,843

 
106,278

 
(29,435
)
 
(28
)%
Loss on impairment
 
405,512

 
745,428

 
(339,916
)
 
(46
)%
 
 
2,394,814

 
3,025,888

 
(631,074
)
 
(21
)%
Operating income
 
$
955,393

 
$
204,365

 
$
751,028

 
367
 %
(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.
**
Not a meaningful percentage.
Operating Revenues. Changes in contract drilling services revenues for the current year as compared to the prior year were driven by a 6 percent increase in average dayrates, partially offset by a 2 percent decrease in operating days. The 6 percent increase in average dayrates increased revenues by approximately $175 million, while the 2 percent decrease in operating days decreased revenues by $61 million.
The increase in contract drilling services revenues relates to our drillships which generated approximately $453 million more revenue in 2015. This amount was offset by decreases in revenues for our semisubmersibles and jackups, which declined by $330 million and $9 million, respectively, from the prior year.
During the current year, we recognized $145 million of dayrate revenues related to the Noble Discoverer cancellation agreement with Shell. Excluding the cancellation agreement, drillship revenues increased by $308 million driven by an 18 percent increase in operating days and a 4 percent increase in average dayrates, resulting in a $242 million and a $66 million increase in revenues, respectively, from the prior year. The increase in both average dayrates and operating days was the result of a full year of operations from the Noble Sam Croft and the Noble Tom Madden, which commenced operations in July 2014 and November 2014, respectively.
During the current year, we recognized $137 million of dayrate revenues related to the Noble Homer Ferrington arbitration award. Excluding the arbitration award, semisubmersible revenues decreased by $467 million driven by a 34 percent decline in operating days and a 9 percent decline in average dayrates, resulting in a $397 million and a $70 million decline in revenues, respectively, from the prior year. The decrease in both operating days and average dayrates was primarily attributable to the retirement of the Noble Jim Thompson, the Noble Driller and the Noble Paul Wolff as a result of our decision to retire these rigs based on the declining market conditions. Additionally, the Noble Max Smith was operational during the prior year but was off contract during the current year and the Noble Paul Romano was operational during the prior year but was off contract for a significant portion of the current year. This was partially offset by the Noble Amos Runner, which operated during the current year but was in the shipyard undergoing regulatory inspections and maintenance during a portion of the prior year.
The decrease in jackup revenues was driven by an 8 percent decrease in average dayrates, which resulted in a $59 million decrease in revenues driven by unfavorable dayrate changes on contracts across the jackup fleet. This was partially offset by an 8 percent increase in operating days, which resulted in a $50 million increase in revenues from the prior year. The increase in operating days was the result of a full year of revenue from the Noble Houston Colbert and the Noble Sam Turner, which began operations in March 2014 and August 2014, respectively, coupled with the commencement of the Noble Tom Prosser during October 2015. Additionally, the Noble David Tinsley experienced full utilization in the current year but was off contract for a

38



majority of the prior year. This was partially offset by the Noble Mick O’Brien, which was available during the current year but was under contract for a substantial portion of 2014.
Operating Costs and Expenses. Contract drilling services operating costs and expenses decreased $268 million for the current year as compared to the prior year. This was due to decreased costs of $117 million related to the retirement of the Noble Jim Thompson, the Noble Driller and the Noble Paul Wolff and $83 million related to idle or stacked rigs. This was partially offset by crew-up and operating expenses for our newbuild rigs as they commenced, or prepared to commence, operating under contracts, which added approximately $118 million in expense in the current year. Excluding these factors, contract drilling services costs decreased by $186 million. This decrease was driven by a $41 million decrease in labor costs due to the termination of retention bonuses and decreases in certain non-contractual crew positions, a $40 million decrease in mobilization and transportation expenses related to certain rig moves during the prior year, a $32 million decrease in repair and maintenance costs, a $24 million decrease in operations support costs, a $16 million decrease in other rig-related expenses, an $11 million decrease in insurance costs related to our policy renewal in March 2015, a $12 million decrease in fuel and travel rotational expenses and a $10 million decrease for the reimbursement of costs and fees related to the Noble Homer Ferrington arbitration award during the current year that were previously recognized through contract drilling services operating costs and expenses.
Depreciation and amortization increased $3 million in 2015 over 2014, which is primarily attributable to newbuild rigs placed in service partially offset by the retirement of the three semisubmersible rigs discussed above.
Loss on impairment during the current year of $406 million relates to the Noble Discoverer and the Noble Charles Copeland, which we elected to discontinue marketing due to current market conditions. Additionally, as a result of a fourth quarter review of capital spare equipment, we elected to retire certain capital spare equipment. Loss on impairment during the prior year of $745 million relates to a $685 million charge on three of our semisubmersibles, the Noble Driller, the Noble Jim Thompson and the Noble Paul Wolff, which we decided not to actively market as a result of the declining market conditions, and a $60 million impairment charge for goodwill that originated from the acquisition of Frontier in 2010.
Other Income and Expenses
General and administrative expenses. Overall, general and administrative expenses decreased $30 million in 2015 from 2014, primarily as a result of decreased office and other expenses of $13 million, employee related costs of $10 million and legal and other professional fees of $7 million.
Interest Expense, net of amount capitalized. Interest expense, net of amount capitalized, increased $59 million in 2015 from 2014. The increase is a result of the issuance of $1.1 billion of Senior Notes in March 2015, coupled with lower capitalized interest in the current year as compared to the prior year due primarily to the completion of construction on four of our newbuild jackups and two of our newbuild drillships. During the current year, we capitalized approximately 10 percent of total interest charges versus approximately 23 percent during the prior year.
Interest Income and Other, Net. Interest income and other, net increased $38 million in the current year as compared to the prior year. The increase is primarily the result of $30 million of interest income recognized in connection with the Noble Homer Ferrington arbitration award, coupled with $5 million of interest received on a U.S. Internal Revenue Service (“IRS”) tax refund for the years 2006 and 2007 during the current year.
Income Tax Provision. Our income tax provision increased $53 million in the current year, of which $27 million related to the Noble Homer Ferrington arbitration award. Excluding the arbitration award, our income tax provision increased by $26 million. Excluding the impact of the impairment charges recognized in 2015 and 2014 and the Noble Discoverer contract cancellation payment in the fourth quarter of 2015, taxes decreased $7 million as a result of a lower worldwide effective tax rate, partially offset by higher pre-tax income. The 13 percent decrease in the worldwide effective tax rate during the current year generated a $19 million decrease to income tax expense, and was primarily a result of the geographic mix of pre-tax income, the effect of lower downtime and various discrete items. This was partially offset by a 9 percent increase in pre-tax earnings, which generated a $12 million increase in income tax expense.
Discontinued Operations. There was no activity related to discontinued operations during the current year. During the prior year, net income from discontinued operations was $161 million. In 2014, revenues reported within discontinued operations were $1.0 billion and operating income included within discontinued operations was $220 million.
LIQUIDITY AND CAPITAL RESOURCES
Overview
Cash flows from discontinued operations for the year ended December 31, 2014 are combined with cash flows from continuing operations within each cash flow statement category on our Consolidated Statements of Cash Flows. Net cash from

39



operating activities in 2016 was $1.1 billion, compared to $1.8 billion and $1.8 billion in 2015 and 2014, respectively. The decrease in net cash from operating activities is primarily attributable to a reduction in operating income. We had working capital of $559 million and $377 million at December 31, 2016 and 2015, respectively.
Net cash used in investing activities in 2016 was $670 million, which compared to $433 million and $2.1 billion in 2015 and 2014, respectively. The increase in net cash used is primarily attributable to newbuild expenditures, partially offset by a reduction of cash used for capital expenditures during 2016.
Net cash used in financing activities in 2016 and 2015 was $245 million and $886 million, respectively, which compared to net cash provided from financing activities of $285 million in 2014. During 2016, our primary uses of cash included the debt extinguishment of $300 million of 3.05% Senior Notes, coupled with dividend payments to shareholders and noncontrolling interests of approximately $48 million and $86 million, respectively. Although we issued $1 billion of Senior Notes in December 2016, this amount was substantially offset by early repayments of a portion of our 2020, 2021 and 2022 Senior Notes through two separate tender offers during 2016.
During 2015, our primary uses of cash from financing activities included the repayment of $350 million of 3.45% Senior Notes in August 2015, coupled with dividends to shareholders and noncontrolling interests of approximately $316 million and $72 million, respectively, and the repurchase of 6.2 million shares for $101 million. Although we issued $1.1 billion of Senior Notes in March 2015, this amount was substantially offset by a net reduction in indebtedness outstanding on our Credit Facilities and commercial paper program during 2015 as a result of the application of proceeds from the Senior Notes offering.
Our principal source of capital in the Current Period was cash generated from operating activities coupled with the $1 billion Senior Notes offering in December 2016. Cash generated during the Current Period was primarily used for the following:
early repayment of a portion of our 2020, 2021 and 2022 Senior Notes;
normal recurring operating expenses;
repayment of our maturing $300 million 3.05% Senior Notes;
the final payment for the Noble Lloyd Noble and capital expenditures; and
payment of three quarterly dividends, where fourth quarter dividends were cancelled
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
repayment of debt and interest.
We currently expect to fund these cash flow needs with cash generated by our operations, cash on hand, borrowings under our existing credit facility, potential issuances of long-term debt, or asset sales. 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, 2016, we had a total contract drilling services backlog of approximately $3.3 billion. Our backlog as of December 31, 2016 includes a commitment of 52 percent of available days for 2017. See “Contract Drilling Services Backlog” for additional information regarding our backlog.
Capital Expenditures
Capital expenditures, including capitalized interest, totaled $660 million, $423 million and $2.1 billion for 2016, 2015 and 2014, respectively. Capital expenditures during 2016 consisted of the following:
$203 million for sustaining capital, major projects, subsea related expenditures and upgrades and replacements to drilling equipment;
$435 million in newbuild expenditures, including costs for the Noble Lloyd Noble; and
$22 million in capitalized interest.
Our total capital expenditure budget for 2017 is approximately $115 million, which is currently anticipated to be spent as follows:
approximately $76 million for sustaining capital; and  
$39 million for major projects, subsea related expenditures and upgrades and replacements to drilling equipment.
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 and changes in design criteria or specifications during repair or construction.

40



Dividends
Our most recent quarterly dividend payment to shareholders, totaling approximately $5 million (or $0.02 per share), was declared on July 22, 2016 and paid on August 8, 2016 to holders of record on August 1, 2016.
Our Board of Directors eliminated our quarterly cash dividend of $0.02 per share, beginning with the Company's fourth quarter dividend.
The declaration and payment of dividends require 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. Noble-UK is not permitted to pay dividends out of share capital, which includes share premiums. The resumption of the payment of future dividends will depend on our results of operations, financial condition, cash requirements, future business prospects, contractual restrictions and other factors deemed relevant by our Board of Directors.
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. In December 2014, we received shareholder approval to repurchase up to 37 million ordinary shares, or approximately 15 percent of our outstanding ordinary shares at the time of the shareholder approval. The authority to make such repurchases expired at the end of the Company’s 2016 annual general meeting of shareholders, which was held on April 22, 2016. During 2015, we repurchased 6.2 million of our ordinary shares covered by this authorization at an average price of $16.10 per share, excluding commissions and stamp tax, for a total cost of approximately $101 million. All share repurchases were made in the open market and were pursuant to the share repurchase program discussed above. All shares repurchased during 2015 were immediately cancelled. During the year ended December 31, 2016, we did not repurchase any of our shares.
Share repurchases for each of the three years ended December 31 are as follows:
Year Ended
December 31,
 
Total Number
of Shares
Purchased
 
Total Cost (1)                           (in thousands)
 
Average
Price Paid
per Share (1)
2016
 

 
$

 
$

2015
 
6,209,400

 
100,630

 
16.21

2014
 
6,769,891

 
154,145

 
22.77

(1)
The total cost and average price paid per share includes the impact of commissions and stamp tax for share repurchases made in the open market.
Credit Facilities and Senior Unsecured Notes
Credit Facilities and Commercial Paper Program
We currently have a five-year $2.4 billion senior unsecured credit facility that matures in January 2020 and is guaranteed by our indirect, wholly owned subsidiary, Noble Holding International Limited ("NHIL"), and Noble Holding Corporation ("NHC"). The credit facility provides us with the ability to issue up to $500 million in letters of credit. The issuance of letters of credit under the facility reduces the amount available for borrowing.
Throughout the term of the Five-Year Revolving Credit Facility, we pay a facility fee on the daily unused amount of the underlying commitment which ranges from 0.10 percent to 0.35 percent depending on our debt ratings. Effective February 2016, as a result of a reduction of our debt ratings, the facility fee increased to 0.275 percent from 0.15 percent. Effective July 2016, as a result of a reduction of our debt ratings, the facility fee increased to 0.35 percent from 0.275 percent. At December 31, 2016, based on our debt ratings on that date, the facility fee was 0.35 percent. At December 31, 2016, we had no borrowings outstanding or letters of credit issued.
In addition, our credit facility has provisions which vary the applicable interest rates based upon our debt ratings. Currently, the interest rate in effect is the highest permitted interest rate under the credit facility.
During 2016, we terminated our commercial paper program, which had allowed us to issue up to $2.4 billion in unsecured commercial paper notes. This termination does not reduce the capacity under our credit facility.
Debt Issuances
In December 2016, we issued $1 billion aggregate principal amount of 7.75% Senior Notes, which we issued through our indirect wholly-owned subsidiary, NHIL. The net proceeds of approximately $968 million, after estimated expenses, were primarily used to retire debt related to our tender offer and the remaining portion will be used for general corporate purposes.

41



In March 2015, we issued $1.1 billion aggregate principal amount of Senior Notes, which we issued through our indirect wholly-owned subsidiary, NHIL. These Senior Notes were issued in three separate tranches, consisting of $250 million of 4.00% Senior Notes due 2018, $450 million of 5.95% Senior Notes due 2025 and $400 million of 6.95% Senior Notes due 2045. The net proceeds of approximately $1.08 billion, after estimated expenses, were used to repay indebtedness outstanding under our Credit Facilities and commercial paper program.
Interest Rate Adjustments
In February 2016 Moody’s Investors Service downgraded our debt rating below investment grade, resulting in an interest rate increase of 1.00% on each of certain notes. Effective March 16, 2016, the interest rate on our Senior Notes due 2018 increased to 5.00% as a result of the downgrade. Effective April 1, 2016, the interest rates on our Senior Notes due 2025 and Senior Notes due 2045 increased to 6.95% and 7.95%, respectively, as a result of the downgrade.
In July 2016, S&P Global Ratings issued an additional downgrade, resulting in an interest rate increase of 0.25% each, of the same notes. Effective September 16, 2016, the interest rate on our Senior Notes due 2018 increased to 5.25%. Effective October 1, 2016, the interest rates on our Senior Notes due 2025 and Senior Notes due 2045 increased to 7.20% and 8.20%, respectively. The weighted average coupon of all three tranches is now 7.12%.
In December 2016, S&P Global Ratings issued an additional downgrade, resulting in an interest rate increase of 0.5% each, of the same notes. Effective March 16, 2017, the interest rate on our Senior Notes due 2018 is scheduled to increase to 5.75% as a result of the downgrade. Effective April 1, 2017, the interest rates on our Senior Notes due 2025 and Senior Notes due 2045 are scheduled to increase to 7.70% and 8.70%, respectively, as a result of this downgrade.
The interest rates on these Senior Notes may be further increased if our debt ratings were to be downgraded further (up to a maximum of an additional 25 basis points) or decreased if our debt ratings were to be raised. Our other outstanding senior notes, including the Senior Notes due 2024 issued in December 2016, do not contain provisions varying applicable interest rates based upon our credit ratings. Please see discussion on the credit facility above as it relates to the interest rate adjustments on our five-year senior unsecured credit facility.
Debt Tender Offers and Repayments
In December 2016, we commenced cash tender offers for our 4.90% Senior Notes due 2020, of which $468 million principal amount was outstanding, our 4.625% Senior Notes due 2021, of which $397 million principal amount was outstanding and our 3.95% Senior Notes due 2022, of which $400 million principal amount was outstanding. On December 28, 2016, we purchased $762 million of these Senior Notes for $750 million, plus accrued interest, using the net proceeds of the $1 billion Senior Notes due 2024 issuance in December 2016. As a result of this transaction, we recognized a net gain of approximately $7 million.
In March 2016, we commenced cash tender offers for our 4.90% Senior Notes due 2020, of which $500 million principal amount was outstanding, and our 4.625% Senior Notes due 2021, of which $400 million principal amount was outstanding. On April 1, 2016, we purchased $36 million of these Senior Notes for $24 million, plus accrued interest, using cash on hand. As a result of this transaction, we recognized a net gain of approximately $11 million during the current year.
We anticipate using cash on hand to repay the outstanding balance of our $300 million 2.50% Senior Notes, maturing in March 2017.
In March 2016, we repaid our $300 million 3.05% Senior Notes using cash on hand. In August 2015, we repaid our $350 million 3.45% Senior Notes using cash on hand.
Covenants
The credit facility is guaranteed by our indirect, wholly-owned subsidiaries, NHIL and NHC. The credit facility contains a covenant that limits our ratio of debt to total tangible capitalization, as defined in the credit facility, to 0.60. At December 31, 2016, our ratio of debt to total tangible capitalization was approximately 0.41. We were in compliance with all covenants under the credit facilities as of December 31, 2016.
In addition to the covenants from the credit facility noted 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. In addition, there are restrictions on incurring or assuming certain liens and on entering into sale and lease-back transactions. At December 31, 2016, we were in compliance with all of our debt covenants.

42



Summary of Contractual Cash Obligations and Commitments
The following table summarizes our contractual cash obligations and commitments at December 31, 2016 (in thousands):
 
 
 
 
Payments Due by Period
 
 
 
 
Total
 
2017
 
2018
 
2019
 
2020
 
2021
 
Thereafter
 
Other
Contractual Cash Obligations
 
 

 
 

 
 

 
 

 
 

 
 

 
 

 
 

Debt obligations
 
$
4,372,724

 
$
299,992

 
$
249,771

 
$
201,695

 
$
167,576

 
$
208,538

 
$
3,245,152

 
$

Interest payments
 
3,854,169

 
240,663

 
267,350

 
252,599

 
245,036

 
231,989

 
2,616,532

 

Operating leases
 
38,423

 
15,718

 
7,750

 
6,542

 
1,892

 
1,632

 
4,889

 

Pension plan contributions
 
132,535

 
12,629

 
10,478

 
10,911

 
11,457

 
15,275

 
71,785

 

Tax reserves (1)
 
172,520

 

 

 

 

 

 

 
172,520

Total contractual cash obligations
 
$
8,570,371

 
$
569,002

 
$
535,349

 
$
471,747

 
$
425,961

 
$
457,434

 
$
5,938,358

 
$
172,520

(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 Note 13 to our accompanying consolidated financial statements.
At December 31, 2016, 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, 2016 (in thousands):
 
 
 

 
Amount of Commitment Expiration Per Period
 
 
Total
 
2017
 
2018
 
2019
 
2020
 
2021
 
Thereafter
Contractual Cash Obligations
 
 

 
 

 
 

 
 

 
 

 
 

 
 

Letters of credit
 
$
7,989

 
$
4,195

 
$
335

 
$

 
$

 
$

 
$
3,459

Total commercial commitments
 
$
7,989

 
$
4,195

 
$
335

 
$

 
$

 
$

 
$
3,459

CRITICAL ACCOUNTING POLICIES AND ESTIMATES
Our consolidated financial statements are impacted by the accounting policies used and the estimates and assumptions made by management during their preparation. Critical accounting policies and estimates that most significantly impact our consolidated financial statements are described below.
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 both December 31, 2016 and 2015 totaled $1.4 billion. These assets were primarily funded through partner equity contributions. Cash held by the Bully joint ventures totaled approximately $35 million at December 31, 2016 as compared to approximately $50 million at December 31, 2015. Operating revenues were $332 million, $334 million and $372 million in 2016, 2015 and 2014, respectively. Net income totaled $151 million, $154 million and $157 million in 2016, 2015 and 2014, respectively.
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, 2016 and 2015, we had $112 million and $761 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

43



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. Capitalized interest for the years ended December 31, 2016, 2015 and 2014 was $22 million, $25 million and $47 million, 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 $187 million and $202 million at December 31, 2016 and 2015, respectively. Depreciation expense from continuing operations related to overhauls and asset replacement totaled $86 million, $75 million and $77 million for the years ended December 31, 2016, 2015 and 2014, respectively.
We evaluate the impairment of property and equipment whenever events or changes in circumstances (including the decision to cold stack, retire or sale a rig) indicate that the carrying amount of an asset may not be recoverable. In addition, on an annual basis in the fourth quarter, we complete an impairment analysis on our rig fleet. 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, 2016, 2015, and 2014 we recognized a non-cash loss on impairment of $1.5 billion and $418 million, and $745 million, respectively, related to our long-lived assets. See Part II, Item 7, "Management Discussion and Analysis - Executive Overview," and Item 8, “Financial Statements and Supplementary Data, Note 12 - Loss on Impairment," for additional information.

Revenue Recognition
Our typical dayrate drilling contracts require our performance of a variety of services for a specified period of time. We determine progress towards completion of the contract by measuring efforts expended and the cost of services required to perform under a drilling contract, as the basis for our revenue recognition. Revenues generated from our dayrate-basis drilling contracts and labor contracts are recognized on a per day basis as services are performed and begin upon the contract commencement, as defined under the specified drilling or labor contract. Dayrate revenues are typically earned, and contract drilling expenses are typically incurred ratably over the term of our drilling contracts. We review and monitor our performance under our drilling contracts to confirm the basis for our revenue recognition. Revenues from bonuses are recognized when earned, and when collectability is reasonably assured.
In our dayrate drilling contracts, we typically receive compensation and incur costs for mobilization, equipment modification or other activities prior to the commencement of a contract. Any such compensation may be paid through a lump-sum payment or other daily compensation. Pre-contract compensation and costs are deferred until the contract commences. The deferred pre-contract compensation and costs are amortized into income or loss, using the straight-line method, over the term of the initial contract period, regardless of the activity taking place. This approach is consistent with the economics for which the parties have contracted. Once a contract commences, we may conduct various activities, including drilling and well bore related activities, rig maintenance and equipment installation, movement between well locations or other activities.
Deferred revenues from drilling contracts totaled $134 million and $180 million at December 31, 2016 and 2015, 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 $54 million at December 31, 2016 as compared to $78 million at December 31, 2015, and are included in either “Prepaid expenses and other current assets” or “Other assets” in the accompanying Consolidated Balance Sheets, based upon our expected time of recognition.
In April 2015, we agreed to contract dayrate reductions for five rigs working for Saudi Aramco, which were effective from January 1, 2015 through December 31, 2015. However, given current market conditions and based on discussions with the customer, we do not expect the rates to return to the original contract rates. In accordance with accounting guidance, we are recognizing the reductions on a straight-line basis over the remaining life of the existing Saudi Aramco contracts. At December 31, 2016 and 2015, four of the five original rigs had revenues recorded in excess of billings as a result of this recognition which totaled $18 million

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and $53 million, respectively, and are included in either “Prepaid expenses and other current assets” or “Other assets” 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.
During 2014, the 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 year. On December 19, 2016, we received the Revenue Agent Report ("RAR") from the IRS. We believe that we have accurately reported all amounts in our tax returns, and we will submit 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. We have also been informed by the IRS that our 2012 and 2013 tax returns will be examined, and we anticipate that examination beginning during 2017. The IRS exam team also completed its examination of two U.S. subsidiaries of Frontier Drilling for 2011, and proposed no changes to those returns.
Under the tax sharing agreement (“TSA”) entered into at the time of the Spin-off, Noble and Paragon Offshore are each responsible for the taxes that relate to their respective business and provide a corresponding indemnity.  In addition, in April 2016, we entered into a settlement agreement (following an agreement in principle entered into in February 2016) with Paragon Offshore relating to tax matters in Mexico described below in exchange for a full and unconditional release of any claims by Paragon Offshore in connection with the Spin-off (including fraudulent conveyance claims that could be brought on behalf of its creditors).
Audit claims of approximately $151 million attributable to income and other business taxes have been assessed against us in Mexico, as detailed below. Under our settlement agreement with Paragon Offshore, we agreed to assume the administration of Paragon Offshore’s Mexican income and value-added taxes for the years 2005 through 2010 and for Paragon Offshore’s Mexican customs taxes through 2010, as well as the related bonding obligations and certain of the tax related liabilities. In addition, under the agreement with Paragon Offshore, we agreed to (i) pay all of the ultimate resolved amount of Mexican income and value-added taxes related to Paragon Offshore’s business that were incurred through a Noble-retained entity, (ii) pay 50 percent of the ultimate resolved amount of Mexican income and value-added taxes related to Paragon Offshore’s business that were incurred through a Paragon Offshore-retained entity, (iii) pay 50 percent of the ultimate resolved amount of Mexican custom taxes related to Paragon Offshore’s business, and (iv) post any tax appeal bond that may be required to challenge a final assessment. Paragon Offshore also agreed to pay 50 percent of the third party costs incurred by us in the administration of the tax claims. Pursuant to an amendment agreed to on August 5, 2016 we have also agreed to allow Paragon Offshore to pay up to $5 million of the Mexican tax and administrative costs described above that become owed to us in the form of an interest bearing note, which will be due at the end of the four year period following the date of approval of Paragon Offshore's bankruptcy plan. Tax assessments of approximately $43 million for income and value-added taxes have been made against Noble entities in Mexico. Tax assessments for income and value-added taxes of approximately $176 million have been made against Paragon Offshore entities in Mexico, of which approximately $40 million relates to Noble’s business that operated through Paragon Offshore-retained entities in Mexico prior to the Spin-off. We will only be obligated to post a tax appeal bond in the event a final assessment is made by Mexican authorities. As of February 15, 2017, there have been $3 million in final assessments that have been bonded.
In January 2015, Noble received an official notification of a ruling from the Second Chamber of the Supreme Court in Mexico. The ruling settled an ongoing dispute in Mexico relating to the classification of a Noble subsidiary’s business activity and the applicable rate of depreciation under the Mexican law applicable to the activities of that subsidiary. The ruling did not result in any additional tax liability to Noble. Additionally, the ruling is only applicable to the Noble subsidiary named in the ruling and, therefore, does not establish the depreciation rate applicable to the assets of other Noble subsidiaries. Under the settlement agreement with Paragon Offshore, we agreed to be responsible for any tax liability ultimately incurred because these depreciation liabilities would be incurred by Noble-retained entities, and such amounts are reflected in the discussion of Mexican audit claims in the preceding paragraph. We will continue to contest future assessments received, and can make no assurances regarding the ultimate outcome of these tax claims or our obligations to pay additional taxes in respect of these tax claims.

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Paragon Offshore has received tax assessments of approximately $154 million attributable to income, customs and other business taxes in Brazil, of which $44 million relates to Noble’s business that operated through a Paragon Offshore-retained entity in Brazil prior to the Spin-off. Under the TSA, we must indemnify Paragon Offshore for all assessed amounts that are related to Noble’s Brazil business, approximately $44 million, if and when such payments become due.
We have contested, or intend to contest or cooperate with Paragon Offshore in Brazil where it is contesting, the assessments described above, including through litigation if necessary, and we believe the ultimate resolution, for which we have not made any accrual, will not have a material adverse effect on our consolidated financial statements. Tax authorities may issue additional assessments or pursue legal actions as a result of tax audits and we cannot predict or provide assurance as to the ultimate outcome of such assessments and legal actions or our ability to collect indemnities from Paragon Offshore under the TSA or the recent agreement with Paragon Offshore.
We have been notified by Petrobras that it is currently challenging assessments by Brazilian tax authorities of withholding taxes associated with the provision of drilling rigs for its operations in Brazil during 2008 and 2009. Petrobras has also notified us that if Petrobras must ultimately pay such withholding taxes, it will seek reimbursement from us for the portion allocable to our drilling rigs. The amount of withholding tax that Petrobras indicates may be allocable to Noble drilling rigs is approximately $24 million. We believe that our contract with Petrobras requires Petrobras to indemnify us for these withholding taxes. We will, if necessary, vigorously defend our rights.
In certain circumstances, we expect that, due to changing demands of the offshore drilling markets and the ability to redeploy our offshore drilling units, certain units will not reside in a location long enough to give rise to future tax consequences. As a result, no deferred tax asset or liability has been recognized in these circumstances. Should our expectations change regarding the length of time an offshore drilli