Item 1. Business.
Overview
Noble Corporation plc, a public limited company incorporated under the laws of England and Wales (“Noble-UK”), is a leading offshore drilling contractor for the oil and gas industry. We provide contract drilling services to the international oil and gas industry with our global fleet of mobile offshore drilling units. We focus on a balanced, high-specification fleet of floating and jackup rigs and the deployment of our drilling rigs in oil and gas basins around the world. Noble and its predecessors have been engaged in the contract drilling of oil and gas wells since 1921.
We report our contract drilling operations as a single reportable segment, Contract Drilling Services, which reflects how we manage our business. The mobile offshore drilling units comprising our offshore rig fleet operate in a global market for contract drilling services and are often redeployed to different regions due to changing demands of our customers, which consist primarily of large, integrated, independent and government-owned or controlled oil and gas companies throughout the world. As of February 18, 2020, our fleet of 25 drilling rigs consisted of 12 floaters and 13 jackups.
Noble Corporation, a Cayman Islands company (“Noble-Cayman”), is an indirect, wholly-owned subsidiary of Noble-UK, our publicly-traded parent company. Noble-UK’s principal asset is all of the shares of Noble-Cayman. Noble-Cayman has no public equity outstanding. The consolidated financial statements of Noble-UK include the accounts of Noble-Cayman, and Noble-UK conducts substantially all its business through Noble-Cayman and its subsidiaries.
On August 1, 2014, Noble-UK completed the separation and spin-off of a majority of its standard specification offshore drilling business (the “Spin-off”) through a pro rata distribution of all the ordinary shares of its wholly-owned subsidiary, Paragon Offshore plc (“Paragon Offshore”), to the holders of Noble’s ordinary shares. The results of operations for Paragon Offshore prior to the Spin-off date and incremental Spin-off related costs have been classified as discontinued operations for all periods presented in this Annual Report on Form 10-K. For additional information regarding the Spin-off and certain matters relating to Paragon Offshore, see Part I, Item 1A, “Risk Factors” and Part II, Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations- Executive Overview- Spin-off of Paragon Offshore plc” and Part II, Item 8, “Financial Statements and Supplementary Data, Note 16- Commitments and Contingencies.”
Drilling Services
We typically provide contract drilling services under an individual contract, on a dayrate basis. Although the final terms of the contracts result from negotiations with our customers, many contracts are awarded based upon a competitive bidding process. Our drilling contracts generally contain the following terms:
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contract duration extending over a specific period of time or a period necessary to drill a defined number of wells;
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payment of compensation to us (generally in US Dollars although some customers, typically national oil companies, require a part of the compensation to be paid in local currency) on a “daywork” basis, so that we receive a fixed amount for each day (“dayrate”) that the drilling unit is operating under contract (a lower rate or no compensation is payable during periods of equipment breakdown and repair or adverse weather or in the event operations are interrupted by other conditions, some of which may be beyond our control);
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provisions permitting early termination of the contract by the customer (i) if the unit is lost or destroyed, (ii) if operations are suspended for a specified period of time due to breakdown of equipment or breach of contract or (iii) for convenience;
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provisions allowing the impacted party to terminate the contract if specified “force majeure” events beyond the contracting parties’ control occur for a defined period of time;
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payment by us of the operating expenses of the drilling unit, including labor costs and the cost of incidental supplies;
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provisions that allow us to recover certain cost increases from our customers in certain long-term contracts; and
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provisions that require us to lower dayrates for documented cost decreases in certain long-term contracts.
Generally, our contracts allow us to recover our mobilization and demobilization costs associated with moving a drilling unit from one regional location to another. When market conditions require us to assume these costs, our operating margins are reduced accordingly. For shorter moves, such as “field moves,” our customers have generally agreed to assume the costs of moving the unit in the form of a reduced dayrate or “move rate” while the unit is being moved. Under current market conditions, we are much less likely to receive full reimbursement of our mobilization and demobilization costs.
Contracts often contain early termination provisions permitting the customer to terminate the contract if the unit is lost or destroyed or if operations are suspended for a specified period of time due to breakdown of equipment or breach of contract. In addition, the terms of some of our drilling contracts permit the customer to terminate the contract after specified notice periods by tendering contractually specified termination amounts and, in certain cases, without any payment.
During periods of depressed market conditions, such as the one we have been experiencing, our customers may attempt to renegotiate or repudiate their contracts with us although we seek to enforce our rights under our contracts. The renegotiations may include changes to key contract terms, such as pricing, termination and risk allocation.
For a discussion of our backlog of commitments for contract drilling services, please read Part II, Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations- Contract Drilling Services Backlog.”
Drilling Fleet
Noble is a leading offshore drilling contractor for the oil and gas sector. Noble owns and operates one of the most modern, versatile and technically advanced fleets of mobile offshore drilling units in the offshore drilling industry. Noble provides, through its subsidiaries, contract drilling services with a fleet of 25 offshore drilling units, consisting of 12 floaters and 13 jackups, focused largely on ultra-deepwater and high-specification drilling opportunities in both established and emerging regions worldwide. Each type of drilling rig is described further below. Several factors determine the type of unit most suitable for a particular job, the most significant of which include the water depth and the environment of the intended drilling location, whether the drilling is being done over a platform or other structure, and the intended well depth. At December 31, 2019, our fleet was located in Canada, Far East Asia, the Middle East, the North Sea, Oceania, South America and the US Gulf of Mexico.
Floaters
Our floating fleet consists of the following:
A drillship is a type of floating drilling unit that is based on the ship-based hull of the vessel and equipped with modern drilling equipment that gives it the capability of easily transitioning from various worldwide locations and carrying high capacities of equipment while being able to drill ultra-deepwater oil and gas wells in up to 12,000 feet of water. Drillships can stay directly over the drilling location without anchors in open seas using a dynamic positioning system (“DPS”), which coordinates position references from satellite signals and acoustic seabed transponders with the drillship's six to eight thrusters to keep the ship directly over the well that is being drilled. Drillships are selected to drill oil and gas wells for programs that require a high level of simultaneous operations, where drilling loads are expected to be high, or where there are occurrences of high ocean currents, where the drillship's hull shape is the most efficient. Noble's fleet consists of eight drillships capable of water depths from 8,200 feet to 12,000 feet.
Semisubmersible drilling units are designed as a floating drilling platform incorporating one or several pontoon hulls, which are submerged in the water to lower the center of gravity and make this type of drilling unit exceptionally stable in the open sea. Semisubmersible drilling units are generally categorized in terms of the water depth in which they are capable of operating, from the mid-water range of 300 feet to 4,000 feet, the deepwater range of 4,000 feet to 7,500 feet, to the ultra-deepwater range of 7,500 feet to 12,000 feet as well as by their generation, or date of construction. This type of drilling unit typically exhibits excellent stability characteristics, providing a stable platform for drilling in even rough seas. Semisubmersible drilling units hold their position over the drilling location using either an anchored mooring system or a DPS and may be self-propelled. Noble's fleet consists of four semisubmersible drilling units, two of which are equipped with anchored mooring systems and two of which utilize DPS, with fleet diversity to operate in mid-water, deepwater and ultra-deepwater depth ranges with high levels of efficiency.
Jackups
Noble's fleet of modern, high-specification jackup drilling units gives us the flexibility to provide drilling solutions to our customers who have drilling requirements in the shallower waters of the continental shelf, in depths ranging from less than 100 feet to as deep as 500 feet. Jackup rigs can be used in open water exploration locations, as well as over fixed, bottom-supported platforms. A jackup drilling unit is a towed mobile vessel consisting of a floating hull equipped with three or four legs, which are lowered to the seabed at the drilling location. The hull is then elevated out of the water by the jacking system using the legs to support weight of the hull and drilling equipment against the seabed. Once the hull is elevated to the desired level, or jacked up, the drilling package can be extended out over an existing production platform or the open water location and drilling can commence. Noble's fleet of 13 jackups varies from two standard units capable of drilling in up to 375 feet of water to premium and high-specification units capable of drilling in up to 500 feet of water with drilling hookloads greater than 2,500,000 pounds.
Offshore Fleet
The following table presents certain information concerning our offshore fleet at February 18, 2020. We own and operate all of the units included in the table.
(1)
Rigs designated with an “R” were modified, refurbished or otherwise upgraded in the year indicated by capital expenditures of an amount deemed material by management. Rigs designated with an “N” are newbuilds. Rigs designated with an “M” have been upgraded to the Noble NC-5SM mooring standard.
(2)
Rated water depth for drillships and semisubmersibles reflects the maximum water depth for which a floating rig has been designed for drilling operations.
(3)
Rigs listed as “active” are operating, preparing to operate or under contract; rigs listed as “available” are actively seeking contracts and may include those that are idle or warm stacked; rigs listed as “shipyard” are in a shipyard for construction, repair, refurbishment or upgrade; rigs listed as “stacked” are idle without a contract and have reduced or no crew and are not actively marketed in present market conditions.
(4)
Harsh environment capability.
(5)
The Noble Joe Beall will not be marketed once the rig completes its current contract, which is expected to be in late February 2020.
Market
The offshore contract drilling industry is a highly competitive and cyclical business characterized by large capital expenditures and large swings in pricing. Demand for offshore drilling equipment is driven by the exploration and development programs of oil and gas companies, which in turn are influenced by many factors, including the price of oil and gas, the availability and relative cost of onshore oil and gas resources, general global economic conditions, energy demand, environmental considerations and national oil and gas policy.
In the provision of offshore contract drilling services, competition is largely governed by price but involves numerous other factors as well. Rig availability, location, suitability and technical specifications are the primary factors in determining which rig is qualified for a job, and additional factors are considered when determining which contractor is awarded a job, including experience of the workforce, efficiency, safety performance record, condition of equipment, operating integrity, reputation, industry standing and client relations. In addition to having one of the newest fleets in the industry among our peer companies, we strive to keep our equipment well-maintained and technologically competitive.
We maintain a global operational presence and compete in most of the major offshore oil and gas basins worldwide. All of our drilling rigs are mobile, and we may mobilize our drilling rigs among regions for a variety of reasons, including to respond to customer requirements. We compete in both the jackup and floating rig market segments, each of which may have different supply and demand dynamics at a given period in time or in different regions.
Demand for our services is, in significant part, a function of the worldwide demand for oil and gas and the global supply of mobile offshore drilling units. Since late 2014, the offshore drilling industry has experienced a severe and prolonged downturn stemming from the combination of an oversupply of competing drilling rigs, weak and volatile crude oil prices, and the advancement of onshore opportunities and technology, leading to heightened competition for opportunities to re-contract our rigs upon expiry of existing contracts.
We believe that improvements in market conditions will ultimately result from, among other things, improved oil prices, additional investment by our customers in offshore exploration and development, and attrition of rigs in the global offshore fleet. Our young and technologically advanced fleet is well positioned to compete now and in the future as market dynamics improve.
Significant Customers
Offshore contract drilling operations accounted for approximately 95 percent, 96 percent and 98 percent of our operating revenues for the years ended December 31, 2019, 2018 and 2017, respectively. During the three years ended December 31, 2019, we principally conducted our contract drilling operations in Canada, Far East Asia, the Middle East, the North Sea, Oceania, the Black Sea, Africa, South America and the US Gulf of Mexico. Revenues from Royal Dutch Shell plc (“Shell”), Exxon Mobil Corporation (“ExxonMobil”), Equinor ASA (“Equinor”) and Saudi Arabian Oil Company (“Saudi Aramco”) accounted for approximately 36.5 percent, 13.7 percent, 13.1 percent and 11.9 percent, respectively, of our consolidated operating revenues, which was inclusive of the Noble Bully II contract buyout, for the year ended December 31, 2019. Exclusive of the Noble Bully II contract buyout, revenues from Shell, ExxonMobil, Equinor and Saudi Aramco accounted for approximately 27.1 percent, 15.7 percent, 15.1 percent and 13.6 percent, respectively, of our consolidated operating revenues for the year ended December 31, 2019. Revenues from Shell, Equinor and Saudi Aramco accounted for approximately 45.0 percent, 13.2 percent and 11.4 percent, respectively, of our consolidated operating revenues for the year ended December 31, 2017. No other customer accounted for more than 10 percent of our consolidated operating revenues in 2019, 2018 or 2017.
Employees
At December 31, 2019, we had approximately 2,000 employees, excluding approximately 1,000 persons we engaged through labor contractors or agencies. Approximately 85 percent of our workforce is located offshore. We are not a party to any material collective bargaining agreements, and we consider our employee relations to be satisfactory.
We place considerable value on the involvement of our employees and maintain a practice of keeping them informed on matters affecting them, as well as on the performance of the Company. Accordingly, we conduct formal and informal meetings with employees, maintain a Company intranet website with matters of interest, issue periodic publications of Company activities and other matters of interest, and offer a variety of in-house training, including through NobleAdvances, our state-of-the art training facility in Sugar Land, Texas.
We are committed to a policy of recruitment and promotion based upon merit without discrimination. Management actively pursues both the employment of disabled persons whenever a suitable vacancy arises and the continued employment and retraining of employees who become disabled while employed by the Company. Training and development is undertaken for all employees, including disabled persons.
Governmental Regulations and Environmental Matters
Political developments and numerous governmental regulations, which may relate directly or indirectly to the contract drilling industry, affect many aspects of our operations. Our contract drilling operations are subject to various laws and regulations in countries in which we operate, including laws and regulations relating to the equipping, supplying and operation of drilling units, environmental protection and related recordkeeping, health and safety of personnel, safety management systems, the reduction of atmospheric emissions that contribute to a cumulative effect on the overall air quality and environment (commonly referred to as greenhouse gases), currency conversions and repatriation, oil and gas exploration and development, taxation of capital equipment, taxation of offshore earnings and earnings of expatriate personnel, employee benefits 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 influenced their need for offshore drilling services, and likely will continue to do so.
The regulations applicable to our operations include provisions that regulate the discharge of materials into the environment or require remediation of contamination under certain circumstances. Many of the countries in whose waters we operate from time to time regulate the discharge of oil and other contaminants in connection with drilling and marine operations. Failure to comply with these laws and regulations, or failure to obtain or comply with permits, may result in the assessment of administrative, civil and criminal penalties, imposition of remedial requirements and the imposition of injunctions to force future compliance. Although these requirements impact the oil and gas and energy services industries, generally they do not appear to affect us in any material respect that is different, or to any materially greater or lesser extent, than other companies in the energy services industry. However, our business and prospects could be adversely affected by regulatory activity that prohibits or restricts our customers’ exploration and production activities, resulting in reduced demand for our services or imposing environmental protection requirements that result in increased costs to us, our customers or the oil and natural gas industry in general.
The following is a summary of some of the existing laws and regulations that apply in the United States and Europe, which serves as an example of the various laws and regulations to which we are subject. While laws vary widely in each jurisdiction, each of the laws and regulations below addresses environmental issues similar to those in most of the other jurisdictions in which we operate.
Offshore Regulation and Safety. In response to the Macondo well blowout incident in April 2010, the United States Congress, the US Department of Interior, through the Bureau of Ocean Energy Management (“BOEM”) and the Bureau of Safety and Environmental Enforcement (“BSEE”), and the US Department of Homeland Security, through the United States Coast Guard (“UCSG”), have undertaken an aggressive overhaul of the offshore oil and natural gas related regulatory processes, which has significantly impacted oil and gas development and operational requirements in the US Gulf of Mexico. Such actions by the US government has, on occasion, served as a leading indicator for similar regulatory developments or requirements by other countries where, from time to time, new rules, regulations and requirements in the United States and in other countries have been proposed and implemented that materially limit or prohibit, and increase the cost of, offshore drilling and related operations. Other similar regulations impact certain operational requirements on rigs and govern liability for vessel or cargo loss, or damage to life, property, or the marine environment. See Part I, Item 1A, “Risk Factors -Changes in, compliance with, or our failure to comply with the certain laws and regulations may negatively impact our operations and could have a material adverse effect on our results of operations” for additional information.
Spills and Releases. The US Oil Pollution Act of 1990 (“OPA”), the Comprehensive Environmental Response, Compensation, and Liability Act in the United States (“CERCLA”), and similar regulations, including but not limited to the International Convention for the Prevention of Pollution from Ships (“MARPOL”), adopted by the International Maritime Organization (“IMO”), as enforced in the United States through the domestic implementing law called the Act to Prevent Pollution from Ships, impose certain operational requirements on offshore rigs operating in the United States and govern liability for leaks, spills and blowouts involving pollutants. OPA imposes strict, joint and several liabilities on “responsible parties” for damages, including natural resource damages, resulting from oil spills into or upon navigable waters, adjoining shorelines or in the exclusive economic zone of the United States. A “responsible party” includes the owner or operator of an onshore facility and the lessee or permit holder of the area in which an offshore facility is located. CERCLA and similar state and foreign laws and regulation, impose joint and several liabilities, without regard to fault or the legality of the original act, on certain classes of persons that contributed to the release of a “hazardous substance” into the environment. In the course of our ordinary operations, we may generate waste that may fall within the scope of CERCLA's definition of a “hazardous substance.” However, we have to-date not received any notification that we are, or may be, potentially responsible for cleanup costs under CERCLA.
Regulations under OPA require owners and operators of rigs in United States waters to maintain certain levels of financial responsibility. The failure to comply with OPA’s requirements may subject a responsible party to civil, criminal, or administrative enforcement actions. We are not aware of any action or event that would subject us to liability under OPA, and we believe that compliance with OPA’s financial assurance and other operating requirements will not have a material impact on our operations or financial condition.
Waste Handling. The US Resource Conservation and Recovery Act (“RCRA”), and similar state, local and foreign laws and regulations govern the management of wastes, including the treatment, storage and disposal of hazardous wastes. RCRA imposes stringent operating requirements, and liability for failure to meet such requirements, on a person who is either a “generator” or “transporter” of hazardous waste or an “owner” or “operator” of a hazardous waste treatment, storage or disposal facility. RCRA and many state counterparts specifically exclude from the definition of hazardous waste drilling fluids, produced waters, and other wastes associated with the exploration, development, or production of crude oil and natural gas. As a result, our operations generate minimal quantities of RCRA hazardous wastes. We do not believe the current costs of managing our wastes, as they are presently classified, to be significant. However, any repeal or modification of this or similar exemption in similar state statutes, would increase the volume of hazardous waste we are required to manage and dispose of, and would cause us, as well as our competitors, to incur increased operating expenses with respect to our US operations.
Water Discharges. The US 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 US Coast Guard has promulgated requirements for ballast water management as well as supplemental ballast water requirements, which includes limits and, in some cases, water treatment requirements applicable to specific discharge streams, such as deck runoff, bilge water and gray water. We do not anticipate that compliance with these laws will cause a material impact on our operations or financial condition.
Air Emissions. The US Federal Clean Air Act and associated state laws and regulations restrict the emission of air pollutants from many sources, including oil and natural gas operations. New facilities may be required to obtain permits before operations can commence, and existing facilities may be required to obtain additional permits, and incur capital costs, in order to remain in compliance. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the Clean Air Act and associated state laws and regulations. In general, we believe that compliance with the Clean Air Act and similar state laws and regulations will not have a material impact on our operations or financial condition.
Climate Change. There is increasing attention concerning the issue of climate change and the effect of greenhouse gas (“GHG”) emissions. The United States Environmental Protection Agency (“EPA”) regulates the permitting of GHG emissions from stationary sources under the Clean Air Act’s Prevention of Significant Deterioration and Title V permitting programs, which require the use of “best available control technology” for GHG emissions from new and modified major stationary sources, which can sometimes include our rigs. The EPA has also adopted rules requiring the monitoring and reporting of GHG emissions from specified sources in the United States, including, among other things, certain onshore and offshore oil and natural gas production facilities, on an annual basis.
Moreover, in 2005, the Kyoto Protocol to the 1992 United Nations Framework Convention on Climate Change, which establishes a binding set of emission targets for GHGs, became binding on all countries that had ratified it. In 2015, the United Nations (“U.N.”) Climate Change Conference in Paris resulted in the creation of the Paris Agreement. The Paris Agreement requires countries to review and “represent a progression” in their nationally determined contributions, which set emissions reduction goals, every five years beginning in 2020. In November 2019, the United States submitted formal notification to the U.N. that it intends to withdraw from the Paris Agreement. Pursuant to the terms of the Paris Agreement, the withdrawal will take effect in November 2020. However, there are no guarantees that the agreement will not be re-implemented in the United States or that the United States will not otherwise mandate similar emission reduction goals, or that the agreement will not be re-implemented in part by certain state or local governments. Incentives to conserve energy or use alternative energy sources could have a negative impact on our business if such incentives reduce the worldwide demand for oil and gas. See Part I, Item1A, “Risk Factors- Governmental laws and regulations may add to our costs, result in delays, or limit our drilling activity” for additional information.
Countries in the European Union (“EU”) implement the U.N.’s Kyoto Protocol on GHG emissions through the Emissions Trading System (“ETS”). The ETS program establishes a GHG “cap and trade” system for certain industry sectors, including power generation at some offshore facilities. Total GHG from these sectors is capped, and the cap is reduced over time to achieve a 21 percent GHG reduction from these sectors between 2005 and 2020. The ETS program will continue to require GHG reductions in the future. Phase 4 of the ETS program (covering 2021 to 2030) was revised in 2018 to achieve emission reduction targets as part of the EU’s contribution to the Paris Agreement. Phase 4 targets a 43 percent GHG reduction between 2005 and 2030.
In addition, the United Kingdom (“UK”) government, which implements ETS in the UK North Sea, has introduced a carbon price floor mechanism to place an incrementally increasing minimum price on carbon. Thus, the cost of compliance with ETS can be expected to increase over time. Additional member state climate change legislation may result in potentially material capital expenditures.
We have determined that combustion of diesel fuel (Scope 1) aboard all of our vessels worldwide is the Company’s primary source of GHG emissions, including carbon dioxide, methane and nitrous oxide. The data necessary to report indirect emissions from generation of purchased power (Scope 2) has not been previously collected; however, procedures are being established to collect and report Scope 2 data.
For the year ended December 31, 2019, our estimated carbon dioxide equivalent (“CO2e”) gas emissions were 1,063,925 tonnes as compared to 954,944 tonnes for the year ended December 31, 2018. When expressed as an intensity measure of tonnes of CO2e gas emissions per dollar of contract drilling revenues from continuing operations, the intensity measure for December 31, 2019 and 2018 was 0.0009 and 0.0009, respectively. The increase in emissions is due to increases in transoceanic voyages by the Noble Globetrotter I and Noble Globetrotter II as well as activation of the newest additions to the fleet, the Noble Johnny Whitstine and Noble Joe Knight.
Our Scope 1 CO2e gas emissions reporting has been prepared with reference to the requirements set out in the UK Companies Act 2006 Regulations 2013, the Environmental Reporting Guidelines (June 2013) issued by the Department for Environment Food & Rural Affairs, the World Resources Institute and World Business Council for Sustainable Development GHG Protocol Corporate Accounting and Reporting Standard Revised and the International Organization for Standardization (“ISO”) 14064-1, “Specification with guidance at the organizational level for quantification and reporting of greenhouse gas emissions and removals (2006).”
It is our intent to have the procedures related to GHG emissions independently assessed in the future.
Worker Safety. The US Occupational Safety and Health Act (“OSHA”) and other similar laws and regulations govern the protection of the health and safety of employees. The OSHA hazard communication standard, EPA community right-to-know regulations under Title III of CERCLA and similar state statutes require that information be maintained about hazardous materials used or produced in our operations and that this information be provided to employees, state and local governments and citizens. EU member states have also adopted regulations pursuant to EU Directive 2013/30/EU, on the safety of offshore oil and gas operations within the exclusive economic zone (which can extend up to 200 nautical miles from a coast) or the continental shelf. We believe that we are in substantial compliance with OSHA requirements and EU directive 2013/30/EU (as well as the extensive current health and safety regimes implemented in the member states in which we operate), but future developments could require the Company to incur significant costs to comply with the directive's implementation.
International Regulatory Regime. The IMO provides international regulations governing shipping and international maritime trade. IMO regulations have been widely adopted by U.N. member countries, and in some jurisdictions in which we operate, these regulations have been expanded upon. The requirements contained in the International Management Code for the Safe Operation of Ships and for Pollution Prevention, or ISM Code, promulgated by the IMO, govern much of our drilling operations. Among other requirements, the ISM Code requires the party with operational control of a vessel to develop an extensive safety management system that includes, among other things, the adoption of a safety and environmental protection policy setting forth instructions and procedures for operating its vessels safely and describing procedures for responding to emergencies.
The IMO has also adopted and revised MARPOL, including Annex VI to MARPOL, which limits the main air pollutants contained in exhaust gas from ships, including sulfur oxides (“SOx”) and nitrous oxides (“NOx”), prohibits deliberate emissions of ozone depleting substances (“ODS”), regulates shipboard incineration and the emissions of volatile organic compounds (“VOC”) from tankers, sets a progressive reduction globally in emissions of SOx, NOx and particulate matter, introduces emission control areas (“ECAs”) to reduce emissions of those air pollutants further in designated sea areas, and effective from January 1, 2020, reduces the global sulfur limit in fuel oil from the current 3.50% to 0.50% m/m (mass by mass) sulfur content. Prior to January 1, 2020, our rigs were operating and continue to operate with low sulfur fuel oil at or below the global limits of 0.50%.
The IMO has also negotiated international conventions that impose liability for oil pollution in international waters and the territorial waters of the signatory to such conventions such as the Ballast Water Management Convention, (the “BWM Convention”) and the International Convention for Civil Liability for Bunker Oil Pollution Damage of 2001 (the “Bunker Convention”). The BWM Convention's implementing regulations call for a phased introduction of mandatory ballast of water exchange requirements (beginning in 2009), to be replaced in time with a requirement for mandatory ballast water treatment. The Bunker Convention provides a liability, compensation and compulsory insurance system for the victims of oil pollution damage caused by spills of bunker oil. We believe that all of our drilling rigs are currently compliant in all material respects with these regulations. However, the IMO continues to review and introduce new regulations. It is impossible to predict what additional regulations, if any, may be passed by the IMO and what effect, if any, such regulation may have on our operations.
Insurance and Indemnification Matters
Our operations are subject to many hazards inherent in the drilling business, including blowouts, fires, collisions, groundings, punch-throughs, and damage or loss from adverse weather and sea conditions. These hazards could cause personal injury or loss of life, loss of revenues, pollution and other environmental damage, damage to or destruction of property and equipment and oil and natural gas producing formations, and could result in claims by employees, customers or third parties and fines and penalties.
Our drilling contracts provide for varying levels of indemnification from our customers and in most cases also require us to indemnify our customers for certain losses. Under our drilling contracts, liability with respect to personnel and property is typically assigned on a “knock-for-knock” basis, which means that we and our customers assume liability for our respective personnel and property, generally irrespective of the fault
or negligence of the party indemnified. In addition, our customers may indemnify us in certain instances for damage to our down-hole equipment and, in some cases, our subsea equipment. Also, we generally obtain a mutual waiver of consequential losses in our drilling contracts.
Our customers typically assume responsibility for and indemnify us from loss or liability resulting from pollution or contamination, including third-party damages and clean-up and removal, arising from operations under the contract and originating below the surface of the water. We are generally responsible for pollution originating above the surface of the water and emanating from our drilling units. Additionally, our customers typically indemnify us for liabilities incurred as a result of a blow-out or cratering of the well and underground reservoir loss or damage. In the current market, we are under increasing pressure to accept exceptions to the above-described allocations of risk and, as a result, take on more risk. In such cases where we agree, we generally limit the exposure with a monetary cap and other restrictions.
In addition to the contractual indemnities described above, we also carry Protection and Indemnity (“P&I”) insurance, which is a comprehensive general liability insurance program covering liability resulting from offshore operations. Our P&I insurance includes coverage for liability resulting from personal injury or death of third parties and our offshore employees, third-party property damage, pollution, spill clean-up and containment and removal of wrecks or debris. Our P&I insurance program is renewed in April of each year and currently has a standard deductible of $10 million per occurrence, with maximum liability coverage of $750 million. We also carry hull and machinery insurance that protects us against physical loss or damage to our drilling rigs, subject to a deductible that is currently $10.0 million.
Our insurance policies and contractual rights to indemnity may not adequately cover our losses and liabilities in all cases. For additional information, please read “We may have difficulty obtaining or maintaining insurance in the future and our insurance coverage and contractual indemnity rights may not protect us against all the risks and hazards we face” included in Part I, Item 1A, “Risk Factors” of this Annual Report on Form 10-K.
The above description of our insurance program and the indemnification provisions of our drilling contracts is only a summary as of the time of preparation of this report, and is general in nature. Our insurance program and the terms of our drilling contracts may change in the future. In addition, the indemnification provisions of our drilling contracts may be subject to differing interpretations, and enforcement of those provisions may be limited by public policy and other considerations.
Available Information
Our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act are available free of charge at our website at http://www.noblecorp.com. The US Securities and Exchange Commission (the “SEC”) maintains an internet site that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC at http://www.sec.gov.
You may also find information related to our corporate governance, board committees and company code of ethics (and any amendments or waivers of compliance) at our website. Among the documents you can find there are the following:
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Articles of Association;
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Code of Business Conduct and Ethics;
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Corporate Governance Guidelines;
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Audit Committee Charter;
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Compensation Committee Charter;
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Health, Safety, Environment and Engineering Committee Charter;
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Nominating and Corporate Governance Committee Charter; and
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Finance Committee Charter.
Item 1A.
Item 1A. Risk Factors.
You should carefully consider the following risk factors in addition to the other information included in this Annual Report on Form 10-K. Each of these risk factors could affect our business, operating results and financial condition, as well as affect an investment in our shares.
Our business and results of operations have been materially and negatively impacted and our market value has substantially declined due to depressed market conditions which are the result of the dramatic drop in the oil price, the development of additional onshore oil and gas resources and the oversupply of offshore drilling rigs.
After a period of sustained high crude oil prices, oil prices began a steep decline beginning in late 2014 and dropped to as low as approximately $30 per barrel in January 2016. Oil prices have partially recovered to a price of approximately $58 per barrel on February 18, 2020, but have been volatile and have not recovered to 2014 levels. As a result of the oil price environment prior to the significant drop in 2014, the offshore drilling business flourished with high utilization and high dayrates, and a large number of offshore drilling rigs were constructed to take advantage of the market. Also, many in our industry extended the lives of older rigs rather than retiring these rigs. These factors have led to a significant oversupply
of drilling rigs while our customers have greatly reduced their planned offshore exploration and development spending in response to the depressed price of oil.
During the same period, onshore crude oil production in the United States rose sharply. While the cost of production onshore varies, in some cases it may be less than the cost of production in offshore fields where our rigs are designed to operate, especially deepwater fields. Additionally onshore production is perceived as yielding more consistent results and posing lower regulatory risk than offshore production.This increase in onshore US production has had a negative impact on the price of oil and the demand for our services. Further, given the reduced oil price and often the lower operating costs onshore, many of our customers have allocated more of their capital budgets to onshore exploration activities than offshore exploration activities, particularly deepwater exploration activities, which has also led to a decrease in the demand for offshore drilling services since 2014.
These factors have affected market conditions and led to a material decline in the demand for our services since 2014, the dayrates we are paid by our customers and the level of utilization of our drilling rigs. These poor market conditions, in turn, have led to a material deterioration in our results of operations. We have experienced a substantial decline in the price of our shares, which declined from $27 on August 4, 2014 post Spin-off to $0.83 at February 18, 2020. There can be no assurance as to if, when or to what extent the current depressed market conditions, and our business, results of operations or enterprise value, will improve. Further, even if the price of oil and gas were to increase dramatically, we cannot assure you that there would be any increase in demand for our services.
If we cannot meet the continued listing requirements of the New York Stock Exchange, our shares may be subject to delisting from the New York Stock Exchange, which would have a material adverse effect on our business, financial condition, prospects and liquidity and value of our shares.
On February 19, 2020, we were notified by the New York Stock Exchange (“NYSE”) that the average closing price of our shares was below $1.00 per share over a period of 30 consecutive trading days, which is the minimum average share price required to maintain listing on the NYSE under Section 802.01C of the NYSE Listed Company Manual.We have a period of six months following receipt of the NYSE’s notice to regain compliance with the NYSE’s minimum share price requirement, during which time our shares would continue to be listed and traded on the NYSE, subject to our compliance with other continued listing standards. In order to regain compliance, on the last trading day of any calendar month during the cure period, our shares must have: (i) a closing price of at least $1.00 per share and (ii) an average closing price of at least $1.00 per share over the 30-trading day period ending on the last trading day of such month. If we fail to regain compliance with Section 802.01C of the NYSE Listed Company Manual by the end of the cure period, the shares will be subject to the NYSE’s suspension and delisting procedures. If necessary to regain compliance with NYSE listing standards, we may, subject to approval of our board of directors and shareholders, implement a reverse stock split. A delisting of our shares from the NYSE could negatively impact us by, among other things, reducing the liquidity and market price of our shares, reducing the number of investors willing to hold or acquire our shares and limiting our ability to issue securities or obtain financing in the future.
Our business depends on the level of activity in the oil and gas industry. Adverse developments affecting the industry, including a decline in the price of oil or gas, reduced demand for oil and gas products and increased regulation of drilling and production, could have a material adverse effect on our business, financial condition and results of operations.
Demand for drilling services depends on a variety of economic and political factors and the level of activity in offshore oil and gas exploration and development and production markets worldwide. As noted above, the price of oil and gas, and market expectations of potential changes in the price, significantly affect this level of activity, as well as dayrates that we can charge customers for our services. However, higher prices do not necessarily translate into increased drilling activity because our clients take into account a number of considerations when they decide to invest in offshore oil and gas resources, including expectations regarding future commodity prices. The price of oil and gas and the level of activity in offshore oil and gas exploration and development are extremely volatile and are affected by numerous factors beyond our control, including:
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the cost of exploring for, developing, producing and delivering oil and gas;
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the ability of OPEC to set and maintain production levels and pricing;
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expectations regarding future energy prices;
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increased supply of oil and gas resulting from onshore hydraulic fracturing activity and shale development;
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the relative cost of offshore oil and gas exploration versus onshore oil and gas production;
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worldwide production and demand for oil and gas, which are impacted by changes in the rate of economic growth in the global economy;
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potential acceleration in the development, and the price and availability, of alternative fuels or energy sources;
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the level of production in non-OPEC countries;
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worldwide financial instability or recessions;
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regulatory restrictions or any moratorium on offshore drilling;
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the discovery rate of new oil and gas reserves either onshore or offshore;
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the rate of decline of existing and new oil and gas reserves;
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available pipeline and other oil and gas transportation capacity;
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oil refining capacity;
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the ability of oil and gas companies to raise capital;
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limitations on liquidity and available credit;
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advances in exploration, development and production technology either onshore or offshore;
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technical advances affecting energy consumption, including the displacement of hydrocarbons through increasing transportation fuel efficiencies;
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merger and divestiture activity among oil and gas producers;
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the availability of, and access to, suitable locations from which our customers can produce hydrocarbons;
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adverse weather conditions, including hurricanes, typhoons, cyclones, winter storms and rough seas;
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tax laws, regulations and policies;
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laws and regulations related to environmental matters, including those addressing alternative energy sources and the risks of global climate change;
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the political environment of oil-producing regions, including uncertainty or instability resulting from civil disorder, an outbreak or escalation of armed hostilities or acts of war or terrorism; and
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the laws and regulations of governments regarding exploration and development of their oil and gas reserves or speculation regarding future laws or regulations.
Adverse developments affecting the industry as a result of one or more of these factors, including any further decline in the price of oil and gas from their current levels or the failure of the price of oil and gas to recover to a level that encourages our clients to expand their capital spending, the inability of our customers to access capital on economically advantageous terms, including as a result of the increasing focus on climate change by investors, a global recession, reduced demand for oil and gas products, increased supply due to the development of new onshore drilling and production technologies, and increased regulation of drilling and production, particularly if several developments were to occur in a short period of time, would have a material adverse effect on our business, financial condition and results of operations. The current level of oil and gas prices has had a material adverse effect on demand for our services since 2014 and is expected to continue to have a material adverse effect on our business and results of operations.
The offshore contract drilling industry is a highly competitive and cyclical business with intense price competition. We have competitors who are larger and have more financial resources than us. If we are unable to compete successfully, our profitability may be materially reduced.
The offshore contract drilling industry is a highly competitive and cyclical business characterized by high capital and operating costs and evolving capability of newer rigs. Drilling contracts are traditionally awarded on a competitive bid basis. Price competition, rig availability, location and rig suitability and technical specifications are the primary factors in determining which rig is qualified for a job, and additional factors are considered when determining which contractor is awarded a job, including experience of the workforce, efficiency, safety performance record, condition of equipment, operating integrity, reputation, industry standing and client relations. Our future success and profitability will partly depend upon our ability to keep pace with our customers’ demands with respect to these factors. In the past several years, the pace of consolidation in our industry has increased, leading to the creation of a number of larger and financially stronger competitors. If we are unable, or our customers believe that we are unable, to compete with the scale and financial strength of these larger competitors, it could harm our competitiveness and our ability to secure new drilling contracts. If current competitors, or new market entrants, implement new technical capabilities, services or standards that are more attractive to our customers or price their product offerings more competitively, it could have a material adverse effect on our business, financial condition and results of operations.
In addition to intense competition, our industry has historically been cyclical. The offshore contract drilling industry is currently in a period characterized by low demand for drilling services and excess rig supply. Periods of low demand or excess rig supply intensify the competition in the industry and have resulted in, and are expected to continue to result in, many of our rigs earning substantially lower dayrates or being idle for long periods of time. We cannot provide you with any assurances as to when such period will end, and when there will be higher demand for contract drilling services or a meaningful reduction in the number of drilling rigs.
The over-supply of offshore rigs is contributing to depressed dayrates and demand for our rigs, which may continue for some time and, therefore, is expected to further adversely impact our revenues and profitability.
Prior to the current downturn, we experienced an extended period of high utilization and high dayrates, and industry participants materially increased the supply of drilling rigs by building new drilling rigs, including some that have not yet entered service. This increase in supply, combined with the decrease in demand for drilling rigs resulting from the substantial decline in the price of oil that began in 2014, has resulted in an oversupply of drilling rigs, which has contributed to the decline in utilization and dayrates.
We are currently experiencing competition from newbuild rigs that have either already entered the market or are available to enter the market. The entry of these rigs into the market has resulted in lower dayrates for both newbuilds and existing rigs rolling off their current contracts. Lower utilization and dayrates have adversely affected our revenues and profitability and may continue to do so for some time in the future. In
addition, our competitors may relocate rigs to geographic markets in which we operate, which could exacerbate excess rig supply and result in lower dayrates and utilization in those markets. To the extent that the drilling rigs currently under construction or on order do not have contracts upon their completion, there may be increased price competition as such vessels become operational, which could lead to a further reduction in dayrates and in utilization, and we may be required to idle additional drilling rigs. As a result, our business, financial condition and results of operations would be materially adversely affected.
We may record impairment charges on property and equipment, including rigs and related capital spares.
We evaluate the impairment of property and equipment, which include rigs and related capital spares, whenever events or changes in circumstances (including a decision to cold stack, retire or sell rigs) indicate that the carrying amount of an asset may not be recoverable. An impairment loss on our property and equipment may exist when the estimated undiscounted cash flows expected to result from the use of the asset and its eventual disposition are less than its carrying amount. Any impairment loss recognized represents the excess of the asset’s carrying value over the estimated fair value. As part of this analysis, we make assumptions and estimates regarding future market conditions. To the extent actual results do not meet our estimated assumptions, for a given rig or piece of equipment, we may take an impairment loss in the future. In addition, we may also take an impairment loss on capital spares and other capital equipment when we deem the value of those items has declined due to factors like obsolescence, deterioration or damage. Based upon our impairment analyses for the years ended December 31, 2019 and 2018, we recorded impairment charges of $615.3 million and $802.1 million, respectively, on various rigs and certain capital spares during those periods. There can be no assurance that we will not have to take additional impairment charges in the future if current depressed market conditions persist, or that we will be able to return cold stacked rigs to service in the time frame and at the reactivation costs or at the dayrates that we projected. It is reasonably possible that the estimate of undiscounted cash flows may change in the near term, resulting in the need to write down the affected assets to their corresponding estimated fair values.
We may not be able to renew or replace expiring contracts, and our customers may terminate or seek to renegotiate or repudiate our drilling contracts or may have financial difficulties that prevent them from meeting their obligations under our drilling contracts.
Since the market downturn began at the end of 2014, the new customer contracts we have entered into have generally had less favorable terms, including dayrates, than contracts entered into prior to the downturn. In addition, for some of our older rigs we were unable to find any replacement contracts. Our ability to renew contracts that expire or obtain new contracts and the terms of any such contracts will depend on market conditions and our customers' expectations and assumptions of future oil prices and other factors.
Our customers may generally terminate our drilling contracts if a drilling rig is destroyed or lost or if we have to suspend drilling operations for a specified period of time as a result of a breakdown of major equipment or, in some cases, due to other events beyond the control of either party. In the case of nonperformance and under certain other conditions, our drilling contracts generally allow our customers to terminate without any payment to us. The terms of some of our drilling contracts permit the customer to terminate the contract after a specified notice period by tendering contractually specified termination amounts and, in some cases, without any payment. These termination payments, if any, may not fully compensate us for the loss of a contract. The early termination of a contract may result in a rig being idle for an extended period of time and a reduction in our contract backlog and associated revenue, which could have a material adverse effect on our business, financial condition and results of operations. Moreover, if any of our long-term contracts were to be terminated early, such termination could affect our future earnings flow and could have material adverse effect on our future financial condition and results of operations, even if we were to receive the contractually specified termination amount.
In addition, during periods of depressed market conditions, such as the one we are currently experiencing, we are subject to an increased risk of our customers seeking to renegotiate or repudiate their contracts. The ability of our customers to perform their obligations under drilling contracts with us may also be adversely affected by the financial condition of the customer, restricted credit markets, economic downturns and industry downturns. We may elect to renegotiate the rates we receive under our drilling contracts downward if we determine that to be a reasonable business solution. If our customers cancel or are unable to perform their obligations under their drilling contracts, including their payment obligations, and we are unable to secure new contracts on a timely basis on substantially similar terms or if we elect to renegotiate our drilling contracts and accept terms that are less favorable to us, it could have a material adverse effect on our business, financial condition and results of operations.
Our current backlog of contract drilling revenue may not be ultimately realized.
Generally, contract backlog only includes future revenues under firm commitments; however, from time to time, we may report anticipated commitments under letters of intent or award for which definitive agreements have not yet been, but are expected to be, executed. We may not be able to perform under these contracts as a result of operational or other breaches or due to events beyond our control, and we may not be able to ultimately execute a definitive agreement in cases where one does not currently exist. Moreover, we can provide no assurance that our customers will be able to or willing to fulfill their contractual commitments to us or that they will not seek to renegotiate or repudiate their contracts, especially during the current industry downturn. In estimating backlog, we make certain assumptions about applicable dayrates for our longer-term contracts with dayrate adjustment mechanisms (like certain of our contracts with Shell). We cannot assure you that actual results will mirror these assumptions.
Our inability to perform under our contractual obligations or to execute definitive agreements, our customers’ inability or unwillingness to fulfill their contractual commitments to us, including as a result of contract repudiations or our decision to accept less favorable terms on our drilling contracts, or the failure of actual results to reflect the assumptions we use to estimate backlog for certain contracts, may have a material adverse effect on our business, financial condition and results of operations.
We are substantially dependent on several of our customers, including Shell, ExxonMobil, Equinor and Saudi Aramco, and the loss of any of these customers would have a material adverse effect on our financial condition and results of operations.
Any concentration of customers increases the risks associated with any possible termination or nonperformance of drilling contracts, failure to renew contracts or award new contracts or reduction of their drilling programs. Shell, ExxonMobil, Equinor and Saudi Aramco accounted for approximately 36.5 percent, 13.7 percent, 13.1 percent and 11.9 percent, respectively, of our consolidated operating revenues and approximately 51.1 percent, 12.4 percent, 6.6 percent and 23.0 percent, respectively, of our backlog for the year ended December 31, 2019. 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.
We have substantial debt obligations with significant covenants that could restrict our operations and prevent us from fulfilling our debt obligations.
As of February 18, 2020, Noble-Cayman and its subsidiaries, including Noble Holding International Limited and its subsidiaries, had approximately $3.5 billion aggregate principal amount of unsecured long-term senior notes and seller loans (including current maturities) outstanding. At February 18, 2020, we had $335 million of borrowings outstanding under our 2017 Credit Facility. We may also incur additional indebtedness in the future. If we do so, the risks related to our level of debt could intensify. Our substantial indebtedness could have adverse consequences, including:
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making it more difficult for us to satisfy our financial obligations, including our obligations with respect to our outstanding debt;
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increasing our vulnerability to adverse economic, regulatory and industry conditions, and placing us at a disadvantage compared to our competitors that are less leveraged;
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limiting our ability to compete and our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate;
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limiting our ability to borrow additional funds for working capital, capital expenditures, acquisitions and general corporate or other purposes;
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increasing the possibility that our customers may react adversely to our significant debt level and seek alternative service providers; and
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increasing the possibility that our suppliers may react adversely to our significant debt level and seek alternative payment terms or security.
Our debt service obligations will require us to use a significant portion of our operating cash flow to pay interest and principal on indebtedness instead of for other corporate purposes, including funding future expansion of our business and ongoing capital expenditures, which could impede our growth. If our operating cash flow and capital resources are insufficient to comply with the financial covenants in our 2017 Credit Facility or to service our debt obligations, we may be forced to sell assets, seek additional equity or debt financing or restructure our debt, which could severely harm our long-term business prospects. Our failure to comply with those covenants could result in an event of default which, if not cured or waived, could result in the acceleration of all our debt, which could result in our inability to continue as a going concern. Our 2017 Credit Facility contains a covenant that limits our ratio of Senior Guaranteed Indebtedness (as defined therein) to Adjusted EBITDA (as defined therein) as of the last day of each fiscal quarter, with such ratio not to exceed 4.0 to 1.0 for the fiscal quarters ending September 30, 2019 through December 31, 2020, 3.5 to 1.0 for the fiscal quarters ending March 31, 2021 through December 31, 2021, and 3.0 to 1.0 for the fiscal quarters ending March 31, 2022 and thereafter. Our two Seller Loans (as defined herein) contain a covenant that limits our debt to total tangible capitalization (less noncontrolling interest) to a maximum 0.55 ratio. If we increase our indebtedness, including by borrowing under the 2017 Credit Facility, or incur further losses, including but not limited to further losses caused by impairment charges or an adverse judgement in relation to the Paragon Offshore litigation, without reducing our indebtedness or increasing capital by an equivalent amount, our debt to total tangible capitalization ratio and our ratio of Senior Guaranteed Indebtedness to Adjusted EBITDA would both likely, increase.
Liquidity risk could impair our ability to fund operations and jeopardize our financial condition, growth and prospects.
We are largely dependent on cash generated by our operations, cash on hand, borrowings under our 2017 Credit Facility and potential issuances of equity or long-term debt to cover our operating expenses, service our indebtedness and fund our other liquidity needs. The level of cash available to us depends on numerous factors, including demand for our services, the dayrates we are paid by our customers, the level of utilization of our drilling rigs, our ability to control and reduce costs, our access to capital markets and amounts available to us under our 2017 Credit Facility. If the oil and gas industry does not experience improved conditions over the next several years, one or more of such factors could
be negatively impacted and our sources of liquidity could be insufficient to fund our operations and service our obligations such that we may require capital in excess of the amount available from those sources. Our access to funding sources in amounts adequate to finance our operations and planned capital expenditures and repay our indebtedness or on terms that are acceptable could be impaired by factors such as negative views and expectations about us, the oil and gas industry or the economy in general and disruptions in the financial markets.
Our financial flexibility will be severely constrained if we experience a significant decrease in cash generated from our operations or are unable to maintain our access to or secure new sources of financing. If additional financing sources are unavailable, or not available on reasonable terms, our financial condition, results of operations, growth and future prospects could be materially adversely affected, and we may be unable to continue as a going concern. As such, we cannot assure you that cash flow generated from our business and other sources of cash, including future borrowings under our 2017 Credit Facility, will be sufficient to enable us to pay our indebtedness and to fund our other liquidity needs.
As a result of our significant cash flow needs, we may be required to raise funds through the issuance of additional debt or equity, and in the event of lost market access, may have to delay or cancel discretionary capital expenditures.
Our cash flow needs, both in the short-term and long-term, may include the following:
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normal recurring operating expenses;
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planned and discretionary capital expenditures; and
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repayment of debt and interest.
In the future, we may require funding for capital expenditures that is beyond the amount available to us from cash generated by our operations, cash on hand and borrowings under our 2017 Credit Facility. We may raise such additional capital in a number of ways, including accessing capital markets, obtaining additional lines of credit or disposing of assets. However, we can provide no assurance that any of these options will be available to us on acceptable terms, or at all.
We may delay or cancel discretionary capital expenditures, which could have certain adverse consequences, including delaying upgrades or equipment purchases that could make the affected rigs less competitive, adversely affect customer relationships and negatively impact our ability to contract such rigs.
We may have additional requirements for surety bonds or letters of credit that could reduce available liquidity.
We routinely post surety bonds and letters of credit to support our performance of contractual obligations or for legal or tax appeals. Our customers or jurisdictions where we operate or have operated may require additional surety bonds or letters of credit in the future. We may not have access to unsecured credit lines to issue surety bonds or letters of credit which could cause us to issue new letters of credit under our 2017 Credit Facility and reduce availability for borrowings.
A litigation trust was formed and funded as part of the Paragon Offshore bankruptcy proceedings and the litigation trust has filed claims against us and certain of our officers and directors. In addition, Paragon Offshore rejected in the bankruptcy proceedings certain separation agreements entered into with us, and as a result, we are responsible for those liabilities for which we would have otherwise sought indemnification under the separation agreements.
On August 1, 2014, Noble-UK completed the 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. In February 2016, Paragon Offshore sought approval of a pre-negotiated plan of reorganization (the “Prior Plan”) by filing for voluntary relief under Chapter 11 of the United States Bankruptcy Code. As part of the Prior Plan, we entered into a settlement agreement with Paragon Offshore (the “Settlement Agreement”). The Prior Plan was rejected by the bankruptcy court in October 2016.
In April 2017, Paragon Offshore filed a revised plan of reorganization (the “New Plan”) in its bankruptcy proceeding. Under the New Plan, Paragon Offshore no longer needed the Mexican tax bonding that Noble-UK was required to provide under the Settlement Agreement. Consequently, Paragon Offshore abandoned the Settlement Agreement as part of the New Plan, and the Settlement Agreement was terminated at the time of the filing of the New Plan. On May 2, 2017, Paragon Offshore announced that it had reached an agreement in principle with both its secured and unsecured creditors to revise the New Plan to create and fund a litigation trust to pursue litigation against us. On June 7, 2017, the revised New Plan was approved by the bankruptcy court and Paragon Offshore emerged from bankruptcy on July 18, 2017.
On December 15, 2017, the litigation trust filed claims relating to the Spin-off against us and certain of our current and former officers and directors in the Delaware bankruptcy court that heard Paragon Offshore’s bankruptcy, and the litigation trust filed an amended complaint in October 2019. The amended complaint alleges claims of actual and constructive fraudulent conveyance, unjust enrichment and recharacterization of intercompany notes as equity claims against Noble and claims of breach of fiduciary duty and aiding and abetting breach of fiduciary duty against the officer and director defendants. The litigation trust is seeking damages of (i) approximately $1.7 billion from the Company, an amount equal to the amount borrowed by Paragon Offshore immediately prior to the Spin-off, (ii) an additional approximately $935 million relating to the transfer of intercompany receivables and notes from a Paragon subsidiary to a Noble subsidiary prior to the Spin-off (bringing the total claimed damages to approximately $2.6 billion), and (iii) unspecified amounts in respect of the claims against the officer and director defendants, all of
whom have indemnification agreements with us. A trial date has been set for September 2020.
We believe that Paragon Offshore, at the time of the Spin-off, was properly funded, solvent and had appropriate liquidity and that the claims brought by the litigation trust are without merit. However, the Company continually assesses potential outcomes, including the probability of the
parties ultimately resolving the matter through settlement in light of various factors, including given the complex factual issues involved, the uncertainty and risk inherent in this type of litigation, the time commitment and distraction of our organization, the potential effect of the ongoing litigation and uncertainty on our business, and the substantial expense incurred in litigating the claims. As such, the Company’s current estimated loss related to the final disposition of this matter is $100.0 million, which the Company recorded as a general and administrative expense for the year ended December 31, 2019 and is reflected as a current liability as of December 31, 2019. As pre-trial matters progress, the Company’s estimated loss could change from time to time, and any such change individually or in the aggregate could be material.
There is inherent risk and substantial expense in litigation, and the amount of damages that the plaintiff is seeking is substantial. If any of the litigation trust’s claims are successful, or if we elect to settle any claims (in part to reduce or eliminate the ongoing cost of defending the litigation and eliminate any risk of a larger judgment against us), any damages or other amounts we would be required to or agree to pay in excess of the amount we recognized at December 31, 2019, could have a material adverse effect on our business, financial condition and results of operations, including impeding our ability to meet ongoing financial obligations or to continue as a going concern. Given the risks and considerations discussed above, we cannot predict with any degree of certainty what the outcome of the litigation may be. Furthermore, as discussed below, we cannot predict the amount of insurance coverage, if any, that we may have if we were to settle or be found liable in the litigation.
We have directors’ and officers’ indemnification coverage for the officers and directors who have been sued by the litigation trust. The insurers have accepted coverage for the director and officer claims and we are continuing to discuss with them the scope of their reimbursement of litigation expenses. In addition, at the time of the Spin-off we had entity coverage, or “Side C” coverage, which was meant to cover certain litigation claims up to the coverage limit of $150.0 million, including litigation expenses. We have made a claim for coverage of the litigation trust’s claims against Noble under such entity insurance. The insurers have rejected coverage for these claims. However, we intend to pursue coverage should the litigation be concluded adversely to us or should we settle the litigation. We cannot predict the amount of claims and expenses we may incur, pay or settle in the Paragon Offshore litigation that such insurance will cover, if any.
We entered into certain separation agreements with Paragon Offshore at the time of the Spin-off (including a master separation agreement, tax sharing agreement, transition services agreement and transition services agreement relating to our operations offshore Brazil) under which we agreed to indemnify Paragon Offshore for certain liabilities, and Paragon Offshore agreed to indemnify us for certain liabilities. As part of its final bankruptcy plan, Paragon Offshore rejected all of these contracts. Accordingly, we are no longer entitled to seek indemnity from Paragon Offshore under such agreements, and we would be responsible for those liabilities for which we would have otherwise sought indemnification. Such liabilities could have a material adverse effect on our business, financial condition and results of operations.
Our business involves numerous operating hazards.
Our operations are subject to many hazards inherent in the drilling business, including:
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well blowouts;
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fires;
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collisions or groundings of offshore equipment and helicopter accidents;
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punch-throughs;
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mechanical or technological failures;
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failure of our employees or third-party contractors to comply with our internal environmental, health and safety guidelines;
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pipe or cement failures and casing collapses, which could release oil, gas or drilling fluids;
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geological formations with abnormal pressures;
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loop currents or eddies;
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failure of critical equipment;
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toxic gas emanating from the well;
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spillage handling and disposing of materials; and
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adverse weather conditions, including hurricanes, typhoons, tsunamis, cyclones, winter storms and rough seas.
These hazards could cause personal injury or loss of life, suspend drilling operations, result in regulatory investigation or penalties, seriously damage or destroy property and equipment, result in claims by employees, customers or third parties, cause environmental damage and cause substantial damage to oil and gas producing formations or facilities. Operations also may be suspended because of machinery breakdowns, abnormal drilling conditions, and failure of subcontractors to perform or supply goods or services or personnel shortages. The occurrence of any of the hazards we face could have a material adverse effect on our business, financial condition and results of operations.
We 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:
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seizure, nationalization or expropriation of property or equipment;
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monetary policies, government credit rating downgrades and potential defaults, and foreign currency fluctuations and devaluations;
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limitations on the ability to repatriate income or capital;
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complications associated with repairing and replacing equipment in remote locations;
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repudiation, nullification, modification or renegotiation of contracts;
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limitations on insurance coverage, such as war risk coverage, in certain areas;
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import-export quotas, wage and price controls, imposition of trade barriers and other forms of government regulation and economic conditions that are beyond our control;
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delays in implementing private commercial arrangements as a result of government oversight;
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financial or operational difficulties in complying with foreign bureaucratic actions;
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changing taxation rules or policies;
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other forms of government regulation and economic conditions that are beyond our control and that create operational uncertainty;
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governmental corruption;
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the occurrence or threat of epidemic or pandemic diseases or any government response to such occurrence or threat;
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piracy; and
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terrorist acts, war, revolution and civil disturbances.
Further, we operate or have operated in certain less-developed countries with legal systems that are not as mature or predictable as those in more developed countries, which can lead to greater uncertainty in legal matters and proceedings. Examples of challenges of operating in these countries include:
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procedural requirements for temporary import permits, which may be difficult to obtain;
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the effect of certain temporary import permit regimes, where the duration of the permit does not coincide with the general term of the drilling contract; and
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ongoing claims in Brazil related to withholding taxes payable on our service contracts.
Our ability to do business in a number of jurisdictions is subject to maintaining required licenses and permits and complying with applicable laws and regulations. Changes in, compliance with, or our failure to comply with the laws and regulations of the countries where we operate may negatively impact our operations in those countries and could have a material adverse effect on our results of operations.
In addition, OPEC initiatives, as well as other governmental actions, may continue to cause oil price volatility. In some areas of the world, this governmental activity has adversely affected the amount of exploration and development work done by major oil companies, which may continue. In addition, some governments favor or effectively require the awarding of drilling contracts to local contractors, require use of a local agent, require partial local ownership or require foreign contractors to employ citizens of, or purchase supplies from, a particular jurisdiction. These practices may adversely affect our ability to compete and our results of operations.
In June 2016, the UK held a referendum in which voters approved an exit from the EU, commonly referred to as “Brexit” and in March 2017 the UK formally started the process for the UK to leave the EU. The UK exited the EU on January 31, 2020, consistent with the terms of the EU-UK Withdrawal Agreement. The terms of that agreement provides for a transition period from January 31, 2020 to December 31, 2020 (the “Transition Period”), during which the trading relationship between the EU and the UK will remain the same while the UK and the EU try to negotiate an agreement regarding their future trading relationship. Given the lack of comparable precedent, it is unclear how disruptive the UK's withdrawal from the EU will be, including possible financial, trade, regulatory and legal implications. In particular, depending on the terms agreed as to their future trading relationship, the ability to trade freely between the EU and the UK may be adversely affected at the end of the Transition Period. Brexit creates global political and economic uncertainty, which may cause, among other consequences, volatility in exchange rates and interest rates, and changes in regulations. The Company provides contract drilling services to the international oil and gas industry and our fleet operates globally across multiple locations. While our business is internationally diversified, the Company is incorporated and registered within the UK. Based on our global operating model and the versatility and marketability of our fleet, we do not expect the impact of Brexit to be significant to the Company.
Operating and maintenance costs of our rigs may be significant and may not correspond to revenue earned.
Our operating expenses and maintenance costs depend on a variety of factors including: crew costs, costs of provisions, equipment, insurance, maintenance and repairs, and shipyard costs, many of which are beyond our control. Our total operating costs are generally related to the number of drilling rigs in operation and the cost level in each country or region where such drilling rigs are located. Equipment maintenance costs fluctuate depending upon the type of activity that the drilling rig is performing and the age and condition of the equipment. Operating and maintenance costs will not necessarily fluctuate in proportion to changes in operating revenues. While operating revenues may fluctuate as a function of changes in dayrate, costs for operating a rig may not be proportional to the dayrate received and may vary based on a variety of factors, including the scope and length of required rig preparations and the duration of the contractual period over which such expenditures are amortized. Any investments in our rigs may not result in an increased dayrate for or income from such rigs. A disproportionate amount of operating and maintenance costs in comparison to dayrates could have a material adverse effect on our business, financial condition and results of operations.
Drilling contracts with national oil companies may expose us to greater risks than we normally assume in drilling contracts with non-governmental clients.
Contracts with national oil companies are often non-negotiable and may expose us to greater commercial, political and operational risks than we assume in other contracts, such as exposure to materially greater environmental liability and other claims for damages (including consequential damages) and personal injury related to our operations, or the risk that the contract may be terminated by our client without cause on short-term notice, contractually or by governmental action, under certain conditions that may not provide us an early termination payment, collection risks and political risks. In addition, our ability to resolve disputes or enforce contractual provisions may be negatively impacted with these contracts. We can provide no assurance that the increased risk exposure will not have an adverse impact on our future operations or that we will not increase the number of rigs contracted to national oil companies with commensurate additional contractual risks.
Changes in the method of determining the London Interbank Offered Rate, or the replacement of the London Interbank Offered Rate with an alternative reference rate, may adversely affect interest expense related to outstanding debt.
Borrowings under the 2017 Credit Facility bear interest at the London Interbank Offered Rate (“LIBOR”) plus an applicable margin. On July 27, 2017, the Financial Conduct Authority in the UK, which regulates LIBOR, announced that it intends to phase out LIBOR as a benchmark by the end of 2021. It is unclear whether new methods of calculating LIBOR will be established such that it continues to exist after 2021. The 2017 Credit Facility, which, at the present time, has a term that extends beyond 2021, provides for a mechanism to amend the facility to reflect the establishment of an alternative rate of interest upon the occurrence of certain events related to the phase-out of LIBOR. However, we have not yet pursued any technical amendment or other contractual alternative to address this matter and are currently evaluating the impact of the potential replacement of the LIBOR interest rate. In addition, the overall financial markets may be disrupted as a result of the phase-out or replacement of LIBOR. Uncertainty as to the nature of such potential phase-out and alternative reference rates or disruption in the financial market could have a material adverse effect on our financial condition, results of operations and cash flows.
Governmental laws and regulations may add to our costs, result in delays, or limit our drilling activity.
Our business is affected by public policy and laws and regulations relating to the energy industry in the geographic areas where we operate.
The drilling industry is dependent on demand for services from the oil and gas exploration and production industry, and accordingly, we are directly affected by the adoption of laws and regulations that for economic, environmental or other policy reasons curtail exploration and development drilling for oil and gas. We may be required to make significant capital expenditures to comply with governmental laws and regulations. Governments in some foreign countries are increasingly active in regulating and controlling the ownership of concessions, the exploration for oil and gas, and other aspects of the oil and gas industries. There is increasing attention in the United States and worldwide concerning the issue of climate change and the effect of greenhouse gases, or GHGs. This increased attention may result in new environmental laws or regulations that may unfavorably impact us, our suppliers and our customers.
The modification of existing laws or regulations or the adoption of new laws or regulations that result in the curtailment of exploratory or developmental drilling for oil and gas could materially and adversely affect our operations by limiting drilling opportunities increasing our cost of doing business, discouraging our customers from drilling for hydrocarbons, disrupting revenue through permitting or similar delays, or subjecting us to liability.
In addition to the regulatory efforts described above, there have also been efforts in recent years aimed at the investment community, including investment advisors, sovereign wealth funds, public pension funds, universities and other groups, promoting the divestment of fossil fuel equities as well as to pressure lenders and other financial services companies to limit or curtail activities with fossil fuel companies. If this were to continue, it could have a material adverse effect on the price of our securities and our ability to access equity capital markets. Members of the investment community have begun to screen companies such as ours for sustainability performance, including practices related to GHGs and climate change, before investing in our stock. If we are unable to find economically viable, as well as publicly acceptable, solutions that reduce our GHG emissions and/or GHG intensity for new and existing projects, we could experience additional costs or financial penalties, delayed or
cancelled projects, and/or reduced production and reduced demand for hydrocarbons, which could have a material adverse effect on our earnings, cash flows and financial condition.
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 US Foreign Corrupt Practices Act of 1977 (the “FCPA”), the United Kingdom Bribery Act 2010 (the “UK Bribery Act”) and similar laws in other countries. Any violation of the FCPA, UK Bribery Act or other applicable anti-corruption laws could result in substantial fines, sanctions, civil and/or criminal penalties and curtailment of operations in certain jurisdictions and might adversely affect our business, financial condition and results of operations. In addition, actual or alleged violations could damage our reputation and ability to do business. Further, detecting, investigating and resolving actual or alleged violations is expensive and can consume significant time and attention of our senior management.
Changes in, compliance with, or our failure to comply with the certain laws and regulations may negatively impact our operations and could have a material adverse effect on our results of operations.
Our operations are subject to various laws and regulations in countries in which we operate, including laws and regulations relating to:
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the environment and the health and safety of personnel;
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the importing, exporting, equipping and operation of drilling rigs;
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currency exchange controls;
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oil and gas exploration and development;
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taxation of offshore earnings and earnings of expatriate personnel; and
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use and compensation of local employees and suppliers by foreign contractors.
Public and governmental scrutiny of the energy industry has resulted in increased regulations being proposed and often implemented. In addition, existing regulations might be revised or reinterpreted, new laws, regulations and permitting requirements might be adopted or become applicable to us, our rigs, our customers, our vendors or our service providers, and future changes in laws and regulations could significantly increase our costs and could have a material adverse effect on our business, financial condition and results of operations. In addition, we may be required to post additional surety bonds to secure performance, tax, customs and other obligations relating to our rigs in jurisdictions where bonding requirements are already in effect and in other jurisdictions where we may operate in the future. These requirements would increase the cost of operating in these countries, which could materially adversely affect our business, financial condition and results of operations.
From time to time, new rules, regulations and requirements regarding oil and gas development have been proposed and implemented by BOEM, BSEE or the United States Congress, as well as other jurisdictions outside the United States, that could materially limit or prohibit, and increase the cost of, offshore drilling. For example, in July 2016, BOEM and BSEE finalized a rule revising and adding requirements for drilling on the US Arctic Outer Continental Shelf. Similarly, in April 2016, BSEE announced a final blowout preventer systems and well control rule. BSEE also finalized a rule in September 2016 concerning production safety systems for oil and natural gas operations on the Outer Continental Shelf. However, BSEE amended both the September 2016 production safety systems rule and the April 2016 blowout preventer systems and well control rule in September 2018 and May 2019, respectively. The amended final rules are intended to revise or remove regulatory provisions that create unnecessary burdens on stakeholders and clarify other provisions, while ensuring safety and environmental protection. BOEM also released a Notice to Lessees and Operators in the Outer Continental Shelf (“NTL”) in September 2016 that updates offshore bonding requirements. This update eliminates waivers of supplemental bonding and prohibits a company from relying on the financial strength of its co-lessees unless its co-lessees agree to allocate BOEM-determined self-insurance to the lease. In January 2017, BOEM extended the implementation timeline for the NTL by six months. In May 2017, the Secretary of the Interior directed BOEM to review the NTL and provide a report describing the results of the review and options for revising or rescinding the NTL. BOEM again extended the implementation timeline for the NTL in June 2017. Implementation of the NTL is currently stayed pending further action by BOEM. However, these new bonding requirements may increase our customers’ operating costs and impact our customers’ ability to obtain leases, thereby reducing demand for our services. We are also subject to increasing regulatory requirements and scrutiny in the North Sea jurisdictions and other countries. These new rules, regulations and requirements, including the adoption of new safety requirements and policies relating to the approval of drilling permits, restrictions on oil and gas development and production activities in the US Gulf of Mexico and elsewhere, implementation of safety and environmental management systems, mandatory third party compliance audits, and the promulgation of numerous Notices to Lessees or similar new regulatory requirements outside of the United States, have impacted and may continue to impact our operations by causing increased costs, delays and operational restrictions. In addition to these rules, regulations and requirements, the US federal government is considering new legislation that could impose additional equipment and safety requirements on operators and drilling contractors in the United States, as well as regulations relating to the protection of the environment. If the new regulations, policies, operating procedures and possibility of increased legal liability resulting from the adoption or amendment of rules and regulations applicable to our operations in the United States or other jurisdictions are viewed by our current or future customers as a significant
impairment to expected profitability on projects, then they could discontinue or curtail their offshore operations in the impacted region, thereby adversely affecting our operations by limiting drilling opportunities or imposing materially increased costs.
We could also be affected by challenges to offshore operations by environmental groups and coastal states. For example, in December 2018, environmental groups challenged incidental harassment authorizations issued by the National Marine Fisheries Service that allow companies to conduct air gun seismic surveys for oil and gas exploration off the Atlantic coast. The attorney generals for ten US coastal states also intervened as plaintiffs. Restrictions on authorizations needed to conduct seismic surveys could impact our customers’ ability to identify oil and gas reserves, thereby reducing demand for our services. Several coastal states have also taken steps to prohibit offshore drilling. For example, California passed laws in September 2018 barring the construction of new oil drilling-related infrastructure in state waters. Similarly, in November 2018, voters in Florida approved an amendment to the state constitution that would ban oil and gas drilling in offshore state waters. Such initiatives could reduce opportunities for our customers and thereby reduce demand for our services.
Adverse effects may continue as a result of the uncertainty of ongoing inquiries, investigations and court proceedings, or additional inquiries and proceedings by federal or state regulatory agencies or private plaintiffs. In addition, we cannot predict the outcome of any of these inquiries or whether these inquiries will lead to additional legal proceedings against us, civil or criminal fines or penalties, or other regulatory action, including legislation or increased permitting requirements. Legal proceedings or other matters against us, including environmental matters, suits, regulatory appeals, challenges to our permits by citizen groups and similar matters, might result in adverse decisions against us. The result of such adverse decisions, both individually or in the aggregate, could be material and may not be covered fully or at all by insurance.
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 that is 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 that exceeds 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:
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breakdowns of equipment and other unforeseen engineering problems;
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work stoppages, including labor strikes;
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shortages of material and skilled labor;
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delays in repairs by suppliers;
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surveys by government and maritime authorities;
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periodic classification surveys;
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inability to obtain permits;
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severe weather, strong ocean currents or harsh operating conditions;
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force majeure events; and
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the occurrence or threat of epidemic or pandemic diseases or any government response to such occurrence or threat.
If the interruption of operations exceeds a determined period due to an event of force majeure, our customers have the right to pay a rate that is significantly lower than the waiting rate for a period of time and, thereafter, may terminate the drilling contracts related to the subject rig. Suspension of drilling contract payments, prolonged payment of reduced rates or termination of any drilling contract as a result of an interruption of operations as described herein could materially adversely affect our business, financial condition and results of operations.
We may have difficulty obtaining or maintaining insurance in the future and our insurance coverage and contractual indemnity rights may not protect us against all the risks and hazards we face.
We do not procure insurance coverage for all of the potential risks and hazards we may face. Furthermore, no assurance can be given that we will be able to obtain insurance against all of the risks and hazards we face or that we will be able to obtain or maintain adequate insurance at rates and with deductibles or retention amounts that we consider commercially reasonable.
Our insurance carriers may interpret our insurance policies such that they do not cover losses for which we make claims. Our insurance policies may also have exclusions of coverage for some losses. Uninsured exposures may include expatriate activities prohibited by US laws, radiation hazards, certain loss or damage to property onboard our rigs and losses relating to shore-based terrorist acts or strikes. Furthermore, the damage sustained to offshore oil and gas assets in the United States as a result of hurricanes has negatively impacted certain aspects of the energy insurance market, resulting in more restrictive and expensive coverage for US named windstorm perils due to the price or lack of availability of coverage. Accordingly, we have in the past self-insured the rigs in the US Gulf of Mexico for named windstorm perils. We currently have US windstorm coverage for most of our US fleet subject to certain limits, but will continue to monitor the insurance market conditions in the future and may decide not to, or be unable to, purchase named windstorm coverage for some or all of the rigs operating in the US Gulf of Mexico.
Under our drilling contracts, liability with respect to personnel and property is customarily assigned on a “knock-for-knock” basis, which means that we and our customers assume liability for our respective personnel and property, irrespective of the fault or negligence of the party
indemnified. Although our drilling contracts generally provide for indemnification from our customers for certain liabilities, including liabilities resulting from pollution or contamination originating below the surface of the water, enforcement of these contractual rights to indemnity may be limited by public policy and other considerations and, in any event, may not adequately cover our losses from such incidents. There can also be no assurance that those parties with contractual obligations to indemnify us will necessarily be in a financial position to do so. During depressed market periods such as the one in which we currently operate, the contractual indemnity provisions we are able to negotiate in our drilling contracts may require us to assume more risk than we would during normal market periods.
Although we maintain insurance in the geographic areas in which we operate, pollution, reservoir damage and environmental risks generally are not fully insurable. Our insurance policies may not adequately cover our losses or may have exclusions of coverage for some losses. We do not have insurance coverage or rights to indemnity for all risks, including loss of hire insurance on most of the rigs in our fleet. Uninsured exposures may include expatriate activities prohibited by US laws and regulations, radiation hazards, cyber risks, certain loss or damage to property onboard our rigs and losses relating to shore-based terrorist acts or strikes. If a significant accident or other event occurs and is not fully covered by insurance or contractual indemnity, it could adversely affect our business, financial condition and results of operations.
Our failure to adequately protect our sensitive information technology systems and critical data and our service providers’ failure to protect their systems and data could have a material adverse effect on our business, results of operations and financial condition.
We depend on information technology systems that we manage, and others that are managed by our third-party service and equipment providers, to conduct our day-to-day operations, including critical systems on our drilling units, and these systems are subject to risks associated with cyber incidents or attacks. It has been reported that unknown entities or groups have mounted cyber-attacks on businesses and other organizations solely to disable or disrupt computer systems, disrupt operations and, in some cases, steal data. Due to the nature of cyber-attacks, breaches to our systems or our service or equipment providers’ systems could go undetected for a prolonged period of time. While the Company has a cybersecurity program, a significant cyber attack could disrupt our operations and result in downtime, loss of revenue, harm to the Company's reputation, or the loss, theft, corruption or unauthorized release of critical data of us or those with whom we do business as well as result in higher costs to correct and remedy the effects of such incidents. If our or our service or equipment providers’ systems for protecting against cyber incidents or attacks prove to be insufficient and an incident were to occur, it could have a material adverse effect on our business, financial condition and results of operations, along with our reputation. Currently, we do not carry insurance for losses related to cybersecurity attacks, and may elect to not obtain such insurance in the future.
In addition, laws and regulations governing data privacy and the unauthorized disclosure of confidential or protected information, including the European Union General Data Protection Regulation and recent legislation in various US states, pose increasingly complex compliance challenges and potentially elevate costs, and any failure to comply with these laws and regulations could result in significant penalties and legal liability.
A loss of a major tax dispute or a successful tax challenge to our operating structure, intercompany pricing policies or the taxable presence of our subsidiaries in certain countries could result in a higher tax rate on our worldwide earnings, which could result in a material adverse effect on our financial condition and results of operations.
Income tax returns that we file will be subject to review and examination. We recognize the benefit of income tax positions we believe are more likely than not to be sustained upon challenge by a tax authority. If any tax authority successfully challenges our operational structure, intercompany pricing policies or the taxable presence of our subsidiaries in certain countries, if the terms of certain income tax treaties are interpreted in a manner that is adverse to our structure, or if we lose a material tax dispute in any country, our effective tax rate on our worldwide earnings could increase substantially and result in a material adverse effect on our financial condition.
Our consolidated effective income tax rate may vary substantially from one reporting period to another.
We cannot provide any assurances as to what our consolidated effective income tax rate will be because of, among other matters, uncertainty regarding the nature and extent of our business activities in any particular jurisdiction in the future and the tax laws of such jurisdictions, as well as potential changes in UK, US and other tax laws, regulations or treaties or the interpretation or enforcement thereof, changes in the administrative practices and precedents of tax authorities or any reclassification or other matter (such as changes in applicable accounting rules) that increases the amounts we have provided for income taxes or deferred tax assets and liabilities in our consolidated financial statements. For example, the Organization for Economic Cooperation and Development (“OECD”) has issued its final reports on Base Erosion and Profit Shifting, which generally focus on situations where profits are earned in low-tax jurisdictions, or payments are made between affiliates from jurisdictions with high tax rates to jurisdictions with lower tax rates. Certain countries within which we operate have recently enacted changes to their tax laws in response to the OECD recommendations or otherwise and these and other countries may enact changes to their tax laws or practices in the future (prospectively or retroactively), which may have a material adverse effect on our financial position, operating results and/or cash flows.
In addition, as a result of frequent changes in the taxing jurisdictions in which our drilling rigs are operated and/or owned, changes in the overall level of our income and changes in tax laws, our consolidated effective income tax rate may vary substantially from one reporting period to another. Income tax rates imposed in the tax jurisdictions in which our subsidiaries conduct operations vary, as does the tax base to which the
rates are applied. In some cases, tax rates may be applicable to gross revenues, statutory or negotiated deemed profits or other bases utilized under local tax laws, rather than to net income. Our drilling rigs frequently move from one taxing jurisdiction to another to perform contract drilling services. In some instances, the movement of drilling rigs among taxing jurisdictions will involve the transfer of ownership of the drilling rigs among our subsidiaries. If we are unable to mitigate the negative consequences of any change in law, audit, business activity or other matter, this could cause our consolidated effective income tax rate to increase and cause a material adverse effect on our financial position, operating results and/or cash flows.
Our operations are subject to numerous laws and regulations relating to the protection of the environment and of human health and safety, and compliance with these laws and regulations could impose significant costs and liabilities that exceed our current expectations.
Substantial costs, liabilities, delays and other significant issues could arise from environmental, health and safety laws and regulations covering our operations, and we may incur substantial costs and liabilities in maintaining compliance with such laws and regulations. Our operations are subject to extensive international conventions and treaties, and national or federal, state and local laws and regulations, governing environmental protection, including with respect to the discharge of materials into the environment and the security of chemical and industrial facilities. These laws govern a wide range of environmental issues, including:
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the release of oil, drilling fluids, natural gas or other materials into the environment;
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air emissions from our drilling rigs or our facilities;
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handling, cleanup and remediation of solid and hazardous wastes at our drilling rigs or our facilities or at locations to which we have sent wastes for disposal;
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restrictions on chemicals and other hazardous substances; and
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wildlife protection, including regulations that ensure our activities do not jeopardize endangered or threatened animals, fish and plant species, nor destroy or modify the critical habitat of such species.
Various governmental authorities have the power to enforce compliance with these laws and regulations and the permits issued under them, oftentimes requiring difficult and costly actions. Failure to comply with these laws, regulations and permits, or the release of oil or other materials into the environment, may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations, the imposition of stricter conditions on or revocation of permits, the issuance of moratoria or injunctions limiting or preventing some or all of our operations, delays in granting permits and cancellation of leases, or could affect our relationship with certain consumers.
There is an inherent risk of the incurrence of environmental costs and liabilities in our business, some of which may be material, due to the handling of our customers’ hydrocarbon products as they are gathered, transported, processed and stored, air emissions related to our operations, historical industry operations, and water and waste disposal practices. For example, we, as an operator of mobile offshore drilling units in navigable US waters and certain offshore areas, including the US Outer Continental Shelf, are liable for damages and for the cost of removing oil spills for which we may be held responsible, subject to certain limitations. Our operations may involve the use or handling of materials that are classified as environmentally hazardous. Environmental laws and regulations may expose us to liability for the conduct of or conditions caused by others or for acts that were in compliance with all applicable laws at the time they were performed. Joint, several or strict liability may be incurred without regard to fault under certain environmental laws and regulations for the remediation of contaminated areas and in connection with past, present or future spills or releases of natural gas, oil and wastes on, under, or from past, present or future facilities. Private parties may have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or property damage arising from our operations. In addition, increasingly strict laws, regulations and enforcement policies could materially increase our compliance costs and the cost of any remediation that may become necessary. Our insurance may not cover all environmental risks and costs or may not provide sufficient coverage if an environmental claim is made against us.
Our business may be adversely affected by increased costs due to stricter pollution control equipment requirements or liabilities resulting from non-compliance with required operating or other regulatory permits. Also, we might not be able to obtain or maintain from time to time all required environmental regulatory approvals for our operations. If there is a delay in obtaining any required environmental regulatory approvals, or if we fail to obtain and comply with them, the operation or construction of our facilities could be prevented or become subject to additional costs. In addition, the steps we could be required to take to bring certain facilities into regulatory compliance could be prohibitively expensive, and we might be required to shut down, divest or alter the operation of those facilities, which might cause us to incur losses.
We make assumptions and develop expectations about possible expenditures related to environmental conditions based on current laws and regulations and current interpretations of those laws and regulations. If the interpretation of laws or regulations, or the laws and regulations themselves, change, our assumptions may change, and new capital costs may be incurred to comply with such changes. In addition, new environmental laws and regulations might adversely affect our operations, as well as waste management and air emissions. For instance, governmental agencies could impose additional safety requirements, which could affect our profitability. Further, new environmental laws and regulations might adversely affect our customers, which in turn could affect our profitability.
Finally, although some of our drilling rigs will be separately owned by our subsidiaries, under certain circumstances a parent company and all of the unit-owning affiliates in a group under common control engaged in a joint venture could be held liable for damages or debts owed by
one of the affiliates, including liabilities for oil spills under environmental laws. Therefore, it is possible that we could be subject to liability upon a judgment against us or any one of our subsidiaries.
Reactivation, refurbishment, conversion or upgrades of rigs are subject to risks, including delays and cost overruns, that could have an adverse impact on our available cash resources and results of operations.
We will continue to make upgrades, refurbishment and repair expenditures to our fleet from time to time, some of which may be unplanned. In addition, we may continue to reactivate rigs that have been cold or warm stacked and make selective purchases of rigs, such as the Noble Johnny Whitstine purchased in 2018 and the Noble Joe Knight purchased in February 2019. Our customers may also require certain shipyard reliability upgrade projects for our rigs. These projects and other efforts of this type are subject to risks of cost overruns or delays inherent in any large construction project as a result of numerous factors, including the following:
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shortages of equipment, materials or skilled labor;
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work stoppages and labor disputes;
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unscheduled delays in the delivery of ordered materials and equipment;
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local customs strikes or related work slowdowns that could delay importation of equipment or materials;
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weather interferences;
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difficulties in obtaining necessary permits or approvals or in meeting permit or approval conditions;
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design and engineering problems;
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inadequate regulatory support infrastructure in the local jurisdiction;
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latent damages or deterioration to hull, equipment and machinery in excess of engineering estimates and assumptions;
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unforeseen increases in the cost of equipment, labor and raw materials, particularly steel;
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unanticipated actual or purported change orders;
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client acceptance delays;
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disputes with shipyards and suppliers;
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delays in, or inability to obtain, access to funding;
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shipyard availability, failures and difficulties, including as a result of financial problems of shipyards or their subcontractors; and
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failure or delay of third-party equipment vendors or service providers.
The failure to complete a rig reactivation, repair, upgrade, refurbishment or new construction on time, or at all, or the inability to complete a rig conversion or new construction in accordance with its design specifications, may result in loss of revenues, penalties, or delay, renegotiation or cancellation of a drilling contract or the recognition of an asset impairment. Additionally, capital expenditures for rig reactivation, repair, upgrade, refurbishment and construction projects could materially exceed our planned capital expenditures. Moreover, when our rigs are undergoing upgrade, refurbishment and repair, they may not earn a dayrate during the period they are out of service. If we experience substantial delays and cost overruns in our shipyard projects, it could have a material adverse effect on our business, financial condition and results of operations. We currently have no new rigs under construction.
Failure to attract and retain skilled personnel or an increase in personnel costs could adversely affect our operations.
We require skilled personnel to operate and provide technical services and support for our drilling units. In the past, during periods of high demand for drilling services and increasing worldwide industry fleet size, shortages of qualified personnel have occurred. During the last few years of reduced demand, there were layoffs of qualified personnel, who often find work with competitors or leave the industry. As a result, if market conditions improve and we seek to reactivate warm or cold stacked rigs, upgrade our working rigs or purchase additional rigs, we may face shortages of qualified personnel, which would impair our ability to attract qualified personnel for our new or existing drilling units, impair the timeliness and quality of our work and create upward pressure on personnel costs, any of which could adversely affect our operations.
Supplier capacity constraints or shortages in parts or equipment, supplier production disruptions, supplier quality and sourcing issues or price increases could increase our operating costs, decrease our revenues and adversely impact our operations.
Our reliance on third-party suppliers, manufacturers and service providers to secure equipment used in our drilling operations exposes us to volatility in the quality, price and availability of such items. Certain specialized parts and equipment we use in our operations may be available only from a single or small number of suppliers. During the last few years of reduced demand, many of these third-party suppliers reduced their inventories of parts and equipment and, in some cases, reduced their production capacity. If the market for our services improves and we seek to reactivate warm or cold stacked rigs, upgrade our working rigs or purchase additional rigs, these reductions could make it more difficult for us to find equipment and parts for our rigs. A disruption or delay in the deliveries from such third-party suppliers, capacity constraints, production disruptions, price increases, defects or quality-control issues, recalls or other decreased availability or servicing of parts and equipment could adversely affect our ability to reactivate rigs, upgrade working rigs, purchase additional rigs or meet our commitments to customers on a timely basis, adversely impact our operations and revenues by resulting in uncompensated downtime, reduced dayrates, the incurrence of liquidated damages or other penalties or the cancellation or termination of contracts, or increase our operating costs.
Acts of terrorism, piracy and political and social unrest could affect the markets for drilling services, which may have a material adverse effect on our results of operations.
Acts of terrorism and social unrest, brought about by world political events or otherwise, have caused instability in the world’s financial and insurance markets in the past and may occur in the future. Such acts could be directed against companies such as ours. In addition, acts of terrorism, piracy and social unrest could lead to increased volatility in prices for crude oil and natural gas and could affect the markets for drilling services. Insurance premiums could increase and coverage may be unavailable in the future. Government regulations may effectively preclude us from engaging in business activities in certain countries. These regulations could be amended to cover countries where we currently operate or where we may wish to operate in the future.
Our drilling contracts do not generally provide indemnification against loss of capital assets or loss of revenues resulting from acts of terrorism, piracy or political or social unrest. We have limited insurance for our assets providing coverage for physical damage losses resulting from risks, such as terrorist acts, piracy, vandalism, sabotage, civil unrest, expropriation and acts of war, and we do not carry insurance for loss of revenues resulting from such risks.
Public health threats could have a material adverse effect on our business and results of operations.
Public health threats, such as coronavirus, Severe Acute Respiratory Syndrome, severe influenza and other highly communicable viruses or diseases, outbreaks of which have already occurred in various parts of the world in which we operate, could adversely impact our operations, the operations of our customers and the global economy, including the worldwide demand for oil and gas and the level of demand for our services. The quarantine of personnel or the inability or unwillingness of personnel to access our offices or rigs could adversely affect our operations. Travel restrictions or operational problems in any part of the world in which we operate, or any reduction in the demand for drilling services caused by public health threats in the future, may materially impact our operations and have an adverse effect on our results of operations.
Unionization efforts and labor regulations in certain countries in which we operate could materially increase our costs or limit our flexibility.
Certain of our employees and contractors in international markets are represented by labor unions or work under collective bargaining or similar agreements, which are subject to periodic renegotiation. Efforts may be made from time to time to unionize portions of our workforce. In addition, we may be subject to strikes or work stoppages and other labor disruptions in the future. Additional unionization efforts, new collective bargaining agreements or work stoppages could materially increase our costs, reduce our revenues or limit our operational flexibility.
Any failure to comply with the complex laws and regulations governing international trade could adversely affect our operations.
The shipment of goods, services and technology across international borders subjects our business to extensive trade laws and regulations. Import activities are governed by unique customs laws and regulations in each of the countries of operation. Moreover, many countries, including the United States, control the export and re-export of certain goods, services and technology and impose related export recordkeeping and reporting obligations. Governments also may impose economic sanctions against certain countries, persons and other entities that may restrict or prohibit transactions involving such countries, persons and entities. US 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 US government or identified by the US government as state sponsors of terrorism, such as the Crimean region of the Ukraine, Cuba, Iran, North Korea, Sudan and Syria. The US 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. There can be no assurance that we will be in compliance in the future, particularly as the scope of certain laws may be unclear and may be subject to changing interpretations. Any such violation could result in fines or other penalties and could result in some investors deciding, or being required, to divest their interest, or not to invest, in us. In addition, certain institutional investors may have investment policies or restrictions that prevent them from holding securities of companies that have contracts with countries identified by the US 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 US sanctions and embargo laws that are not controlled by the governments of those countries, or engaging in operations associated with those countries pursuant to contracts with third parties that are unrelated to those countries or entities controlled by their governments.
Pension expenses associated with our retirement benefit plans may fluctuate significantly depending upon changes in actuarial assumptions, future investment performance of plan assets and legislative or other regulatory actions.
A portion of our current and retired employee population is covered by pension and other post-retirement benefit plans, the costs of which are dependent upon various assumptions, including estimates of rates of return on benefit plan assets, discount rates for future payment obligations, mortality assumptions, rates of future cost growth and trends for future costs. In addition, funding requirements for benefit obligations of our pension and other post-retirement benefit plans are subject to legislative and other government regulatory actions. Future changes in estimates and assumptions associated with our pension and other post-retirement benefit plans could have a material adverse effect on our financial condition, results of operations, cash flows and/or financial disclosures.
Fluctuations in exchange rates and nonconvertibility of currencies could result in losses to us.
We may experience currency exchange losses when revenues are received or expenses are paid in nonconvertible currencies, when we do not hedge an exposure to a foreign currency, when the result of a hedge is a loss or if any counterparty to our hedge were to experience financial difficulties. We may also incur losses as a result of an inability to collect revenues due to a shortage of convertible currency available to the country of operation, controls over currency exchange or controls over the repatriation of income or capital.
We are subject to litigation that could have an adverse effect on us.
We are, from time to time, involved in various litigation matters. These matters may include, among other things, contract disputes, personal injury claims, asbestos and other toxic tort claims, environmental claims or proceedings, employment matters, issues related to employee or representative conduct, governmental claims for taxes or duties, and other litigation that arises in the ordinary course of our business. Although we intend to defend or pursue such matters vigorously, we cannot predict with certainty the outcome or effect of any claim or other litigation matter, and there can be no assurance as to the ultimate outcome of any litigation. Litigation may have an adverse effect on us because of potential negative outcomes, legal fees, the allocation of management’s time and attention, and other factors.
We are a holding company, and we are dependent upon cash flow from subsidiaries to meet our obligations.
We currently conduct our operations through our subsidiaries, and our operating income and cash flow are generated by our subsidiaries. As a result, cash we obtain from our subsidiaries is the principal source of funds necessary to meet our debt service obligations. Unless they are guarantors of our indebtedness, our subsidiaries do not have any obligation to pay amounts due on our indebtedness or to make funds available for that purpose. Contractual provisions or laws, as well as our subsidiaries’ financial condition and operating requirements, may also limit our ability to obtain the cash that we require from our subsidiaries to pay our debt service obligations. Applicable tax laws may also subject such payments to us by our subsidiaries to further taxation.
Item 1B.
Item 1B. Unresolved Staff Comments.
None.
Item 2.
Item 2. Properties.
The description of our rig fleet included under “Part I, Item 1, Business” is incorporated by reference herein. Our corporate headquarters is located in London, England. We also maintain offices in Sugar Land, Texas, where significant worldwide global support activity occurs. In addition, we own and lease operational, administrative and marketing offices, as well as other sites used primarily for operations, storage and maintenance and repairs for drilling rigs and equipment in various locations worldwide.
Item 3.
Item 3. Legal Proceedings.
Information regarding legal proceedings is presented in “Note 16- Commitments and Contingencies” to our consolidated financial statements included in Part II, Item 8 of this Annual Report on Form 10-K.
Item 4.
Item 4. Mine Safety Disclosures.
Not applicable.
PART II
Item 5.
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.
Market for Shares and Related Shareholder Information
Noble-UK shares are listed and traded on the New York Stock Exchange under the symbol “NE.”
The declaration and payment of dividends require the authorization of the Board of Directors of Noble-UK, provided that such dividends on issued share capital may be paid only out of Noble-UK’s “distributable reserves” on its statutory balance sheet in accordance with UK law. Therefore, Noble-UK is not permitted to pay dividends out of share capital, which includes share premium. Noble has not paid dividends since the third quarter of 2016. The payment of future dividends will depend on our results of operations, financial condition, cash requirements, future business prospects, contractual and indenture restrictions and other factors deemed relevant by our Board of Directors.
On February 18, 2020, there were 249,811,683 shares outstanding held by 136 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.
Disposition of Noble-UK Shares
Shareholders who are neither UK tax residents nor holding their Noble-UK shares in connection with a trade carried on through a permanent establishment in the UK will not be subject to any UK taxes on chargeable gains as a result of any disposals of their shares. Noble-UK shares held outside the facilities of The Depository Trust Company (“DTC”) should be treated as UK situs assets for the purpose of UK inheritance tax.
UK Withholding Tax-Dividends to Shareholders
Payments of dividends by Noble-UK will not be subject to any withholding in respect of UK taxation, regardless of the tax residence of the recipient shareholder.
Stamp Duty and Stamp Duty Reserve Tax in Relation to the Transfer of Shares
Stamp duty and/or stamp duty reserve tax (“SDRT”) are imposed by the UK on certain transfers of chargeable securities (which include shares in companies incorporated in the UK) at a rate of 0.5 percent of the consideration paid for the transfers in question. Certain transfers of shares to depositaries or into clearance systems are charged at a higher rate of 1.5 percent. Her Majesty’s Revenue and Customs (“HMRC”) regard DTC as a clearance system for these purposes.
Transfers of the ordinary shares through the facilities of DTC will not attract a charge to stamp duty or SDRT in the UK. Any transfer of title to ordinary shares from within those facilities to a holder outside those facilities, and any subsequent transfers that occur entirely outside those facilities, will ordinarily attract stamp duty or SDRT at a rate of 0.5 percent. This duty must be paid (and, where relevant, the transfer document stamped by HMRC) before the transfer can be registered in the books of Noble-UK. However, if those ordinary shares of Noble-UK are redeposited into the facilities of DTC, that redeposit will attract stamp duty or SDRT at the rate of 1.5 percent.
Share Repurchases
Under UK law, the Company is only permitted to purchase its own shares by way of an “off-market purchase” in a plan approved by shareholders. We currently do not have shareholder authority to repurchase shares. During the years ended December 31, 2019, 2018 and 2017, we did not repurchase any of our shares.
Stock Performance Graph
The chart below presents a comparison of the five-year cumulative total return, assuming $100 was invested on December 31, 2014 for Noble-UK, the Standard & Poor's 500 Index, Dow Jones US Oil Equipment and Services and a self-determined offshore drillers peer group. Total return assumes the reinvestment of dividends, if any, in the security on the ex-dividend date.
(1)
Our self-determined peer group is weighted according to market capitalization and consists of the Company and the following peer companies: Atwood Oceanics (through October 5, 2017), Diamond Offshore Drilling Inc., Valaris (formerly known as Ensco plc), Rowan Companies plc (through April 10, 2019), Seadrill Ltd. and Transocean Ltd.
The above graph and related information shall not be deemed “soliciting material” or to be “filed” with the SEC, nor shall such information be incorporated by reference into any future filing under the Securities Act or the Exchange Act, except to the extent that we specifically incorporate it by reference into such filing.
Item 6.
Item 6. Selected Financial Data.
The following table presents selected financial data of us and our consolidated subsidiaries over the five-year period ended December 31, 2019, which information is derived from our audited financial statements. This information should be read in conjunction with, and is qualified in its entirety by, the more detailed information in our financial statements included in Part II, Item 8, “Financial Statements and Supplementary Data” in this Annual Report on Form 10-K.
(1)
Results for 2019, 2018, 2017, 2016 and 2015 include impairment charges of $615.3 million, $802.1 million, $121.6 million, $1.5 billion and $418.3 million, respectively. Results for 2019 include estimated loss of $100.0 million related to the final disposition of Paragon.
(2)
Consists of long-term debt and current maturities of long-term debt.
(3)
Working capital is calculated as current assets less current liabilities.
Item 7.
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.
The following discussion is intended to assist you in understanding our financial position at December 31, 2019 and 2018, and our results of operations for each of the years in the three-year period ended December 31, 2019. 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, 2019 filed by Noble-UK and Noble-Cayman.
Executive Overview
We provide contract drilling services to the international oil and gas industry with our global fleet of mobile offshore drilling units. Our business strategy focuses on a balanced, high-specification fleet of both floating and jackup rigs and the deployment of our drilling rigs in established and emerging offshore oil and gas basins around the world. We emphasize safe operations through the employment of qualified, well-trained crews and strive to manage rig operating costs through the implementation and continuous improvement of innovative systems and processes, including the use of data analytics and predictive maintenance technology.
As of the filing date of this Annual Report on Form 10-K, our fleet of 25 drilling rigs consisted of 12 floaters and 13 jackups strategically deployed worldwide in both ultra-deepwater and shallow water locations. We typically employ each drilling unit under an individual contract, and many contracts are awarded based upon a competitive bidding process.
Our 2019 financial and operating results from continuing operations include:
•
operating revenues totaling $1.3 billion;
•
net loss attributable to Noble Corporation plc of $700.6 million, or 2.81 per diluted share, which includes a $615.3 million before-tax impairment charge recognized on two of our rigs and certain capital spare equipment; and
•
net cash provided by operating activities totaling $186.8 million.
Our floating and jackup drilling fleet is among the youngest, most modern and versatile in the industry. Our fleet consists predominately of technologically advanced units, equipped with sophisticated systems and components capable of executing our customers’ increasingly complicated offshore drilling programs safely and with greater efficiency. A total of 17 of our drilling rigs have been delivered since 2011 following their construction primarily in quality shipyards located in Korea and Singapore. The last of our new rig additions was delivered in July 2016, and no further newbuild rig construction is in process. We retired or sold 12 drilling rigs since late 2014, due in part to advanced service lives, high cost of operation and limited customer appeal. Current market conditions could lead to us stacking or retiring additional rigs.
Although we plan to prioritize capital preservation and liquidity based on the challenging market conditions, from time to time we will also continue to evaluate opportunities to enhance our fleet of floating and jackup rigs, particularly focusing on higher specification rigs, to execute the increasingly complex drilling programs required by our customers.
In September 2018, we purchased the Noble Johnny Whitstine, a new GustoMSC CJ46 design jackup rig, from the PaxOcean Group (“PaxOcean”) in connection with a concurrently awarded drilling contract in the Middle East region. We paid $93.8 million for the rig, with $33.8 million paid in cash and the remaining $60.0 million of the purchase price financed with a loan by the seller. On February 28, 2019, we purchased another GustoMSC CJ46 rig, the Noble Joe Knight, from PaxOcean. The rig has an awarded drilling contract in the Middle East region. We paid $83.8 million for the rig, with $30.2 million paid in cash and the remaining $53.6 million of the purchase price financed with a loan by the seller. See Part II, Item 8, “Financial Statements and Supplementary Data, Note 7- Debt” for additional information.
Market Outlook
The offshore drilling industry experienced a significant expansion from the early 2000s to the mid-2010s. Since that time, a significant reduction in oil prices from the levels experienced earlier in the 2010s, partly driven by the high level of growth in US onshore production, coupled with meaningful increases in offshore rig supply, have led to an industry-wide supply and demand imbalance and an extremely challenging environment. This period of oil price weakness and volatility compelled many exploration and production companies to deemphasize offshore programs while focusing instead on less capital intensive onshore-based opportunities. Levels of offshore rig utilization have been adversely impacted and contract awards have generally been subject to an extremely competitive bidding process. As a result, the contracts have included dayrates that are substantially lower than dayrates for the same class of rigs before this period of supply and demand imbalance.
However, while the environment remains extremely challenging, we believe that the industry is experiencing a gradual improvement driven by several factors. Over the last few years, customers have reduced the costs associated with many offshore projects through revised engineering solutions, advances in rig technologies and drilling efficiencies, and project simplification, resulting in more robust offshore project economics. Also, access has improved to some of the world’s most promising offshore basins, leading to the acquisition by exploration and production companies of large offshore positions and the commencement of exploration and development drilling campaigns. In addition, the oversupply of offshore rigs has improved as a result of a higher level of fleet attrition, due to the challenging environment, advanced service life of rigs, high maintenance and reactivation costs and limited customer appeal. Furthermore, during 2019, higher average crude oil prices and customer spending offshore led to an improvement in activity. The jackup market improved steadily throughout the year, driven primarily by activity in the Middle East, Asia and Mexico, and the floating fleet recognized pricing improvement during the fourth quarter of 2019 for the first time in several years.
With regard to industry prospects in 2020, customer surveys showing expected higher levels of offshore capital spending in 2020 have provided optimism that the favorable trends experienced during 2019 will continue. This optimism is somewhat tempered by the recent decline in oil prices experienced to-date in 2020 driven by the potential economic impact of the coronavirus, uncertainty regarding the viability and length
of reductions in production agreed to by the Organization of Petroleum Exporting Countries (“OPEC”) plus other non-OPEC producers including Russia and continued limits on certain of our customers’ access to capital.
Over the longer term, we believe that any number of other factors could contribute to an improvement in the market for our services. These factors include:
•
oil demand growth;
•
our customers’ access to capital
•
sustained higher crude oil prices;
•
renewed focus by operators on offshore exploration and development and accompanying increase in spending offshore;
•
improved geologic success with regard to our customers’ exploration efforts;
•
greater customer access to areas with promising offshore resource potential;
•
advances in offshore technological applications which reduce offshore costs and improve project economics;
•
high rate of natural depletion relating to land-based sources of crude oil production;
•
deteriorating annual production and poor reserve replacement metrics caused, in part, by a period of sustained under-investment by our customers; and
•
declining supply of rigs due to continued attrition.
We cannot give any assurances as to whether the favorable trends experienced in 2019 will continue or when the oversupply of available drilling rigs and the reduced demand from customers will come back into balance. Due to numerous factors that influence our customers’ annual global offshore spending patterns, including access to capital, cheaper onshore production opportunities and geopolitical events, we cannot predict the future level of demand or dayrates for our services, or future conditions in the offshore contract drilling industry.
Recent Events
Management Changes
On February 19, 2020, we announced that our Board of Directors approved the upcoming appointment of Julie J. Robertson, who currently serves as Chairman of the Board, President and Chief Executive Officer of the Company, to the newly created position of Chairman of the Board in the capacity of an executive of the Company (“Executive Chairman”). At the time Ms. Robertson transitions to the position of Executive Chairman, Ms. Robertson will step down from her positions of President and Chief Executive Officer of the Company. On February 19, 2020, our Board of Directors also approved the upcoming appointment of Mr. Robert W. Eifler, who currently serves as Senior Vice President, Commercial of the Company, to succeed Ms. Robertson as President and Chief Executive Officer. Such transitions will be effective as of the close of the Company’s 2020 annual general meeting of shareholders.
Spin-off of Paragon Offshore plc
On August 1, 2014, Noble-UK completed the separation and spin-off of a majority of its standard specification offshore drilling business (the “Spin-off”) through a pro rata distribution of all of the ordinary shares of its wholly-owned subsidiary, Paragon Offshore plc (“Paragon Offshore”), to the holders of Noble’s ordinary shares. In February 2016, Paragon Offshore sought approval of a pre-negotiated plan of reorganization (the “Prior Plan”) by filing for voluntary relief under Chapter 11 of the United States Bankruptcy Code. As part of the Prior Plan, we entered into a settlement agreement with Paragon Offshore (the “Settlement Agreement”). The Prior Plan was rejected by the bankruptcy court in October 2016.
In April 2017, Paragon Offshore filed a revised plan of reorganization (the “New Plan”) in its bankruptcy proceeding. Under the New Plan, Paragon Offshore no longer needed the Mexican tax bonding that Noble-UK was required to provide under the Settlement Agreement. Consequently, Paragon Offshore abandoned the Settlement Agreement as part of the New Plan, and the Settlement Agreement was terminated at the time of the filing of the New Plan. On May 2, 2017, Paragon Offshore announced that it had reached an agreement in principle with both its secured and unsecured creditors to revise the New Plan to create and fund a litigation trust to pursue litigation against us. On June 7, 2017, the revised New Plan was approved by the bankruptcy court and Paragon Offshore emerged from bankruptcy on July 18, 2017.
On December 15, 2017, the litigation trust filed claims relating to the Spin-off against us and certain of our current and former officers and directors in the Delaware bankruptcy court that heard Paragon Offshore’s bankruptcy, and the litigation trust filed an amended complaint in October 2019. The amended complaint alleges claims of actual and constructive fraudulent conveyance, unjust enrichment and recharacterization of
intercompany notes as equity claims against Noble and claims of breach of fiduciary duty and aiding and abetting breach of fiduciary duty against the officer and director defendants. The litigation trust is seeking damages of (i) approximately $1.7 billion from the Company, an amount equal to the amount borrowed by Paragon Offshore immediately prior to the Spin-off, (ii) an additional approximately $935 million relating to the transfer of intercompany receivables and notes from a Paragon subsidiary to a Noble subsidiary prior to the Spin-off (bringing the total claimed damages to approximately $2.6 billion), and (iii) unspecified amounts in respect of the claims against the officer and director defendants, all of whom have indemnification agreements with us. A trial date has been set for September 2020.
We believe that Paragon Offshore, at the time of the Spin-off, was properly funded, solvent and had appropriate liquidity and that the claims brought by the litigation trust are without merit. However, the Company continually assesses potential outcomes, including the probability of the parties ultimately resolving the matter through settlement in light of various factors, including given the complex factual issues involved, the uncertainty and risk inherent in this type of litigation, the time commitment and distraction of our organization, the potential effect of the ongoing litigation and uncertainty on our business, and the substantial expense incurred in litigating the claims. As such, the Company’s current estimated loss related to final disposition of this matter is $100.0 million, which the Company recorded as a general and administrative expense for the year ended December 31, 2019 and is reflected as a current liability as of December 31, 2019. As pre-trial matters progress, the Company’s estimated loss could change from time to time, and any such change individually or in the aggregate could be material.
There is inherent risk and substantial expense in litigation, and the amount of damages that the plaintiff is seeking is substantial. If any of the litigation trust’s claims are successful, or if we elect to settle any claims (in part to reduce or eliminate the ongoing cost of defending the litigation and eliminate any risk of a larger judgment against us), any damages or other amounts we would be required to or agree to pay in excess of the amount we recognized at December 31, 2019, could have a material adverse effect on our business, financial condition and results of operations, including impeding our ability to meet ongoing financial obligations or to continue as a going concern. Given the risks and considerations discussed above, we cannot predict with any degree of certainty what the outcome of the litigation may be. Furthermore, as discussed below, we cannot predict the amount of insurance coverage, if any, that we may have if we were to settle or be found liable in the litigation.
We have directors’ and officers’ indemnification coverage for the officers and directors who have been sued by the litigation trust. The insurers have accepted coverage for the director and officer claims and we are continuing to discuss with them the scope of their reimbursement of litigation expenses. In addition, at the time of the Spin-off, we had entity coverage, or “Side C” coverage, which was meant to cover certain litigation claims up to the coverage limit of $150.0 million, including litigation expenses. We have made a claim for coverage of the litigation trust’s claims against Noble under such entity insurance. The insurers have rejected coverage for these claims. However, we intend to pursue coverage should the litigation be concluded adversely to us or should we settle the litigation. We cannot predict the amount of claims and expenses we may incur, pay or settle in the Paragon Offshore litigation that such insurance will cover, if any.
Prior to the completion of the Spin-off, Noble-UK and Paragon Offshore entered into a series of agreements to effect the separation and Spin-off and govern the relationship between the parties after the Spin-off (the “Separation Agreements”), including a Master Separation Agreement (the “MSA”) and a Tax Sharing Agreement (the “TSA”).
As part of its final bankruptcy plan, Paragon Offshore rejected the Separation Agreements. Accordingly, the indemnity obligations that Paragon Offshore potentially would have owed us under the Separation Agreements have now terminated, including indemnities arising under the MSA and the TSA in respect of obligations related to Paragon Offshore’s business that were incurred through Noble-retained entities prior to the Spin-off. Likewise, any potential indemnity obligations that we would have owed Paragon Offshore under the Separation Agreements, including those under the MSA and the TSA in respect of Noble-UK’s business that was conducted prior to the Spin-off through Paragon Offshore-retained entities, are now also extinguished. In the absence of the Separation Agreements, liabilities relating to the respective parties will be borne by the owner of the legal entity or asset at issue and neither party will look to an allocation based on the historic relationship of an entity or asset to one of the party’s business, as had been the case under the Separation Agreements.
The rejection and ultimate termination of the indemnity and related obligations under the Separation Agreements resulted in a number of accounting charges and benefits during the year ended December 31, 2017, and such termination may continue to affect us in the future as liabilities arise for which we would have been indemnified by Paragon Offshore or would have had to indemnify Paragon Offshore. We do not expect that, overall, the rejection of the Separation Agreements by Paragon Offshore will have a material adverse effect on our financial condition or liquidity. However, any loss we experience with respect to which we would have been able to secure indemnification from Paragon Offshore under one or more of the Separation Agreements could have an adverse impact on our results of operations in any period, which impact may be material depending on our results of operations during this down-cycle.
During the year ended December 31, 2019, we recognized charges of $3.8 million recorded in “Net loss from discontinued operations, net of tax” on our Consolidated Statement of Operations relating to settlement of Mexico customs audits from rigs included in the Spin-off.
Impairment
As more thoroughly described in Part II, Item 8, “Financial Statements and Supplementary Data, Note 6- Loss on Impairment” we evaluate our property and equipment for impairment whenever there are changes in facts that suggest that the value of the asset is not recoverable. An impairment loss is recognized when and to the extent that an asset's carrying value exceeds its estimated fair value. As part of this analysis, we make assumptions and estimates regarding future market conditions. To the extent actual results do not meet our estimated assumptions for a given rig or piece of equipment, we may take an impairment loss in the future.
During the years ended December 31, 2019, 2018 and 2017, we recognized non-cash, before-tax impairment charges of $615.3 million, $802.1 million and $121.6 million, respectively, related to certain rigs and related capital spares. These impairments were driven by factors such as customer suspensions of drilling programs, contract cancellations, a further reduction in the number of new contract opportunities, capital spare equipment obsolescence, and our belief that a drilling unit is no longer marketable and is unlikely to return to service.
There can be no assurance that we will not have to take additional impairment charges in the future if current depressed market conditions persist, or that we will be able to return cold stacked rigs to service in the time frame and at the reactivation costs or at the dayrates that we projected. It is reasonably possible that the estimate of undiscounted cash flows may change in the near term, resulting in the need to write down the affected assets to their corresponding estimated fair values.
Contract Drilling Services Backlog
We maintain a backlog of commitments for contract drilling services. Our contract drilling services backlog reflects estimated future revenues attributable to signed drilling contracts. While backlog did not include any letters of intent as of December 31, 2019, in the past we have included in backlog certain letters of intent that we expect to result in binding drilling contracts.
We calculate backlog for any given unit and period by multiplying the full contractual operating dayrate for such unit by the number of days remaining in the period, and for the two rigs contracted with Royal Dutch Shell plc (“Shell”) mentioned below, we utilize the idle period and floor rates as described in footnote (2) to the backlog table below. The reported contract drilling services backlog does not include amounts representing revenues for mobilization, demobilization and contract preparation, which are not expected to be significant to our contract drilling services revenues, amounts constituting reimbursables from customers or amounts attributable to uncommitted option periods under drilling contracts or letters of intent.
The table below presents the amount of our contract drilling services backlog and the percent of available operating days committed for the periods indicated:
(1)
Represents a twelve-month period beginning January 1.
(2)
As previously reported, two of our long-term drilling contracts with Shell, the Noble Globetrotter I and Noble Globetrotter II, contain a dayrate adjustment mechanism that utilizes an average of market rates that match a set of distinct technical attributes and is subject to a modest discount, beginning on the fifth-year anniversary of the contract and continuing every six months thereafter. On December 12, 2016, we amended those drilling contracts with Shell. As a result of the amendments, each of the contracts now has a contractual dayrate floor. The contract amendments for the Noble Globetrotter I and Noble Globetrotter II provide a dayrate floor of $275,000 per day. Once the dayrate adjustment mechanism becomes effective and following any idle periods, the dayrate for these rigs will not be lower than the higher of (i) the contractual dayrate floor or (ii) the market rate as calculated under the adjustment mechanism. The impact to contract backlog from these amendments has been reflected in the table above and the backlog calculation assumes that, after any idle period at the contractual stacking rate, each rig will work at its respective dayrate floor for the remaining contract term.
(3)
The backlog figures and days committed to contracts excludes the multi-year Commercial Enabling Agreement (the “CEA”) with Exxon Mobil Corporation (“ExxonMobil”) executed in February 2020. Concurrent with signing the CEA, ExxonMobil, has awarded three and half years of term to be added at the conclusion of the Noble Tom Madden’s (three years) and the Noble Bob Douglas’ (six months) current contract commitments, or approximately $242.3 million in backlog based on the initial agreed-upon rates that will be applicable once the first rig is operating under the CEA. Subsequent to the execution of the CEA, ExxonMobil awarded a one-year primary term contract for approximately $69.4 million in backlog on the Noble Sam Croft in February 2020, which has also been excluded from the backlog table above and will be added to the CEA. The aforementioned additional backlog was estimated using an illustrative dayrate of $200,000 and discount, net of performance bonus, of 5%.
(4)
Some of our drilling contracts provide customers with certain early termination rights and, in limited cases, those termination rights require minimal or no notice and minimal financial penalties.
(5)
Percent of available days committed is calculated by dividing the total number of days our rigs are operating under contract for such period by the product of the number of our rigs and the number of calendar days in such period.
The amount of actual revenues earned and the actual periods during which revenues are earned may be materially different than the backlog amounts and backlog periods presented in the table above due to various factors, including, but not limited to, shipyard and maintenance projects, unplanned downtime, the operation of market benchmarks for dayrate resets, achievement of bonuses, weather conditions, reduced standby or mobilization rates and other factors that result in applicable dayrates lower than the full contractual operating dayrate. In addition, amounts included in the backlog may change because drilling contracts may be varied or modified by mutual consent or customers may exercise early termination rights contained in some of our drilling contracts or decline to enter into a drilling contract after executing a letter of intent. As a result, our backlog as of any particular date may not be indicative of our actual operating results for the periods for which the backlog is calculated. See Part I, Item 1A, “Risk Factors- Our current backlog of contract drilling revenue may not be ultimately realized.”
For the year ended December 31, 2019, Shell, Saudi Arabian Oil Company (“Saudi Aramco”), ExxonMobil and Equinor ASA represented approximately 51.1 percent, 23.0 percent, 12.4 percent and 6.6 percent of our backlog, respectively.
Results of Operations
2019 Compared to 2018
Net loss from continuing operations attributable to Noble-UK for the year ended December 31, 2019 was $696.8 million, or $2.79 per diluted share, on operating revenues of $1.3 billion, compared to a net loss from continuing operations for the year ended December 31, 2018 of $885.1 million, or $3.59 per diluted share, on operating revenues of $1.1 billion.
As a result of Noble-UK conducting all of its business through Noble-Cayman and its subsidiaries, the financial position and results of operations for Noble-Cayman, and the reasons for material changes in the amount of revenue and expense items between December 31, 2019 and December 31, 2018, would be the same as the information presented below regarding Noble-UK in all material respects, with the exception of operating income (loss). During the years ended December 31, 2019 and 2018, Noble-Cayman's operating loss was $138.8 million and $40.7 million lower, respectively, than that of Noble-UK. The operating loss difference is primarily a result of expenses related to ongoing litigation, administration and other costs directly attributable to Noble-UK for operations support and stewardship-related services. In the year ended December 31, 2019, Noble-UK recorded a $100.0 million expense related to ongoing litigation, which was not recognized by Noble-Cayman.
Key Operating Metrics
Operating results for our contract drilling services segment are dependent on three primary metrics: operating days, dayrates and operating costs. We also track rig utilization, which is a function of operating days and the number of rigs in our fleet. For more information on operating costs, see “-Contract Drilling Services” below. The following table presents the average rig utilization, operating days and average dayrates for our rig fleet for the years ended December 31, 2019 and 2018:
(1)
We define utilization for a specific period as the total number of days our rigs are operating under contract, divided by the product of the total number of our rigs, including cold stacked rigs, and the number of calendar days in such period. Information reflects our policy of reporting on the basis of the number of available rigs in our fleet, excluding newbuild rigs under construction.
(2)
Information reflects the number of days that our rigs were operating under contract.
(3)
Includes the impact of the Noble Bully II contract buyout during the year ended December 31, 2019. Exclusive of this item, the average dayrate for the year ended December 31, 2019 would have been $205,304 for floaters and $159,106 for total rigs.
Contract Drilling Services
The following table presents the operating results for our contract drilling services segment for the years ended December 31, 2019 and 2018 (dollars in thousands):
(1)
Changes in the amount of these reimbursables generally do not have a material effect on our financial position, results of operations or cash flows. For additional information, see Part II, Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations- Critical Accounting Policies.”
Operating Revenues. Contract drilling services revenues increased $210.0 million for the year ended December 31, 2019 as compared to the same period of 2018. During 2019, we recognized $166.9 million related to a one-time contract buyout on the Noble Bully II. In addition to the one-time contract buyout, revenue increased $43.1 million with our jackup fleet contributing $44.6 million of the increase offset by a reduction in revenues for our floating fleet of $1.5 million.
The $1.5 million decrease in our floater fleet is attributable to a $47.4 million decrease due to reductions in dayrates offset by a $45.9 million increase attributable to additional operating days in the current period. The net reduction in dayrates was primarily comprised of approximately $90.5 million resulting from the expiration of legacy contracts that were replaced with lower rate contracts, partially offset by approximately $43.1 million attributable to new higher rate contracts, including utilization of the Company-owned managed pressure drilling system. Additional operating days in the current period were primarily attributable to the reactivations of the Noble Sam Croft and the Noble Tom Madden in early 2019 and late 2018, respectively, and the Noble Bob Douglas and the Noble Clyde Boudreaux operating during the majority of 2019. These operating day increases were partially offset by lower operating days on the Noble Don Taylor, which prepared for a new contract that commenced in late 2019, as well as fewer operating days as the Noble Paul Romano and the Noble Bully II completed contracts in late 2018 and late 2019, respectively.
The $44.6 million increase in our jackup fleet revenue is attributable to a $40.3 million increase for additional operating days and a $4.3 million increase from higher dayrates. The jackup fleet had a $53.1 million increase from additional operating days on various rigs, including the Noble Sam Hartley, the Noble Mick O’Brien and the Noble Hans Deul, as well as a $20.6 million increase from the Noble Johnny Whitstine and the Noble Joe Knight being placed into service for the first time. These increases were partially offset by a $33.4 million decrease in revenues attributable to fewer operating days primarily due to the Noble Gene House being retired in the first quarter of 2019 and the Noble Houston Colbert preparing for its contract that commenced in late 2019. There was also a $19.1 million increase due to higher dayrates on various rigs, primarily the Noble Hans Deul, the Noble Lloyd Noble and the Noble Regina Allen, offset by a $14.8 million decrease due to lower dayrates on various rigs, primarily the Noble Sam Hartley and the Noble Sam Turner.
Operating Costs and Expenses. Contract drilling services costs increased $68.4 million for the year ended December 31, 2019 as compared to the same period of 2018. The primary cost increases were due to: (i) a $31.2 million increase from the Noble Sam Croft, Noble Tom Madden and Noble Clyde Boudreaux experiencing a full operating year in 2019 after reactivation activities began in 2018, (ii) the Noble Johnny Whitstine and Noble Joe Knight commencing operations during 2019, resulting in an increase of $30.4 million, (iii) a $19.8 million increase on various rigs that had additional operating days during 2019 compared to 2018, (iv) a $13.7 million increase attributable to locations with higher operating costs, and (v) an acceleration of deferred costs of $6.8 million as a result of the Noble Bully II contract early termination. These increases were offset by a $28.3 million decrease for various rigs with fewer operating days during 2019 compared to 2018, as well as other cost reductions.
Depreciation and amortization decreased $27.1 million for the year ended December 31, 2019 as compared to the same period of 2018. The decline was due to the effect of rig impairments recorded during both the second and fourth quarters of 2018 and the third quarter of 2019.
Loss on Impairments. We recorded a loss on impairment of $615.3 million for the year ended December 31, 2019 as compared to a loss on impairment of $802.1 million for the same period of 2018. We evaluate our property and equipment for impairment whenever there are changes in facts that suggest that the value of the asset is not recoverable. In connection with the preparation of our financial statements for the year ended December 31, 2019 and 2018, we conducted a review of our fleet. The review included an assessment of certain assumptions, including future marketability of each unit in light of its current technical specifications. Based upon our impairment analysis, we impaired the carrying values to estimated fair values for the Noble Bully II, Noble Paul Romano, and certain capital spare equipment during 2019 and the Noble Bully I, Noble Dave Beard, Noble Gene House, Noble Joe Beall, Noble Paul Romano, and certain capital spare equipment during 2018. For additional information, see Part II, Item 8, “Financial Statements and Supplementary Data, Note 6- Loss on Impairment.”
Other Income and Expenses
General and Administrative Expenses. General and administrative expenses increased $95.6 million during the year ended December 31, 2019 as compared to the same period of 2018, primarily as a result of Noble-UK recognizing a $100.0 million expense in connection with ongoing litigation during the year ended December 31, 2019 coupled with higher legal fees, partially offset by a decrease in employee-related costs.
Interest Expense. Interest expense decreased $18.2 million during the year ended December 31, 2019 as compared to the same period of 2018. This decrease was primarily due to the retirement of a portion of various tranches of our senior notes as a result of tender offers and open market repurchases throughout 2018 and early 2019. This decrease was partially offset by additional interest expense from the issuance of our Senior Notes due 2026 (the “2026 Notes”) in January 2018, the issuance of our two Seller Loans in late 2018 and early 2019 and the borrowing on our Credit Facilities (as defined herein) throughout 2019. For additional information, see Part II, Item 8, “Financial Statements and Supplementary Data, Note 7- Debt”.
Income Tax Benefit. Our income tax benefit decreased by $68.1 million for the year ended December 31, 2019 as compared to the same period of 2018. Excluding the tax impact of extraordinary items consisting of a gain on debt extinguishment of $6.6 million, the release of uncertain tax positions related to the settlement of our 2010-2011 US tax audit of $33.7 million, internal restructuring of $36.8 million in the current period, asset impairments of $35.6 million in the prior period, and our 2017 US return-to-provision adjustment of $24.9 million in the prior period, our tax benefit increased by $38.6 million. This increase is due to an increase in our worldwide tax rate applied to a lower pre-tax loss for the current period as compared to the prior period, which included a negative worldwide tax rate applied to a higher pre-tax loss. The increase in the worldwide effective tax rate is primarily a result of the geographic mix of income and sources of revenue during the current period.
2018 Compared to 2017
Information related to a comparison of our results of operations for our fiscal year ended December 31, 2018 compared to our fiscal year ended December 31, 2017 is included in Part II, Item 7, “Management's Discussion and Analysis of Financial Condition and Results of Operations” of our Annual Report on Form 10-K for the fiscal year ended December 31, 2018, filed with the SEC on February 21, 2019, and is incorporated by reference into this Annual Report on Form 10-K
Liquidity and Capital Resources
Overview
Net cash provided by operating activities was $186.8 million for the year ended December 31, 2019 as compared to $171.9 million for the year ended December 31, 2018. The increase in net cash provided by operating activities for the year ended December 31, 2019 was primarily attributable to the contract buyout for the Noble Bully II in 2019 and a $24.7 million decline in cash outflow from changes in other working capital accounts year-over-year. These increases are partially offset by a net reduction in tax refunds of $95.5 million year-over-year (including a one-time VAT payment for the temporary import of the Noble Houston Colbert into the UK, of which we received a full refund in January 2020), and a decrease in contract drilling services margin (excluding the Noble Bully II contract buyout) year-over-year. We had negative working capital of $94.8 million and working capital of $293.6 million at December 31, 2019 and December 31, 2018, respectively.
Net cash used in investing activities for the year ended December 31, 2019 was $256.0 million as compared to $189.4 million for the year ended December 31, 2018. The variance primarily relates to the purchase of the Noble Joe Knight, and shipyard projects undertaken to ready the Noble Johnny Whitstine and the Noble Joe Knight for their respective contracts with Saudi Aramco, and various major projects in the current period.
Net cash used in financing activities for the year ended December 31, 2019 was $200.7 million as compared to $269.4 million for the year ended December 31, 2018. Our primary use of cash in both periods was the retirement of a portion of various tranches of our senior notes as a result of tender offers. This use of cash was offset in the current period by net borrowings under our Credit Facilities.
In March 2019, we completed cash tender offers for our Senior Notes due 2020 (the “2020 Notes”), Senior Notes due 2021 (the “2021 Notes”), Senior Notes due 2022 (the “2022 Notes”) and Senior Notes due 2024 (the “2024 Notes”). Pursuant to such tender offers, we purchased $440.9 million aggregate principal amount of these senior notes for $400.0 million, plus accrued interest, using borrowings under the 2015 Credit Facility (as defined herein) and cash on hand.
Our principal sources of capital in the current period were cash generated from operating activities and funding from our Credit Facilities. Cash on hand during the current period was primarily used for the following:
•
normal recurring operating expenses;
•
retirement of a portion of various tranches of our senior notes in tender offers; and
•
capital expenditures.
Our currently anticipated cash flow needs, both in the short-term and long-term, may include the following:
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normal recurring operating expenses;
•
planned and discretionary capital expenditures; and
•
repayments of debt and interest.
We currently expect to fund these cash flow needs with cash generated by our operations, cash on hand, borrowings under our 2017 Credit Facility (as defined herein) and potential issuances of equity or long-term debt. However, to adequately cover our expected cash flow needs, we may require capital in excess of the amount available from these sources, and we may seek additional sources of liquidity and/or delay or cancel certain discretionary capital expenditures or other payments as necessary. If additional financing sources are unavailable, or not available on reasonable terms, our financial condition, results of operations, growth and future prospects could be materially adversely affected, and we may be unable to continue as a going concern.
At December 31, 2019, we had a total contract drilling services backlog of approximately $1.5 billion, which includes a commitment of 52.0 percent of available days for 2020. For additional information regarding our backlog, see “-Contract Drilling Services Backlog.”
Capital Expenditures
Capital expenditures totaled $306.4 million, $281.3 million and $111.1 million for the years ended December 31, 2019, 2018 and 2017, respectively. Capital expenditures during 2019 consisted of the following:
•
$74.6 million for sustaining capital;
•
$120.3 million in major projects, including upgrades to the Noble Johnny Whitstine and Noble Joe Knight, reactivations and subsea and other related projects;
•
$83.8 million to purchase the Noble Joe Knight (inclusive of cash paid and seller financing);
•
$18.1 million for rebillable capital modifications; and
•
$9.6 million in capitalized interest.
Our total capital expenditure estimate for 2020 is is expected to range between $190.0 million and $200.0 million, of which approximately $115.0 million is currently anticipated to be spent for sustaining capital.
From time to time we consider possible projects that would require expenditures that are not included in our capital budget, and such unbudgeted expenditures could be significant. In addition, we will continue to evaluate acquisitions of drilling units from time to time. Other factors that could cause actual capital expenditures to materially exceed plan include delays and cost overruns in shipyards (including costs attributable to labor shortages), shortages of equipment, latent damage or deterioration to hull, equipment and machinery in excess of engineering estimates and assumptions, changes in governmental regulations and requirements, possible refurbishment and reactivation of rigs and changes in design criteria or specifications during repair or construction.
Share Capital
The declaration and payment of dividends require the authorization of the Board of Directors of Noble-UK, provided that such dividends on issued share capital may be paid only out of Noble-UK’s “distributable reserves” on its statutory balance sheet in accordance with UK law. Therefore, Noble-UK is not permitted to pay dividends out of share capital, which includes share premium. Noble has not paid dividends since the third quarter of 2016. The payment of future dividends will depend on our results of operations, financial condition, cash requirements, future business prospects, contractual and indenture restrictions and other factors deemed relevant by our Board of Directors.
At our 2019 Annual General Meeting, shareholders authorized our Board of Directors to increase share capital through the issuance of up to approximately 83.1 million ordinary shares (at current nominal value of $0.01 per share). The authority to allot shares will expire at the end of our 2020 Annual General Meeting unless we seek an extension from shareholders at that time. Other than shares issued to our directors under our Noble Corporation plc 2017 Director Omnibus Plan, the authority was not used to allot shares during the year ended December 31, 2019.
Share Repurchases
Under UK law, the Company is only permitted to purchase its own shares by way of an “off-market purchase” in a plan approved by shareholders. We currently do not have shareholder authority to repurchase shares. During the years ended December 31, 2019, 2018 and 2017, we did not repurchase any of our shares.
Credit Facilities
2015 Credit Facility
Effective January 2018, in connection with entering into the 2017 Credit Facility, we amended our $300.0 million senior unsecured credit facility that would have matured in January 2020 and was guaranteed by our indirect, wholly-owned subsidiaries, Noble Holding (U.S.) LLC (“NHUS”) and Noble Holding International Limited (“NHIL”) (as amended, the “2015 Credit Facility”), which resulted in, among other things, a reduction in the aggregate principal amount of commitments thereunder. As a result of the 2015 Credit Facility's reduction in the aggregate principal amount of commitments, we recognized a net loss of approximately $2.3 million in the year ended December 31, 2018. On December 20, 2019, we repaid $300.0 million of outstanding borrowings and terminated the 2015 Credit Facility.
2017 Credit Facility
On December 21, 2017, Noble Cayman Limited, a Cayman Islands company and a wholly-owned indirect subsidiary of Noble-Cayman; Noble International Finance Company, a Cayman Islands company and a wholly-owned indirect subsidiary of Noble-Cayman; and Noble Holding UK Limited, a company incorporated under the laws of England and Wales and a wholly-owned direct subsidiary of Noble-UK (“NHUK”), as parent guarantor, entered into a new senior unsecured credit agreement (as amended, the “2017 Credit Facility” and, together with the 2015 Credit Facility, the “Credit Facilities”). In July 2019, we executed an amendment to our 2017 Credit Facility (the “First Amendment to the 2017 Credit Facility”), which, among other things, reduced the maximum aggregate amount of commitments thereunder from $1.5 billion to $1.3 billion. As a result of such reduction in the maximum aggregate amount of commitments, we recognized a net loss of approximately $0.7 million in the year ended December 31, 2019. Borrowings under the 2017 Credit Facility are subject to certain conditions precedent to advance loans. The First Amendment to the 2017 Credit Facility added a requirement that any amounts drawn under the 2017 Credit Facility plus any undrawn amounts needed to cause us to be in compliance with the $300.0 million Liquidity (as defined in the First Amendment to the 2017 Credit Facility) covenant not exceed the amount of the Indenture Secured Debt Basket (as defined in the First Amendment to the 2017 Credit Facility) at the time of each borrowing. The maximum aggregate amount of commitments under the 2017 Credit Facility on December 31, 2019 was $1.3 billion with approximately $660 million available to borrow. The First Amendment to the 2017 Credit Facility also replaced the debt to capitalization ratio financial covenant with a Senior Guaranteed Indebtedness to Adjusted EBITDA (each as defined in the First Amendment to the 2017 Credit Facility) ratio financial covenant, as described below.
The 2017 Credit Facility will mature in January 2023. Borrowings may be used for working capital and other general corporate purposes. The 2017 Credit Facility provides for a letter of credit sub-facility currently in the amount of $15.0 million, with the ability to increase such amount up to $500.0 million with the approval of the lenders. Borrowings under the 2017 Credit Facility bear interest at LIBOR plus an applicable margin, which is currently the maximum contractual rate of 4.25%. At December 31, 2019, we had $335.0 million of borrowings outstanding under the 2017 Credit Facility.
At December 31, 2019, we had $9.0 million of letters of credit issued under the 2017 Credit Facility and an additional $12.3 million in letters of credit and surety bonds issued under unsecured bilateral arrangements.
Both of our Credit Facilities had or have provisions which vary the applicable interest rates for borrowings based upon our debt ratings. We also paid a facility fee under the 2015 Credit Facility on the full commitments thereunder (used or unused) and pay a commitment fee under the 2017 Credit Facility on the daily unused amount of the underlying commitments, in each case which varies depending on our credit ratings. At December 31, 2019, the interest rates in effect under our 2017 Credit Facility were the highest permitted interest rates under that agreement.
Debt Issuance
In January 2018, we issued $750.0 million aggregate principal amount of the 2026 Notes through our indirect wholly-owned subsidiary, NHIL. The net proceeds of the offering of approximately $737.4 million, after expenses, were used to retire a portion of our near-term senior notes in a related tender offer.
The indenture for the 2026 Notes contains certain covenants and restrictions, including, among others, restrictions on our subsidiaries’ ability to incur certain additional indebtedness. Additionally, the subsidiary guarantors must own, directly or indirectly, (i) assets comprising at least 85% of the revenue of Noble-Cayman and its subsidiaries on a consolidated basis and (ii) jackups, semisubmersibles, drillships, submersibles or other mobile offshore drilling units of material importance, the combined book value of which comprises at least 85% of the combined book value of all such assets of Noble-Cayman and its subsidiaries on a consolidated basis, in each case, with respect to the most recently completed fiscal year.
Seller Loans
2019 Seller Loan
In February 2019, we purchased the Noble Joe Knight for $83.8 million with a $53.6 million seller-financed secured loan (the “2019 Seller Loan”). The 2019 Seller Loan has a term of four years and requires a 5% principal payment at the end of the third year with the remaining 95% of the principal due at the end of the term. The 2019 Seller Loan bears a cash interest rate of 4.25% and the equivalent of a 1.25% interest rate paid-in-kind over the four-year term of the 2019 Seller Loan. Based on the terms of the 2019 Seller Loan, the 1.25% paid-in-kind interest rate is accelerated into the first year, resulting in an overall first year interest rate of 8.91%, of which only 4.25% is payable in cash. Thereafter, the paid-in-kind interest ends and the cash interest rate of 4.25% is payable for the remainder of the term.
2018 Seller Loan
In September 2018, we purchased the Noble Johnny Whitstine for $93.8 million with a $60.0 million seller-financed secured loan (the “2018 Seller Loan” and, together with the 2019 Seller Loan, the “Seller Loans”). The 2018 Seller Loan has a term of four years and requires a 5% principal payment at the end of the third year with the remaining 95% of the principal due at the end of the term. The 2018 Seller Loan bears a cash interest rate of 4.25% and the equivalent of a 1.25% interest rate paid-in-kind over the four-year term of the 2018 Seller Loan. Based on the terms of the 2018 Seller Loan, the 1.25% paid-in-kind interest rate is accelerated into the first year, resulting in an overall first year interest rate of 8.91%, of which only 4.25% is payable in cash. Thereafter, the paid-in-kind interest ends and the cash interest rate of 4.25% is payable for the remainder of the term.
Both of the Seller Loans are guaranteed by Noble-Cayman and each is secured by a mortgage on the applicable rig and by the pledge of the shares of the applicable single-purpose entity that owns the relevant rig. Each Seller Loan contains a debt to total capitalization ratio requirement that such ratio not exceed 0.55 at the end of each fiscal quarter, a $300.0 million minimum liquidity financial covenant and an asset and revenue covenant substantially similar to the 2026 Notes, as well as other covenants and provisions customarily found in secured transactions, including a cross default provision. Each Seller Loan requires immediate repayment on the occurrence of certain events, including the termination of the drilling contract associated with the relevant rig or circumstances in connection with a material adverse effect.
Senior Notes Interest Rate Adjustments
Our Senior Notes due 2025 and our Senior Notes due 2045 are subject to provisions that vary the applicable interest rates based on our debt rating. Effective April 2018, these senior notes have reached the contractually defined maximum interest rate set for each rating agency and no further interest rate increases are possible. The interest rates on these senior notes may be decreased if our debt ratings were to be raised by either rating agency above specified levels. Our other outstanding senior notes do not contain provisions varying applicable interest rates based upon our credit ratings.
Debt Tender Offers, Repayments and Open Market Repurchases
In March 2019, we completed cash tender offers for the 2020 Notes, the 2021 Notes, the 2022 Notes, and the 2024 Notes. Pursuant to such tender offers, we purchased $440.9 million aggregate principal amount of these senior notes for $400.0 million, plus accrued interest, using cash on hand and borrowings under the 2015 Credit Facility. As a result of this transaction, we recognized a net gain of approximately $31.3 million.
In October 2018, we purchased $27.4 million aggregate principal amount of various tranches of our senior notes for approximately $20.2 million, plus accrued interest, as open market repurchases and recognized a net gain of approximately $6.9 million.
In August 2018, we purchased $0.4 million aggregate principal amount of our Senior Notes due 2042 for approximately $0.3 million, plus accrued interest, as open market repurchases and recognized a net gain of approximately $0.1 million.
In March 2018, we repaid the remaining aggregate principal amount of $126.6 million of our Senior Notes due 2018 (the “2018 Notes”) at maturity using cash on hand.
In March 2018, we purchased $9.5 million aggregate principal amount of various tranches of our senior notes for approximately $8.7 million, plus accrued interest, as open market repurchases and recognized a net gain of approximately $0.5 million.
In February 2018, we redeemed the remaining principal amount of $61.9 million of our Senior Notes due 2019 (the “2019 Notes”) for approximately $65.3 million, plus accrued interest. As a result of this transaction, we recognized a net loss of approximately $3.5 million.
In February 2018, we completed cash tender offers for the 2018 Notes, the 2019 Notes, the 2020 Notes, the 2021 Notes, the 2022 Notes and the 2024 Notes. Pursuant to such tender offers, we purchased $754.2 million aggregate principal amount of these senior notes for $750.0 million, plus accrued interest, using the net proceeds of the 2026 Notes issuance and cash on hand. As a result of this transaction, we recognized a net loss of approximately $3.5 million.
Covenants
At December 31, 2019, the 2017 Credit Facility contained certain financial covenants applicable to NHUK and its subsidiaries, including (i) a covenant that limits our ratio of Senior Guaranteed Indebtedness to Adjusted EBITDA as of the last day of each fiscal quarter, with such ratio not being permitted to exceed 4.0 to 1.0 for the fiscal quarters ending September 30, 2019 through December 31, 2020, 3.5 to 1.0 for the fiscal quarters ending March 31, 2021 through December 31, 2021 and 3.0 to 1.0 for the fiscal quarters ending March 31, 2022 and thereafter, (ii) a minimum Liquidity requirement of $300.0 million, (iii) a covenant that the ratio of the Rig Value (as defined in the 2017 Credit Facility) of Marketed Rigs (as defined in the 2017 Credit Facility) to the sum of commitments under the 2017 Credit Facility plus indebtedness for borrowed money of the borrowers and guarantors, in each case, that directly own Marketed Rigs, is not less than 3:00 to 1:00 at the end of each fiscal quarter and (iv) a covenant that the ratio of (A) the Rig Value of the Closing Date Rigs (as defined in the 2017 Credit Facility) that are directly wholly owned by the borrowers and guarantors to (B) the Rig Value of the Closing Date Rigs owned by NHUK, subsidiaries of NHUK and certain local content affiliates, is not less than 80% at the end of each fiscal quarter (such covenants described in (iii) and (iv) of this paragraph, the “Guarantor Ratio Covenants”). The 2017 Credit Facility also includes restrictions on borrowings if, after giving effect to any such borrowings and the application of the proceeds thereof, the aggregate amount of Available Cash (as defined in the 2017 Credit Facility) would exceed $200.0 million and a requirement that any amounts drawn under the 2017 Credit Facility plus any undrawn amounts needed to cause us to be in compliance with the $300.0 million Liquidity covenant not exceed the amount of the Indenture Secured Debt Basket at the time of each borrowing. As of February 18, 2020, we had $335 million of borrowings outstanding under the 2017 Credit Facility, and we would have been able to borrow a maximum of an additional approximately $660 million thereunder.
NHUK has guaranteed the obligations of the borrowers under the 2017 Credit Facility. In addition, certain indirect subsidiaries of Noble-UK that own rigs are guarantors under the 2017 Credit Facility. Certain other subsidiaries of Noble-UK may be required from time to time to guarantee the obligations of the borrowers under the 2017 Credit Facility in order maintain compliance with the Guarantor Ratio Covenants.
The 2017 Credit Facility contains additional restrictive covenants generally applicable to NHUK and its subsidiaries, including restrictions on the incurrence of liens and indebtedness, mergers and other fundamental changes, restricted payments, repurchases and redemptions of indebtedness with maturities outside of the maturity of the 2017 Credit Facility, sale and leaseback transactions and transactions with affiliates.
In addition to the covenants from the 2017 Credit Facility noted above, the covenants from the 2026 Notes described under “-Debt Issuance” above and the covenants from the Seller Loans described under “-Seller Loans” above, the indentures governing our outstanding senior unsecured notes contain covenants that place restrictions on certain merger and consolidation transactions, unless we are the surviving entity or the other party assumes the obligations under the indenture, and on the ability to sell or transfer all or substantially all of our assets. There are also restrictions on incurring or assuming certain liens and on entering into sale and lease-back transactions.
At December 31, 2019, our debt to total tangible capitalization ratio under our Seller Loans was approximately 0.50 and we were in compliance with all applicable debt covenants. We continually monitor compliance with the covenants under our 2017 Credit Facility, senior notes and Seller Loans, and expect to remain in compliance throughout 2020.
Summary of Contractual Cash Obligations and Commitments
The following table summarizes our contractual cash obligations and commitments (in thousands):
(1)
Tax reserves are included in “Other” due to the difficulty in making reasonably reliable estimates of the timing of cash settlements to taxing authorities. See Part II, Item 8, “Financial Statements and Supplementary Data, Note 12- Income Taxes.”
At December 31, 2019, we had other commitments that we are contractually obligated to fulfill with cash if the obligations are called. These obligations include letters of credit that guarantee our performance as it relates to our drilling contracts, tax and other obligations in various jurisdictions. These letters of credit obligations are not normally called, as we typically comply with the underlying performance requirement.
The following table summarizes our other commercial commitments at December 31, 2019 (in thousands):
Critical Accounting Policies
We consider the following to be our critical accounting policies and estimates since they are very important to the understanding of our financial condition and results and require our most subjective and complex judgments. We have discussed the development, selection and disclosure of such policies and estimates with the Audit Committee of our Board of Directors. For a discussion of our significant accounting policies, refer to Part II, Item 8, “Financial Statements and Supplementary Data, Note 1- Organization and Significant Accounting Policies.”
We prepare our consolidated financial statements in accordance with accounting principles generally accepted in the United States (“GAAP”), which require us to make estimates that affect the reported amounts of assets, liabilities, revenues, expenses and related disclosures of contingent assets and liabilities. These estimates require significant judgments and assumptions. We base our estimates on historical experience and on various other assumptions that we believe are reasonable under the circumstances, the results of which form the basis for making judgments about the carrying amounts of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates.
Principles of Consolidation
The consolidated financial statements include our accounts and those of our wholly-owned subsidiaries and entities in which we hold a controlling financial interest. Until December 3, 2019, our consolidated financial statements included the accounts of two joint ventures, in each of which we owned a 50 percent interest. On December 3, 2019, we acquired the remaining 50 percent interest not owned by us and as a result the two joint ventures became our wholly-owned subsidiaries. Our historical ownership interest in the joint ventures met the definition of variable interest under Financial Accounting Standards Board (“FASB”) codification and we determined that we were the primary beneficiary. Intercompany balances and transactions have been eliminated in consolidation.
The combined carrying amount of the Bully-class drillships at December 31, 2018 totaled $0.7 billion. These assets were primarily funded through partner equity contributions. Cash held by the Bully joint ventures totaled approximately $45.2 million at December 31, 2018.
Basis of Presentation-UK Companies Act 2006 Section 435 Statement
The accompanying consolidated financial statements have been prepared in accordance with GAAP, which the Board of Directors considers to be the most meaningful presentation of our results of operations and financial position. The accompanying consolidated financial statements do not constitute statutory accounts required by the UK Companies Act 2006 (“Companies Act”), which will be prepared in accordance with International Financial Reporting Standards, as adopted by the European Union and delivered to the Registrar of Companies in the UK following the annual general meeting of shareholders.
Property and Equipment
Property and equipment is stated at cost, reduced by provisions to recognize economic impairment in value whenever events or changes in circumstances indicate an asset’s carrying value may not be recoverable. At December 31, 2019 and 2018, we had $88.9 million and $209.1 million of construction-in-progress, respectively. Such amounts are included in “Property and equipment, at cost” in the accompanying Consolidated Balance Sheets. Major replacements and improvements are capitalized. When assets are sold, retired or otherwise disposed of, the cost and related accumulated depreciation are eliminated from the accounts and the gain or loss is recognized. Drilling equipment and facilities are depreciated using the straight-line method over their estimated useful lives as of the date placed in service or date of major refurbishment. Estimated useful lives of our drilling equipment range from three to thirty years. Other property and equipment is depreciated using the straight-line method over useful lives ranging from two to forty years.
Interest is capitalized on construction-in-progress using the weighted average cost of debt outstanding during the period of construction. During the years ended December 31, 2019, 2018 and 2017, there was $9.6 million, $2.9 million and zero capitalized interest, respectively.
Scheduled maintenance of equipment is performed based on the number of hours operated in accordance with our preventative maintenance program. Routine repair and maintenance costs are charged to expense as incurred; however, the costs of the overhauls and asset replacement projects that benefit future periods and which typically occur every three to five years are capitalized when incurred and depreciated over an equivalent period. These overhauls and asset replacement projects are included in “Property and equipment, at cost” in the Consolidated Balance Sheets. Such amounts, net of accumulated depreciation, totaled $143.4 million and $146.3 million at December 31, 2019 and 2018, respectively. Depreciation expense from continuing operations related to overhauls and asset replacement totaled $61.3 million, $66.9 million and $79.2 million for the years ended December 31, 2019, 2018 and 2017, respectively.
We evaluate the impairment of property and equipment whenever events or changes in circumstances (including the decision to cold stack, retire or sell a rig) indicate that the carrying amount of an asset may not be recoverable. An impairment loss on our property and equipment may exist when the estimated undiscounted cash flows expected to result from the use of the asset and its eventual disposition are less than its carrying amount. Any impairment loss recognized represents the excess of the asset's carrying value over the estimated fair value. As part of this analysis, we make assumptions and estimates regarding future market conditions. To the extent actual results do not meet our estimated assumptions, for a given rig or piece of equipment, we may take an impairment loss in the future.
During the years ended December 31, 2019, 2018 and 2017, we recognized a non-cash loss on impairment of $615.3 million, $802.1 million and $121.6 million, respectively, related to our long-lived assets. See Part II, Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations- Executive Overview,” and Part II, Item 8, “Financial Statements and Supplementary Data, Note 6- Loss on Impairment” for additional information.
Revenue Recognition
The activities that primarily drive the revenue earned in our drilling contracts include (i) providing a drilling rig and the crew and supplies necessary to operate the rig, (ii) mobilizing and demobilizing the rig to and from the drill site, and (iii) performing rig preparation activities and/or modifications required for the contract. Consideration received for performing these activities may consist of dayrate drilling revenue, mobilization and demobilization revenue, contract preparation revenue and reimbursement revenue. We account for these integrated services provided within our drilling contracts as a single performance obligation satisfied over time and comprised of a series of distinct time increments in which we provide drilling services.
Our standard drilling contracts require that we operate the rig at the direction of the customer throughout the contract term (which is the period we estimate to benefit from the corresponding activities and generally ranges from two to 60 months). The activities performed and the level of service provided can vary hour to hour. Our obligation under a standard contract is to provide whatever level of service is required by the operator, or customer, over the term of the contract. We are, therefore, under a stand-ready obligation throughout the entire contract duration. Consideration for our stand-ready obligation corresponds to distinct time increments, though the rate may be variable depending on various factors, and is recognized in the period in which the services are performed. The total transaction price is determined for each individual contract by estimating both fixed and variable consideration expected to be earned over the term of the contract. We have elected to exclude from the transaction
price measurement all taxes assessed by a governmental authority. See further discussion regarding the allocation of the transaction price to the remaining performance obligations below.
The amount estimated for variable consideration may be subject to interrupted or restricted rates and is only included in the transaction price to the extent that it is probable that a significant reversal of previously recognized revenue will not occur throughout the term of the contract (“constrained revenue”). When determining if variable consideration should be constrained, management considers whether there are factors outside the Company’s control that could result in a significant reversal of revenue as well as the likelihood and magnitude of a potential reversal of revenue. These estimates are re-assessed each reporting period as required.
Dayrate Drilling Revenue. Our drilling contracts generally provide for payment on a dayrate basis, with higher rates for periods when the drilling unit is operating and lower rates or zero rates for periods when drilling operations are interrupted or restricted. The dayrate invoices billed to the customer are typically determined based on the varying rates applicable to the specific activities performed on an hourly basis. Such dayrate consideration is allocated to the distinct hourly increment it relates to within the contract term, and therefore, recognized in line with the contractual rate billed for the services provided for any given hour.
Mobilization/Demobilization Revenue. We may receive fees (on either a fixed lump-sum or variable dayrate basis) for the mobilization and demobilization of our rigs. These activities are not considered to be distinct within the context of the contract and, therefore, the associated revenue is allocated to the overall performance obligation and the associated pre-operating costs are deferred. We record a contract liability for mobilization fees received and a deferred asset for costs. Both revenue and pre-operating costs are recognized ratably over the initial term of the related drilling contract.
In most contracts, there is uncertainty as to the amount of expected demobilization revenue due to contractual provisions that stipulate that certain conditions must be present at contract completion for such revenue to be received and as to the amount thereof, if any. For example, contractual provisions may require that a rig demobilize a certain distance before the demobilization revenue is payable or the amount may vary dependent upon whether or not the rig has additional contracted work within a certain distance from the wellsite. Therefore, the estimate for such revenue may be constrained, as described earlier, depending on the facts and circumstances pertaining to the specific contract. We assess the likelihood of receiving such revenue based on past experience and knowledge of the market conditions. In cases where demobilization revenue is expected to be received upon contract completion, it is estimated as part of the overall transaction price at contract inception and recognized in earnings ratably over the initial term of the contract with an offset to an accretive contract asset.
Contract Preparation Revenue. Some of our drilling contracts require downtime before the start of the contract to prepare the rig to meet customer requirements. At times, we may be compensated by the customer for such work (on either a fixed lump-sum or variable dayrate basis). These activities are not considered to be distinct within the context of the contract and, therefore, the related revenue is allocated to the overall performance obligation and recognized ratably over the initial term of the related drilling contract. We record a contract liability for contract preparation fees received, which is amortized ratably to contract drilling revenue over the initial term of the related drilling contract.
Bonuses, Penalties and Other Variable Consideration. We may receive bonus increases to revenue or penalty decreases to revenue. Based on historical data and ongoing communication with the operator/customer, we are able to reasonably estimate this variable consideration. We will record such estimated variable consideration and re-measure our estimates at each reporting date. For revenue estimated, but not received, we will record to “Prepaid expenses and other current assets” on our Consolidated Balance Sheets.
Capital Modification Revenue. From time to time, we may receive fees from our customers for capital improvements to our rigs to meet contractual requirements (on either a fixed lump-sum or variable dayrate basis). Such revenue is allocated to the overall performance obligation and recognized ratably over the initial term of the related drilling contract as these activities are integral to our drilling activities and are not considered to be a stand-alone service provided to the customer within the context of our contracts. We record a contract liability for such fees and recognize them ratably as contract drilling revenue over the initial term of the related drilling contract.
Revenues Related to Reimbursable Expenses. We generally receive reimbursements from our customers for the purchase of supplies, equipment, personnel services and other services provided at their request in accordance with a drilling contract or other agreement. Such reimbursable revenue is variable and subject to uncertainty, as the amounts received and timing thereof is highly dependent on factors outside of our influence. Accordingly, reimbursable revenue is constrained revenue and not included in the total transaction price until the uncertainty is resolved, which typically occurs when the related costs are incurred on behalf of a customer. We are generally considered a principal in such transactions and record the associated revenue at the gross amount billed to the customer as “Reimbursables and other” in our Consolidated Statements of Operations. Such amounts are recognized ratably over the period within the contract term during which the corresponding goods and services are to be consumed.
Deferred revenues from drilling contracts totaled $65.1 million and $80.8 million at December 31, 2019 and 2018, respectively. Such amounts are included in either “Other current liabilities” or “Other liabilities” in the accompanying Consolidated Balance Sheets, based upon our expected time of recognition. Related expenses deferred under drilling contracts totaled $30.8 million at December 31, 2019 as compared to $47.7
million at December 31, 2018 and are included in either “Prepaid expenses and other current assets,” “Other assets,” or “Property and equipment, net” in the accompanying Consolidated Balance Sheets, based upon our expected time of recognition.
We record reimbursements from customers for “out-of-pocket” expenses as revenues and the related direct cost as operating expenses.
Income Taxes
We currently operate, and have in the past operated, in a number of countries throughout the world and our tax returns filed in those jurisdictions are subject to review and examination by tax authorities within those jurisdictions. We recognize uncertain tax positions that we believe have a greater than 50 percent likelihood of being sustained upon challenge by a tax authority. We cannot predict or provide assurance as to the ultimate outcome of any existing or future assessments. Our net deferred tax asset balance at year-end reflects the application of our income tax accounting policies and is based on management’s estimates, judgments and assumptions regarding realizability. If it is more likely than not that a portion of the deferred tax assets will not be realized in a future period, the deferred tax assets will be reduced by a valuation allowance based on management’s estimates. The Company has adopted an accounting policy to look through the outside basis of partnerships and all other flow-through entities and exclude these from the computation of deferred taxes.
The Internal Revenue Service (“IRS”) has completed its examination procedures including all appeals and administrative reviews for the taxable years ended December 31, 2010 and 2011. In June 2019, the IRS examination team notified us that it was no longer proposing any adjustments with respect to our tax reporting for the taxable years ended December 31, 2010 and December 31, 2011. During the third quarter of 2017, the IRS initiated its examination of our 2012, 2013, 2014 and 2015 tax returns. In October 2019, we received a notice that the IRS added our 2016 and 2017 tax returns to its examination. We believe that we have accurately reported all amounts in our 2012, 2013, 2014, 2015, 2016 and 2017 tax returns.
Audit claims of approximately $74.0 million attributable to income and other business taxes were assessed against Noble entities in Mexico related to tax years 2005 and 2007 and in Australia related to tax years 2013 to 2016. We intend to vigorously defend our reported positions, and believe the ultimate resolution of the audit claims will not have a material adverse effect on our consolidated financial statements.
Insurance Reserves
We maintain various levels of self-insured retention for certain losses including property damage, loss of hire, employment practices liability, employers’ liability and general liability, among others. We accrue for property damage and loss of hire charges on a per event basis.
Employment practices liability claims are accrued based on actual claims during the year. Maritime employer’s liability claims are generally estimated using actuarial determinations. General liability claims are estimated by our internal claims department by evaluating the facts and circumstances of each claim (including incurred but not reported claims) and making estimates based upon historical experience with similar claims. At December 31, 2019 and 2018, loss reserves for personal injury and protection claims totaled $27.9 million and $22.4 million, respectively, and such amounts are included in “Other current liabilities” in the accompanying Consolidated Balance Sheets.
Certain Significant Estimates and Contingent Liabilities
The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amount of revenues and expenses during the reporting period. Certain accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. We evaluate our estimates and assumptions on a regular basis. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates and assumptions used in preparation of our consolidated financial statements. We follow FASB standards regarding contingent liabilities, which are discussed in Part II, Item 8, “Financial Statements and Supplementary Data, Note 16- Commitments and Contingencies.”
Off-Balance Sheet Arrangements
We have no off-balance sheet arrangements as that term is defined in Item 303(a)(4)(ii) of Regulation S-K.
New Accounting Pronouncements
See Part II, Item 8, “Financial Statements and Supplementary Data, Note 1- Organization and Significant Accounting Policies” for a description of the recent accounting pronouncements.
Item 7A.
Item 7A. Quantitative and Qualitative Disclosures about Market Risk.
Market risk is the potential for loss due to a change in the value of a financial instrument as a result of fluctuations in interest rates, currency exchange rates or equity prices, as further described below.
Interest Rate Risk
We are subject to market risk exposure related to changes in interest rates on borrowings under the 2017 Credit Facility. Interest on borrowings under our 2017 Credit Facility is at an agreed upon percentage point spread over LIBOR, or a base rate stated in the agreements. Borrowings under the 2017 Credit Facility bear interest at LIBOR plus an applicable margin, which is currently the maximum contractual rate of 4.25%. At December 31, 2019, we had $335.0 million of borrowings outstanding under the 2017 Credit Facility, plus $9.0 million of performance letters of credit.
Our Senior Notes due 2025 and our Senior Notes due 2045 are subject to provisions that vary the applicable interest rates based on our debt rating. Effective April 2018, these senior notes have reached the contractually defined maximum interest rate set for each rating agency and no further interest rate increases are possible. The interest rates on these senior notes may be decreased if our debt ratings were to be raised by either rating agency above specified levels. Our other outstanding senior notes do not contain provisions varying applicable interest rates based upon our credit ratings.
We maintain certain debt instruments at a fixed rate whose fair value will fluctuate based on changes in market expectations for interest rates and perceptions of our credit risk. The fair value of our total debt was $2.2 billion and $2.9 billion at December 31, 2019 and December 31, 2018, respectively. The decrease in the fair value of debt relates to changes in market expectations for interest rates and perceptions of our credit risk and a reduction in total principal amount outstanding due to our debt repayments during 2019, partially offset by the issuance of the 2019 Seller Loan and draws on our Credit Facilities during 2019.
Foreign Currency Risk
Although we are a UK company, we define foreign currency as any non-US denominated currency. Our functional currency is the US Dollar. However, outside the United States, a portion of our expenses are incurred in local currencies. Therefore, when the US Dollar weakens (strengthens) in relation to the currencies of the countries in which we operate, our expenses reported in US Dollars will increase (decrease).
We are exposed to risks on future cash flows to the extent that local currency expenses exceed revenues denominated in local currency that are other than the functional currency. To help manage this potential risk, we periodically enter into derivative instruments to manage our exposure to fluctuations in currency exchange rates, and we may conduct hedging activities in future periods to mitigate such exposure. These contracts are primarily accounted for as cash flow hedges, with the effective portion of changes in the fair value of the hedge recorded on the Consolidated Balance Sheets and in “Accumulated other comprehensive income (loss)” (“AOCI”). Amounts recorded in AOCI are reclassified into earnings in the same period or periods that the hedged item is recognized in earnings. The ineffective portion of changes in the fair value of the hedged item is recorded directly to earnings. We have documented policies and procedures to monitor and control the use of derivative instruments. We do not engage in derivative transactions for speculative or trading purposes, nor are we a party to leveraged derivatives.
Several of our regional shorebases have a significant amount of their cash operating expenses payable in local currencies. To limit the potential risk of currency fluctuations, we periodically enter into forward contracts, which have historically settled monthly in the operations’ respective local currencies. All of these contracts had a maturity of less than 12 months. During 2019 and 2018, we entered into forward contracts of approximately $15.8 million and zero, respectively, all of which settled during their respective years. At both December 31, 2019 and 2018, we had no outstanding derivative contracts.
Market Risk
We have a US noncontributory defined benefit pension plan that covers certain salaried employees and a US noncontributory defined benefit pension plan that covers certain hourly employees, whose initial date of employment is prior to August 1, 2004 (collectively referred to as our “qualified US plans”). These plans are governed by the Noble Drilling Employees’ Retirement Trust. The benefits from these plans are based primarily on years of service and, for the salaried plan, employees’ compensation near retirement. These plans are designed to qualify under the Employee Retirement Income Security Act of 1974 (“ERISA”), and our funding policy is consistent with funding requirements of ERISA and other applicable laws and regulations. We make cash contributions, or utilize credits available to us, for the qualified US plans when required. The benefit amount that can be covered by the qualified US plans is limited under ERISA and the Internal Revenue Code of 1986. Therefore, we maintain an unfunded, nonqualified excess benefit plan designed to maintain benefits for specified employees at the formula level in the qualified salary US plan. We refer to the qualified US plans and the excess benefit plan collectively as the “US plans.”
In addition to the US plans, Noble Drilling (Land Support) Limited, an indirect, wholly-owned subsidiary of Noble-UK, maintains a pension plan that covers all of its salaried, non-union employees, whose most recent date of employment is prior to April 1, 2014 (referred to as our “non-US plan”). Benefits are based on credited service and employees’ compensation, as defined by the non-US plan.
Changes in market asset values related to the pension plans noted above could have a material impact upon our Consolidated Statements of Comprehensive Income (Loss) and could result in material cash expenditures in future periods.
Item 8.
Item 8. Financial Statements and Supplementary Data.
The following financial statements are filed in this Item 8:
Report of Independent Registered Public Accounting Firm
To the Board of Directors and
Shareholders of Noble Corporation plc:
Opinions on the Financial Statements and Internal Control over Financial Reporting
We have audited the accompanying consolidated balance sheets of Noble Corporation plc and its subsidiaries (the “Company”) as of December 31, 2019 and 2018, and the related consolidated statements of operations, comprehensive income (loss), cash flows and equity for each of the three years in the period ended December 31, 2019, including the related notes (collectively referred to as the “consolidated financial statements”). We also have audited the Company's internal control over financial reporting as of December 31, 2019, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”).
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2019 and 2018, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2019 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2019, based on criteria established in Internal Control - Integrated Framework (2013) issued by the COSO.
Basis for Opinions
The Company's management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Annual Report on Internal Control Over Financial Reporting appearing under Item 9A. Our responsibility is to express opinions on the Company’s consolidated financial statements and on the Company’s internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (“PCAOB”) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.
Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
Definition and Limitations of Internal Control over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
We have served as the Company’s auditor since 1994.
NOBLE CORPORATION PLC AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Unless otherwise indicated, dollar amounts in tables are in thousands, except per share data)
See accompanying notes to the consolidated financial statements.
NOBLE CORPORATION PLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(Unless otherwise indicated, dollar amounts in tables are in thousands, except per share data)
See accompanying notes to the consolidated financial statements.
NOBLE CORPORATION PLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(Unless otherwise indicated, dollar amounts in tables are in thousands)
See accompanying notes to the consolidated financial statements.
NOBLE CORPORATION PLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unless otherwise indicated, dollar amounts in tables are in thousands)
See accompanying notes to the consolidated financial statements.
NOBLE CORPORATION PLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF EQUITY
(Unless otherwise indicated, dollar amounts in tables are in thousands)
(1)
Activity associated with dividend equivalents, which are related to 2016 performance awards to be paid upon vesting.
See accompanying notes to the consolidated financial statements.
Report of Independent Registered Public Accounting Firm
To the Board of Directors and
Shareholder of Noble Corporation:
Opinions on the Financial Statements and Internal Control over Financial Reporting
We have audited the accompanying consolidated balance sheets of Noble Corporation and its subsidiaries (the “Company”) as of December 31, 2019 and 2018, and the related consolidated statements of operations, comprehensive income (loss), cash flows and equity for each of the three years in the period ended December 31, 2019, including the related notes (collectively referred to as the “consolidated financial statements”). We also have audited the Company's internal control over financial reporting as of December 31, 2019, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”).
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2019 and 2018, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2019 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2019, based on criteria established in Internal Control - Integrated Framework (2013) issued by the COSO.
Basis for Opinions
The Company's management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Annual Report on Internal Control Over Financial Reporting appearing under Item 9A. Our responsibility is to express opinions on the Company’s consolidated financial statements and on the Company’s internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (“PCAOB”) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.
Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
Definition and Limitations of Internal Control over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
We have served as the Company’s auditor since 1994.
NOBLE CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Unless otherwise indicated, dollar amounts in tables are in thousands, except per share data)
See accompanying notes to the consolidated financial statements.
NOBLE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(Unless otherwise indicated, dollar amounts in tables are in thousands, except per share data)
See accompanying notes to the consolidated financial statements.
NOBLE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(Unless otherwise indicated, dollar amounts in tables are in thousands)
See accompanying notes to the consolidated financial statements.
NOBLE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unless otherwise indicated, dollar amounts in tables are in thousands)
See accompanying notes to the consolidated financial statements.
NOBLE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF EQUITY
(Unless otherwise indicated, dollar amounts in tables are in thousands)
See accompanying notes to the consolidated financial statements.
NOBLE CORPORATION PLC AND SUBSIDIARIES
NOBLE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unless otherwise indicated, dollar amounts in tables are in thousands)
Note 1- Organization and Significant Accounting Policies
Noble Corporation plc, a public limited company incorporated under the laws of England and Wales (“Noble-UK”), is a leading offshore drilling contractor for the oil and gas industry. We provide contract drilling services to the international oil and gas industry with our global fleet of mobile offshore drilling units. As of December 31, 2019, our fleet of 25 drilling rigs consisted of 12 floaters and 13 jackups.
We report our contract drilling operations as a single reportable segment, Contract Drilling Services, which reflects how we manage our business. The mobile offshore drilling units comprising our offshore rig fleet operate in a global market for contract drilling services and are often redeployed to different regions due to changing demands of our customers, which consist primarily of large, integrated, independent and government-owned or controlled oil and gas companies throughout the world.
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.
Beginning in 2019, we combined the semisubmersibles and drillships in our contract drilling services fleet into a single category, floaters, for reporting purposes. We have made certain reclassifications to prior year so as to conform to such current period presentation. The reclassification did not have a material effect on our Condensed Consolidated Statements of Operations or related disclosures.
Principles of Consolidation
The consolidated financial statements include our accounts and those of our wholly-owned subsidiaries and entities in which we hold a controlling financial interest. Until December 3, 2019 our consolidated financial statements included the accounts of two joint ventures, in each of which we owned a 50 percent interest. On December 3, 2019, we acquired the remaining 50 percent interest not owned by us and as a result the two joint ventures became our wholly-owned subsidiaries. Our historical ownership interest in the joint ventures met the definition of variable interest under Financial Accounting Standards Board (“FASB”) codification and we determined that we were the primary beneficiary. Intercompany balances and transactions have been eliminated in consolidation.
The combined carrying amount of the Bully-class drillships at December 31, 2018 totaled $0.7 billion. These assets were primarily funded through partner equity contributions. Cash held by the Bully joint ventures totaled approximately $45.2 million at December 31, 2018.
Foreign Currency Translation
Although we are a UK company, our functional currency is the US dollar, and we define any non-US dollar denominated currency as “foreign currencies.” In non-US locations where the US Dollar has been designated as the functional currency (based on an evaluation of factors including the markets in which the subsidiary operates, inflation, generation of cash flow, financing activities and intercompany arrangements), local currency transaction gains and losses are included in net income or loss. In non-US locations where the local currency is the functional currency, assets and liabilities are translated at the rates of exchange on the balance sheet date, while statement of operations items are translated at average rates of exchange during the year. The resulting gains or losses arising from the translation of accounts from the functional currency to the US Dollar are included in “Accumulated other comprehensive loss” in the Consolidated Balance Sheets. We did not recognize any material gains or losses on foreign currency transactions or translations during the three years ended December 31, 2019.
Cash and Cash Equivalents
Cash and cash equivalents include cash on hand, demand deposits with banks and all highly liquid investments with original maturities of three months or less. Our cash, cash equivalents and short-term investments are subject to potential credit risk, and certain of our cash accounts carry balances greater than the federally insured limits. Cash and cash equivalents are primarily held by major banks or investment firms. Our cash management and investment policies restrict investments to lower risk, highly liquid securities and we perform periodic evaluations of the relative credit standing of the financial institutions with which we conduct business.
NOBLE CORPORATION PLC AND SUBSIDIARIES
NOBLE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unless otherwise indicated, dollar amounts in tables are in thousands)
Restricted Cash
We classify restricted cash balances in current assets if the restriction is expected to expire or otherwise be resolved within one year and in other assets if the restriction is expected to expire or otherwise be resolved in more than one year. As of December 31, 2019 and 2018, our restricted cash balance consisted of $1.3 million and $0.7 million, respectively, associated with our financing of the Noble Johnny Whitstine and Noble Joe Knight, recorded in Prepaid expenses and other current assets.
Accounts Receivable
We record accounts receivable at the amount we invoice our clients, net of allowance for doubtful accounts. We provide an allowance for uncollectible accounts, as necessary. Our allowance for doubtful accounts as of December 31, 2019 and 2018 was $1.9 million and $2.2 million, respectively.
Property and Equipment
Property and equipment is stated at cost, reduced by provisions to recognize economic impairment. Major replacements and improvements are capitalized. When assets are sold, retired or otherwise disposed of, the cost and related accumulated depreciation are eliminated from the accounts and the gain or loss is recognized. Drilling equipment and facilities are depreciated using the straight-line method over their estimated useful lives as of the date placed in service or date of major refurbishment. Estimated useful lives of our drilling equipment range from three to thirty years. Other property and equipment is depreciated using the straight-line method over useful lives ranging from two to forty years. Included in accounts payable were $36.0 million and $52.1 million of capital accruals as of December 31, 2019 and 2018, respectively.
Interest is capitalized on long-term construction project using the weighted average cost of debt outstanding during the period of construction.
Scheduled maintenance of equipment is performed based on the number of hours operated in accordance with our preventative maintenance program. Routine repair and maintenance costs are charged to expense as incurred; however, the costs of the overhauls and asset replacement projects that benefit future periods and which typically occur every three to five years are capitalized when incurred and depreciated over an equivalent period. These overhauls and asset replacement projects are included in “Drilling equipment and facilities” in “Note 5- Property and Equipment.”
We evaluate our property and equipment for impairment whenever there are changes in facts that suggest that the value of the asset is not recoverable. For more detailed information, see “Note 6- Loss on Impairment.”
Fair Value Measurements
We measure certain of our assets and liabilities based on a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The three-level hierarchy, from highest to lowest level of observable inputs, are as follows:
Level 1 - Valuations based on quoted prices in active markets for identical assets;
Level 2 - Valuations based on observable inputs that do not meet the criteria for Level 1, including quoted prices in inactive markets and quoted prices in active markets for similar but not identical instruments; and
Level 3 - Valuations based on unobservable inputs.
Revenue Recognition
The activities that primarily drive the revenue earned in our drilling contracts include (i) providing a drilling rig and the crew and supplies necessary to operate the rig, (ii) mobilizing and demobilizing the rig to and from the drill site, and (iii) performing rig preparation activities and/or modifications required for the contract. Consideration received for performing these activities may consist of dayrate drilling revenue, mobilization and demobilization revenue, contract preparation revenue and reimbursement revenue. We account for these integrated services provided within our drilling contracts as a single performance obligation satisfied over time and comprised of a series of distinct time increments in which we provide drilling services.
Our standard drilling contracts require that we operate the rig at the direction of the customer throughout the contract term (which is the period we estimate to benefit from the corresponding activities and generally ranges from two to 60 months). The activities performed and the level of service provided can vary hour to hour. Our obligation under a standard contract is to provide whatever level of service is required by the operator, or customer, over the term of the contract. We are, therefore, under a stand-ready obligation throughout the entire contract duration. Consideration for our stand-ready obligation corresponds to distinct time increments, though the rate may be variable depending on various factors,
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unless otherwise indicated, dollar amounts in tables are in thousands)
and is recognized in the period in which the services are performed. The total transaction price is determined for each individual contract by estimating both fixed and variable consideration expected to be earned over the term of the contract. We have elected to exclude from the transaction price measurement all taxes assessed by a governmental authority. See further discussion regarding the allocation of the transaction price to the remaining performance obligations below.
The amount estimated for variable consideration may be subject to interrupted or restricted rates and is only included in the transaction price to the extent that it is probable that a significant reversal of previously recognized revenue will not occur throughout the term of the contract (“constrained revenue”). When determining if variable consideration should be constrained, management considers whether there are factors outside the Company’s control that could result in a significant reversal of revenue as well as the likelihood and magnitude of a potential reversal of revenue. These estimates are re-assessed each reporting period as required.
Dayrate Drilling Revenue. Our drilling contracts generally provide for payment on a dayrate basis, with higher rates for periods when the drilling unit is operating and lower rates or zero rates for periods when drilling operations are interrupted or restricted. The dayrate invoices billed to the customer are typically determined based on the varying rates applicable to the specific activities performed on an hourly basis. Such dayrate consideration is allocated to the distinct hourly increment it relates to within the contract term, and therefore, recognized in line with the contractual rate billed for the services provided for any given hour.
Mobilization/Demobilization Revenue. We may receive fees (on either a fixed lump-sum or variable dayrate basis) for the mobilization and demobilization of our rigs. These activities are not considered to be distinct within the context of the contract and, therefore, the associated revenue is allocated to the overall performance obligation and the associated pre-operating costs are deferred. We record a contract liability for mobilization fees received and a deferred asset for costs. Both revenue and pre-operating costs are recognized ratably over the initial term of the related drilling contract.
In most contracts, there is uncertainty as to the amount of expected demobilization revenue due to contractual provisions that stipulate that certain conditions must be present at contract completion for such revenue to be received and as to the amount thereof, if any. For example, contractual provisions may require that a rig demobilize a certain distance before the demobilization revenue is payable or the amount may vary dependent upon whether or not the rig has additional contracted work within a certain distance from the wellsite. Therefore, the estimate for such revenue may be constrained, as described earlier, depending on the facts and circumstances pertaining to the specific contract. We assess the likelihood of receiving such revenue based on past experience and knowledge of the market conditions. In cases where demobilization revenue is expected to be received upon contract completion, it is estimated as part of the overall transaction price at contract inception and recognized in earnings ratably over the initial term of the contract with an offset to an accretive contract asset.
Contract Preparation Revenue. Some of our drilling contracts require downtime before the start of the contract to prepare the rig to meet customer requirements. At times, we may be compensated by the customer for such work (on either a fixed lump-sum or variable dayrate basis). These activities are not considered to be distinct within the context of the contract and, therefore, the related revenue is allocated to the overall performance obligation and recognized ratably over the initial term of the related drilling contract. We record a contract liability for contract preparation fees received, which is amortized ratably to contract drilling revenue over the initial term of the related drilling contract.
Bonuses, Penalties and Other Variable Consideration. We may receive bonus increases to revenue or penalty decreases to revenue. Based on historical data and ongoing communication with the operator/customer, we are able to reasonably estimate this variable consideration. We will record such estimated variable consideration and re-measure our estimates at each reporting date. For revenue estimated, but not received, we will record to “Prepaid expenses and other current assets” on our Consolidated Balance Sheets.
Capital Modification Revenue. From time to time, we may receive fees from our customers for capital improvements to our rigs to meet contractual requirements (on either a fixed lump-sum or variable dayrate basis). Such revenue is allocated to the overall performance obligation and recognized ratably over the initial term of the related drilling contract as these activities are integral to our drilling activities and are not considered to be a stand-alone service provided to the customer within the context of our contracts. We record a contract liability for such fees and recognize them ratably as contract drilling revenue over the initial term of the related drilling contract.
Revenues Related to Reimbursable Expenses. We generally receive reimbursements from our customers for the purchase of supplies, equipment, personnel services and other services provided at their request in accordance with a drilling contract or other agreement. Such reimbursable revenue is variable and subject to uncertainty, as the amounts received and timing thereof is highly dependent on factors outside of our influence. Accordingly, reimbursable revenue is constrained revenue and not included in the total transaction price until the uncertainty is resolved, which typically occurs when the related costs are incurred on behalf of a customer. We are generally considered a principal in such transactions and record the associated revenue at the gross amount billed to the customer as “Reimbursables and other” in our Consolidated Statements of Operations. Such amounts are recognized ratably over the period within the contract term during which the corresponding goods and services are to be consumed.
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NOBLE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unless otherwise indicated, dollar amounts in tables are in thousands)
Deferred revenues from drilling contracts totaled $65.1 million and $80.8 million at December 31, 2019 and 2018, respectively. Such amounts are included in either “Other current liabilities” or “Other liabilities” in the accompanying Consolidated Balance Sheets, based upon our expected time of recognition. Related expenses deferred under drilling contracts totaled $30.8 million at December 31, 2019 as compared to $47.7 million at December 31, 2018 and are included in either “Prepaid expenses and other current assets,” “Other assets” or “Property and equipment, net” in the accompanying Consolidated Balance Sheets, based upon our expected time of recognition.
We record reimbursements from customers for “out-of-pocket” expenses as revenues and the related direct cost as operating expenses.
Income Taxes
Income taxes are based on the laws and rates in effect in the countries in which operations are conducted or in which we or our subsidiaries are considered resident for income tax purposes. In certain circumstances, we expect that, due to changing demands of the offshore drilling markets and the ability to redeploy our offshore drilling units, certain of such units will not reside in a location long enough to give rise to future tax consequences. As a result, no deferred tax asset or liability has been recognized in these circumstances. Should our expectations change regarding the length of time an offshore drilling unit will be used in a given location, we will adjust deferred taxes accordingly.
Deferred tax assets and liabilities are recognized for the anticipated future tax effects of temporary differences between the financial statement basis and the tax basis of our assets and liabilities using the applicable jurisdictional tax rates at year-end. A valuation allowance for deferred tax assets is recorded when it is more likely than not that the deferred tax asset will not be realized in a future period.
We operate through various subsidiaries in numerous countries throughout the world, including the United States. Consequently, we are subject to changes in tax laws, treaties or regulations or the interpretation or enforcement thereof in the United States, UK and any other jurisdictions in which we or any of our subsidiaries operate or are resident. 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 the IRS 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 including the imposition of a higher effective tax rate on our worldwide earnings or a reclassification of the tax impact of our significant corporate restructuring transactions. The Company has adopted an accounting policy to look through the outside basis of partnerships and all other flow-through entities and exclude these from the computation of deferred taxes.
Insurance Reserves
We maintain various levels of self-insured retention for certain losses including property damage, loss of hire, employment practices liability, employers’ liability and general liability, among others. We accrue for property damage and loss of hire charges on a per event basis.
Employment practices liability claims are accrued based on actual claims during the year. Maritime employer’s liability claims are generally estimated using actuarial determinations. General liability claims are estimated by our internal claims department by evaluating the facts and circumstances of each claim (including incurred but not reported claims) and making estimates based upon historical experience with similar claims. At December 31, 2019 and 2018, loss reserves for personal injury and protection claims totaled $27.9 million and $22.4 million, respectively, and such amounts are included in “Other current liabilities” in the accompanying Consolidated Balance Sheets.
Earnings per Share
Our unvested share-based payment awards, which contain non-forfeitable rights to dividends, are participating securities and are included in the computation of earnings per share pursuant to the two-class method. The two-class method allocates undistributed earnings between common shares and participating securities. The diluted earnings per share calculation under the two-class method also includes the dilutive effect of potential shares issued in connection with stock options. The dilutive effect of stock options is determined using the treasury stock method.
Share-Based Compensation Plans
We record the grant date fair value of share-based compensation arrangements as compensation cost using a straight-line method over the service period. Share-based compensation is expensed or capitalized based on the nature of the employee’s activities.
Litigation Contingencies
We are involved in legal proceedings, claims, and regulatory, tax or government inquiries and investigations that arise in the ordinary course of business. Certain of these matters include speculative claims for substantial or indeterminate amounts of damages. We record a liability when we believe that it is both probable that a loss has been incurred and the amount can be reasonably estimated. If we determine that a loss is reasonably possible and the loss or range of loss can be estimated, we disclose the possible loss in the notes to the consolidated financial statements.
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NOBLE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unless otherwise indicated, dollar amounts in tables are in thousands)
We review the developments in our contingencies that could affect the amount of the provisions that has been previously recorded, and the matters and related possible losses disclosed. We make adjustments to our provisions and changes to our disclosures accordingly to reflect the impact of negotiations, settlements, rulings, advice of legal counsel, and updated information. Significant judgement is required to determine both the probability and the estimated amount.
Discontinued Operations
On August 1, 2014, Noble-UK completed the separation and spin-off of a majority of its standard specification offshore drilling business (the “Spin-off”) through a pro rata distribution of all of the ordinary shares of its wholly-owned subsidiary, Paragon Offshore plc (“Paragon Offshore”), to the holders of Noble’s ordinary shares. Paragon Offshore, which had been reflected as continuing operations in our consolidated financial statements prior to the Spin-off, meets the criteria for being reported as discontinued operations and has been reclassified as such in our results of operations.
Prior to the completion of the Spin-off, Noble-UK and Paragon Offshore entered into a series of agreements to effect the separation and Spin-off and govern the relationship between the parties after the Spin-off (the “Separation Agreements”), including the Master Separation Agreement (the “MSA”) and the Tax Sharing Agreement (the “TSA”). During the year ended December 31, 2017, we recorded a non-cash loss of $1.5 million in “Net loss from discontinued operations, net of tax” on our Consolidated Statement of Operations from the effects of Paragon Offshore's rejection of the Separation Agreements. During the year ended December 31, 2019, we recognized charges of $3.8 million recorded in “Net loss from discontinued operations, net of tax” on our Consolidated Statement of Operations relating to settlement of Mexico customs audits from rigs included in the Spin-off. For additional information related to the Spin-off, refer to “Note 16- Commitments and Contingencies.”
Certain Significant Estimates
The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amount of revenues and expenses during the reporting period. Certain accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. We evaluate our estimates and assumptions on a regular basis. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates and assumptions used in preparation of our consolidated financial statements.
Accounting Pronouncements
Accounting Standards Adopted
In February 2016, the FASB issued Accounting Standards Update (“ASU”) No. 2016-02 (Topic 842, “Leases”), as amended, which generally requires lessees to recognize operating and financing lease liabilities and corresponding right-of-use assets on the balance sheet and to provide enhanced disclosures surrounding the amount, time and uncertainty of cash flows arising from lease agreements. We adopted this standard, on a modified retrospective basis, effective January 1, 2019 and did not restate comparative periods. Our adoption did not have a material effect on our consolidated financial statements.
With respect to leases in which we are the lessee, we recognized a lease liability and a corresponding right-of-use asset of approximately $28.0 million on our Consolidated Balance Sheet as of January 1, 2019. We have elected the package of practical expedients that permits us to not reassess (1) whether previously expired or existing contracts are or contain leases, (2) the lease classification for any expired or existing leases, and (3) any initial direct costs for any existing leases as of the effective date. In addition, we have elected the hindsight practical expedient in connection with our adoption of the new lease standard. As lessee, we have made the accounting policy election to not recognize a right-of-use asset lease and lease liability for leases with a term of 12 months or less. We will recognize lease payments in the Consolidated Statements of Operations on a straight-line basis over the lease term. We have also elected the practical expedient to not separate lease and non-lease components.
Our drilling contracts contain a lease component related to the underlying drilling equipment, in addition to the service component provided by our crews and our expertise to operate such drilling equipment. We have concluded the non-lease service of operating our equipment and providing expertise in the drilling of the client’s well is predominant in our drilling contracts. We have applied the practical expedient to account for the lease and associated nonlease components as a single component. With the election of the practical expedient, we will continue to present a single performance obligation under the new revenue guidance in Accounting Standards Codification (“ASC”) Topic 606, “Revenue from Contracts with Customers.”
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unless otherwise indicated, dollar amounts in tables are in thousands)
Recently Issued Accounting Standards
In December 2019, the FASB issued ASU No. 2019-12, which amends ASC Subtopic 740, “Income Taxes” This update simplifies the accounting for income taxes by removing certain exceptions to general principles. The amendment is effective for fiscal years beginning after December 15, 2020 and is required to be adopted on a retrospective basis for all periods presented. We are evaluating what impact, if any, the adoption of this guidance will have on our consolidated financial statements.
In August 2018, the FASB issued ASU No. 2018-14, which amends ASC Subtopic 715-20, “Compensation - Retirement Benefits - Defined Benefit Plans - General.” This update applies to all employers that sponsor defined benefit pension or other postretirement plans and is part of the disclosure framework project to improve the effectiveness of disclosures in notes to the financial statements. The amendment is effective for fiscal years ending after December 15, 2020 and is required to be adopted on a retrospective basis for all periods presented. We do not expect the adoption of this guidance to materially affect our consolidated financial statements.
In June 2016, the FASB issued ASU No. 2016-13 (Topic 326, “Measurement of Credit Losses on Financial Instruments”), which requires changes to the recognition of credit losses on financial instruments not accounted for at fair value through net income, including loans, debt securities, trade receivables, net investments in leases and available-for-sale debt securities. This guidance will be effective for annual and interim periods beginning after December 15, 2019. Entities are required to apply the standard’s provisions as a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is adopted. We do not expect the adoption of this guidance to materially affect our consolidated financial statements.
With the exception of the updated standards discussed above, there have been no new accounting pronouncements not yet effective that have significance, or potential significance, to our consolidated financial statements.
Note 2- Consolidated Joint Ventures
On December 3, 2019, we completed a transaction with a subsidiary of Royal Dutch Shell plc (“Shell”), in which Shell bought out the remaining term of its drilling contract for the drillship Noble Bully II for $166.9 million, and we acquired Shell’s 50 percent interests in the Bully I and Bully II joint ventures for $106.7 million. As a result of this transaction, the former joint venture entities became our wholly-owned subsidiaries.
Prior to this transaction, we maintained a 50 percent interest in the two joint ventures, each with Shell, that owned and operated the two Bully-class drillships. We had determined that we were the primary beneficiary of the joint ventures. Accordingly, we consolidated the entities in our consolidated financial statements after eliminating intercompany transactions. Shell’s equity interests were presented as noncontrolling interests on our Consolidated Balance Sheets.
During the years ended December 31, 2019, 2018 and 2017, the Bully joint ventures approved and paid dividends totaling $50.2 million, $55.2 million and $113.8 million, respectively. Of these amounts, 50 percent was paid to our former joint venture partner, Shell.
The combined carrying amount of the Bully-class drillships at December 31, 2018 totaled $0.7 billion. These assets were primarily funded through partner equity contributions. During the year ended December 31, 2019, we recognized a $595.5 million impairment charge on the Noble Bully II, of which $265.0 million is attributable to Shell, our former joint venture partner. During the year ended December 31, 2018, we recognized a $550.3 million impairment on the Noble Bully I, of which $250.3 million is attributable to our former joint venture partner. See “Note 6- Loss on Impairment” for additional information. Cash held by our wholly-owned subsidiaries that were formerly the Bully joint ventures totaled approximately $45.2 million at December 31, 2018.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unless otherwise indicated, dollar amounts in tables are in thousands)
Note 3- Loss Per Share
The following table presents the computation of basic and diluted loss per share for Noble-UK:
Only those items having a dilutive impact on our basic loss per share are included in diluted loss per share. For the years ended December 31, 2019, 2018 and 2017, 11.9 million, 12.5 million and 12.0 million share-based awards, respectively, were excluded from the diluted loss per share since the effect would have been anti-dilutive.
Note 4- Receivables from Customers
At December 31, 2016, we had receivables of approximately $14.4 million related to the Noble Max Smith, which had been disputed by our former customer, Petróleos Mexicanos (“Pemex”) and were classified as long-term and included in “Other assets” on our Consolidated Balance Sheet. The receivables were related to lost revenues for downtime that occurred after our rig was damaged when one of Pemex's supply boats collided with our rig in 2010. A Mexican subsidiary of Paragon Offshore, which had operated the Noble Max Smith, had been prosecuting the claim against Pemex. As of December 31, 2017, Paragon Offshore announced that, as part of its bankruptcy plan, it will liquidate the Mexican entity involved.
While Noble owns all rights to amounts from that claim and will take available actions to recover such amounts, we believe the announced actions by Paragon Offshore create uncertainty relating to the prosecution of the claim and associated recovery, and accordingly, the disputed amounts of approximately $14.4 million were written off through “Contract drilling services” costs on our Consolidated Statements of Operations during the year ended December 31, 2017.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unless otherwise indicated, dollar amounts in tables are in thousands)
Note 5- Property and Equipment
Property and equipment, at cost, for Noble-UK consisted of the following:
Capital expenditures, including capitalized interest, totaled $306.4 million, $281.3 million and $111.1 million for the years ended December 31, 2019, 2018 and 2017, respectively. During the years ended December 31, 2019, 2018 and 2017, capitalized interest was $9.6 million, $2.9 million and zero, respectively.
During the year ended December 31, 2017, we recognized a $14.3 million charge in “Contract drilling services” costs related to damages sustained on the Noble Danny Adkins and Noble Jim Day during Hurricane Harvey in the US Gulf of Mexico region.
On February 28, 2019, we purchased a new GustoMSC CJ46 rig, the Noble Joe Knight, from the PaxOcean Group (“PaxOcean”) in connection with a concurrently awarded drilling contract in the Middle East region. We paid $83.8 million for the rig, with $30.2 million paid in cash and the remaining $53.6 million of the purchase price financed with a loan by the seller. See “Note 7- Debt” for additional information.
On September 21, 2018, we purchased the Noble Johnny Whitstine, a new GustoMSC CJ46 design jackup rig, from PaxOcean in connection with a concurrently awarded drilling contract in the Middle East region. We paid $93.8 million for the rig, with $33.8 million paid in cash and the remaining $60.0 million of the purchase price financed with a loan by the seller. See “Note 7- Debt” for additional information.
During the years ended December 31, 2019, 2018 and 2017, we recognized a non-cash loss on impairment of $615.3 million, $802.1 million and $121.6 million, respectively, related to our long-lived assets. See “Note 6- Loss on Impairment” for additional information.
Note 6- Loss on Impairment
Asset Impairments
In connection with the preparation of the consolidated financial statements included in this Annual Report, consistent with our accounting policies discussed in “Note 1- Organization and Significant Accounting Policies,” we evaluate our property and equipment for impairment whenever there are changes in facts that suggest that the value of the asset is not recoverable. In connection with the preparation of our financial statements for the year ended December 31, 2019, we conducted a review of our fleet. The review included an assessment of certain assumptions, including future marketability of each unit in light of its current technical specifications. Assumptions used in our assessment included, but were not limited to, timing of future contract awards and expected operating dayrates, operating costs, utilization rates, discount rates, capital expenditures, reactivation costs, estimated economic useful lives and, in certain cases, our belief that a drilling unit is no longer marketable and is unlikely to return to service.
During the years ended December 31, 2019, 2018, and 2017, we recognized non-cash losses on impairment of $615.3 million, $802.1 million and $121.6 million, respectively, related to certain rigs and related capital spares.
Based upon our impairment analyses, we impaired the carrying value to their corresponding estimated fair values for the Noble Bully II, Noble Paul Romano, and certain capital spare equipment, which resulted in an impairment charge of approximately $615.3 million for the year ended December 31, 2019. During the year ended December 31, 2019, we recognized a $595.5 million impairment on the Noble Bully II, of which $265.0 million was attributable to our joint venture partner at the time of impairment. See “Note 2- Consolidated Joint Ventures” for additional information. For our impaired units, we estimated the fair value of these units by applying the income valuation approach utilizing significant unobservable inputs, representative of a Level 3 fair value measurement. If we experience unfavorable changes to current market conditions, reactivation costs or dayrates, or we are unable to return cold stacked rigs to service in the anticipated time frame or if we are unable to secure new or extended contracts for our active rigs, it is reasonably possible that the estimate of undiscounted cash flows may change in the near term, resulting in the need to write down the affected assets to their corresponding estimated fair values.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unless otherwise indicated, dollar amounts in tables are in thousands)
Based upon our impairment analysis, we impaired the carrying values to their corresponding estimated fair values for the Noble Bully I, Noble Dave Beard, Noble Gene House, Noble Joe Beall, Noble Paul Romano, and certain capital spare equipment. During the year ended December 31, 2018, impairment charges related to these units and certain capital spare equipment were approximately $802.1 million. For our impaired units, we estimated the fair values of these units by applying the income valuation approach utilizing significant unobservable inputs, representative of a Level 3 fair value measurement. During the year ended December 31, 2018, we recognized a $550.3 million impairment on the Noble Bully I, of which $250.3 million was attributable to our joint venture partner at the time of impairment. See “Note 2- Consolidated Joint Ventures” for additional information.
During the year ended December 31, 2017, we identified indicators that certain assets in our fleet might not be recoverable. Such indicators included additional customer suspensions of drilling programs, contract cancellations, a further reduction in the number of new contract opportunities, resulting in reduced drilling contracts, and our belief that a drilling unit is no longer marketable and is unlikely to return to service. As a result, we determined that the carrying amounts of the Noble Amos Runner, Noble Alan Hay, Noble David Tinsley and certain capital spares were impaired and recorded an impairment charge of approximately $121.6 million.
Note 7- Debt
Credit Facilities
2015 Credit Facility
Effective January 2018, in connection with entering into the 2017 Credit Facility (as defined herein), we amended our $300.0 million senior unsecured credit facility that would have matured in January 2020 and was guaranteed by our indirect, wholly-owned subsidiaries, Noble Holding (U.S.) LLC (“NHUS”) and Noble Holding International Limited (“NHIL”) (as amended, the “2015 Credit Facility”), which resulted in, among other things, a reduction in the aggregate principal amount of commitments thereunder. As a result of the 2015 Credit Facility's reduction in the aggregate principal amount of commitments, we recognized a net loss of approximately $2.3 million in the year ended December 31, 2018. On December 20, 2019, we repaid $300.0 million of outstanding borrowings and terminated the 2015 Credit Facility.
2017 Credit Facility
On December 21, 2017, Noble Cayman Limited, a Cayman Islands company and a wholly-owned indirect subsidiary of Noble-Cayman; Noble International Finance Company, a Cayman Islands company and a wholly-owned indirect subsidiary of Noble-Cayman; and Noble Holding UK Limited, a company incorporated under the laws of England and Wales and a wholly-owned direct subsidiary of Noble-UK (“NHUK”), as parent guarantor, entered into a new senior unsecured credit agreement (as amended, the “2017 Credit Facility” and, together with the 2015 Credit Facility, the “Credit Facilities”). In July 2019, we executed an amendment to our 2017 Credit Facility (the “First Amendment to the 2017 Credit Facility”), which, among other things, reduced the maximum aggregate amount of commitments thereunder from $1.5 billion to $1.3 billion. As a result of such reduction in the maximum aggregate amount of commitments, we recognized a net loss of approximately $0.7 million in the year ended December 31, 2019. Borrowings under the 2017 Credit Facility are subject to certain conditions precedent to advance loans. The First Amendment to the 2017 Credit Facility added a requirement that any amounts drawn under the 2017 Credit Facility plus any undrawn amounts needed to cause us to be in compliance with the $300.0 million Liquidity (as defined in the First Amendment to the 2017 Credit Facility) covenant not exceed the amount of the Indenture Secured Debt Basket (as defined in the First Amendment to the 2017 Credit Facility) at the time of each borrowing. The maximum aggregate amount of commitments under the 2017 Credit Facility on December 31, 2019 was $1.3 billion with approximately $660 million available to borrow. The First Amendment to the 2017 Credit Facility also replaced the debt to capitalization ratio financial covenant with a Senior Guaranteed Indebtedness to Adjusted EBITDA (each as defined in the First Amendment to the 2017 Credit Facility) ratio financial covenant, as described below.
The 2017 Credit Facility will mature in January 2023. Borrowings may be used for working capital and other general corporate purposes. The 2017 Credit Facility provides for a letter of credit sub-facility currently in the amount of $15.0 million, with the ability to increase such amount up to $500.0 million with the approval of the lenders. Borrowings under the 2017 Credit Facility bear interest at LIBOR plus an applicable margin, which is currently the maximum contractual rate of 4.25%. At December 31, 2019, we had $335.0 million of borrowings outstanding under the 2017 Credit Facility.
At December 31, 2019, we had $9.0 million of letters of credit issued under the 2017 Credit Facility and an additional $12.2 million in letters of credit and surety bonds issued under unsecured bilateral arrangements.
Both of our Credit Facilities had or have provisions which vary the applicable interest rates for borrowings based upon our debt ratings. We also paid a facility fee under the 2015 Credit Facility on the full commitments thereunder (used or unused) and pay a commitment fee under the 2017 Credit Facility on the daily unused amount of the underlying commitments, in each case which varies depending on our credit ratings. At December 31, 2019, the interest rates in effect under our 2017 Credit Facility were the highest permitted interest rates under that agreement.
NOBLE CORPORATION PLC AND SUBSIDIARIES
NOBLE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unless otherwise indicated, dollar amounts in tables are in thousands)
Debt Issuance
In January 2018, we issued $750.0 million aggregate principal amount of our Senior Notes due 2026 (the “2026 Notes”) through our indirect wholly-owned subsidiary, NHIL. The net proceeds of the offering of approximately $737.4 million, after expenses, were used to retire a portion of our near-term senior notes in a related tender offer.
The indenture for the 2026 Notes contains certain covenants and restrictions, including, among others, restrictions on our subsidiaries’ ability to incur certain additional indebtedness. Additionally, the subsidiary guarantors must own, directly or indirectly, (i) assets comprising at least 85% of the revenue of Noble-Cayman and its subsidiaries on a consolidated basis and (ii) jackups, semisubmersibles, drillships, submersibles or other mobile offshore drilling units of material importance, the combined book value of which comprises at least 85% of the combined book value of all such assets of Noble-Cayman and its subsidiaries on a consolidated basis, in each case, with respect to the most recently completed fiscal year.
Seller Loans
2019 Seller Loan
In February 2019, we purchased the Noble Joe Knight for $83.8 million with a $53.6 million seller-financed secured loan (the “2019 Seller Loan”). The 2019 Seller Loan has a term of four years and requires a 5% principal payment at the end of the third year with the remaining 95% of the principal due at the end of the term. The 2019 Seller Loan bears a cash interest rate of 4.25% and the equivalent of a 1.25% interest rate paid-in-kind over the four-year term of the 2019 Seller Loan. Based on the terms of the 2019 Seller Loan, the 1.25% paid-in-kind interest rate is accelerated into the first year, resulting in an overall first year interest rate of 8.91%, of which only 4.25% is payable in cash. Thereafter, the paid-in-kind interest ends and the cash interest rate of 4.25% is payable for the remainder of the term.
2018 Seller Loan
In September 2018, we purchased the Noble Johnny Whitstine for $93.8 million with a $60.0 million seller-financed secured loan (the “2018 Seller Loan” and, together with the 2019 Seller Loan, the “Seller Loans”). The 2018 Seller Loan has a term of four years and requires a 5% principal payment at the end of the third year with the remaining 95% of the principal due at the end of the term. The 2018 Seller Loan bears a cash interest rate of 4.25% and the equivalent of a 1.25% interest rate paid-in-kind over the four-year term of the 2018 Seller Loan. Based on the terms of the 2018 Seller Loan, the 1.25% paid-in-kind interest rate is accelerated into the first year, resulting in an overall first year interest rate of 8.91%, of which only 4.25% is payable in cash. Thereafter, the paid-in-kind interest ends and the cash interest rate of 4.25% is payable for the remainder of the term.
Both of the Seller Loans are guaranteed by Noble-Cayman and each is secured by a mortgage on the applicable rig and by the pledge of the shares of the applicable single-purpose entity that owns the relevant rig. Each Seller Loan contains a debt to total capitalization ratio requirement that such ratio not exceed 0.55 at the end of each fiscal quarter, a $300.0 million minimum liquidity financial covenant and an asset and revenue covenant substantially similar to the 2026 Notes, as well as other covenants and provisions customarily found in secured transactions, including a cross-default provision. Each Seller Loan requires immediate repayment on the occurrence of certain events, including the termination of the drilling contract associated with the relevant rig or circumstances in connection with a material adverse effect.
Senior Notes Interest Rate Adjustments
Our Senior Notes due 2025 and our Senior Notes due 2045 are subject to provisions that vary the applicable interest rates based on our debt rating. Effective April 2018, these senior notes have reached the contractually defined maximum interest rate set for each rating agency and no further interest rate increases are possible. The interest rates on these senior notes may be decreased if our debt ratings were to be raised by either rating agency above specified levels. Our other outstanding senior notes do not contain provisions varying applicable interest rates based upon our credit ratings.
Debt Tender Offers, Repayments and Open Market Repurchases
In March 2019, we completed cash tender offers for our Senior Notes due 2020 (the “2020 Notes”), Senior Notes due 2021 (the “2021 Notes”), Senior Notes due 2022 (the “2022 Notes”) and Senior Notes due 2024 (the “2024 Notes”). Pursuant to such tender offers, we purchased $440.9 million aggregate principal amount of these senior notes for $400.0 million, plus accrued interest, using cash on hand and borrowings under the 2015 Credit Facility. As a result of this transaction, we recognized a net gain of approximately $31.3 million.
In October 2018, we purchased $27.4 million aggregate principal amount of various tranches of our senior notes for approximately $20.2 million, plus accrued interest, as open market repurchases and recognized a net gain of approximately $6.9 million.
NOBLE CORPORATION PLC AND SUBSIDIARIES
NOBLE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unless otherwise indicated, dollar amounts in tables are in thousands)
In August 2018, we purchased $0.4 million aggregate principal amount of our Senior Notes due 2042 for approximately $0.3 million, plus accrued interest, as open market repurchases and recognized a net gain of approximately $0.1 million.
In March 2018, we repaid the remaining aggregate principal amount of $126.6 million of our Senior Notes due 2018 (the “2018 Notes”) at maturity using cash on hand.
In March 2018, we purchased $9.5 million aggregate principal amount of various tranches of our senior notes for approximately $8.7 million, plus accrued interest, as open market repurchases and recognized a net gain of approximately $0.5 million.
In February 2018, we redeemed the remaining principal amount of $61.9 million of our Senior Notes due 2019 (the “2019 Notes”) for approximately $65.3 million, plus accrued interest. As a result of this transaction, we recognized a net loss of approximately $3.5 million.
In February 2018, we completed cash tender offers for the 2018 Notes, the 2019 Notes, the 2020 Notes, the 2021 Notes, the 2022 Notes, and the 2024 Notes. Pursuant to such tender offers, we purchased $754.2 million aggregate principal amount of these senior notes for $750.0 million, plus accrued interest, using the net proceeds of the 2026 Notes issuance and cash on hand. As a result of this transaction, we recognized a net loss of approximately $3.5 million.
Covenants
At December 31, 2019, the 2017 Credit Facility contained certain financial covenants applicable to NHUK and its subsidiaries, including (i) a covenant that limits our ratio of Senior Guaranteed Indebtedness to Adjusted EBITDA as of the last day of each fiscal quarter, with such ratio not being permitted to exceed 4.0 to 1.0 for the fiscal quarters ending September 30, 2019 through December 31, 2020, 3.5 to 1.0 for the fiscal quarters ending March 31, 2021 through December 31, 2021 and 3.0 to 1.0 for the fiscal quarters ending March 31, 2022 and thereafter, (ii) a minimum Liquidity requirement of $300.0 million, (iii) a covenant that the ratio of the Rig Value (as defined in the 2017 Credit Facility) of Marketed Rigs (as defined in the 2017 Credit Facility) to the sum of commitments under the 2017 Credit Facility plus indebtedness for borrowed money of the borrowers and guarantors, in each case, that directly own Marketed Rigs, is not less than 3:00 to 1:00 at the end of each fiscal quarter and (iv) a covenant that, the ratio of (A) the Rig Value of the Closing Date Rigs (as defined in the 2017 Credit Facility) that are directly wholly owned by the borrowers and guarantors to (B) the Rig Value of the Closing Date Rigs owned by NHUK, subsidiaries of NHUK and certain local content affiliates, is not less than 80% at the end of each fiscal quarter (such covenants described in (iii) and (iv) of this paragraph, the “Guarantor Ratio Covenants”). The 2017 Credit Facility also includes restrictions on borrowings if, after giving effect to any such borrowings and the application of the proceeds thereof, the aggregate amount of Available Cash (as defined in the 2017 Credit Facility) would exceed $200.0 million and a requirement that any amounts drawn under the 2017 Credit Facility plus any undrawn amounts needed to cause us to be in compliance with the $300.0 million Liquidity covenant not exceed the amount of the Indenture Secured Debt Basket at the time of each borrowing. As of February 18, 2020, we had $335 million of borrowings outstanding under the 2017 Credit Facility, and we would have been able to borrow a maximum of an additional approximately $660 million thereunder.
NHUK has guaranteed the obligations of the borrowers under the 2017 Credit Facility. In addition, certain indirect subsidiaries of Noble-UK that own rigs are guarantors under the 2017 Credit Facility. Certain other subsidiaries of Noble-UK may be required from time to time to guarantee the obligations of the borrowers under the 2017 Credit Facility in order maintain compliance with the Guarantor Ratio Covenants.
The 2017 Credit Facility contains additional restrictive covenants generally applicable to NHUK and its subsidiaries, including restrictions on the incurrence of liens and indebtedness, mergers and other fundamental changes, restricted payments, repurchases and redemptions of indebtedness with maturities outside of the maturity of the 2017 Credit Facility, sale and leaseback transactions and transactions with affiliates.
In addition to the covenants from the 2017 Credit Facility noted above, the covenants from the 2026 Notes described under “-Debt Issuance” above, and the covenants from the Seller Loans described under “-Seller Loans” above, the indentures governing our outstanding senior unsecured notes contain covenants that place restrictions on certain merger and consolidation transactions, unless we are the surviving entity or the other party assumes the obligations under the indenture, and on the ability to sell or transfer all or substantially all of our assets. There are also restrictions on incurring or assuming certain liens and on entering into sale and lease-back transactions.
At December 31, 2019, our debt to total tangible capitalization ratio under our Seller Loans was approximately 0.50 and we were in compliance with all applicable debt covenants. We continually monitor compliance with the covenants under our 2017 Credit Facility, senior notes and Seller Loans and expect to remain in compliance throughout 2020. However, our failure to comply with those covenants could result in an event of default which, if not cured or waived, could result in the acceleration of all our debt, which could result in our inability to continue as a going concern.
NOBLE CORPORATION PLC AND SUBSIDIARIES
NOBLE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unless otherwise indicated, dollar amounts in tables are in thousands)
Five-year debt obligations
At December 31, 2019, aggregate principal repayments of total debt for the next five years and thereafter are as follows:
Fair Value of Debt
Fair value represents the amount at which an instrument could be exchanged in a current transaction between willing parties. The estimated fair value of our debt instruments was based on the quoted market prices for similar issues or on the current rates offered to us for debt of similar remaining maturities (Level 2 measurement). The carrying amount of the 2017 Credit Facility approximates fair value as the interest rate is variable and reflective of market rates. All remaining fair value disclosures are presented in “Note 15- Fair Value of Financial Instruments.”
The following table presents the carrying value, net of unamortized debt issuance costs and discounts, and the estimated fair value of our total debt, not including the effect of unamortized debt issuance costs, respectively:
Note 8- Equity
Share Capital
As of December 31, 2019, Noble-UK had approximately 249.2 million shares outstanding and trading as compared to approximately 246.8 million shares outstanding and trading at December 31, 2018. At our 2019 Annual General Meeting, shareholders authorized our Board of Directors to increase share capital through the issuance of up to approximately 83.1 million ordinary shares (at current nominal value of $0.01 per share). That authority to allot shares will expire at the end of our 2020 Annual General Meeting unless we seek an extension from shareholders at that time. Other than shares issued to our directors under our Noble Corporation plc 2017 Director Omnibus Plan, the authority was not used to allot shares during the year ended December 31, 2019.
NOBLE CORPORATION PLC AND SUBSIDIARIES
NOBLE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unless otherwise indicated, dollar amounts in tables are in thousands)
The declaration and payment of dividends require the authorization of the Board of Directors of Noble-UK, provided that such dividends on issued share capital may be paid only out of Noble-UK’s “distributable reserves” on its statutory balance sheet in accordance with UK law. Therefore, Noble-UK is not permitted to pay dividends out of share capital, which includes share premium. Noble has not paid dividends since the third quarter of 2016. The payment of future dividends will depend on our results of operations, financial condition, cash requirements, future business prospects, contractual and indenture restrictions and other factors deemed relevant by our Board of Directors.
Share Repurchases
Under UK law, the Company is only permitted to purchase its own shares by way of an “off-market purchase” in a plan approved by shareholders. We currently do not have shareholder authority to repurchase shares. During the years ended December 31, 2019, 2018 and 2017, we did not repurchase any of our shares.
Share-Based Compensation Plans
Stock Plans
During 2015, Noble Corporation plc shareholders approved a new equity plan, the Noble Corporation plc 2015 Omnibus Incentive Plan (the “Noble Incentive Plan”), which permits grants of options, stock appreciation rights (“SARs”), stock or stock unit awards or cash awards, any of which may be structured as a performance award, from time to time to employees who are to be granted awards under the Noble Incentive Plan. Neither consultants nor non-employee directors are eligible for awards under the Noble Incentive Plan. The Noble Incentive Plan replaced the Noble Corporation 1991 Stock Options and Restricted Stock Plan, as amended (the “1991 Plan”). The 1991 Plan was terminated, and equity awards have thereafter only been made under the Noble Incentive Plan. Stock option awards previously granted under the 1991 Plan remain outstanding in accordance with their terms.
During 2019, 2018 and 2017, the Noble Incentive Plan was restated and shareholders approved amendments, primarily to increase the number of ordinary shares available for issuance as long-term incentive compensation under the Noble Incentive Plan by 5.8 million, 5.0 million and 3.7 million shares, respectively. The maximum aggregate number of ordinary shares that may be granted for any and all awards under the Noble Incentive Plan will not exceed 31.3 million shares and at December 31, 2019, we had 13.2 million shares remaining available for grants to employees.
During 2017, upon shareholder approval, the Noble Corporation plc 2017 Director Omnibus Plan (the “Director Plan”) replaced the previous plans that were terminated. Equity awards to our non-employee directors have thereafter only been made under the Director Plan. No awards made under previous plans remain outstanding.
During 2019, shareholders approved amendments to increase the number of ordinary shares available for issuance under the Director Plan by 0.9 million shares, bringing the maximum aggregate number of ordinary shares that may be granted for any and all awards under the Director Plan to 1.8 million shares. At December 31, 2019, we had 1.0 million shares remaining for grants to non-employee directors.
Stock Options
Options have a term of 10 years, an exercise price equal to the fair market value of a share on the date of grant and generally vest over a three-year period. A summary of the status of stock options granted under the 1991 Plan as of December 31, 2019, 2018 and 2017 and the changes during the year ended on those dates is presented below:
(1)
Options outstanding and exercisable at December 31, 2019 had no intrinsic value.
NOBLE CORPORATION PLC AND SUBSIDIARIES
NOBLE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unless otherwise indicated, dollar amounts in tables are in thousands)
The following table summarizes additional information about stock options outstanding at December 31, 2019:
The fair value of each option is estimated on the date of grant using a Black-Scholes pricing model. The expected term of options granted represents the period of time that the options are expected to be outstanding and is derived from historical exercise behavior, current trends and values derived from lattice-based models. Expected volatilities are based on implied volatilities of traded options on our shares, historical volatility of our shares, and other factors. The expected dividend yield is based on historical yields on the date of grant. The risk-free rate is based on the US Treasury yield curve in effect at the time of grant.
There were no non-vested stock option balances at December 31, 2019 or any changes during the year ended December 31, 2019. No new stock options were granted during the years ended December 31, 2019, 2018 and 2017. There was no compensation cost recognized during the years ended December 31, 2019, 2018 and 2017 related to stock options.
Restricted Stock Units (“RSUs”)
We have awarded both Time Vested (“TVRSUs”) and Performance Vested (“PVRSUs”) RSUs under the Noble Incentive Plan. The TVRSUs generally vest over a three-year period. The number of PVRSUs which vest will depend on the degree of achievement of specified corporate performance criteria over a three-year performance period. Depending on the date the PVRSU was awarded, these criteria consist of market based criteria or market and performance based criteria.
The TVRSUs are valued on the date of award at our underlying share price. The total compensation for units that ultimately vest is recognized over the service period. The shares and related nominal value are recorded when the restricted stock unit vests and additional paid-in capital is adjusted as the share-based compensation cost is recognized for financial reporting purposes.
The market-based PVRSUs are valued on the date of grant based on the estimated fair value. Estimated fair value is determined based on numerous assumptions, including an estimate of the likelihood that our stock price performance will achieve the targeted thresholds and the expected forfeiture rate. The fair value is calculated using a Monte Carlo Simulation Model. The assumptions used to value the PVRSUs include historical volatility and risk-free interest rates over a time period commensurate with the remaining term prior to vesting, as follows:
Additionally, similar assumptions were made for each of the companies included in the defined index and the peer group of companies in order to simulate the future outcome using the Monte Carlo Simulation Model.
NOBLE CORPORATION PLC AND SUBSIDIARIES
NOBLE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unless otherwise indicated, dollar amounts in tables are in thousands)
A summary of the RSUs awarded for each of the years ended December 31, 2019, 2018 and 2017 is as follows:
During the years ended December 31, 2019, 2018 and 2017, we awarded 280,635, 267,204 and 197,316 shares, respectively, to our non-employee directors.
A summary of the status of non-vested RSUs at December 31, 2019 and changes during the year ended December 31, 2019 is presented below:
(1)For awards granted prior to 2019, the number of PVRSUs shown equals the units that would vest if the “maximum” level of performance is achieved. The minimum number of units is zero and the “target” level of performance is 50 percent of the amounts shown. For awards granted during 2019, the number of PVRSUs shown equals the units that would vest if the “target” level of performance is achieved. The minimum number of units is zero and the “maximum” level of performance is 200 percent of the amounts shown.
At December 31, 2019, there was $12.7 million of total unrecognized compensation cost related to the TVRSUs, which is expected to be recognized over a remaining weighted-average period of 1.6 years. The total award-date fair value of TVRSUs vested during the year ended December 31, 2019 was $15.8 million.
At December 31, 2019, there was $5.9 million of total unrecognized compensation cost related to the PVRSUs, which is expected to be recognized over a remaining weighted-average period of 1.1 years. The total potential compensation for PVRSUs is recognized over the service period regardless of whether the performance thresholds are ultimately achieved.
Share-based amortization recognized during the years ended December 31, 2019, 2018 and 2017 related to all restricted stock totaled $14.7 million ($14.1 million net of income tax), $24.0 million ($21.9 million net of income tax) and $29.1 million ($26.3 million net of income tax), respectively. During the years ended December 31, 2019, 2018 and 2017, capitalized share-based amortization was zero.
NOBLE CORPORATION PLC AND SUBSIDIARIES
NOBLE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unless otherwise indicated, dollar amounts in tables are in thousands)
Note 9- Accumulated Other Comprehensive Income (Loss)
The following table presents the changes in the accumulated balances for each component of “Accumulated other comprehensive income (loss)” for the years ended December 31, 2019 and 2018. All amounts within the tables are shown net of tax.
(1)
Defined benefit pension items relate to actuarial changes and the amortization of prior service costs. Reclassifications from AOCI are recognized as expense on our Consolidated Statements of Operations through “Other income (expense).” See “Note 13- Employee Benefit Plans” for additional information.
NOBLE CORPORATION PLC AND SUBSIDIARIES
NOBLE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unless otherwise indicated, dollar amounts in tables are in thousands)
Note 10- Revenue and Customers
Contract Balances
Accounts receivable are recognized when the right to consideration becomes unconditional based upon contractual billing schedules. Payment terms on invoiced amounts are typically 30 days. Current contract asset and liability balances are included in “Prepaid expenses and other current assets” and “Other current liabilities,” respectively, and noncurrent contract assets and liabilities are included in “Other assets” and “Other liabilities,” respectively, on our Consolidated Balance Sheets.
The following table provides information about contract assets and contract liabilities from contracts with customers:
Significant changes in the remaining performance obligation contract assets and the contract liabilities balances for the years ended December 31, 2019 and 2018 are as follows:
Contract Costs
Certain direct and incremental costs incurred for upfront preparation, initial rig mobilization and modifications are costs of fulfilling a contract and are recoverable. These recoverable costs are deferred and amortized ratably to contract drilling expense as services are rendered over the initial term of the related drilling contract. Certain of our contracts include capital rig enhancements used to satisfy our performance obligations. These capital items are capitalized and depreciated in accordance with our existing property and equipment accounting policy.
NOBLE CORPORATION PLC AND SUBSIDIARIES
NOBLE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unless otherwise indicated, dollar amounts in tables are in thousands)
Costs incurred for the demobilization of rigs at contract completion are recognized as incurred during the demobilization process. Costs incurred for rig modifications or upgrades required for a contract, which are considered to be capital improvements, are capitalized as drilling and other property and equipment and depreciated over the estimated useful life of the improvement.
Transaction Price Allocated to the Remaining Performance Obligations
The following table reflects revenue expected to be recognized in the future related to unsatisfied performance obligations, by rig type, at the end of the reporting period:
The revenue included above consists of expected mobilization, demobilization, and upgrade revenue for unsatisfied performance obligations. The amounts are derived from the specific terms within drilling contracts that contain such provisions, and the expected timing for recognition of such revenue is based on the estimated start date and duration of each respective contract based on information known at December 31, 2019. The actual timing of recognition of such amounts may vary due to factors outside of our control. We have taken the optional exemption, permitted by accounting standards, to exclude disclosure of the estimated transaction price related to the variable portion of unsatisfied performance obligations at the end of the reporting period, as our transaction price is based on a single performance obligation consisting of a series of distinct hourly, or more frequent, periods, the variability of which will be resolved at the time of the future services.
Disaggregation of Revenue
The following table provides information about contract drilling revenue by rig types:
(1) Includes the impact of the Noble Bully II contract buyout during the year ended December 31, 2019. Exclusive of this item, revenue for the year ended December 31, 2019 would have been $560,319 for floaters and $1,079,200 for total rigs.
Note 11- Leases
Leases
We determine if an arrangement is a lease at inception. Our operating lease agreements are primarily for real estate, equipment, storage, dock space and automobiles and are included within “Other current liabilities,” “Other assets” and “Other liabilities,” respectively, on our Consolidated Balance Sheets.
As most of our leases do not provide an implicit rate, we use our incremental borrowing rate based on the information available at commencement date in determining the present value of lease payments. Certain of our lease agreements include options to extend or terminate the lease, which we do not include in our minimum lease terms unless management is reasonably certain to exercise.
NOBLE CORPORATION PLC AND SUBSIDIARIES
NOBLE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unless otherwise indicated, dollar amounts in tables are in thousands)
Supplemental balance sheet information related to leases was as follows:
The components of lease cost were as follows:
Supplemental cash flow information related to leases was as follows:
Maturities of lease liabilities as of December 31, 2019 were as follows:
Note 12- Income Taxes
Noble-UK is a company which is a tax resident in the UK and, as such, will be subject to UK corporation tax on its taxable profits and gains. A UK tax exemption is available in respect of qualifying dividends income and capital gains related to the sale of qualifying participations. We operate in various countries throughout the world, including the United States. The income or loss of the non-UK subsidiaries is not expected to be subject to UK corporation tax.
Consequently, we have taken account of the above exemption and provided for income taxes based on the laws and rates in effect in the countries in which operations are conducted, or in which we or our subsidiaries have a taxable presence for income tax purposes.
NOBLE CORPORATION PLC AND SUBSIDIARIES
NOBLE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unless otherwise indicated, dollar amounts in tables are in thousands)
The components of the net deferred taxes are as follows:
Loss from continuing operations before income taxes consists of the following:
NOBLE CORPORATION PLC AND SUBSIDIARIES
NOBLE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unless otherwise indicated, dollar amounts in tables are in thousands)
The income tax provision (benefit) for continuing operations consists of the following:
The following is a reconciliation of our reserve for uncertain tax positions, excluding interest and penalties.
The liabilities related to our reserve for uncertain tax positions are comprised of the following:
At December 31, 2019, the reserves for uncertain tax positions totaled $159.7 million (net of related tax benefits of $0.4 million). If a portion or all of the December 31, 2019 reserves are not realized, the provision for income taxes could be reduced by up to $159.7 million. At December 31, 2018, the reserves for uncertain tax positions totaled $183.8 million (net of related tax benefits of $1.0 million).
It is reasonably possible that our existing liabilities related to our reserve for uncertain tax positions may fluctuate in the next 12 months primarily due to the completion of open audits or the expiration of statutes of limitation. We estimate the potential changes could range from $80.0 million to $100.0 million.
We include, as a component of our “Income tax benefit (provision),” potential interest and penalties related to recognized tax contingencies within our global operations. Interest and penalties resulted in an income tax benefit of $3.0 million in 2019, an income tax expense of $5.1 million in 2018 and an income tax benefit of $4.7 million in 2017.
During the year ended December 31, 2019, our income tax provision included a discrete item of $36.8 million as a result of an internal restructuring.
During the year ended December 31, 2019, our income tax benefit included a net discrete tax benefit of $33.7 million following the settlement of the examination of our US tax returns for the taxable years ended December 31, 2010 and 2011 and a net tax benefit of $5.2 million following the settlement and expiration of taxable years ended December 31, 2005 and 2008 related to former Mexico tax operations.
During the year ended December 31, 2019, our income tax benefit included non-cash items of $2.6 million related to the impairment of two rigs and certain capital spares. During the year ended December 31, 2018, our income tax provision included non-cash items of $35.6 million related to the impairment of three rigs and certain capital spares. See “Note 6- Loss on Impairment” for additional information.
NOBLE CORPORATION PLC AND SUBSIDIARIES
NOBLE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unless otherwise indicated, dollar amounts in tables are in thousands)
We conduct business globally and, as a result, we file numerous income tax returns in US and in non-US jurisdictions. In the normal course of business, we are subject to examination by taxing authorities throughout the world, including in jurisdictions such as Brazil, Brunei, Bulgaria, Canada, Cyprus, Egypt, Ghana, Guyana, Hungary, Malta, Mexico, Nigeria, Norway, Saudi Arabia, Argentina, Australia, Denmark, Gabon, Luxembourg, Malaysia, Morocco, Myanmar, the Netherlands, Oman, Qatar, Tanzania, Timor-Leste, Singapore, Suriname, Switzerland, the United Kingdom and the United States. We are no longer subject to US Federal income tax examinations for years before 2012 and non-US income tax examinations for years before 2007.
Noble-UK conducts substantially all of its business through Noble-Cayman and its subsidiaries. The income or loss of our non-UK subsidiaries is not subject to UK income tax. Earnings are taxable in the United Kingdom at the UK statutory rate of 19 percent. The ongoing consultative process in the United Kingdom and a possible change in law could materially impact our tax rate on operations in the United Kingdom continental shelf. A reconciliation of tax rates outside of the United Kingdom and the Cayman Islands to our Noble-UK effective rate for continuing operations is shown below:
Due to US foreign tax credit limitation constraints, for the years ended December 31, 2019, 2018 and 2017, the Company has made the determination to take foreign tax expense as a deduction against US taxable income.
At December 31, 2019, the Company asserts that its investment in certain subsidiaries is permanent in nature.
Note 13- Employee Benefit Plans
Defined Benefit Plans
Noble Drilling (Land Support) Limited, an indirect, wholly-owned subsidiary of Noble-UK (“NDLS”), maintains a pension plan that covers all of its salaried, non-union employees, whose most recent date of employment is prior to April 1, 2014 (referred to as our “non-US plan”).
In addition to the non-US plan discussed above, we have a US noncontributory defined benefit pension plan that covers certain salaried employees and a US noncontributory defined benefit pension plan that covers certain hourly employees, whose initial date of employment is prior to August 1, 2004 (collectively referred to as our “qualified US plans”). These plans are governed by the Noble Drilling Employees’ Retirement Trust (the “Trust”). The benefits from these plans are based primarily on years of service and, for the salaried plan, employees' compensation near retirement. These plans are designed to qualify under the Employee Retirement Income Security Act of 1974 (“ERISA”), and our funding policy is consistent with funding requirements of ERISA and other applicable laws and regulations. We make cash contributions, or utilize credits available to us, for the qualified US plans when required. The benefit amount that can be covered by the qualified US plans is limited under ERISA and the Internal Revenue Code of 1986. Therefore, we maintain an unfunded, nonqualified excess benefit plan designed to maintain benefits for specified employees at the formula level in the qualified salaried US plan. We refer to the qualified US plans and the excess benefit plan collectively as the “US plans.”
During the fourth quarter of 2016, we approved amendments, effective as of December 31, 2016, to our non-US and US defined benefit plans. With these amendments, employees and alternate payees will accrue no future benefits under the plans after December 31, 2016. However, these amendments will not affect any benefits earned through that date.
NOBLE CORPORATION PLC AND SUBSIDIARIES
NOBLE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unless otherwise indicated, dollar amounts in tables are in thousands)
A reconciliation of the changes in projected benefit obligations (“PBO”) for our non-US and US plans is as follows:
A reconciliation of the changes in fair value of plan assets is as follows:
The funded status of the plans is as follows:
NOBLE CORPORATION PLC AND SUBSIDIARIES
NOBLE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unless otherwise indicated, dollar amounts in tables are in thousands)
Amounts recognized in the Consolidated Balance Sheets consist of:
Amounts recognized in AOCI consist of:
Pension costs include the following components:
There is less than $0.1 million and $2.9 million estimated net actuarial losses and prior service costs for the non-US plan and the US plans, respectively, that will be amortized from AOCI into net periodic pension cost in 2020.
During the years ended December 31, 2019, 2018 and 2017, we adopted the Retirement Plan (“RP”) mortality tables with the Mortality Projection (“MP”) scale as issued by the Society of Actuaries for each of the respective years. The RP 2019, 2018 and 2017 mortality tables represent the new standard for defined benefit mortality assumptions due to adjusted life expectancies. The adoption of the updated mortality tables and the mortality improvement scales decreased our pension liability on our US plans by approximately $2.1 million, $0.6 million and $1.6 million as of December 31, 2019, 2018 and 2017.
During the fourth quarter of 2018, the UK High Court made a judgement confirming that UK pension schemes are required to equalize male and female members’ benefits for the effect of guaranteed minimum pensions (GMP). We have accounted for the impact of the GMP equalization as a plan amendment to our non-US plan, and the impact is included as a prior service cost as of December 31, 2019, which will be amortized over the average life expectancy of the members at that date.
NOBLE CORPORATION PLC AND SUBSIDIARIES
NOBLE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unless otherwise indicated, dollar amounts in tables are in thousands)
Defined Benefit Plans-Disaggregated Plan Information
Disaggregated information regarding our non-US and US plans is summarized below:
The following table provides information related to those plans in which the PBO exceeded the fair value of the plan assets at December 31, 2019 and 2018. The PBO is the actuarially computed present value of earned benefits based on service to date and includes the estimated effect of any future salary increases. Employees and alternate payees have no longer accrued future benefits under the plans since December 31, 2017.
The PBO for the unfunded excess benefit plan was $10.8 million at December 31, 2019 as compared to $10.5 million in 2018, and is included under “US” in the above tables.
The following table provides information related to those plans in which the accumulated benefit obligation (“ABO”) exceeded the fair value of plan assets at December 31, 2019 and 2018. The ABO is the actuarially computed present value of earned benefits based on service to date, but differs from the PBO in that it is based on current salary levels. Employees and alternate payees have no longer accrued future benefits under the plans since December 31, 2016.
The ABO for the unfunded excess benefit plan was $10.8 million at December 31, 2019 as compared to $10.5 million in 2018, and is included under “US” in the above tables.
NOBLE CORPORATION PLC AND SUBSIDIARIES
NOBLE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unless otherwise indicated, dollar amounts in tables are in thousands)
Defined Benefit Plans-Key Assumptions
The key assumptions for the plans are summarized below:
The discount rates used to calculate the net present value of future benefit obligations for our US plans is based on the average of current rates earned on long-term bonds that receive a Moody’s rating of “Aa” or better. We have determined that the timing and amount of expected cash outflows on our plans reasonably match this index. For our non-US plan, the discount rate used to calculate the net present value of future benefit obligations is determined by using a yield curve of high quality bond portfolios with an average maturity approximating that of the liabilities.
In developing the expected long-term rate of return on assets, we considered the current level of expected returns on risk free investments (primarily government bonds), the historical level of risk premium associated with the other asset classes in which the portfolio is invested and the expectations for future returns of each asset class. The expected return for each asset class was then weighted based on the target asset allocation to develop the expected long-term rate of return on assets for the portfolio. To assist us with this analysis, we employ third-party consultants for our US and non-US plans that use a portfolio return model.
Defined Benefit Plans-Plan Assets
Non-US Plan
As of December 31, 2019, the NDLS pension Scheme targets an asset allocation of 48.0% return-seeking securities (Growth) and 52.0% debt securities (Matching). The Trustees have decided to implement a de-risking strategy whereby the level of investment risk reduces as the Scheme’s funding level improves. Consistent with this strategy, the Scheme's Trustees will target an asset allocation of 30.0% return-seeking securities (Growth) and 70.0% in debt securities (Matching) to be implemented in 2020. The overall investment objective of the Scheme, as adopted by the Scheme’s Trustees, is to reach a fully funded position on the agreed de-risking basis of Gilts - 0.20% per annum. The objectives within the Scheme’s overall investment strategy is to outperform the cash + 4% per annum long term objective for Growth assets and to sufficiently hedge interest rate and inflation risk within the Matching portfolio in relation to the Scheme’s liabilities. By achieving these objectives, the Trustees believe the Scheme will be able to avoid significant volatility in the contribution rate and provide sufficient assets to cover the Scheme’s benefit obligations. To achieve this the Trustees have given Mercer, the appointed investment manager, full discretion in the day-to-day management of the Scheme’s assets and implementation of the de-risking strategy, who in turn invests in multiple underlying investment managers where appropriate. The Trustees meet with Mercer periodically to review and discuss their investment performance.
NOBLE CORPORATION PLC AND SUBSIDIARIES
NOBLE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unless otherwise indicated, dollar amounts in tables are in thousands)
The actual fair values of the non-US plan are as follows:
US Plans
The fundamental objective of the US plan (the “Plan”) is to provide the capital assets necessary to meet the financial obligations made to Plan participants. In order to meet this objective, the Investment Policy Statement depicts how the investment assets of the Plan are to be managed in accordance with the overall target asset allocation of approximately 41.0% equity securities, 57.7% fixed income securities, and 1.3% in cash and equivalents. The target asset allocation is intended to generate sufficient capital to meet Plan obligations and provide a portfolio rate of return equal to or greater than the return realized using appropriate blended, market benchmark over a full market cycle (usually a three to five year time period). Actual allocations may deviate from the target range, however any deviation from the target range of asset allocations must be approved by the Trust’s governing committee.
For investments in mutual funds, the assets of the Trust are subject to the guidelines and limits imposed by such mutual fund’s prospectus and the other governing documentation at the fund level.
No shares of Noble were included in equity securities at either December 31, 2019 or 2018.
NOBLE CORPORATION PLC AND SUBSIDIARIES
NOBLE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unless otherwise indicated, dollar amounts in tables are in thousands)
The actual fair values of US plan assets are as follows:
As of December 31, 2019, no single security made up more than 10 percent of total assets of either the US or the non-US plans.
Defined Benefit Plans-Cash Flows
In 2019, we made no contributions to our non-US plan and we made contributions of $1.3 million to our US plans. In 2018, we made no contributions to our non-US plan and contributions of $4.6 million to our US plans. In 2017, we made total contributions of $0.7 million and $2.3 million to our non-US and US plans, respectively. We expect our aggregate minimum contributions to our non-US and US plans in 2020, subject to applicable law, to be zero and $2.5 million, respectively. We continue to monitor and evaluate funding options based upon market conditions and may increase contributions at our discretion.
NOBLE CORPORATION PLC AND SUBSIDIARIES
NOBLE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unless otherwise indicated, dollar amounts in tables are in thousands)
The following table summarizes our estimated benefit payments at December 31, 2019:
Other Benefit Plans
We sponsor a 401(k) Restoration Plan, which is a nonqualified, unfunded employee benefit plan under which specified employees may elect to defer compensation in excess of amounts deferrable under our 401(k) savings plan. The 401(k) Restoration Plan has no assets, and amounts withheld for the 401(k) Restoration Plan are kept by us for general corporate purposes. The investments selected by employees and associated returns are tracked on a phantom basis. Accordingly, we have a liability to the employee for amounts originally withheld plus phantom investment income or less phantom investment losses. We are at risk for phantom investment income and, conversely, benefit should phantom investment losses occur. At December 31, 2019 and 2018, our liability for the 401(k) Restoration Plan was $8.4 million and $8.2 million, respectively, and is included in “Accrued payroll and related costs.”
In 2005, we enacted a profit sharing plan, the Noble Drilling Services Inc. Profit Sharing Plan, which covers eligible employees, as defined in the plan. Participants in the plan become fully vested in the plan after three years of service. We sponsor other retirement, health and welfare plans and a 401(k) savings plan for the benefit of our employees. On January 1, 2019, the 401(k) savings plan and the profit sharing plan were merged into the Noble Drilling Services Inc. 401(k) and Profit Sharing Plan.
Profit sharing contributions are discretionary, require Board of Directors approval and are made in the form of cash. Contributions recorded related to this plan totaled $2.4 million, $2.3 million and $3.1 million, respectively, for three years ended December 31, 2019, 2018 and 2017. The cost of maintaining these plans for continuing operations aggregated approximately $28.1 million, $25.0 million and $27.6 million in 2019, 2018 and 2017, respectively. We do not provide post-retirement benefits (other than pensions) or any post-employment benefits to our employees.
Note 14- Derivative Instruments and Hedging Activities
We are exposed to certain concentrations of interest rate and foreign currency exchange rate risk: periodically, we enter into derivative instruments to manage our exposure to fluctuations in these rates. We have documented policies and procedures to monitor and control the use of derivative instruments. We do not engage in derivative transactions for speculative or trading purposes, nor are we a party to leveraged derivatives.
For foreign currency forward contracts, hedge effectiveness is evaluated at inception based on the matching of critical terms between derivative contracts and the hedged item. Any change in fair value resulting from ineffectiveness is recognized immediately in earnings.
Cash Flow Hedges
Several of our regional shorebases have a significant amount of their cash operating expenses payable in local currencies. To limit the potential risk of currency fluctuations, we periodically enter into forward contracts, which have historically settled monthly in the operations’ respective local currencies. All of these contracts had a maturity of less than 12 months. During 2019 and 2018, we entered into forward contracts of approximately $15.8 million and zero, respectively, all of which settled during their respective years. At both December 31, 2019 and 2018, we had no outstanding derivative contracts.
NOBLE CORPORATION PLC AND SUBSIDIARIES
NOBLE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unless otherwise indicated, dollar amounts in tables are in thousands)
Financial Statement Presentation
The following table, together with “Note 15- Fair Value of Financial Instruments,” summarizes the recognized gains and losses of cash flow hedges and non-designated derivatives through AOCI or as “Contract drilling services” revenue or costs for the years ended December 31, 2019 and 2018:
There were no foreign currency forward contracts outstanding as of December 31, 2019.
Note 15- Fair Value of Financial Instruments
The following tables present the carrying amount and estimated fair value of our financial instruments recognized at fair value on a recurring basis:
Our cash and cash equivalents, and restricted cash, accounts receivable, marketable securities and accounts payable are by their nature short-term. As a result, the carrying values included in our Consolidated Balance Sheets approximate fair value.
Note 16- Commitments and Contingencies
Transocean Ltd.
In January 2017, a subsidiary of Transocean Ltd. (“Transocean”) filed suit against us and certain of our subsidiaries seeking damages for patent infringement in a Texas federal court. The suit claims that five of our newbuild rigs that operated in the US Gulf of Mexico violated Transocean patents relating to what is generally referred to as dual-activity drilling, and Transocean is seeking royalties of a $10.0 million fee and a five percent license fee for the pertinent period of operation for each vessel and damages for the breach of contract. We were aware of the patents when we constructed the rigs. The patents are now expired in the United States and most other countries. While there is inherent risk in litigation, we do not believe that our rigs infringe the Transocean patents. Transocean also recently added another claim alleging that we breached a 2007 settlement agreement we entered into with Transocean relating to patent claims in respect of another Noble rig. We also do not believe there has been any breach of the 2007 agreement. The litigation continues, and a trial date has been set for May 2020. We continue to defend ourselves vigorously against this claim.
NOBLE CORPORATION PLC AND SUBSIDIARIES
NOBLE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unless otherwise indicated, dollar amounts in tables are in thousands)
Paragon Offshore
On August 1, 2014, Noble-UK completed the 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. In February 2016, Paragon Offshore sought approval of a pre-negotiated plan of reorganization (the “Prior Plan”) by filing for voluntary relief under Chapter 11 of the United States Bankruptcy Code. As part of the Prior Plan, we entered into a settlement agreement with Paragon Offshore (the “Settlement Agreement”). The Prior Plan was rejected by the bankruptcy court in October 2016.
In April 2017, Paragon Offshore filed a revised plan of reorganization (the “New Plan”) in its bankruptcy proceeding. Under the New Plan, Paragon Offshore no longer needed the Mexican tax bonding that Noble-UK was required to provide under the Settlement Agreement. Consequently, Paragon Offshore abandoned the Settlement Agreement as part of the New Plan, and the Settlement Agreement was terminated at the time of the filing of the New Plan. On May 2, 2017, Paragon Offshore announced that it had reached an agreement in principle with both its secured and unsecured creditors to revise the New Plan to create and fund a litigation trust to pursue litigation against us. On June 7, 2017, the revised New Plan was approved by the bankruptcy court and Paragon Offshore emerged from bankruptcy on July 18, 2017.
On December 15, 2017, the litigation trust filed claims relating to the Spin-off against us and certain of our current and former officers and directors in the Delaware bankruptcy court that heard Paragon Offshore’s bankruptcy, and the litigation trust filed an amended complaint in October 2019. The amended complaint alleges claims of actual and constructive fraudulent conveyance, unjust enrichment and recharacterization of intercompany notes as equity claims against Noble and claims of breach of fiduciary duty and aiding and abetting breach of fiduciary duty against the officer and director defendants. The litigation trust is seeking damages of (i) approximately $1.7 billion from the Company, an amount equal to the amount borrowed by Paragon Offshore immediately prior to the Spin-off, (ii) an additional approximately $935 million relating to the transfer of intercompany receivables and notes from a Paragon subsidiary to a Noble subsidiary prior to the Spin-off (bringing the total claimed damages to approximately $2.6 billion), and (iii) unspecified amounts in respect of the claims against the officer and director defendants, all of whom have indemnification agreements with us. A trial date has been set for September 2020.
We believe that Paragon Offshore, at the time of the Spin-off, was properly funded, solvent and had appropriate liquidity and that the claims brought by the litigation trust are without merit. However, the Company continually assesses potential outcomes, including the probability of the parties ultimately resolving the matter through settlement in light of various factors, including given the complex factual issues involved, the uncertainty and risk inherent in this type of litigation, the time commitment and distraction of our organization, the potential effect of the ongoing litigation and uncertainty on our business, and the substantial expense incurred in litigating the claims. As such, the Company’s current estimated loss related to the final disposition of this matter is $100.0 million, which the Company recorded as a general and administrative expense for the year ended December 31, 2019 and is reflected as a current liability as of December 31, 2019. As pre-trial matters progress, the Company’s estimated loss could change from time to time, and any such change individually or in the aggregate could be material.
There is inherent risk and substantial expense in litigation, and the amount of damages that the plaintiff is seeking is substantial. If any of the litigation trust’s claims are successful, or if we elect to settle any claims (in part to reduce or eliminate the ongoing cost of defending the litigation and eliminate any risk of a larger judgment against us), any damages or other amounts we would be required to or agree to pay in excess of the amount we recognized at December 31, 2019, could have a material adverse effect on our business, financial condition and results of operations, including impeding our ability to meet ongoing financial obligations or to continue as a going concern. Given the risks and considerations discussed above, we cannot predict with any degree of certainty what the outcome of the litigation may be. Furthermore, as discussed below, we cannot predict the amount of insurance coverage, if any, that we may have if we were to settle or be found liable in the litigation.
We have directors’ and officers’ indemnification coverage for the officers and directors who have been sued by the litigation trust. The insurers have accepted coverage for the director and officer claims and we are continuing to discuss with them the scope of their reimbursement of litigation expenses. In addition, at the time of the Spin-off, we had entity coverage, or “Side C” coverage, which was meant to cover certain litigation claims up to the coverage limit of $150.0 million, including litigation expenses. We have made a claim for coverage of the litigation trust’s claims against Noble under such entity insurance. The insurers have rejected coverage for these claims. However, we intend to pursue coverage should the litigation be concluded adversely to us or should we settle the litigation. We cannot predict the amount of claims and expenses we may incur, pay or settle in the Paragon Offshore litigation that such insurance will cover, if any.
Prior to the completion of the Spin-off, Noble-UK and Paragon Offshore entered into the Separation Agreements to effect the separation and Spin-off and govern the relationship between the parties after the Spin-off, including the MSA and the TSA.
As part of its final bankruptcy plan, Paragon Offshore rejected the Separation Agreements. Accordingly, the indemnity obligations that Paragon Offshore potentially would have owed us under the Separation Agreements have now terminated, including indemnities arising under the MSA and the TSA in respect of obligations related to Paragon Offshore’s business that were incurred through Noble-retained entities prior to
NOBLE CORPORATION PLC AND SUBSIDIARIES
NOBLE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unless otherwise indicated, dollar amounts in tables are in thousands)
the Spin-off. Likewise, any potential indemnity obligations that we would have owed Paragon Offshore under the Separation Agreements, including those under the MSA and the TSA in respect of Noble-UK’s business that was conducted prior to the Spin-off through Paragon Offshore-retained entities, are now also extinguished. In the absence of the Separation Agreements, liabilities relating to the respective parties will be borne by the owner of the legal entity or asset at issue and neither party will look to an allocation based on the historic relationship of an entity or asset to one of the party’s business, as had been the case under the Separation Agreements.
The rejection and ultimate termination of the indemnity and related obligations under the Separation Agreements resulted in a number of accounting charges and benefits during the year ended December 31, 2017, and such termination may continue to affect us in the future as liabilities arise for which we would have been indemnified by Paragon Offshore or would have had to indemnify Paragon Offshore. We do not expect that, overall, the rejection of the Separation Agreements by Paragon Offshore will have a material adverse effect on our financial condition or liquidity. However, any loss we experience with respect to which we would have been able to secure indemnification from Paragon Offshore under one or more of the Separation Agreements could have an adverse impact on our results of operations in any period, which impact may be material depending on our results of operations during this down-cycle.
During the year ended December 31, 2017, we recognized net charges of $15.9 million, with a non-cash loss of $1.5 million recorded in “Net loss from discontinued operations, net of tax” on our Consolidated Statement of Operations relating to Paragon Offshore’s emergence from bankruptcy.
During the year ended December 31, 2019, we recognized charges of $3.8 million recorded in “Net loss from discontinued operations, net of tax” on our Consolidated Statement of Operations relating to settlement of Mexico customs audits from rigs included in the Spin-off.
Tax matters
The Internal Revenue Service (“IRS”) has completed its examination procedures including all appeals and administrative reviews for the taxable years ended December 31, 2010 and 2011. In June 2019, the IRS examination team notified us that it was no longer proposing any adjustments with respect to our tax reporting for the taxable years ended December 31, 2010 and December 31, 2011. During the third quarter of 2017, the IRS initiated its examination of our 2012, 2013, 2014 and 2015 tax returns. In October 2019, we received a notice that the IRS added our 2016 and 2017 tax returns to its examination. We believe that we have accurately reported all amounts in our 2012, 2013, 2014, 2015, 2016 and 2017 tax returns.
Audit claims of approximately $74.0 million attributable to income and other business taxes were assessed against Noble entities in Mexico related to tax years 2005 and 2007 and in Australia related to tax years 2013 to 2016. We intend to vigorously defend our reported positions, and believe the ultimate resolution of the audit claims will not have a material adverse effect on our consolidated financial statements.
We operate in a number of countries throughout the world and our tax returns filed in those jurisdictions are subject to review and examination by tax authorities within those jurisdictions. We recognize uncertain tax positions that we believe have a greater than 50 percent likelihood of being sustained upon challenge by a tax authority. We cannot predict or provide assurance as to the ultimate outcome of any existing or future assessments.
Other contingencies
We have entered into agreements with certain of our executive officers, as well as certain other employees. These agreements become effective upon a change of control of Noble-UK (within the meaning set forth in the agreements) or a termination of employment in connection with or in anticipation of a change of control, and remain effective for three years thereafter. These agreements provide for compensation and certain other benefits under such circumstances.
We are a defendant in certain claims and litigation arising out of operations in the ordinary course of business, including personal injury claims, the resolution of which, in the opinion of management, will not be material to our financial position, results of operations or cash flows. There is inherent risk in any litigation or dispute and no assurance can be given as to the outcome of these claims.
We lease certain office space and warehouse facilities under cancelable and non-cancelable leases. Rent expense under these arrangements totaled $7.5 million and $8.3 million for the years ended December 31, 2018 and 2017, respectively.
NOBLE CORPORATION PLC AND SUBSIDIARIES
NOBLE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unless otherwise indicated, dollar amounts in tables are in thousands)
Note 17- Segment and Related Information
We report our contract drilling operations as a single reportable segment, Contract Drilling Services, which reflects how we manage our business. The mobile offshore drilling units comprising our offshore rig fleet operate in a global market for contract drilling services and are often redeployed to different regions due to changing demands of our customers, which consist primarily of large, integrated, independent and government-owned or controlled oil and gas companies throughout the world. As of December 31, 2019, our contract drilling services segment conducts contract drilling operations in Canada, Far East Asia, the Middle East, the North Sea, Oceania, South America and the US Gulf of Mexico.
The following table presents revenues and identifiable assets by country based on the location of the service provided:
Note 18- Supplemental Financial Information
Consolidated Balance Sheets Information
Deferred revenues from drilling contracts totaled $65.1 million and $80.8 million at December 31, 2019 and 2018, respectively. Such amounts are included in either “Other current liabilities” or “Other liabilities” in the accompanying Consolidated Balance Sheets, based upon our expected time of recognition. Related expenses deferred under drilling contracts totaled $30.8 million at December 31, 2019 as compared to $47.7 million at December 31, 2018, and are included in either “Prepaid expenses and other current assets,” “Other assets” or “Property and equipment, net” in the accompanying Consolidated Balance Sheets, based upon our expected time of recognition.
NOBLE CORPORATION PLC AND SUBSIDIARIES
NOBLE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unless otherwise indicated, dollar amounts in tables are in thousands)
Consolidated Statements of Cash Flows Information
Operating cash activities
The net effect of changes in other assets and liabilities on cash flows from operating activities is as follows:
Non-cash investing and financing activities
Additions to property and equipment, at cost for which we had accrued a corresponding liability in accounts payable as of December 31, 2019, 2018 and 2017 were $36.0 million, $52.1 million and $25.5 million, respectively.
We entered into the $60.0 million 2018 Seller Loan to finance a portion of the purchase price for the Noble Johnny Whitstine in September 2018. We entered into the $53.6 million 2019 Seller Loan to finance a portion of the purchase price for the Noble Joe Knight in February 2019. See “Note 7- Debt” for additional information.
Additional cash flow information is as follows:
NOBLE CORPORATION PLC AND SUBSIDIARIES
NOBLE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unless otherwise indicated, dollar amounts in tables are in thousands
Note 19- Condensed Consolidating Financial Information
Guarantees of Registered Securities
Noble-Cayman, or one or more 100 percent owned subsidiaries of Noble-Cayman, is an issuer or full and unconditional guarantor or otherwise obligated as of December 31, 2019 with respect to registered securities as follows (see “Note 7- Debt” for additional information):
(1) Our 2026 Notes are excluded from this list as they are unregistered securities issued in a non-public offering.
The following condensed consolidating financial statements of Noble-Cayman, NHIL and all other subsidiaries present investments in both consolidated and unconsolidated affiliates using the equity method of accounting.
NOBLE CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATING BALANCE SHEET
December 31, 2019
(Unless otherwise indicated, dollar amounts in tables are in thousands)
NOBLE CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATING BALANCE SHEET
December 31, 2018
(Unless otherwise indicated, dollar amounts in tables are in thousands)
NOBLE CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS and COMPREHENSIVE INCOME (LOSS)
Year Ended December 31, 2019
(Unless otherwise indicated, dollar amounts in tables are in thousands)
NOBLE CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS and COMPREHENSIVE INCOME (LOSS)
Year Ended December 31, 2018
(Unless otherwise indicated, dollar amounts in tables are in thousands)
NOBLE CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENT OF INCOME and COMPREHENSIVE INCOME (LOSS)
Year Ended December 31, 2017
(Unless otherwise indicated, dollar amounts in tables are in thousands)
NOBLE CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
Year Ended December 31, 2019
(Unless otherwise indicated, dollar amounts in tables are in thousands)
NOBLE CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
Year Ended December 31, 2018
(Unless otherwise indicated, dollar amounts in tables are in thousands)
NOBLE CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
Year Ended December 31, 2017
(Unless otherwise indicated, dollar amounts in tables are in thousands)
NOBLE CORPORATION PLC AND SUBSIDIARIES
NOBLE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unless otherwise indicated, dollar amounts in tables are in thousands)
Note 20- Unaudited Interim Financial Data
Unaudited interim consolidated financial information from continuing operations for Noble-UK is as follows:
(1)
Net loss per share is computed independently for each of the quarters presented. Therefore, the sum of the quarters’ net loss per share may not equal the total computed for the year.
Item 9.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.
Item 9A.
Item 9A. Evaluation of Disclosure Controls and Procedures
Noble Corporation plc
Conclusions Regarding Disclosure Controls and Procedures
Julie J. Robertson, Chairman, President and Chief Executive Officer (Principal Executive Officer) of Noble-UK, and Stephen M. Butz, Executive Vice President and Chief Financial Officer (Principal Financial Officer) of Noble-UK, have evaluated the disclosure controls and procedures of Noble-UK as of the end of the period covered by this report. On the basis of this evaluation, Ms. Robertson and Mr. Butz have concluded that Noble-UK’s disclosure controls and procedures were effective as of December 31, 2019. Noble-UK’s disclosure controls and procedures are designed to ensure that information required to be disclosed by Noble-UK in the reports that it files with or submits to the SEC are recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and is accumulated and communicated to management as appropriate to allow timely decisions regarding required disclosure.
Changes in Internal Control Over Financial Reporting
There were no changes in Noble-UK’s internal control over financial reporting that occurred during the year ended December 31, 2019 that have materially affected, or are reasonably likely to materially affect, the internal control over financial reporting of Noble-UK.
Management’s Annual Report on Internal Control Over Financial Reporting
The management of Noble-UK is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Rule 13a-15(f) promulgated under the US Securities Exchange Act of 1934, as amended.
Internal control over financial reporting includes the controls themselves, monitoring (including internal auditing practices), and actions taken to correct deficiencies as identified. There are inherent limitations to the effectiveness of internal control over financial reporting, however well designed, including the possibility of human error and the possible circumvention or overriding of controls. The design of an internal control system is also based in part upon assumptions and judgments made by management about the likelihood of future events, and there can be no assurance that an internal control will be effective under all potential future conditions. As a result, even an effective system of internal controls can provide no more than reasonable assurance with respect to the fair presentation of financial statements and the processes under which they were prepared.
Under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission in 2013. Based on the assessment by management of Noble-UK, Noble-UK maintained effective internal control over financial reporting as of December 31, 2019.
PricewaterhouseCoopers LLP, the independent registered public accounting firm that audited our financial statements included in this Annual Report on Form 10-K, has audited the effectiveness of internal control over financial reporting as of December 31, 2019 as stated in their report, which is provided in Part II, Item 8, “Financial Statements and Supplementary Data” in this Annual Report on Form 10-K.
Noble Corporation
Conclusions Regarding Disclosure Controls and Procedures
Julie J. Robertson, President and Chief Executive Officer (Principal Executive Officer) of Noble-Cayman, and Stephen M. Butz, Director, Executive Vice President and Chief Financial Officer (Principal Financial Officer) of Noble-Cayman, have evaluated the disclosure controls and procedures of Noble-Cayman as of the end of the period covered by this report. On the basis of this evaluation, Ms. Robertson and Mr. Butz have concluded that Noble-Cayman’s disclosure controls and procedures were effective as of December 31, 2019. Noble-Cayman’s disclosure controls and procedures are designed to ensure that information required to be disclosed by Noble-Cayman in the reports that it files with or submits to the SEC are recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and is accumulated and communicated to management as appropriate to allow timely decisions regarding required disclosure.
Changes in Internal Control Over Financial Reporting
There were no changes in Noble-Cayman’s internal control over financial reporting that occurred during the year ended December 31, 2019 that have materially affected, or are reasonably likely to materially affect, the internal control over financial reporting of Noble-Cayman.
Management’s Annual Report on Internal Control Over Financial Reporting
The management of Noble-Cayman is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Rule 13a-15(f) promulgated under the US Securities Exchange Act of 1934, as amended.
Internal control over financial reporting includes the controls themselves, monitoring (including internal auditing practices), and actions taken to correct deficiencies as identified. There are inherent limitations to the effectiveness of internal control over financial reporting, however well designed, including the possibility of human error and the possible circumvention or overriding of controls. The design of an internal control system is also based in part upon assumptions and judgments made by management about the likelihood of future events, and there can be no assurance that an internal control will be effective under all potential future conditions. As a result, even an effective system of internal controls can provide no more than reasonable assurance with respect to the fair presentation of financial statements and the processes under which they were prepared.
Under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission in 2013. Based on the assessment by management of Noble-Cayman, Noble-Cayman maintained effective internal control over financial reporting as of December 31, 2019.
PricewaterhouseCoopers LLP, the independent registered public accounting firm that audited our financial statements included in this Annual Report on Form 10-K, has audited the effectiveness of internal control over financial reporting as of December 31, 2019 as stated in their report, which is provided in Part II, Item 8, “Financial Statements and Supplementary Data” in this Annual Report on Form 10-K.
Item 9B.
Item 9B. Other Information.
None.
PART III
Item 10.
Item 10. Directors, Executive Officers and Corporate Governance.
The sections entitled “Election of Directors,” “Continuing Directors,” “Board Committees, Meetings and Other Governance Matters,” “Delinquent Section 16(a) Reports” and “Other Matters” appearing in the proxy statement for the 2020 annual general meeting of shareholders (the “2020 Proxy Statement”), will set forth certain information with respect to directors, certain corporate governance matters and reporting under Section 16(a) of the US Securities Exchange Act of 1934, as amended and are incorporated in this report by reference.
Executive Officers of the Registrant
The following table presents certain information as of February 20, 2020 with respect to our executive officers:
Julie J. Robertson was named Chairman of the Board, President and Chief Executive Officer of the Company in January 2018. Previously, Ms. Robertson served as Executive Vice President of the Company from February 2006 and as Senior Vice President - Administration from July 2001 to February 2006. Ms. Robertson also served continuously as Corporate Secretary of the Company from December 1993 until assuming the Chairman’s role in 2018. Ms. Robertson has also served as Vice President - Administration of Noble Drilling from 1996 to July 2001 and as Vice President - Administration of Noble Drilling Services Inc beginning in 1994. From 1989 to 1994, Ms. Robertson served consecutively as Manager of Benefits and Director of Human Resources for Noble Drilling Services Inc. Prior to 1989, Ms. Robertson served consecutively in the positions of Risk and Benefits Manager and Marketing Services Coordinator for a predecessor subsidiary of Noble, beginning in 1979.
Stephen M. Butz was named Executive Vice President and Chief Financial Officer of Noble Corporation in December 2019. Prior to joining Noble, from December 2014 until its merger with Ensco plc in April 2019, Mr. Butz served as Executive Vice President and Chief Financial Officer of Rowan Companies plc. From April 2005 through November 2014, Mr. Butz served in various roles at Hercules Offshore, Inc., most recently as Executive Vice President and Chief Financial Officer. Prior to that time, Mr. Butz worked as an equity research analyst covering various energy related industries and as a commercial banker.
William E. Turcotte was named Senior Vice President and General Counsel effective December 16, 2008. He was named Corporate Secretary in January 2018. Prior to joining Noble, Mr. Turcotte served as Senior Vice President, General Counsel and Corporate Secretary of Cornell Companies, Inc., a private corrections company, since March 2007. He served as Vice President, Associate General Counsel and Assistant Secretary of Transocean, Inc., an offshore oil and gas drilling contractor, from October 2005 to March 2007, and as Associate General Counsel and Assistant Secretary from January 2000 to October 2005. From 1992 to 2000, Mr. Turcotte served in various legal positions with Schlumberger Limited in Houston, Caracas and Paris. Mr. Turcotte was in private practice prior to joining Schlumberger.
Robert W. Eifler was named Senior Vice President, Commercial effective August 2019. Previously, Mr. Eifler served as our Senior Vice President, Marketing and Contracts from February 2019 to August 2019, and as our Vice President and General Manager - Marketing and Contracts from July 2017 to August 2019. Prior to that time, Mr. Eifler led Noble's marketing and contracts efforts for the Eastern Hemisphere while based in London. From November 2013 to March 2015, Mr. Eifler worked for Hercules Offshore, Inc., an offshore driller, as Director International Marketing. Mr. Eifler originally joined Noble in February 2005 as part of the management development program and held numerous operational and marketing roles with increasing responsibility around the world until joining Hercules in 2013.
Barry M. Smith was named Senior Vice President, Operations on June 3, 2019. Mr. Smith has over 30 years of experience in offshore rig operations and technical services. Mr. Smith was previously employed with Atwood Oceanics, Inc. beginning in 2006, where he held a number of operational positions until he was appointed Senior Vice President of Technical Services in 2015. Mr. Smith served in that capacity until October
2017, when Atwood was acquired. He managed his ranching and other business interests from November 2017 until he joined the Company. Prior to Atwood and for over 20 years, Mr. Smith held various operations related roles with Transocean Ltd.
Laura D. Campbell was named Vice President and Controller effective August 1, 2018. Ms. Campbell is also the Company's Principal Accounting Officer. Prior to joining Noble, Ms. Campbell served as Assistant Controller, Policy and Corporate Reporting at Chevron Phillips Chemical Company LLC, a petrochemical company, from March 2017 until July 2018. Prior to that time, Ms. Campbell worked at the Company from 2007 to March 2017, serving in the positions of Assistant Controller and Director of Corporate Accounting.
Code of Ethics
We have adopted a Code of Business Conduct and Ethics that applies to directors, officers and employees, including our principal executive officer, principal financial officer and principal accounting officer. Our Code of Business Conduct and Ethics is posted on our website at http://www.noblecorp.com in the “Corporate Governance” area. Changes to and waivers granted with respect to our Code of Business Conduct and Ethics related to the officers identified above, and our other executive officers and directors, that we are required to disclose pursuant to applicable rules and regulations of the SEC will also be posted on our website.
Item 11.
Item 11. Executive Compensation.
The sections entitled “2019 Compensation Information,” “Compensation Discussion and Analysis” and “Compensation Committee Report” appearing in the 2020 Proxy Statement set forth certain information with respect to the compensation of our management and our compensation committee report, and are incorporated in this report by reference.
Item 12.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.
The sections entitled “Equity Compensation Plan Information” and “Security Ownership of Certain Beneficial Owners and Management” appearing in the 2020 Proxy Statement set forth certain information with respect to securities authorized for issuance under equity compensation plans and the ownership of our voting securities and equity securities, and are incorporated in this report by reference.
Item 13.
Item 13. Certain Relationships and Related Transactions and Director Independence.
The sections entitled “Board Independence” and “Policies and Procedures Relating to Transactions with Related Persons” appearing in the 2020 Proxy Statement set forth certain information with respect to director independence and transactions with related persons, and are incorporated in this report by reference.
Item 14.
Item 14. Principal Accounting Fees and Services.
The section entitled “Auditors” appearing in the 2020 Proxy Statement sets forth certain information with respect to accounting fees and services, and is incorporated in this report by reference.
PART IV
Item 15.
Item 15. Exhibits, Financial Statement Schedules.
(a)
The following documents are filed as part of this report:
(1)
A list of the financial statements filed as a part of this report is set forth in Item 8 on page 47 and is incorporated herein by reference.
(2)
Financial Statement Schedules:
All schedules are omitted because they are either not applicable or required information is shown in the financial statements or notes thereto.
(3)
Exhibits:
The information required by this Item 15(a)(3) is set forth in the Index to Exhibits accompanying this Annual Report on Form 10-K and is incorporated herein by reference.
Item 16. Form 10-K Summary.
None.
Index to Exhibits
______________________________________________________
*
Management contract or compensatory plan or arrangement.
+
Furnished in accordance with Item 601(b)(32)(ii) of Regulation S-K.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
Noble Corporation plc, a company registered under the laws of England and Wales
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
Noble Corporation, a Cayman Islands company
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.