Noble Corp - Annual Report: 2014 (Form 10-K)

Table of Contents

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

For the fiscal year ended December 31, 2014

For the transition period from                      to                         

Commission file number: 001-36211

Noble Corporation plc

(Exact name of registrant as specified in its charter)

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:

Commission file number: 001-31306

Noble Corporation

(Exact name of registrant as specified in its charter)

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.

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, 2014, the aggregate market value of the registered shares of Noble Corporation plc held by non-affiliates of the registrant was $8.5 billion based on the closing sale price as reported on the New York Stock Exchange.

Number of shares outstanding and trading at February 13, 2015: Noble Corporation plc – 241,954,168

Number of shares outstanding: Noble Corporation – 261,245,693

DOCUMENTS INCORPORATED BY REFERENCE

The proxy statement for the 2015 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

TABLE OF CONTENTS

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.

Table of Contents

PART I

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 fleet of mobile offshore drilling units located worldwide. As of the filing date of this Annual Report on Form 10-K, our fleet consisted of 15 jackups, nine drillships and eight semisubmersibles, including one high-specification, harsh environment jackup under construction. This excludes the semisubmersibles, Noble Driller, Noble Jim Thompson and Noble Paul Wolff.

For additional information on the specifications of our fleet, see “Item 2. Properties.—Drilling Fleet.” At December 31, 2014, our fleet was located in the United States, Brazil, Argentina, the North Sea, the Mediterranean, the Middle East, Asia and Australia. 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, see “Part II Item 8 Financial Statements and Supplementary Data, Note 2—Spin-off of Paragon Offshore plc.”

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:

2

Table of Contents

Our business strategy has also focused on reshaping our fleet to emphasize our deepwater and high specification jackup capabilities, coupled with utilizing those drilling assets in important oil and gas producing areas throughout the world.

We have actively expanded our deepwater and high-specification drilling capabilities in recent years through the construction of rigs. As part of this technical and operational expansion, we believe that we have a fleet which gives us a competitive advantage for the increasingly complex programs required by our customers. During 2014, we continued to execute our newbuild program, completing the following milestones:

Our historical strategy with respect to construction of new rigs has typically been to expand our drilling fleet in connection with a long-term drilling contract that covers a substantial portion of our capital investment and provides an acceptable return on our capital employed. However, in response to the addition of a significant number of new, technologically advanced units in the global fleet, changes in customer requirements and preferences and our strong backlog, we determined that in order to maintain long-term competitiveness, it was both necessary and desirable for us to engage in building high-specification jackups and floating units on a speculative basis. In 2011, we began our current newbuild program. To date, we have completed and are operating four drillships and four jackups. Currently, we have one newbuild project remaining, the heavy-duty, harsh environment jackup, Noble Lloyd Noble. Additionally, the Noble Sam Hartley, a newbuild heavy-duty, harsh environment jackup, is currently undergoing post-delivery modifications in the shipyard. The Noble Sam Hartley does not have a customer contract and we continue to market the unit. We currently do not have plans to build additional units on speculation given the market uncertainty. While we may decide to pursue new speculative building in the future, we do not plan to do so until we have better visibility into the offshore drilling market.

Demand for our services is, in 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, many of which are currently under construction without a contract. The introduction of non-contracted newbuild rigs into the marketplace has increased the supply of rigs competing for drilling service contracts. Further, since June 2014 the price of oil has dropped by more than 50 percent. As a result, our customers have reduced their planned exploration and development spending and the number of rigs they have under contract and plan to contract during 2015. This combination of increased supply of drilling rigs and reduced demand for such rigs has resulted in falling dayrates and may result in reduced utilization of our units if current contracts expire.

3

Table of Contents

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:

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 some cases, without any payment.

Generally, our contracts allow us to recover our mobilization and demobilization costs associated with moving a drilling unit from one regional location to another. When market conditions require us to assume these costs, our operating margins are reduced accordingly. For shorter moves, such as “field moves,” our customers have generally agreed to assume the costs of moving the unit in the form of a reduced dayrate or “move rate” while the unit is being moved.

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 98 percent of our operating revenues for the years ended December 31, 2014, 2013 and 2012. During the three years ended December 31, 2014, we principally conducted our contract drilling operations in the United States, Argentina, Brazil, the North Sea, the Mediterranean, West Africa, the Middle East, Asia and Australia. Revenues from Royal Dutch Shell, plc (“Shell”) and its affiliates accounted for approximately 55 percent, 67 percent and 51 percent of our consolidated operating revenues in 2014, 2013 and 2012, respectively. Revenues from Saudi Arabian Oil Company (“Saudi Aramco”) accounted for approximately 10 percent of our consolidated operating revenues in both 2013 and 2012. Saudi Aramco did not account for more than 10 percent of our consolidated operating revenues in 2014. Revenues from Petróleo Brasileiro S.A. (“Petrobras”) accounted for approximately 11 percent of our consolidated operating revenues in 2012. Petrobras did not account for more than 10 percent of our consolidated operating revenues in either 2014 or 2013. No other single customer accounted for more than 10 percent of our consolidated operating revenues in 2014, 2013 or 2012.

Labor Contracts

During 2011, we commenced a refurbishment project with Shell for one of its rigs. Under the contract, we provided the management and oversight of the project, as well as the personnel necessary to complete the refurbishment. During 2012, the construction phase of the project was completed and the rig began operating off the coast of Alaska. In 2013, in connection with Shell’s delay of the Alaskan Arctic drilling project, this contract was terminated. We provided labor personnel and management services on the project, but did not own or lease the related rig. During 2014, we did not have any active labor contracts nor did we have any revenues or expenses from continuing operations related to labor services contracts.

4

Table of Contents

Competition

The offshore contract drilling industry is a highly competitive and cyclical business characterized by high capital 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 suitability, experience of the workforce, efficiency, safety performance record, condition and age of equipment, operating integrity, reputation, industry standing and client relations. 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 large peer companies, we follow a policy of keeping our equipment well-maintained and technologically competitive. However, our equipment 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 at any particular time. Demand for offshore drilling equipment also depends on the exploration and development programs of oil and gas producers, which in turn are influenced by many factors, including: the financial condition of such producers, general global economic conditions, prices of oil and gas, political considerations and national oil and gas production policies.

In addition, industry-wide shortages of supplies, services, skilled personnel and equipment necessary to conduct our business have historically occurred. 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 have made, and will continue to make, expenditures to comply with environmental requirements. To date, we have not made material expenditures in order to comply, and 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 energy 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.

5

Table of Contents

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.

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. 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. 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.

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 establishes a liability limit for onshore facilities of $350 million, while the liability limit for offshore facilities is equal to all removal costs plus up to $75 million in other damages. In December 2014, BOEM proposed increasing this liability limit to $134 million. 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.

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

6

Table of Contents

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. 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. Recent international discussions in advance of the United Nations Climate Change Conference in Paris in 2015 are exploring options to replace the Kyoto Protocol. 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.

7

Table of Contents

Countries in the European Union 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% GHG reduction from these sectors between 2005 and 2020. More generally, the EU Commission has proposed a roadmap for reducing emissions by 80% by 2050 compared to 1990 levels. Some EU member states have enacted additional and more long-term legally binding targets. For example, the U.K. has committed to reduce GHG emissions by 80% 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.

Entities operating under the cap must either reduce their GHG emissions, 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. 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 “backloading.” EU proposals for wider structural reform of the EU ETS may follow the enactment of the backloading proposal. Both backloading and wider structural reforms are aimed at reviving the EU carbon price.

In addition, the U.K. government, which implements ETS in the U.K. 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 in 2015.

For the year ended December 31, 2014, our estimated carbon dioxide equivalent (“CO2e”) gas emissions, including Paragon Offshore through the Spin-off date, were 832,845 tonnes as compared to 873,971 tonnes for the year ended December 31, 2013. Excluding Paragon Offshore, our estimated CO2e gas emissions for the year ended December 31, 2014 were 631,612 tonnes as compared to 505,223 tonnes for the year ended December 31, 2013 due to fleet expansion. When expressed as an intensity measure of tonnes of C02e gas emissions per dollar of contract drilling revenues from continuing operations, both the 2014 and 2013 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.

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 will be 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.

8

Table of Contents

International Regulatory Regime. IMO provides international regulations governing shipping and international maritime trade. IMO regulations have been widely adopted by U.N. member countries, and in some jurisdictions in which we operate, these regulations have been expanded upon. The requirements contained in the International Management Code for the Safe Operation of Ships and for Pollution Prevention, or ISM Code, promulgated by the IMO, govern much of our drilling operations. Among other requirements, the ISM Code requires the party with operational control of a vessel to develop an extensive safety management system that includes, among other things, the adoption of a safety and environmental protection policy setting forth instructions and procedures for operating its vessels safely and describing procedures for responding to emergencies.

The IMO has also adopted MARPOL, including Annex VI to MARPOL which sets limits on sulfur dioxide and nitrogen oxide emissions from ship exhausts and prohibits deliberate emissions of ozone depleting substances. 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 limitations require that fuels of vessels in covered Emission Control Areas, or ECAs, contain no more than 1% sulfur. The North American ECA became effective in August 2012, capping the sulfur limit in marine fuel at 1%, which has been the capped amount for the North Sea and Baltic Sea ECAs since July 1, 2010. The North Sea ECA encompasses all of the North Sea and the full length of the English Channel. These capped amounts are to decrease progressively until they reach 0.5% by January 1, 2020 for non-ECA areas and 0.1% by January 1, 2015 for ECA areas, including the North American ECA. 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 has not become effective, but the IMO has passed a resolution encouraging the ratification of the BWM Convention and calling upon those countries that have already ratified to encourage the installation of ballast water management systems on new ships. Under the requirements of the BWM Convention for rigs with ballast water capacity of more than 5000 cubic meters that were constructed in 2011 or before, ballast water management exchange or treatment will be accepted until 2016. From 2016 (or not later than the first intermediate or renewal survey after 2016), only ballast water treatment will be accepted by the BWM Convention. 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.

9

Table of Contents

Insurance and Indemnification Matters

Our operations are subject to many hazards inherent in the drilling business, including blowouts, fires and collisions or groundings of offshore equipment, 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.

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, 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.

Our customers typically assume responsibility for and indemnify us from loss or liability resulting from pollution or contamination, including third-party damages and clean-up and removal, arising from operations under the contract and originating below the surface of the water. We are generally responsible for pollution originating above the surface of the water and emanating from our drilling units. Additionally, our customers typically indemnify us for liabilities incurred as a result of a blow-out or cratering of the well and underground reservoir loss or damage.

In 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 insurance policy does not exclude losses resulting from our gross negligence or willful misconduct. Our P&I insurance program is renewed in March of each year and currently has a standard deductible of $10 million per occurrence, with maximum liability coverage of $750 million.

Our insurance policies and contractual rights to indemnity may not adequately cover our losses and liabilities in all cases. For additional information, please read “We may have difficulty obtaining or maintaining insurance in the future and our insurance coverage and contractual indemnity rights may not protect us against all 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, 2014, we had approximately 3,700 employees, excluding approximately 1,100 persons we engaged through labor contractors or agencies. Approximately 81 percent of our employees are 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 a quarterly publication 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.

10

Table of Contents

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 19 — Segment 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 19 — Segment 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:

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 depends on the level of activity in the oil and gas industry. Adverse developments affecting the industry, including a decline in oil or gas prices, 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. Commodity prices, including oil and gas prices, and market expectations of potential changes in these prices, may significantly affect this level of activity, as well as dayrates 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. Oil and gas prices 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:

11

Table of Contents

Adverse developments affecting the industry as a result of one or more of these factors, including a decline in oil or gas prices (such as the decline since June 2014, any further decline, or the failure of oil prices to recover from their current levels), 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 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, experience of the workforce, efficiency, safety performance record, technical capability and condition of equipment, operating integrity, reputation, industry standing and client relations are all factors in determining which contractor is awarded a job. 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, 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.

12

Table of Contents

An over-supply of rigs may lead to a reduction in dayrates and demand for our rigs and, therefore, may adversely impact our revenues and profitability.

Prior to the recent downturn, we experienced a period of high utilization and high dayrates, and industry participants increased the supply of drilling rigs by building new drilling rigs, including some drilling rigs 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 June 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 in 2015 and beyond. The entry of these rigs into the market has resulted in lower dayrates for both newbuilds and experienced rigs rolling off their current contracts. Lower utilization and dayrates adversely affect our revenues and profitability. In addition, our competitors may relocate rigs to markets in which we operate, which could exacerbate excess rig supply which may lower dayrates and utilization in those markets. To the extent that the drilling rigs currently under construction or on order have not been contracted for future work, 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.

We may record additional losses or impairment charges related to sold or idle rigs.

Prolonged periods of low utilization or low dayrates, the cold stacking of idle assets, the sale of assets below their then carrying value or the decline in market value of our assets may cause us to experience losses. If future cash flow estimates, based upon information available to management at the time, indicate that the carrying value of any of our rigs may not be recoverable or if we sell assets for less than their then carrying value, we may recognize additional impairment charges on our fleet. For example, in the fourth quarter of 2014, we decided that we would discontinue marketing the Noble Driller, Noble Paul Wolff and Noble Jim Thompson. In connection with this decision, we recorded an impairment charge of $685 million on these three units.

We may not be able to renew or replace expiring contracts or obtain contracts for our uncontracted newbuilds, and our customers may terminate or seek to renegotiate or repudiate our drilling contracts.

We have a number of customer contracts that will expire in 2015 and 2016. 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. During the fourth quarter of 2014 and the first quarter of 2015, 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 2015 and beyond. These reductions in spending 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.

In addition, the Noble Sam Hartley, a newbuild heavy-duty, harsh environment jackup that is currently undergoing post-delivery modifications in the shipyard, does not have a customer contract. We will attempt to secure a contract for this unit prior to the completion of the modification project, but we may be unable to obtain a contract for this rig. In addition, for our rigs under contract that have expired or have been terminated by our customers, we may be unable to secure extensions or new contracts, or in the alternative, may receive dayrates under new contracts which may be below, perhaps substantially below, the existing dayrates. This would have a material adverse effect on our results of operations and cash flows.

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 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 and which we expect to continue during 2015, we may be subject to an increased risk of our customers seeking to renegotiate or repudiate their contracts. Our customers’ ability to perform their obligations under drilling contracts with us may also be adversely affected by restricted credit markets, economic downturns and industry downturns, such as the one we are currently experiencing. If our customers cancel or are unable to renew some of their contracts and we are unable to secure new contracts on a timely basis and on substantially similar terms, if contracts are disputed or suspended for an extended period of time or if a number of our contracts are renegotiated, it could have a material adverse effect on our business, financial condition and results of operations.

13

Table of Contents

We can provide no assurance that our current backlog of contract drilling revenue will 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. In addition, we may not receive some or all of the bonuses that we include in our backlog. We can provide no assurance that we will be able to perform under these contracts due to events beyond our control or that we will 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. Our inability to perform under our contractual obligations or to execute definitive agreements or our customers’ inability or unwillingness to fulfill their contractual commitments to us, including as a result of contract repudiations during currently depressed market conditions, 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 Freeport-McMoRan, Inc. (“Freeport”), and the loss of these customers could 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. We estimate Shell and Freeport represented approximately 60 percent and 12 percent, respectively, of our backlog at December 31, 2014. Revenues from Shell and Freeport accounted for approximately 55 percent and 4 percent, respectively, of our consolidated operating revenues for the year ended December 31, 2014. This concentration of customers increases the risks associated with any possible termination or nonperformance of contracts, in addition to our exposure to credit risk. If any of these customers were to terminate or fail to perform their obligations under their contracts and we were not able to find other customers for the affected drilling units promptly, our financial condition and results of operations could be materially adversely affected.

Our business involves numerous operating hazards.

Our operations are subject to many hazards inherent in the drilling business, including:

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.

14

Table of Contents

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:

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:

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 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.

15

Table of Contents

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 assurances that the Paragon Offshore indemnities will be sufficient to insure us against the full amount of the related liabilities, or that Paragon Offshore’s ability to satisfy its indemnification obligations will not be impaired 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 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 to fully satisfy its indemnification 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 to satisfy its indemnification obligations, the underlying liabilities could have a material adverse effect on our business, financial condition and results of operations.

Following the Spin-off, we continue to rely on Paragon Offshore to assist us in operations offshore Brazil. In addition, Paragon Offshore has significant payables owed to us in connection with the Spin-off and agreements executed in connection with our separation.

Pursuant to the transition services agreement relating to our operations offshore Brazil, Paragon Offshore has agreed to provide local administrative and operational services for rigs operating in Brazil at the time of the Spin-off. We currently have one rig in Brazil operating under this arrangement. In addition, in connection with the Spin-off, we executed a number of agreements with Paragon Offshore that govern our relationship after the Spin-off. If Paragon Offshore is unable to perform under its obligations under the transition services agreement relating to our operations offshore Brazil or is unable or unwilling to repay its obligations under the agreements executed in connection with our separation, it could have a material adverse effect on our business, financial condition and results of operations.

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 GHGs.

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 or imposing materially increased costs. As a result, the application of these laws could have a material adverse effect on our results of operations by 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.

16

Table of Contents

As disclosed in “Part II Item 8. Financial Statements and Supplementary Data, Note 18 — Commitments and Contingencies”, in November 2012, the U.S. Coast Guard in Alaska conducted an inspection and investigation of the Noble Discoverer and the Kulluk, and referred the matters to the U.S. Department of Justice (“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 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.

In 2010, we finalized settlements with the SEC and the DOJ relating to certain reimbursement payments made by our then Nigerian affiliate to our customs agents in Nigeria in the years 2003 to 2007 and paid fines and penalties to the DOJ and the SEC. 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:

Legal and regulatory proceedings relating to the energy industry, and the complex government regulations to which our business is subject, have at times adversely affected our business and may do so in the future. Governmental actions and initiatives by OPEC may continue to cause oil price volatility. In some areas of the world, this 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 or require foreign contractors to employ citizens of, or purchase supplies from, a particular jurisdiction. These practices may adversely affect our ability to compete and our results of operations.

17

Table of Contents

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.

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, either individually or in the aggregate, could be material and may not be covered fully or at all by insurance.

Possible changes in tax laws could affect us and our shareholders.

We operate through various subsidiaries in numerous countries throughout the world. Consequently, we are subject to changes in tax laws, treaties or regulations or the interpretation or enforcement thereof in the United Kingdom, the U.S. or jurisdictions in which we or any of our subsidiaries operate or are incorporated. For example, the Organization for Economic Co-Operation and Development (“OECD”) published a Base Erosion and Profit Shifting Action Plan (“BEPS”) in July 2013. BEPS seeks to reform the taxation of multinational companies. Although any recommendations made by the OECD are not changes in tax law, this may result in unilateral country action which may be uncoordinated, may create double taxation and increase controversy, both of which would be adverse for the global economy and may result in a material adverse effect on our financial statements.

Tax laws and regulations are highly complex and subject to interpretation. Our income tax expense is based upon our interpretation of the tax laws in effect in various countries at the time that the expense was incurred. If these laws, treaties or regulations change or other taxing authorities do not agree with our assessment of the effects of such laws, treaties and regulations, this could have a material adverse effect on us, resulting in a higher effective tax rate on our worldwide earnings or a reclassification of the tax impact of our significant corporate restructuring transactions.

In addition, the manner in which our shareholders are taxed on distributions on, and dispositions of, our shares could be affected by changes in tax laws, treaties or regulations or the interpretation or enforcement thereof in the United Kingdom, the U.S. or other jurisdictions in which our shareholders are resident. Any such changes could result in increased taxes for our shareholders and affect the trading price of our shares.

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:

18

Table of Contents

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.

19

Table of Contents

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 currently anticipated cash flow needs, both in the short-term and long-term, may include the following:

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 facilities and commercial paper program. 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.

Access to our commercial paper program is dependent upon our credit ratings. A decline in our credit ratings below investment grade would prohibit us from accessing the commercial paper market, and we would likely transfer our outstanding borrowings to our revolving credit facilities. Our revolving credit facilities have interest rates that are generally higher than those found in the commercial paper market, which would result in increased interest expense in the future.

In addition, our revolving credit facilities have provisions which change the applicable interest rates based upon our credit ratings. If our credit ratings were to decline, the interest expense under our revolving credit facilities would increase.

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 shorebased terrorist acts or strikes. Furthermore, the damage sustained to offshore oil and gas assets as a result of hurricanes in recent years has negatively impacted certain aspects of the energy insurance market, resulting in more restrictive and expensive coverage for U.S. named windstorm perils. Accordingly, we have elected to significantly reduce the named windstorm insurance on our rigs operating in the U.S. Gulf of Mexico. Presently, we insure the Noble Jim Thompson, Noble Amos Runner and Noble Driller for “total loss only” when caused by a named windstorm. For the Noble Bully I, our customer assumes the risk of loss due to a named windstorm event, pursuant to the terms of the drilling contract, through the purchase of insurance coverage (provided that we are responsible for any deductible under such policy) or, at its option, the assumption of

20

Table of Contents

the risk of loss up to the insured value in lieu of the purchase of such insurance. The remaining rigs in the U.S. Gulf of Mexico are self-insured for named windstorm perils. Further, we may decide to discontinue named windstorm insurance on all of our rigs in the U.S. Gulf of Mexico. If one or more future significant weather-related events occur in the Gulf of Mexico, or in any other geographic area in which we operate, we may experience increases in insurance costs, additional coverage restrictions or unavailability of certain insurance products.

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, certain loss or damage to property onboard our rigs and losses relating to shorebased 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.

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.

Construction, 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 currently have one remaining ongoing new construction project. In addition, we will continue to make significant upgrade, 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:

21

Table of Contents

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.

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:

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

22

Table of Contents

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.

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. These shortages could result in our loss of qualified personnel to competitors, impair our ability to attract and retain 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.

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

23

Table of Contents

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. Recently, the Society of Actuaries released revised mortality tables, which update life expectancy assumptions. In consideration of these tables, we modified the mortality assumptions used in determining our pension and post-retirement benefit obligations as of December 31, 2014, which increased our pension liability by $14 million as of December 31, 2014. This will have a related impact on our annual pension cost in future years. The new mortality assumptions may result in additional funding requirements dependent upon the funded status of our plans. These expectations presume all other assumptions remain constant and there are no changes to applicable funding regulations. Future changes in estimates and assumptions associated with our pension and other post-retirement benefit plans could have a material adverse effect on our financial condition, results of operations, cash flows and/or financial disclosures.

Our operations present hazards and risks that require significant and continuous oversight, and we depend upon the security and reliability of our technologies, systems and networks in numerous locations where we conduct business.

Our floaters and high-specification units utilize certain technologies that make us vulnerable to cyber-attacks that we may not be able to adequately protect against. These cyber security risks could disrupt certain of our operations for an extended period of time and result in the loss of critical data and in higher costs to correct and remedy the effects of such incidents. If our systems for protecting against information technology and cyber security risks prove to be insufficient, we could be materially adversely affected by having our business and financial systems compromised, our proprietary information altered, lost or stolen, or our business operations and safety procedures disrupted.

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.

24

Table of Contents

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, and Section 21E of the U.S. Securities Exchange Act of 1934, as amended. 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, timing or number of share repurchases, borrowings under our credit facilities or other instruments, sources of funds, completion, delivery dates and acceptance of our newbuild rigs, 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, construction and upgrade of rigs, 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.

None.

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.

Drillships

Our drillships are self-propelled vessels. These units maintain their position over the well through the use of either a fixed mooring system or 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 9 units:

25

Table of Contents

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 eight units:

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 water depths up to approximately 500 feet. As of the filing date of this Annual Report on Form 10-K, we had 15 jackups in our fleet, including one high-specification, harsh environment jackup under construction.

26

Table of Contents

Offshore Fleet Table

The following table sets forth certain information concerning our offshore fleet at February 12, 2015. We operate and own all of the units included in the table.

Footnotes to Drilling Fleet Table

Facilities

Our corporate headquarters are 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.

27

Table of Contents

Information regarding legal proceedings is set forth in Note 18 to our consolidated financial statements included in Item 8 of this Annual Report on Form 10-K.

Not applicable.

PART II

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 and are adjusted retroactively to reflect the impact of the Spin-off of Paragon Offshore, which was completed on August 1, 2014:

The declaration and payment of dividends or returns of capital 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 and our shareholders.

On February 13, 2015, there were 241,954,168 shares outstanding held by 421 shareholder accounts of record.

UK Tax Consequences to Shareholders of Noble-UK

The tax consequences discussed below do not reflect a complete analysis or listing of all the possible tax consequences that may be relevant to shareholders of Noble. Shareholders should consult their own tax advisors in respect of the tax consequences related to receipt, ownership, purchase or sale or other disposition of our shares.

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.

28

Table of Contents

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 U.K. 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. Prior to our redomiciliation to the UK, a resolution was adopted by Noble-UK’s sole shareholder authorizing the repurchase of 6,769,891 shares during the five-year period commencing on the date of the redomiciliation. This number of shares corresponds to the number of shares that Noble-Swiss had authority to repurchase at the time of the redomiciliation. During 2014, we repurchased all shares covered by this authorization.

In December 2014, we received shareholder approval to repurchase up to 37,000,000 additional ordinary shares, or approximately 15 percent of our outstanding ordinary shares at the time of shareholder approval. Any repurchases are expected to be funded using cash on hand, cash from operations or short-term borrowings under our credit facilities. The authority to make such repurchases will expire on the later of April 2016 or at the end of the Company’s 2016 annual general meeting of shareholders, at which time we could seek shareholder approval for further repurchases.

The following table sets forth for the periods indicated certain information with respect to purchases of shares by Noble-UK during the fourth quarter of 2014:

29

Table of Contents

All share repurchases were made in the open market and were pursuant to the share repurchase program discussed above. All shares repurchased during the quarter were immediately cancelled.

In January 2015, we repurchased 6.2 million of our ordinary shares at an average price of $16.10 per share, excluding commissions and stamp tax. Including these items, the average price paid per share during January 2015 was $16.21. There can be no assurance as to the timing or amount of any additional repurchases. However, we intend to take a cautious approach to future share repurchases at least until market conditions in the offshore drilling business stabilize.

Stock Performance Graph

This graph shows the cumulative total shareholder return of our shares over the five-year period from January 1, 2010 to December 31, 2014. 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, 2010 and that all dividends or distributions and returns of capital were reinvested on the date of payment.

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 of 1933 or Securities Exchange Act of 1934, each as amended, except to the extent that we specifically incorporate it by reference into such filing.

30

Table of Contents

The following table sets forth selected financial data of us and our consolidated subsidiaries over the five-year period ended December 31, 2014, 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.

The following discussion is intended to assist you in understanding our financial position at December 31, 2014 and 2013, and our results of operations for each of the years in the three-year period ended December 31, 2014. 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, 2014 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/(loss) from continuing operations. Income/ (loss) from continuing operations is representative of the Company’s current business operations and focus.

31

Table of Contents

Executive Overview

Our 2014 financial and operating results from continuing operations include:

The business environment for offshore drillers during 2014 and early 2015 has been challenging. The supply of offshore drilling rigs from newbuilds and rigs completing current contracts increased while demand for these same rigs decreased. Beginning in June 2014, the price of oil, a key factor in determining customer activity levels, began to decline rapidly, with the Brent crude price declining from approximately $112 per barrel on June 30, 2014 to approximately $52 per barrel on January 30, 2015. In this environment, operators reacted quickly and began to curtail drilling programs. This environment resulted in a dramatic reduction in dayrates for new contracts and lower utilization.

We expect 2015 to be a challenging year with potential for further deterioration of the offshore drilling market. The present level of global economic activity and the lack of production cuts within OPEC are contributing to the uncertainty. Current conditions do not support the capital expenditure programs that the offshore drilling industry has undertaken in recent years. We cannot give any assurances as to when these conditions in the offshore drilling market will improve, or when there will be higher demand for contract drilling services or a decline in the number of drilling rigs. While current market conditions persist, we intend to focus on operating efficiency and cost control, which could include stacking additional drilling rigs.

We do continue to believe in the long-term fundamentals for the industry, especially for those contractors with a modern fleet of high-specification rigs. Also, we believe the ultimate recovery will benefit from any sustained under-investment by clients in this current market phase.

In October 2014, we announced that our Board of Directors authorized the development of a master limited partnership (“MLP”), which would be comprised of interests in select drilling rigs from our existing fleet. The anticipated offering was subject to the final approval of our Board of Directors and market conditions. We believed that the MLP in the then-current market conditions would provide financial flexibility. The drilling market and related MLP market conditions have deteriorated significantly, and we have consequently decided not to pursue an MLP. We will monitor the MLP market and may or may not decide to resume development of an MLP.

In December 2014, we received shareholder approval to repurchase up to 37,000,000 additional ordinary shares, or approximately 15 percent of our outstanding ordinary shares at the time of the shareholder approval. Any repurchases are expected to be funded using cash on hand, cash from operations or short-term borrowings under our credit facilities. During January 2015, we repurchased 6.2 million of our ordinary shares at an average price of $16.10 per share, excluding commissions and stamp tax. There can be no assurance as to the timing or amount of any additional repurchases. However, we intend to take a cautious approach to future share repurchases at least until market conditions in the offshore drilling business stabilize. The authority to make such repurchases will expire on the later of April 2016 or at the end of the Company’s 2016 annual general meeting of shareholders, at which time we could seek shareholder approval for further repurchases.

Our business strategy has focused on reshaping our fleet to emphasize our deepwater drilling and high-specification jackup capabilities and the deployment of our drilling assets in important oil and gas producing areas throughout the world.

32

Table of Contents

We have actively expanded our offshore deepwater drilling and high-specification jackup capabilities in recent years through the construction of rigs. Although we plan to focus on capital preservation and liquidity based on current market conditions, we also plan to continue to evaluate opportunities to enhance our fleet to achieve greater technological capability, which we believe will lead to increased drilling efficiencies and the ability to complete the increasingly more complex programs required by our customers. During 2014, we continued to execute our newbuild program, completing the following milestones:

While we cannot predict the future level of demand or dayrates for our drilling services or future conditions in the offshore contract drilling industry, we continue to believe we are well positioned within the industry and that our newbuild activity will further strengthen our position.

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 all periods presented in this Annual Report on Form 10-K. For additional information regarding the Spin-off, see “Part II Item 8 Financial Statements and Supplementary Data Note 2—Spin-off of Paragon Offshore plc.”

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.

33

Table of Contents

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.

Impairment

In the fourth quarter of 2014, we decided that we would discontinue marketing the semisubmersibles, Noble Driller, Noble Jim Thompson and Noble Paul Wolff, as a result of current market conditions. In connection with the preparation of the consolidated financial statements included in this Annual Report, 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.

Consistent with our policy, we will continue to evaluate property and equipment for impairment on an annual basis or whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. Further sustained declines in the offshore drilling market, or lack of recovery in market conditions, to the extent actual results do not meet our estimated assumptions, may lead to additional impairments losses in the future.

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, 2014, the amount of our contract drilling services backlog and the percent of available operating days committed for the periods indicated:

34

Table of Contents

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, 2014, 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. The reported contract drilling services backlog does not include amounts representing revenues for mobilization, demobilization and contract preparation, which are not expected to be significant to our contract drilling services revenues, amounts constituting reimbursables from customers or amounts attributable to uncommitted option periods under drilling contracts or letters of intent.

The 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, achievement of bonuses, weather conditions 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.”

RESULTS OF OPERATIONS

2014 Compared to 2013

General

Net loss from continuing operations attributable to Noble-UK for 2014 was $152 million, or $0.60 per diluted share, on operating revenues of $3.2 billion, compared to net income from continuing operations for 2013 of $479 million, or $1.86 per diluted share, on operating revenues of $2.5 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 2014 and 2013, 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, 2014 and 2013 was $50 million and $65 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 and $18 million in 2014 and 2013, respectively, related to the Spin-off, which we recognized as part of discontinued operations at the Noble-UK level.

35

Table of Contents

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 2014 and 2013:

Contract Drilling Services

The following table sets forth the operating results from continuing operations for our contract drilling services segment for 2014 and 2013 (dollars in thousands):

Operating Revenues. Changes in contract drilling services revenues for the current year as compared to the prior year were driven by increases in both average dayrates and operating days. The 13 percent increase in average dayrates increased revenues by approximately $352 million while the 14 percent increase in operating days increased revenues by an additional $341 million.

The increase in contract drilling services revenues relates to our drillships and jackups, which generated approximately $636 million and $219 million more revenue, respectively, in 2014. These amounts were offset by decreases in revenues for our semisubmersibles, which declined $162 million from the prior year.

36

Table of Contents

The increase in drillship revenues was driven by a 61 percent increase in operating days and a 19 percent increase in average dayrates, resulting in a $420 million and a $216 million increase in revenues, respectively, from the prior year. The increase in both average dayrates and operating days was primarily the result of the newbuilds Noble Don Taylor, Noble Globetrotter II, Noble Bob Douglas, Noble Sam Croft and Noble Tom Madden, which commenced their contracts in August 2013, September 2013, December 2013, July 2014 and November 2014, respectively. Additionally, there were favorable dayrate changes on the contracts for the Noble Bully II and the Noble Discoverer during the current year.

The 22 percent increase in jackup average dayrates resulted in a $118 million increase in revenues, which was coupled with a 23 percent increase in jackup operating days, resulting in a $101 million increase in revenues from the prior year. The increase in average dayrates and operating days resulted from the contract commencements of the Noble Mick O’Brien, Noble Regina Allen, Noble Houston Colbert and Noble Sam Turner in November 2013, January 2014, March 2014, and August 2014, respectively. Additionally, a contract extension on the Noble Roger Lewis resulted in a favorable dayrate change during 2014. This was partially offset by increased downtime on the Noble Scott Marks and the Noble David Tinsley. Furthermore, the Noble Lewis Dugger, which was sold in July 2013, was utilized during a portion of the prior year.

The 6 percent increase in average dayrates on our semisubmersibles resulted in a $70 million increase in revenues from 2013. The increase in average dayrates was due to favorable dayrate changes on new contracts across the semisubmersible fleet, as well as the Noble Paul Romano returning to work during the current year. The 18 percent decline in operating days resulted in a $232 million decrease in revenues driven by contract completions on the Noble Paul Wolff, Noble Homer Ferrington and Noble Max Smith. Additionally, the Noble Amos Runner was in the shipyard undergoing regulatory inspections and maintenance during a portion of the current year but operated during the prior year.

Operating Costs and Expenses. Contract drilling services operating costs and expenses increased $332 million for the current year as compared to the prior year. A significant portion of the increase was due to the crew-up and operating expenses for our newbuild rigs as they commenced, or prepared to commence, operating under contracts, which added approximately $322 million in expense in the current year. The remaining change was primarily driven by a $20 million increase in mobilization expense due to certain rig moves and the demobilization of certain rigs, partially offset by a $5 million decrease in operations support and rig-related expenses and a $5 million decrease in rig and operations support labor.

Depreciation and amortization increased $111 million in 2014 over 2013, which is primarily attributable to newbuild rigs placed in service since the beginning of 2013 as noted above.

Loss on impairment during the current year relates to a $685 million charge on our semisubmersibles, Noble Driller, Noble Jim Thompson and Noble Paul Wolff, which we decided to no longer actively market as a result of current market conditions. 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, coupled with a decrease in oil and gas prices, significant reductions in the projected dayrates for new contracts and reduced utilization forecasts. Loss on impairment during the prior year was related to our two cold stacked submersible rigs. These rigs were subsequently sold to an unrelated third party in January 2014.

Gain on disposal of assets during the prior year was attributable to the sale of the Noble Lewis Dugger to an unrelated third party in Mexico.

Gain on contract settlements/extinguishments during the prior year was attributable to the $45 million settlement of all claims against the former shareholders of Frontier, which we acquired in July 2010, relating to alleged breaches of various representations and warranties contained in the purchase agreement. A portion of the settlement, totaling approximately $14 million, was allocated to discontinued operations as it related to certain standard specification rigs.

37

Table of Contents

Other

The following table sets forth the operating results from continuing operations for our other services for 2014 and 2013 (dollars in thousands):

Operating Revenues and Costs and Expenses. The change in both revenues and expenses relates to the cancellation of a project with Shell for one of its rigs operating under a labor contract in Alaska during 2013.

Other Income and Expenses

General and administrative expenses. Overall, general and administrative expenses decreased $11 million in 2014 from 2013 primarily as a result of decreased legal and tax expenses related to ongoing projects.

Interest Expense, net of amount capitalized. Interest expense, net of amount capitalized, increased $49 million in 2014 from 2013. The increase is a result of 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 drillships and four of our newbuild jackups, partially offset by the repayment of our $300 million fixed rate senior note in June 2013 and our $250 million fixed rate senior note in March 2014 using availability under our commercial paper program at lower interest rates. During the current year, we capitalized approximately 23 percent of total interest charges versus approximately 52 percent during the prior year.

Income Tax Provision. Our income tax provision increased $15 million in the current year. Excluding the impact of the impairment charges recognized in 2014 and 2013 and the sale of the Noble Lewis Dugger in 2013, taxes increased $58 million driven by a higher worldwide effective tax rate and higher pre-tax income. A 34 percent increase in the worldwide effective tax rate during the current year increased income tax expense by $36 million. The increase in the worldwide effective tax rate was a result of a change in the geographic mix of pre-tax earnings and the effect of the new UK tax law, which became effective retroactively to April 1, 2014, offset by favorable discrete items. Additionally, a 28 percent increase in pre-tax earnings generated a $22 million increase in income tax expense.

Discontinued Operations. Net income from discontinued operations for the current year was $161 million as compared to $304 million for the prior year. Revenues reported within discontinued operations were $1.0 billion during the current year as compared to $1.7 billion for the prior year. Operating income included within discontinued operations was $220 million during the current year and $381 million for the prior year. The variance is attributable to seven months of operations in the current year versus a full year of operations in 2013, coupled with a $45 million increase in non-recurring Spin-off costs during the current year.

38

Table of Contents

2013 Compared to 2012

General

Net income from continuing operations attributable to Noble-UK for 2013 was $479 million, or $1.86 per diluted share, on operating revenues of $2.5 billion, compared to net income from continuing operations for 2012 of $414 million, or $1.63 per diluted share, on operating revenues of $2.2 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 2013 and 2012, 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, 2013 and 2012 was $65 million and $51 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 $18 million and $7 million in 2013 and 2012, respectively, 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 2013 and 2012:

39

Table of Contents

Contract Drilling Services

The following table sets forth the operating results from continuing operations for our contract drilling services segment for 2013 and 2012 (dollars in thousands):

Operating Revenues. Changes in contract drilling services revenues for 2013 as compared to 2012 were driven by increases in both average dayrates and operating days. The 13 percent increase in average dayrates increased revenues by approximately $277 million while the 4 percent increase in operating days increased revenues by an additional $88 million.

The increase in contract drilling services revenues relates to our drillships and jackups, which generated approximately $321 million and $60 million more revenue, respectively, in 2013. These amounts were offset by decreases in revenues for our semisubmersibles, which declined $16 million from 2012.

The increase in drillship revenues was driven by a 57 percent increase in operating days and a 19 percent increase in average dayrates, resulting in a $212 million and a $109 million increase in revenues, respectively, from 2012. The increase in both average dayrates and operating days was the result of the timing of contract commencements of our newbuilds during the period.

The 19 percent increase in jackup average dayrates resulted in a $71 million increase in revenues from 2012. The increase in average dayrates resulted from favorable dayrate changes on new contracts across the jackup fleet and the contract commencement of the Noble Mick O’Brien in November 2013. Additionally, revenue of $18 million was recognized in 2013 in connection with the cancellation of a contract by our customer on the Noble Houston Colbert. The 3 percent decline in operating days resulted in an $11 million decrease in revenues driven by the Noble Lewis Dugger, which was sold in July 2013 but fully utilized during 2012.

The 5 percent increase in average dayrates on our semisubmersibles resulted in a $58 million increase in revenues from 2012. The increase in average dayrates is due to favorable dayrate changes on new contracts across the semisubmersible fleet. The 6 percent decline in operating days resulted in a $74 million decrease in revenues driven by the Noble Paul Romano, which was off contract during 2013 but operated during a portion of 2012 and the Noble Homer Ferrington, which completed its contract during 2013 but experienced full utilization during 2012. These decreases were partially offset by the Noble Max Smith, which experienced full utilization during 2013 after being off contract during 2012.

40

Table of Contents

Operating Costs and Expenses. Contract drilling services operating costs and expenses increased $199 million for 2013 as compared to 2012. A portion of the increase is due to the crew-up and operating expenses for our newbuild rigs as they commenced operating under contracts, which added approximately $134 million in expense in 2013. The remaining change was primarily driven by a $43 million increase in rig and operations support labor due to rigs returning, or preparing to return, to work and salary increases effective in the second and third quarters of 2012 and a $33 million increase in shorebase support due to increased project-related costs. These increases were partially offset by an $11 million decrease in maintenance and rig-related expense.

Depreciation and amortization increased $70 million in 2013 over 2012, which is primarily attributable to newbuild rigs placed in service since the beginning of 2012.

Loss on impairment during 2012 related to an impairment charge on our submersible fleet, primarily as a result of the declining market outlook for drilling services for that rig type. During 2013, we recorded an additional impairment charge of approximately $4 million on our two cold stacked submersible rigs arising from the potential disposition of these assets to an unrelated third party. In January 2014, we completed the sale of the submersibles for a total sales price of $7 million.

Gain on disposal of assets during 2013 was attributable to the sale of the Noble Lewis Dugger to an unrelated third party in Mexico.

Gain on contract settlements/extinguishments during 2013 was attributable to the $45 million settlement of all claims against the former shareholders of Frontier, which we acquired in July 2010, relating to alleged breaches of various representations and warranties contained in the purchase agreement. A portion of the settlement, totaling approximately $14 million, was allocated to discontinued operations as it related to certain standard specification rigs. During 2012, we recognized a $28 million gain on the settlement of an action with certain vendors for damages sustained during Hurricane Ike. Additionally, we recognized a $5 million gain from a claims settlement on the Noble David Tinsley, which had experienced a “punch-through” while being positioned on location in 2009.

Other

The following table sets forth the operating results from continuing operations for our other services for 2013 and 2012 (dollars in thousands):

Operating Revenues and Costs and Expenses. The change in both revenues and expenses for our labor contract drilling services primarily relates to the 2013 cancellation of a project with Shell for one of its rigs operating under a labor contract in Alaska.

41

Table of Contents

Loss on impairment during 2012 related to an impairment charge on certain corporate assets, as a result of a declining market for, and the potential disposal of, the assets.

Other Income and Expenses

General and administrative expenses. Overall, general and administrative expenses increased $18 million in 2013 from 2012 primarily as a result of increased legal and tax expenses related to ongoing projects of $9 million, coupled with increases in employee-related costs of $9 million.

Interest Expense, net of amount capitalized. Interest expense, net of amount capitalized, increased $21 million in 2013 from 2012. The increase is a result of a reduction in capitalized interest in 2013 as compared to 2012 due primarily to the completion of construction on three of our newbuild drillships and two of our newbuild jackups, coupled with increased borrowings outstanding under our credit facilities and commercial paper program. During 2013, we capitalized approximately 52 percent of total interest charges versus approximately 61 percent during 2012.

Income Tax Provision. Our income tax provision decreased $3 million in 2013 as compared to 2012. Excluding the impact of the impairment charges recognized in 2013 and 2012 and the sale of the Noble Lewis Dugger in 2013, taxes decreased $19 million driven by a lower effective tax rate, partially offset by higher pre-tax earnings. A 25 percent decrease in the worldwide effective tax rate during 2013 decreased income tax expense by $26 million. The decrease in the effective tax rate was a result of a change in the geographic mix of pre-tax earnings and the resolution of certain discrete tax items. Additionally, an 8 percent increase in pre-tax earnings generated a $7 million increase in income tax expense.

Discontinued Operations. Net income from discontinued operations for 2013 was $304 million as compared to $108 million for 2012. Revenues reported within discontinued operations were $1.7 billion during 2013 as compared to $1.3 billion for 2012. Operating income included within discontinued operations was $381 million during 2013 and $158 million for 2012. The variance is attributable to an increase in average dayrates as a result of improved market conditions and increased operating days as rigs returned to work, partially offset by an $11 million increase in non-recurring Spin-off costs during 2013.

LIQUIDITY AND CAPITAL RESOURCES

Overview

Cash flows from discontinued operations are combined with cash flows from continuing operations within each cash flow statement category on our Consolidated Statements of Cash Flows included in this Annual Report on Form 10-K. Net cash from operating activities in 2014 was $1.8 billion, which compared to $1.7 billion and $1.4 billion in 2013 and 2012, respectively. We had working capital of $260 million and $339 million at December 31, 2014 and 2013, respectively. Our total debt as a percentage of total debt plus equity increased to 40.1 percent at December 31, 2014, up from 38.0 percent at December 31, 2013 as a result of a decrease in our total equity from the Spin-off and the impairment charge recognized in the current year.

Net cash used in investing activities in 2014 was $2.1 billion, which compared to $2.5 billion and $1.8 billion in 2013 and 2012, respectively. The variance primarily relates to lower expenditures related to the completion of a majority of our newbuild projects, coupled with seven months of expenditures for Paragon Offshore in 2014 as compared to a full year in 2013 and 2012.

Net cash from financing activities in 2014 was $285 million, which compared to $615 million and $452 million in 2013 and 2012, respectively. The variance from 2013 to 2014 primarily relates to an increase in our dividends paid to $1.50 per share in 2014 as compared to $0.76 per share in 2013. In 2014, we repurchased approximately 6.8 million shares in accordance with our share repurchase program. Additionally, 2014 includes the proceeds from the issuance of approximately $1.7 billion of long-term debt by Paragon Offshore prior to the Spin-off, which we used to repay commercial paper issuances.

Our principal sources of capital in 2014 were the proceeds from the indebtedness incurred by Paragon Offshore, the cash generated from operating activities noted above and borrowings under our commercial paper program. Cash generated during the current year was primarily used to fund our capital expenditure program.

42

Table of Contents

Our currently anticipated cash flow needs, both in the short-term and long-term, may include the following:

We currently expect to fund these cash flow needs with cash generated by our operations, cash on hand, borrowings under our existing or future credit facilities and commercial paper program, 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, 2014, we had a total contract drilling services backlog of approximately $10.1 billion. Our backlog as of December 31, 2014 includes a commitment of 81 percent of available days for 2015. See “Contract Drilling Services Backlog” for additional information regarding our backlog.

Capital Expenditures

We expect our primary use of available liquidity during 2015 to be for capital expenditures. Capital expenditures, including capitalized interest, totaled $2.1 billion, $2.5 billion and $1.7 billion for 2014, 2013 and 2012, respectively.

At December 31, 2014, we had one rig under construction, and capital expenditures, excluding capitalized interest, for new construction during 2014 totaled $1.4 billion, as follows (in millions):

In addition to the newbuild expenditures noted above, capital expenditures during 2014, including expenditures related to Paragon Offshore through the date of the Spin-off, consisted of the following:

43

Table of Contents

Our total capital expenditure budget for 2015 is approximately $555 million, which is currently anticipated to be spent as follows:

In addition to the amounts noted above, we anticipate incurring capitalized interest, which may fluctuate as a result of the timing of completion of ongoing projects. In connection with our capital expenditure program, we have entered into certain commitments, including shipyard and purchase commitments, for approximately $729 million at December 31, 2014, of which we expect to spend approximately $308 million in 2015.

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.

Dividends

Our most recent quarterly dividend payment to shareholders, totaling approximately $93 million (or $0.375 per share), was declared on January 30, 2015 and paid on February 20, 2015 to holders of record on February 10, 2015.

The declaration and payment of dividends require authorization of the Board of Directors of Noble-UK and 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 amount 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. Prior to our redomiciliation to the UK, a resolution was adopted by Noble-UK’s sole shareholder authorizing the repurchase of 6,769,891 shares during the five-year period commencing on the date of the redomiciliation. This number of shares corresponds to the number of shares that Noble-Swiss had authority to repurchase at the time of the redomiciliation. During 2014, we repurchased all shares covered by this authorization.

Share repurchases for each of the three years ended December 31 are as follows:

In December 2014, we received shareholder approval to repurchase up to 37,000,000 additional ordinary shares, or approximately 15 percent of our outstanding ordinary shares at the time of the shareholder approval. Any repurchases are expected to be funded using cash on hand, cash from operations or short-term borrowings under our credit facilities. The authority to make such repurchases will expire on the later of April 2016 or the end of the Company’s 2016 annual general meeting of shareholders, at which time we could seek shareholder approval for further repurchases.

44

Table of Contents

In January 2015, we repurchased 6.2 million of our ordinary shares at an average price of $16.10 per share, excluding commissions and stamp tax. Including these items, the average price paid per share during January 2015 was $16.21. There can be no assurance as to the timing or amount of any such repurchases. However, we intend to take a cautious approach to future share repurchases at least until market conditions in the offshore drilling business stabilize.

Credit Facilities and Senior Unsecured Notes

Credit Facilities and Commercial Paper Program

At December 31, 2014, we had three credit facilities with an aggregate maximum available capacity of $2.9 billion, and a commercial paper program, which allowed us to issue up to $2.7 billion in unsecured commercial paper notes. Amounts issued under the commercial paper program are supported by the unused capacity under our credit facilities and, therefore, are classified as long-term on our Consolidated Balance Sheet. The outstanding amounts of commercial paper reduce availability under our credit facilities.

Our total debt related to the credit facilities and commercial paper program was $1.1 billion at December 31, 2014 as compared to $1.6 billion at December 31, 2013. At December 31, 2014, we had no letters of credit issued under the credit facilities.

In January 2015, we replaced the credit facilities discussed above with two new credit facilities, a five year $2.4 billion senior unsecured credit facility that matures in January 2020 and a $225 million 364-day senior unsecured credit facility that matures in January 2016 (together, the “Credit Facilities”). The $2.4 billion 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. Following the establishment of the new Credit Facilities, we reduced the size of our commercial paper program to $2.4 billion from $2.7 billion. We believe this provides us with sufficient borrowing capacity for our current cash flow needs.

Senior Unsecured Notes

Our total debt related to senior unsecured notes was $3.7 billion at December 31, 2014 as compared to $4.0 billion at December 31, 2013. The decrease in senior unsecured notes outstanding is a result of the maturity of our $250 million 7.375% Senior Notes during March 2014, which was repaid using proceeds from issuances under our commercial paper program.

Our $350 million 3.45% Senior Notes mature during the third quarter of 2015. We anticipate using availability under our Credit Facilities or commercial paper issuances to repay the outstanding balance; therefore, we continue to report the balance as long-term at December 31, 2014.

Covenants

The Credit Facilities and commercial paper program are guaranteed by our indirect, wholly-owned subsidiaries, Noble Holding International Limited (“NHIL”) and Noble Holding Corporation (“NHC”). The covenants and events of default under the Credit Facilities are substantially similar, and each facility contains a covenant that limits our ratio of debt to total tangible capitalization, as defined in the Credit Facilities, to 0.60. At December 31, 2014, our ratio of debt to total tangible capitalization was approximately 0.40. We were in compliance with all covenants under the credit facilities as of December 31, 2014.

In addition to the covenants from the Credit Facilities 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 sale and lease-back transactions. At December 31, 2014, we were in compliance with all of our debt covenants. We continually monitor compliance with the covenants under our notes and expect to remain in compliance during 2015.

45

Table of Contents

Other

At December 31, 2014, we had letters of credit of $149 million, including bonds covering the temporary importation of equipment, performance bonds and expatriate visa guarantees.

Summary of Contractual Cash Obligations and Commitments

The following table summarizes our contractual cash obligations and commitments at December 31, 2014 (in thousands):