ITEM 1. BUSINESS
Overview
Rowan Companies plc is a public limited company incorporated under the laws of England and Wales and listed on the NYSE. The terms “Rowan,” “Rowan plc,” “Company,” “we,” “us” and “our” are used to refer to Rowan plc and its consolidated subsidiaries, unless the context otherwise requires. Intercompany balances and transactions have been eliminated in consolidation.
We are a global provider of offshore contract drilling services to the oil and gas industry, with a focus on high-specification and premium jack-up rigs and ultra-deepwater drillships. Prior to ARO commencing operations on October 17, 2017 (see "ARO Joint Venture" below), we operated in two segments: Deepwater and Jack-ups; however, we now operate in three segments: Deepwater, Jack-ups and ARO. The Deepwater segment includes four ultra-deepwater drillships. The Jack-ups segment is composed of 23 self-elevating jack-up rigs, including two LeTourneau Super 116E jack-up rigs purchased in January 2018 (see Note 19 to our consolidated financial statements in Part II, Item 8 of this Annual Report on Form 10-K) and the impact of the various arrangements with ARO (see Note 1 and 3 to our consolidated financial statements in Part II, Item 8 of this Annual Report on Form 10-K). The ARO segment is a 50/50 joint venture with Rowan and Saudi Aramco that owns a fleet of five self-elevating jack-up rigs for operation in the Arabian Gulf for Saudi Aramco. Our fleet operates worldwide, including the US GOM, the U.K. and Norwegian sectors of the North Sea, the Middle East and Trinidad.
As of February 13, 2018, the date of our most recent Fleet Status Report, one of our four drillships was under contract in the US GOM. We had three jack-up rigs under contract in the North Sea, seven under contract in the Middle East, three under contract in Trinidad and one under contract in the US GOM. Additionally, we had five marketed jack-up rigs and three marketed drillships without contracts as well as two cold-stacked jack-up rigs and two jack-ups which have not yet been placed in service for Rowan, the two LeTourneau Super 116E jack-up rigs purchased in January 2018.
We contract our drilling rigs, related equipment and work crews primarily on a “day rate” basis. Under day rate contracts, we generally receive a fixed amount per day for each day we are performing drilling or related services. In addition, our customers may pay all or a portion of the cost of moving our equipment and personnel to and from the well site. Contracts generally range in duration from one month to multiple years.
For information with respect to our revenue, operating income and assets by operating segment, and revenue and long-lived assets by geographic area, see Note 13 to our consolidated financial statements in Part II, Item 8 of this Annual Report on Form 10-K.
ARO Joint Venture
On November 21, 2016, Rowan and Saudi Aramco, through their subsidiaries, entered into a Shareholders’ Agreement to create a 50/50 joint venture to own, manage and operate offshore drilling units in Saudi Arabia. The new entity, ARO, was formed in May 2017 and commenced operations on October 17, 2017. For additional information see "ARO Joint Venture" in Note 1 and Note 3 to our consolidated financial statements in Part II, Item 8 of this Annual Report on Form 10-K. The information discussed therein is incorporated by reference into this Part I, Item 1.
Drilling Fleet
We believe our high-specification and premium jack-up fleet and ultra-deepwater drillships are well positioned to serve the worldwide market, including requirements for HPHT wells in harsh and benign locations. As of February 13, 2018, our drilling fleet consists of the following:
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Four ultra-deepwater drillships;
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Seventeen high-specification jack-up rigs; and
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Six premium jack-up rigs.
We use the term “high-specification” to describe jack-ups with a hook-load capacity of at least two million pounds and the term “premium” to denote independent-leg cantilever jack-ups that can operate in at least 300 feet of water in benign environments.
Ultra-Deepwater Drillships - Our ultra-deepwater drillships are self-propelled vessels equipped with computer-controlled dynamic-positioning systems, which allow them to maintain position without anchors using their onboard propulsion and station-keeping systems. Drillships have greater variable loading capacity than semisubmersible rigs, enabling them to carry more supplies on board and, thus, making them better suited for drilling in deep water in remote locations. Our drillships are equipped with two drilling stations within a single derrick, allowing the drillships to perform preparatory activities off-line and potentially simultaneous
drilling tasks during certain stages of drilling, subject to legal restrictions in various jurisdictions, enabling increased drilling efficiency particularly during the initial stages of a well. In addition, our drillships are equipped to drill in 12,000-foot water depths, are equipped with 2,500,000-pound hook-load capability and are capable of drilling HPHT wells to 40,000-foot depths. Each is equipped with two fully redundant blowout preventers, which are designed to prevent environmental and safety issues as well as significantly reduce non-productive time associated with repair and maintenance. In addition, each drillship is equipped with an active-heave compensating crane for deployment of subsea equipment simultaneous to drilling station operations. The sum total of these and other advanced features make the drillships very attractive to our customers.
Jack-up Rigs - Our jack-ups are capable of drilling wells to maximum depths ranging from 25,000 to 40,000 feet and in maximum water depths ranging from 300 to 550 feet, depending on rig size, location and outfitting. All of our high-specification rigs are equipped with or can readily accommodate the high-pressure circulation and pressure control equipment that is necessary for HPHT operations. Each of our jack-ups is designed with a hull that is fully equipped to serve as a drilling platform supported by three independently elevating legs. The rig is towed to the drilling site where the legs are lowered into and penetrate the ocean floor, and the hull raises itself out of the water up to the elevation required to drill the well using a self-contained rack and pinion system.
Our three N-Class rigs are capable of drilling in water depths to 435 feet in harsh environments such as the North Sea depending on location and outfitting. The N-Class rigs, which were designed for operation in the highly regulated Norwegian sector of the North Sea, can be equipped to perform drilling and production operations simultaneously.
Three of our four Super Gorilla class rigs can be equipped for simultaneous drilling and production operations. They can operate year-round in 400 feet of water in harsh environments such as the North Sea. The Bob Palmer, our fourth Super Gorilla class rig, is an enhanced version of the Super Gorilla class jack-up designated as Super Gorilla XL. The Bob Palmer can operate in water depths up to 550 feet in normally benign environments like the US GOM and the Middle East or in water depths up to 400 feet in harsh environments such as the North Sea.
Our three 240C class rigs were designed for HPHT drilling in water depths up to 400 feet in benign environments, depending on rig size, location and outfitting, and are equipped with a hook-load capacity of 2.5 million pounds. The rigs are also capable of operating in harsh environments at reduced water depths compared to their benign environment ratings.
Our four EXL class rigs enable HPHT drilling in water depths up to 350 feet and are equipped with a hook-load capacity of two million pounds.
We recently purchased two Super 116E class rigs. These are premium rigs capable of drilling in water depths up to 350 feet and are equipped with a hook-load capacity of 1.5 million pounds.
Our two remaining Tarzan Class rigs are specifically designed for deep-well, HPHT drilling in up to 300 feet of water in benign environments.
Our four remaining 116C class rigs are premium rigs capable of operating in water depths up to 300 feet in benign environments. Rowan has three of these rigs under contract directly with Saudi Aramco that are managed by ARO. The fourth rig is cold-stacked.
Our one remaining Gorilla class rig, the Rowan Gorilla IV, was designed as a heavier-duty class of jack-up rig capable of operating in water depths to 450 feet in benign environments.
In November 2017, we sold one of our older rigs in our jack-up fleet, the Cecil Provine, under an agreement that prohibits its future use as a drilling unit. In October 2017, we also sold one premium and two high-specification jack-ups to ARO. See Note 1 to our consolidated financial statements in Part II, Item 8 of this Annual Report on Form 10-K.
See Part I, Item 2, “Properties,” of this Annual Report on Form 10-K for additional information regarding our fleet.
Our operations are subject to many uncertainties and hazards. See Part I, Item 1A, “Risk Factors,” of this Annual Report on Form 10-K for additional information.
Contracts
Our drilling contracts generally provide for a fixed amount of compensation per day (day rate), and are either “well-to-well,” “multiple-well” or "fixed-term" generally ranging from one month to several years. Well-to-well contracts are typically cancellable by either party upon completion of drilling. Fixed-term contracts usually contain a termination provision such that either party may terminate if drilling operations are suspended for extended periods as a result of events of force majeure. While many fixed-term contracts are for relatively short periods of three months or less, others are for one or more years, and all can continue for periods longer than the original terms. Well-to-well contracts can be extended over multiple series of wells. Many drilling contracts
contain renewal or extension provisions exercisable at the option of the customer at mutually agreeable rates. Some of our drilling contracts provide for separate lump-sum payments for rig mobilization and demobilization. We recognize certain lump-sum fees and related expenses over the primary contract term. We recognize reimbursement of certain costs as revenue and expenses at the time they are incurred. Our contracts for work generally provide for payment in USD except for amounts required by applicable law to be paid in the local currency or amounts required to meet local expenses.
A number of factors affect our ability to obtain contracts at profitable rates within a given region. Such factors, which are discussed further under “Competition” in this Part I, Item 1 of this Annual Report on Form 10-K and in “Risk Factors” included in Part I, Item 1A
ITEM 1A. RISK FACTORS
There are numerous factors that affect our business and operating results, many of which are beyond our control. The following is a description of significant factors that might cause our future operating results to differ materially from those currently expected. The risks described below are not the only risks facing our Company.
Our business depends on the level of activity in the offshore oil and gas industry, which is significantly affected by declines in oil or gas prices and reduced demand for oil and gas products.
Our business depends heavily on a variety of economic and political factors and the level of oil and gas activity worldwide. Sustained declines in oil or natural gas prices, combined with market expectations of a prolonged weakened global market, have caused oil and gas companies to significantly reduce their exploration, development and production activities, thereby decreasing demand for offshore drilling services and leading to lower rig utilization and day rates for our services. Oil and natural gas prices have historically been very volatile, and our drilling operations have in the past suffered through long periods of weak market conditions.
Demand for our drilling services depends on many factors beyond our control, including:
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worldwide demand for and prices of oil and natural gas, and expectations regarding future energy prices;
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the supply of drilling units in the worldwide fleet versus demand;
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the level of exploration and development expenditures by energy companies and their ability to raise capital;
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the willingness and ability of the OPEC to limit production levels and influence prices;
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the level of production in non-OPEC countries;
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the effect of economic sanctions that affect the energy industry;
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the general economy, including inflation, interest rates and changes in the rate of economic growth;
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the condition of global capital markets;
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adverse sea, weather and climate conditions in our principal operating areas, including possible disruption of exploration and development activities due to loop currents, hurricanes and other severe sea and weather conditions;
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the cost of exploring for, developing, producing and delivering oil and natural gas;
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environmental and other laws and regulations;
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policies of various governments regarding exploration and development of oil and natural gas reserves;
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nationalization of assets or workforce and/or confiscation of assets;
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worldwide tax policies and treaties;
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political and military conflicts in oil-producing areas and the effects of terrorism;
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increased supply of oil and gas from onshore development and relative cost of offshore drilling versus onshore oil and gas production;
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the development and exploitation of alternative fuels and energy sources including the growing demand, often government-mandated, for electric powered vehicles; and
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merger, divestiture, restructuring and consolidation of our customers and competitors and their assets.
Adverse developments affecting the industry as a result of one or more of these factors, including any further decline in oil or gas prices or the failure of oil or gas prices to increase, a global recession, continued declines in demand for oil and gas products, increased oversupply of drilling units, and increased regulation of drilling and production, would adversely affect our business, financial condition and results of operations.
The success of our business is dependent upon our ability to secure contracts for our drilling units at sufficient day rates. Depressed oil and gas prices and an oversupply of drilling units have led to further reductions in rig utilization and day rates, which may materially impact our profitability.
Our ability to meet our cash flow obligations depends on our ability to secure ongoing work for our drilling units at sufficient day rates. As of February 13, 2018, we had nine jack-up drilling units without contracts (including two cold-stacked and two recently purchased jack-ups which have not yet been placed in service for Rowan, the two LeTourneau Super 116E jack-up rigs); eleven with contract terms ending in 2018; and three with contract terms ending in 2019; and three of our four drillships without contracts; one of our drillships has a contract ending in 2018. Given current market conditions, future demand for offshore drilling units and day rates may continue to remain at low levels, possibly for an extended period of time. Failure to secure profitable contracts for our drilling units could negatively impact our operating results and financial position, impair our ability to generate sufficient cash flow to fund our capital expenditures and/or meet our other obligations.
Prior to the downturn in the drilling sector, the industry experienced a significant increase in construction activity. The resulting increase in supply of newbuild drilling units, combined with the decrease in demand for offshore drilling services, has led to an oversupply of drilling units and further declines in utilization and day rates that is expected to continue for some time. According to industry sources, there were 463 marketed jack-up rigs worldwide as of February 13, 2018, an additional 91 units that are under construction or on order and 201 marketed floaters (drillships and semi-submersible) worldwide, with an additional 42 units that are under construction or on order. (We define marketed rigs as all rigs that are not cold-stacked.) A continued decline in utilization and day rates would further impact our revenue and profitability.
A further decline in the market for contract drilling services could result in additional asset impairment charges.
We recognized asset impairment charges on our jack-up drilling units aggregating approximately $330 million in 2015 and $34 million in 2016, or approximately 4% and 0.5%, respectively, of our fixed asset carrying values. Prolonged periods of low utilization and day rates, the cold-stacking of idle assets, or the sale of assets below their then carrying value could result in the recognition of additional impairment charges on our drilling units if future cash flow estimates, based upon information available to management at the time, indicate that their carrying value may not be recoverable. See “Impairment of Long-lived Assets” in Note 2 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Annual Report on Form 10-K for additional information.
We are subject to operating risks that could result in environmental damage, property loss, personal injury, death, business interruptions and other losses.
Our drilling operations are subject to many operational hazards such as blowouts, explosions, fires, collisions, punch-throughs (i.e., when one leg of a jack-up rig breaks through the hard crust of the ocean floor, placing stress on the other legs), mechanical or technological failures, navigation errors, or equipment defects that could increase the likelihood of accidents. Accidents can result in:
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serious damage to or destruction of property and equipment;
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personal injury or death;
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costly delays or cancellations of drilling operations;
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interruption or cessation of day rate revenue;
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uncompensated downtime;
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reduced day rates;
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significant impairment of producing wells, leased properties, pipelines or underground geological formations;
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damage to fisheries and pollution of the marine and coastal environment; and
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fines and penalties.
Our drilling operations are also subject to marine hazards, whether at drilling sites or while equipment is under tow, such as a vessel capsizing, sinking, colliding or grounding. In addition, raising and lowering jack-up rigs and drilling into high-pressure formations are complex, hazardous activities, and we periodically encounter problems. Any ongoing change in weather or sea patterns or climate conditions could increase the adverse impact of marine hazards.
In past years, we have experienced some of the types of incidents described above, including punch-throughs and towing accidents resulting in lost or damaged equipment and high-pressure drilling accidents resulting in lost or damaged formations. Any future such events could result in operating losses and have a material impact on our business.
The global nature of our operations involves additional risks, particularly in certain jurisdictions.
Our operations are diversified geographically although we have a concentrated presence in certain locations. Foreign operations are often subject to additional political, economic and other uncertainties, such as with respect to taxation policies, customs restrictions, local content requirements, regulatory requirements, currency convertibility and repatriation restrictions, security threats including terrorism, piracy, and the risk of asset expropriation. Political unrest and regulatory restrictions could halt operations or impact us in other unforeseen ways, especially in areas of concentrated presence (see Note 13 to our Consolidated Financial Statements in Part II, Item 8 of this Annual Report on Form 10-K).
Many countries have regulations or policies requiring or rewarding the participation of local companies and individuals in petroleum-related activities. Such participation requirements can include, without limitation, the ownership of oil and gas concessions, the hiring of local agents and partners, the procurement of goods and services from local sources, and the employment of local workers. The requirements can also include co-ownership of our drilling units, in whole or in part, by home country companies or citizens and /or require reflagging of our drilling units under the flag of the home country. The governments of many of these countries have become increasingly active in requiring higher levels of local participation which may increase our costs and risks of operating in these regions, thereby limiting our ability to enter into, relocate from, or compete in these regions.
In addition, our inability to obtain visas and work permits for our employees in the jurisdictions in which we operate on a timely basis could delay or interrupt our operations resulting in an adverse impact on our business. Further, governmental restrictions in some jurisdictions may make it difficult for us to move our personnel, assets and operations in and out of these regions without delays or downtime.
In certain jurisdictions where legal protections may be less available to us, we assume greater risk that our customer may terminate contracts without cause on short notice, contractually or by governmental action. Additionally, operations in certain areas, such as the North Sea and US GOM, are highly regulated and have higher compliance and operating costs in general.
Although we are a U.K. company, a significant majority of our revenue and expenses are transacted in USD, which is our functional currency. However, in certain countries in which we operate, local laws or contracts may require us to receive some portion of payment in the local currency. We are exposed to foreign currency exchange risk to the extent the amount of our monetary assets denominated in the foreign currency differs from our obligations in that foreign currency. In order to mitigate the effect of exchange rate risk, we attempt to limit foreign currency holdings to the extent they are needed to pay liabilities denominated in the foreign currency. We can provide no assurance that we will be able to convert into USD or utilize such foreign currency holdings due to controls over currency exchange or controls over the repatriation of income or capital. For more information, see “Assets and Liabilities Measured at Fair Value on a Recurring Basis” in Note 7 to our Consolidated Financial Statements in Part II, Item 8 of this Annual Report on Form 10-K.
The offshore drilling industry is highly competitive and cyclical, with intense price competition.
The offshore contract drilling industry is a highly competitive and cyclical business characterized by numerous competitors, high capital and operating costs and evolving capability of newer rigs. Drilling contracts are often awarded on a competitive-bid basis, and intense price competition, rig availability, location and suitability, experience of the workforce, efficiency, safety performance record, technical capability and condition of equipment, operating integrity, reputation, industry standing, and client relations are all factors in determining which contractor is awarded a contract. Our future success and profitability will partly depend upon our ability to keep pace with our customers’ demands with respect to these factors.
In addition to intense competition, our industry has historically been cyclical. The contract drilling industry is currently in a period of low demand for offshore drilling services and excess rig supply, resulting from a prolonged period of weak oil and gas prices and reduced worldwide drilling activity. These conditions have intensified the competition in the industry and put significant downward pressure on day rates. As a result, we may be unable to secure profitable contracts for our drilling units, we may have to contract our rigs at substantially lower rates for long periods of time, enter into nontraditional fee arrangements, accept less favorable contract terms or idle or cold-stack some of our drilling units, all of which would adversely affect our operating results, cash flows and financial position.
We may experience reduced profitability if our customers terminate or seek to renegotiate our drilling contracts, and our backlog of drilling revenue may not be fully realized.
We may be subject to the increased risk of our customers seeking to terminate or renegotiate their contracts. Our customers’ ability to perform their obligations under drilling contracts with us may also be adversely affected by their own financial position, restricted credit markets and the current industry downturn. If our customers cancel or are unable to renew some of their contracts and we are unable to secure new contracts on a timely basis and on substantially similar terms, if contracts are disputed or suspended for
an extended period of time, or if a number of our contracts are renegotiated, such events would adversely affect our business, financial condition and results of operations.
Most of our term drilling contracts may be canceled by the customer without penalty upon the occurrence of events beyond our control such as the loss or destruction of the drilling unit, or the suspension of drilling operations for a specified period of time as a result of a breakdown of major equipment. While most of our contracts require the customer to pay a termination fee in the event of an early cancellation without cause, early termination payments may not fully compensate us for the loss of the contract and could result in the drilling unit becoming idle or cold-stacked for an extended period of time. If we or our customers are unable to perform under existing contracts for any reason or replace terminated contracts with new contracts having less favorable terms, our backlog of estimated revenue would decline, adversely affecting our financial results.
We must make substantial capital and operating expenditures to maintain and upgrade our drilling fleet.
Our business is highly capital intensive and dependent on having sufficient cash flow and or available sources of financing in order to fund capital expenditure requirements. We can provide no assurance that we will have access to adequate or economical sources of capital to fund necessary capital and operating expenditures.
We have and will likely continue to have certain customer concentrations, and the loss of a significant customer would adversely impact our financial results.
A concentration of customers increases the risks associated with any possible (i) termination or nonperformance of drilling contracts, (ii) failure to renew contracts or award new contracts, or (iii) reduction of our customers' drilling programs. In 2017, three customers accounted for 60% of our consolidated revenue (Saudi Aramco - 29%; Anadarko - 17%; Cobalt - 14%). The loss or material reduction of business from a significant customer would have an adverse impact on our results of operations and cash flows. Moreover, our drilling contracts subject us to counterparty risks. The ability of each of our counterparties to perform its obligations under a contract with us will depend on a number of factors that are beyond our control such as the overall financial condition of the counterparty. Should a significant counterparty fail to honor its obligations under an agreement with us, we could sustain losses, which could have a material adverse effect on our business, financial condition and results of operations.
If we or our customers are unable to acquire or renew permits and approvals required for drilling operations, we may be forced to suspend or cease our operations, and our profitability may be reduced.
Crude oil and natural gas exploration and production operations require numerous permits and approvals for us and our customers from governmental agencies in the areas in which we operate. In addition, many governmental agencies have increased regulatory oversight and permitting requirements in recent years. If we or our customers are not able to obtain necessary permits and approvals in a timely manner, our operations will be adversely affected. Obtaining all necessary permits and approvals may necessitate substantial expenditures to comply with the requirements of these permits and approvals. Future changes to these permits or approvals or any adverse change in the interpretation of existing permits and approvals could result in further unexpected, substantial expenditures. In addition, such regulatory requirements and restrictions could also delay or curtail our operations, require us to make substantial expenditures to meet compliance requirements, and could have a material impact on our financial condition or results of operations and may create a risk of expensive delays or loss of value if a project is unable to function as planned.
For example, the U.S. Bureau of Ocean Energy Management and BSEE, have implemented significant environmental and safety regulations applicable to drilling operations in the US GOM. These regulations have at times adversely impacted the ability of our customers to obtain necessary permits and approval on a timely basis and/or to continue operations uninterrupted under existing permits.
We may not realize the expected benefits of the ARO joint venture and it may introduce additional risks to our business.
In November 2016, Rowan and Saudi Aramco announced plans to form a 50/50 joint venture with Rowan and Saudi Aramco each selling existing drilling units and contributing capital as the foundation of the new company. The new entity, ARO, commenced operations on October 17, 2017, and is expected to add up to 20 newbuild jack-up rigs to its fleet over ten years commencing as early as 2021. There can be no assurance that the new jack-up rigs will begin operations as anticipated or we will realize the expected return on our investment. We may also experience difficulty jointly managing the venture, and integrating our existing employees, business systems, technologies and services with those of Saudi Aramco in order to operate the joint venture efficiently. Further, in the event ARO has insufficient cash from operations or is unable to obtain third party financing, we may periodically be required to make additional capital contributions to ARO, up to a maximum aggregate contribution of $1.25 billion, which could affect our liquidity position. As a result of these risks, it may take longer than expected for us to realize the expected returns from ARO or such returns may ultimately be less than anticipated. Additionally, if we are unable to make any required contributions, our ownership in ARO could be diluted which could hinder our ability to effectively manage ARO and harm our operating results or financial condition.
Operating through ARO, in which we have a shared interest, may also result in us having less control over many decisions made with respect to projects and internal controls relating to projects. ARO may not apply the same internal controls and internal control reporting that we follow. As a result, internal control issues may arise, which could have a material adverse effect on our financial condition and results of operations. Additionally, in order to establish or preserve our relationship with our joint venture partner, we may agree to risks and contributions of resources that are proportionately greater than the returns we could receive, which could reduce our income and return on our investment in ARO compared to what we may traditionally require in other areas of our business.
Increases in regulatory requirements could significantly increase our costs or delay our operations.
Many aspects of our operations are subject to governmental regulation, including equipping and operating vessels, drilling practices and methods, and taxation. For example, operations in certain areas, such as the US GOM and the North Sea, are highly regulated and have higher compliance and operating costs in general. We may be required to make significant expenditures in order to comply with existing or new governmental laws and regulations. It is also possible that such laws and regulations may in the future add significantly to our operating costs or result in a reduction of revenue associated with downtime required to implement regulatory requirements.
Oil and gas operations in many of the locations in which we operate are subject to regulation with respect to well design, casing and cementing and well control procedures, as well as rules requiring operators to systematically identify risks and establish safeguards against those risks through a comprehensive safety and environmental management system, or SEMS. New regulations continue to be implemented, including rules regarding drilling systems and equipment, such as blowout preventer and well-control systems and lifesaving systems, as well as rules regarding employee training, engaging personnel in safety management and requiring third-party audits of SEMS programs. Such new regulations may require modifications or enhancements to existing systems and equipment, or require new equipment, and could increase our operating costs and cause downtime for our units if we are required to take any of them out of service between scheduled surveys or inspections, or if we are required to extend scheduled surveys or inspections to meet any such new requirements. Additional governmental regulations concerning licensing, taxation, equipment specifications, training requirements or other matters could increase the costs of our operations and could reduce exploration activity in the areas in which we operate.
Governments in some 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 industry. These governmental regulations may limit or substantially increase the cost of drilling activity in an operating area generally. The modification of existing laws or regulations or the adoption of new laws or regulations curtailing exploratory or developmental drilling for oil and gas for economic, environmental or other reasons could materially and adversely affect our operations by limiting drilling opportunities. In addition, the offshore drilling industry is highly dependent on demand for services from the oil and gas industry and accordingly, regulations of the production and transportation of oil and gas generally could impact demand for our services.
Regulation of greenhouse gases and climate change could have a negative impact on our business.
Governments around the world are increasingly focused on enacting laws and regulations regarding climate change and regulation of greenhouse gases. Lawmakers and regulators in the jurisdictions where we operate have proposed or enacted regulations requiring reporting of greenhouse gas emissions and the restriction thereof. In addition, efforts have been made and continue to be made in the international community toward the adoption of international treaties or protocols that would address global climate change issues and impose reductions of hydrocarbon-based fuels. Laws or regulations incentivizing or mandating the use of alternative energy sources such as wind power and solar energy have also been enacted in certain jurisdictions. Numerous large cities globally and a few countries have mandated conversion from internal combustion engine powered vehicles to electric-powered vehicles and placed restrictions on non-public transportation, thereby reducing future demand for oil which could have a material impact on our business. Laws, regulations, treaties and international agreements related to greenhouse gases and climate change may unfavorably impact our business, our suppliers and our customers, and result in increased compliance costs, operating restrictions and could reduce drilling in the offshore oil and gas industry, all of which would have a material adverse impact on our business.
Our drilling units are subject to damage or destruction by severe weather, and our drilling operations may be affected by severe weather conditions.
Our drilling rigs are located in areas that frequently experience hurricanes and other forms of severe weather conditions. These conditions can cause damage or destruction to our drilling units. Further, high winds and turbulent seas can cause us to suspend operations on drilling units for significant periods of time. Even if our drilling units are not damaged or lost due to severe weather, we may experience disruptions in our operations due to evacuations, reduced ability to transport personnel or necessary supplies to the drilling unit, or damage to our customers’ platforms and other related facilities. Additionally, our customers may not choose to contract our rigs for use during hurricane season, particularly in the US GOM. Future severe weather could result in the loss
or damage to our rigs or curtailment of our operations, which could adversely affect our financial position, results of operations and cash flows.
Taxing authorities may challenge our tax positions, and we may not be able to realize expected benefits.
We are subject to tax laws, regulations and treaties in many jurisdictions. Changes to these laws or interpretations could affect the taxes we pay in various jurisdictions. Our tax positions are subject to audit by relevant tax authorities who may disagree with our interpretations or assessments of the effects of tax laws, treaties, or regulations, or their applicability to our corporate structure or certain of our transactions we have undertaken. We could therefore incur material amounts of income tax cost in excess of currently recorded amounts if our positions are challenged and we are unsuccessful in defending them.
Changes in or non-compliance with tax laws and changes to our income tax estimates could adversely impact our financial results.
In 2012, we changed our legal domicile to the U.K. There have been legislative proposals in the U.S. that attempted to treat companies that have undertaken similar transactions as U.S. corporations subject to U.S. taxes or to limit the tax deductions or tax credits available to U.S. subsidiaries of these corporations. The realization of the expected tax benefits of our redomestication could be impacted by changes in tax laws, tax treaties or tax regulations or the interpretation or enforcement thereof or differing interpretation or enforcement of applicable law by the IRS or other tax authorities. Changes in our effective tax rates as determined from time to time, the inability to realize anticipated tax benefits, or the imposition of additional taxes could have a material impact on our results of operations, financial position and cash flows. Our future effective tax rates could be adversely affected by changes in the valuation of our deferred tax assets and liabilities, repatriation of earnings from the non-U.S. subsidiaries of RCI, a wholly owned, indirect subsidiary of the Company, or changes in applicable regulations and accounting principles.
Changes in our recorded tax estimates (including estimated reserves for uncertain tax positions) may have a material impact on our results of operations, financial position and cash flows. We do not provide for deferred income taxes on certain undistributed earnings of non-U.K. subsidiaries. No subsidiary of RCI has a plan to distribute earnings to RCI in a manner that would cause those earnings to be subject to U.S., U.K. or other local country taxation.
On December 22, 2017, the U.S. government enacted tax legislation commonly referred to as the U.S. Tax Act. The U.S. Tax Act significantly changes U.S. corporate income tax laws including but not limited to (i) reducing the U.S. corporate income tax rate from 35% to 21% starting in 2018 (ii) requiring a one-time transition tax on mandatory deemed repatriation of certain unremitted non-U.S. earnings as of December 31, 2017, (iii) changing how non-U.S. subsidiaries are taxed in the U.S. as of January 1, 2017, (iv) eliminating the carryback abilities and establishing an 80% limitation on the annual utilization of net operating losses after December 31, 2017, (v) establishing new limitations on interest deductions as of January 1, 2018 and (vi) requiring additional U.S. tax on certain payments by U.S. subsidiaries to non-U.S. subsidiaries if such payments are subject to reduced rates of U.S. withholding tax under a treaty after December 31, 2017. As we do not have all the necessary information to analyze all effects of this tax reform, our financial statements include provisional amounts, which we believe represents a reasonable estimate of the accounting implications of this tax reform.
The U.S. Tax Act requires complex computations to be performed that were not previously provided in U.S. tax law, significant judgments to be made in interpretation of the U.S. Tax Act, and the preparation and analysis of information not previously relevant or regularly produced. As such, the application of accounting guidance for such items is currently uncertain. As a result, we have provided a provisional estimate on the effect of the U.S. Tax Act in our financial statements. As additional regulatory guidance is issued by the applicable taxing authorities, as accounting treatment is clarified, as we perform additional analysis on the application of the law, and as we refine estimates in calculating the effect, our final analysis, which will be recorded in the period completed, may be different from our current provisional amounts.
Political disturbances, war, or terrorist attacks and changes in global trade policies and economic sanctions could adversely impact our operations.
Our operations are subject to political and economic risks and uncertainties, including instability resulting from civil unrest, political demonstrations, mass strikes, or an escalation or additional outbreak of armed hostilities or other crises in oil or natural gas producing areas, which may result in extended business interruptions, suspended operations and danger to our employees, or result in claims by our customers of a force majeure situation and payment disputes. Additionally, we are subject to risks of terrorism, piracy, political instability, hostilities, expropriation, confiscation or deprivation of our assets or military action impacting our operations, assets or financial performance in many of our areas of operations.
Operating and maintenance costs of our drilling units may be significant and could have an adverse effect on the profitability of our contracts. In addition, operational interruptions or maintenance or repair work may cause our customers to suspend or reduce payment of day rates until operation is resumed, which may lead to loss of revenue or termination or renegotiation of the drilling contract.
Most of our drilling contracts provide for the payment of a fixed day rate during periods of operation and reduced day rates during periods of other activities. Given current market conditions, we may not be able to negotiate day rates sufficient to cover increased or unanticipated costs. Our operating expenses and maintenance costs can be unpredictable and depend on a variety of factors including: crew costs, costs of provisions, equipment, insurance, maintenance and repairs, customer and regulatory requirements, and shipyard costs, many of which are beyond our control. Our profit margins may therefore vary over the terms of our contracts, which could adversely affect our financial position, results of operations and cash flows.
Our customers may be entitled to pay a waiting, or standby, rate lower than the full operational day rate if a drilling unit is idle for reasons that are not related to the ability of the rig to operate. In addition, if a drilling unit is taken out of service for maintenance and repair for a period of time exceeding the scheduled maintenance periods set forth in the drilling contract, we may not be entitled to payment of day rates until the unit is able to work. If the interruption of operations were to exceed a determined period, our customers may 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 could materially adversely affect our business, financial condition and results of operations.
Our rig operating and maintenance costs include fixed costs that will not decline in proportion to decreases in rig utilization and day rates.
We do not expect our rig operating and maintenance costs to decline proportionately when rigs are not in service or when day rates decline. Fixed costs continue to accrue during out-of-service periods (such as shipyard stays and rig mobilizations preceding a contract), which represented approximately 6.8% of our available rig days in 2017. Operating revenue may fluctuate as rigs are recontracted at prevailing market rates upon termination of a contract, but costs for operating a rig are generally fixed or only slightly variable regardless of the day rate being earned. Additionally, if our rigs are idle between contracts, we typically continue to incur operating and personnel costs because the crew is retained to prepare the rig for its next contract. During times of reduced activity, reductions in costs may not be immediate as some crew members may be required to assist in the rig's removal from service. Moreover, as our rigs are mobilized from one geographic location to another, the labor and other operating and maintenance costs may increase significantly.
We may have difficulty obtaining or maintaining insurance in the future, and some of our losses may not be covered by insurance.
We maintain insurance coverage for damage to our drilling rigs, third-party liability, workers’ compensation and employers’ liability, sudden and accidental pollution, and other types of loss or damage. There are some losses, however, for which insurance may not be available or only available at much higher prices. For example, we do not currently maintain named windstorm physical damage coverage on any of our drilling units located in the US GOM.
We can provide no assurance that our insurance coverage will adequately protect us against liability from potential consequences and damages, or that we will be able to maintain adequate insurance in the future. A significant event which is not adequately covered by insurance and /or the failure of one or more of our insurance providers to meet claim obligations or losses or liabilities resulting from uninsured or underinsured events could have material adverse affects on our financial position, results of operations and cash flows.
Our contractual indemnification provisions may not be sufficient to cover our liabilities.
Our drilling contracts provide for varying levels of indemnification and allocation of liabilities between the parties with respect to liabilities resulting from various hazards associated with the drilling industry, such as loss of well control, well-bore pollution and damage to subsurface reservoirs and injury or death to personnel. The degree of indemnification we may receive from operators varies from contract to contract based on market conditions and customer requirements existing when the contract was negotiated, and recovery is dependent on the customer's financial condition. Our drilling contracts generally indemnify us for injuries and death of our customers’ employees and loss or damage to our customers’ property. Our service agreements generally indemnify us for injuries and death of our service providers’ employees. However, the enforceability of our indemnities may be subject to differing interpretations, or further limited or prohibited under applicable law, particularly in cases of gross negligence, willful misconduct, punitive damages or punitive fines and/or penalties. The failure of a customer to meet its indemnification obligations, or losses or liabilities resulting from events excluded from or unenforceable under contractual indemnification obligations would adversely affect our financial position, results of operations and cash flows.
Our information technology systems are subject to cybersecurity risks and threats.
We depend heavily on technologies, systems and networks that we manage, and others that are managed by our third-party service and equipment providers or customers, to conduct our business and operations. Cybersecurity risks and threats to such systems continue to grow and may be difficult to anticipate, prevent, identify or mitigate. If any of our, our service providers' or our customers' security systems prove to be insufficient, we could be adversely affected by having our business and financial systems compromised, our companies’, employees’, vendors’ or customers’ confidential or proprietary information altered, lost or stolen, or our (or our customers’) business operations, financial systems or safety procedures disrupted, degraded or damaged. A breach or failure could also result in injury (financial or otherwise) to people, loss of control of, or damage to, our (or our customers’) assets, harm to the environment, reputational damage, breaches of laws or regulations, litigation and other legal liabilities. In addition, we may incur significant costs to prevent, respond to or mitigate cybersecurity risks or events and to defend against any investigations, litigation or other proceedings that may follow such events. Such a failure or breach of our systems could adversely and materially impact our business operations, financial position, results of operations and cash flows.
Failure to comply with anti-corruption and anti-bribery laws could result in fines, criminal penalties and drilling contract terminations and could have an adverse impact on our business.
The FCPA, the UK Bribery Act and similar laws in other jurisdictions generally prohibit companies and their intermediaries from making improper payments to governmental officials for the purpose of obtaining or retaining business. We have operated and may in the future operate in parts of the world where strict compliance with anti-corruption and anti-bribery laws may conflict with local customs and practices. Any failure to comply with the FCPA, UK Bribery Act, or other anti-corruption laws due to our own acts or omissions or the acts or omissions of others, including our partners, agents or vendors, could subject us to civil and criminal penalties or other sanctions, which would adversely affect our business, financial position, results of operations or cash flows. We could also face fines, sanctions and other penalties from authorities in the relevant jurisdictions, including prohibition of our participation in or curtailment of business operations in those jurisdictions and the seizure of drilling units or other assets.
Failure to retain highly skilled personnel could hurt our operations.
We require highly skilled and experienced personnel to operate our rigs and provide technical services and support for our operations. In the past, during periods of high demand for drilling services and increasing worldwide industry fleet size, shortages of qualified personnel have occurred. The recent prolonged industry downturn may further reduce the number of qualified personnel available in the future. Such shortages could result in our loss of qualified personnel to competitors, impair the timeliness and quality of our work and create upward pressure on costs. If we are unable to retain or train skilled personnel, our operations and quality of service could be adversely impacted.
We are involved in litigation and legal proceedings from time to time that could have a negative effect on us if determined adversely.
We are, from time to time, involved in various legal proceedings, which may include, among other things, contract disputes, personal injury, environmental, toxic tort, employment, tax and securities litigation, governmental investigations or proceedings, and litigation that arises in the ordinary course of our business. Although we intend to defend any of these matters vigorously, we cannot predict with certainty the outcome or effect of any claim or other litigation matter. Our profitability may be adversely affected by the outcome of claims or contract disputes, including any inability to collect receivables or resolve significant contractual or day rate disputes, and any purported nullification, cancellation or breach of contracts with customers or other parties. Litigation may have an adverse effect on us because of potential negative outcomes, the costs associated with defending the lawsuits, the diversion of resources, reputational damage, and other factors.
Downgrades in our credit ratings may affect our ability to access the credit and debt capital markets.
Our ability to maintain a sufficient level of liquidity to meet our financial and operating needs is dependent upon our future performance, operating cash flows, and our access to credit and debt capital markets. In turn, our level of liquidity and access to credit and debt capital markets depends on general economic conditions, industry cycles, financial, business and other factors affecting our operations, as well as our credit ratings. Tightening in the credit markets due to the current economic environment, concerns about the offshore drilling industry and our credit ratings may restrict our access to the credit and debt capital markets in the future and increase the cost of such indebtedness. As a result, our future cash flows and access to capital may be insufficient to meet all of our capital requirements, debt obligations and contractual commitments, and any insufficiency could have an adverse impact on our business.
Certain credit rating agencies have downgraded our credit ratings below investment grade and may further downgrade our credit ratings at any time. A further downgrade in our ratings could have adverse consequences on our business and future prospects, including the following:
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Restrict our ability to access credit and debt capital markets;
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Cause us to refinance or issue debt with less favorable terms and conditions;
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Negatively impact current and prospective customers’ willingness to transact business with us;
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Impose additional insurance, guarantee and collateral requirements; or
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Limit our access to bank and third-party guarantees, surety bonds and letters of credit.
Technology disputes could negatively impact our operations or increase our costs.
Drilling rigs use proprietary technology and equipment which can involve potential infringement of a third party’s rights, including patent rights. The majority of the intellectual property rights relating to our jack-ups and drillships are owned by us or our suppliers or sub-suppliers, however, in the event that we or one of our suppliers or sub-suppliers becomes involved in a dispute over infringement rights relating to equipment owned or used by us, we may lose access to repair services or replacement parts, or we could be required to cease use of some equipment or forced to modify our jack-ups or drillships. We could also be required to pay license fees or royalties for the use of equipment. Technology disputes involving us, or our suppliers or sub-suppliers could adversely affect our financial results and 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 various regions such as Trinidad and Norway are represented by labor unions and work under collective bargaining or similar agreements, which are subject to periodic renegotiation. Further, efforts may be made from time to time to unionize other portions of our workforce. In addition, we have experienced, and in the future may experience, strikes or work stoppages and other labor disruptions. Additional unionization efforts, new collective bargaining agreements or work stoppages could materially increase our costs, reduce our revenue or limit 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 revenue and adversely impact our operations.
Our reliance on third-party suppliers, manufacturers and service providers to secure equipment used in our drilling operations could expose us to volatility in the quality, price and availability of such items. Certain specialized parts and equipment we use in our operations may be available only from a single or small number of suppliers. A disruption in the deliveries from such third-party suppliers, capacity constraints, production disruptions, price increases, defects or quality-control issues, recalls or other decreased availability or servicing of parts and equipment could adversely affect our ability to meet our commitments to customers, adversely impact our operations and revenue by resulting in uncompensated downtime, reduced day rates or the cancellation or termination of contracts, or increase our operating costs. Our reliance on one or more of these third-party suppliers could further exacerbate such issues.
The enforcement of civil liabilities against Rowan plc may be more difficult.
Because Rowan plc is a public limited company incorporated under English law, investors could experience more difficulty enforcing judgments obtained against Rowan plc in U.S. courts than would be the case for U.S. judgments obtained against a U.S. company. In addition, it may be more difficult to bring some types of claims against Rowan plc in courts in the U.K. than it would be to bring similar claims against a U.S. company in a U.S. court.
Our articles of association include mandatory offer provisions that may have the effect of discouraging, delaying or preventing hostile takeovers, including those that might result in a premium being paid over the market price of our shares, and discouraging, delaying or preventing changes in control or management.
Although Rowan plc is not currently subject to the U.K. Takeover Code, certain provisions similar to the mandatory offer provisions and certain other aspects of the U.K. Takeover Code are included in our articles of association. As a result, among other matters, a Rowan plc shareholder, that together with persons acting in concert, acquired 30 percent or more of our issued shares without making an offer to all of our other shareholders that is in cash or accompanied by a cash alternative would be at risk of certain Board sanctions unless they acted with the consent of our Board or the prior approval of the shareholders. The ability of shareholders to retain their shares upon completion of a mandatory offer may depend on whether the offeror subsequently causes us to propose a court-approved scheme of arrangement that would compel minority shareholders to transfer or surrender their shares in favor of the offeror or, if the offeror has acquired at least 90 percent of the relevant shares, the offeror requires minority shareholders to accept the offer under the ‘squeeze-out’ provisions in our articles of association. The mandatory offer provisions in our articles of association could have the effect of discouraging the acquisition and holding of interests of 30 percent or more of issued shares and encouraging those shareholders who may be acting in concert with respect to the acquisition of shares to seek to obtain the
consent of our Board before effecting any additional purchases. In addition, these provisions may adversely affect the market price of our shares or inhibit fluctuations in the market price of our shares that could otherwise result from actual or rumored takeover attempts.
As a result of shareholder approval requirements required under U.K. law, we may have less flexibility than a Delaware corporation with respect to certain aspects of capital management.
Unlike most U.S. state corporate law, English law provides that a board of directors may generally only allot shares with the prior authorization of shareholders, which such authorization may only extend for a maximum period of five years. English law also generally provides shareholders preemptive rights when new shares are issued for cash unless such rights are waived by the shareholders.
English law also generally prohibits us from repurchasing our shares on the open market and prohibits us from repurchasing our shares by way of “off-market purchases” without the prior approval of shareholders, which approval may only extend for a maximum period of five years.
At our 2017 annual general meeting of shareholders, our Board was authorized to allot a certain amount of shares, exclude certain preemptive rights in shares for cash offerings and effect off market purchases, in each case without further shareholder approval. However, these authorizations expire in May 2018. As such, we will be unable to issue new shares or repurchase shares unless and until we receive renewed shareholder approval. In addition, even if approved by shareholders, our ability to issue and repurchase shares may be substantially more restricted than a U.S. company.
English law requires that we meet certain additional financial requirements before we declare dividends and return funds to shareholders.
Under English law, a public company may only declare dividends and make other distributions to shareholders (such as a share buyback) if the company has sufficient distributable reserves and meets certain net asset requirements. If we do not have sufficient distributable reserves or cannot meet the net asset requirements, we may be limited in our ability to timely pay dividends and effect other distributions to our shareholders.
The U.K.’s referendum to exit from the E.U. will have uncertain effects and could adversely impact our business, results of operations and financial condition.
On June 23, 2016, the U.K. voted to exit from the E.U. (commonly referred to as Brexit). The terms of Brexit and the resulting U.K./E.U. relationship are uncertain for companies doing business both in the U.K. and the overall global economy. In addition, our business and operations may be impacted by any subsequent vote in Scotland to seek independence from the U.K. Risks related to Brexit that we may encounter include:
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adverse impact on macroeconomic growth and oil and gas demand;
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continued volatility in currencies including the British pound and USD that may impact our financial results;
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reduced demand for our services in the U.K. and globally;
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increased costs of doing business in the U.K. and in the North Sea;
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increased regulatory costs and challenges for operating our business in the North Sea;
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volatile capital and debt markets, and access to other sources of capital;
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risks related to our global tax structure and the tax treaties upon which we rely;
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business uncertainty resulting from prolonged political negotiations; and
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uncertain stability of the E.U. and global economy if other countries exit the E.U.
ITEM 1B.
ITEM 1B. UNRESOLVED STAFF COMMENTS
The Company has no unresolved SEC staff comments.
ITEM 2.
ITEM 2. PROPERTIES
Our primary U.S. offices are located in leased space in Houston, Texas. Additionally, we own or lease other office, maintenance and warehouse facilities in the U.S., Saudi Arabia (primarily for ARO operations), Norway, Scotland, Trinidad, Bahrain, Dubai, Luxembourg and Egypt.
Drilling Rigs
Following is the principal drilling equipment owned by Rowan and its location at February 13, 2018.
______________________________
(1) High-specification jack-up, which is defined as having hook-load capacity of at least two million pounds.
(2) Premium jack-up, which is defined as an independent leg, cantilevered rig capable of operating in water depths of 300 feet or more.
(3) Currently cold-stacked.
(4) Purchased in January 2018 and not yet placed in service.
(5) Managed by ARO.
(6) Water depths are the maximum "rated" depths as currently outfitted.
(7) Maximum estimated drilling depth, subject to well characteristics and rig outfitting.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
We are involved in various routine legal proceedings incidental to our businesses and vigorously defend our position in all such matters. Although the outcome of such proceedings cannot be predicted with certainty, we believe there are no known contingencies, claims or lawsuits that will have a material adverse effect on our financial position, results of operations or cash flows.
ITEM 4.
ITEM 4. MINE SAFETY DISCLOSURES
Not applicable.
PART II
ITEM 5.
ITEM 5. MARKET FOR REGISTRANT’S COMMON STOCK, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Our shares are listed on the NYSE under the symbol “RDC.” The following table sets forth the high and low sales prices of our shares as reported on the NYSE for the periods indicated.
On February 21, 2018, there were 72 shareholders of record. Many of our shareholders hold their shares in "street name" by a nominee of Depository Trust Company, which is a single shareholder of record.
In January 2016, our Board discontinued dividend payments.
The graph below presents the relative investment performance of our ordinary shares, the Dow Jones U.S. Oil Equipment & Services Index, and the S&P 500 Index for the five-year period ended December 31, 2017, assuming reinvestment of dividends.
Issuer Purchases of Equity Securities
The following table presents information with respect to acquisitions of our shares for the fourth quarter of 2017:
For information concerning our shares to be issued in connection with equity compensation plans, see Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters in Part III, Item 12, of this Annual Report on Form 10-K.
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA
Selected financial data for each of the last five years is presented below:
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(1)
In 2017, the Company recognized a $157.4 million gain on the sale of assets to ARO.
(2)
Gain on litigation settlement includes: 2014 - a gain of $20.9 million in cash received for damages incurred as a result of a tanker’s collision with the Rowan EXL I in 2012.
(3)
Material charges and other operating expenses consisted of the following: 2016 - $34.3 million of non-cash impairment charges and a $1.4 million reversal of an estimated liability for settlement of a withholding tax matter during a tax amnesty period which was related to a legal settlement for a 2014 termination of a contract for refurbishment work on the Rowan Gorilla III, as noted below in the 2015 period. A payment of such withholding taxes during the tax amnesty period resulted in the waiver of applicable penalties and interest; 2015 - $329.8 million of non-cash asset impairment charges and a $7.6 million adjustment to an estimated liability for the 2014 termination of a contract for refurbishment work on the Rowan Gorilla III. A settlement agreement for this matter was signed during the third quarter of 2015; 2014 - $574.0 million of non-cash asset impairment charges; and 2013 - $4.5 million of non-cash asset impairment charges.
(4)
In 2016, other income (expense), net includes $31.2 million loss on debt extinguishment.
(5)
In 2011, the Company sold its manufacturing and land drilling operations, which were classified as discontinued operations. In 2014, we sold a land rig retained from the sale and recognized a $4.0 million gain, net of tax.
(6)
2017 includes a $206.6 million increase to Retained earnings related to the adoption of ASU No. 2016-16.
(7)
Current ratio excludes assets and liabilities of discontinued operations.
ITEM 7.
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
OUR BUSINESS
We are a global provider of offshore contract drilling services to the oil and gas industry, with a focus on high-specification and premium jack-up rigs and ultra-deepwater drillships. Prior to ARO commencing operations on October 17, 2017 (see "ARO Joint Venture" below), we operated in two segments: Deepwater and Jack-ups; however, we now operate in three segments: Deepwater, Jack-ups and ARO. The Deepwater segment includes four ultra-deepwater drillships. The Jack-ups segment is composed of 23 self-elevating jack-up rigs, including two LeTourneau Super 116E jack-up rigs purchased in January 2018 (see Note 19 to our consolidated financial statements in Part II, Item 8 of this Annual Report on Form 10-K) and the impact of the various arrangements with ARO (see Note 1 and 3 to our consolidated financial statements in Part II, Item 8 of this Annual Report on Form 10-K). The ARO segment is a 50/50 joint venture with Rowan and Saudi Aramco that owns a fleet of five self-elevating jack-up rigs for operation in the Arabian Gulf for Saudi Aramco. Our fleet operates worldwide, including the US GOM, the U.K. and Norwegian sectors of the North Sea, the Middle East and Trinidad.
As of February 13, 2018, the date of our most recent Fleet Status Report, one of our four ultra-deepwater drillships was under contract in the US GOM. We had three jack-up rigs under contract in the North Sea, seven under contract in the Middle East, three under contract in Trinidad and one under contract in the US GOM. Additionally, we had an additional five marketed jack-up rigs and three marketed drillships without contracts as well as two cold-stacked jack-up rigs and two jack-ups which have not yet been placed in service for Rowan, the two LeTourneau Super 116E jack-up rigs purchased in January 2018.
We contract our drilling rigs, related equipment and work crews primarily on a “day rate” basis. Under day rate contracts, we generally receive a fixed amount per day for each day we are performing drilling or related services. In addition, our customers may pay all or a portion of the cost of moving our equipment and personnel to and from the well site. Contracts generally range in duration from one month to multiple years.
ARO Joint Venture
On November 21, 2016, Rowan and Saudi Aramco, through their subsidiaries, entered into a Shareholders’ Agreement to create a 50/50 joint venture to own, manage and operate offshore drilling units in Saudi Arabia. The new entity, ARO, was formed in May 2017 and commenced operations on October 17, 2017. See Note 1 to our consolidated financial statements in Part II, Item 8 of this Annual Report on Form 10-K for additional information.
Gain on sale of assets to unconsolidated subsidiary
On October 17, 2017, pursuant to an Asset Transfer and Contribution Agreement with ARO, we agreed to sell three rigs to ARO: the JP Bussell, the Bob Keller and the Gilbert Rowe and related assets for a total cash consideration of $357.7 million. The book value of these assets was approximately $200.3 million. As a result of this sale transaction with ARO, we recognized a gain on the disposal of rig assets in the amount of $157.4 million in 2017. See Notes 1, 3 and 14 to our consolidated financial statements in Part II, Item 8 of this Annual Report on Form 10-K for additional information.
Customer Contract Termination Amendment
On September 15, 2016, we amended our contract with Cobalt, for the drillship Rowan Reliance, which was scheduled to conclude on February 1, 2018. See Note 1 to our consolidated financial statements in Part II, Item 8 of this Annual Report on Form 10-K for additional information.
Customer Contract Termination and Settlement
On May 23, 2016, we reached an agreement with FMOG and its parent company, FCX, in connection with the drilling contract for the drillship Rowan Relentless, which was scheduled to terminate in June 2017. See Note 1 to our consolidated financial statements in Part II, Item 8 of this Annual Report on Form 10-K for additional information.
CURRENT BUSINESS ENVIRONMENT
Commodity prices have broadly improved over the past six months and industry sentiment is more favorable. However, the business environment for offshore drillers continues to be challenging due to a decrease in operators' offshore capital expenditures for the third year in a row, and an imbalance of offshore rig supply and demand, resulting in downward pressure on utilization and day rates.
Over the past three years, the cancellation and postponement of drilling programs have resulted in significantly reduced demand for offshore drilling services globally. Additionally, the 247 new jack-ups and 163 new floaters that have been delivered since the beginning of the current newbuild cycle in early 2006 have exacerbated the supply and demand imbalance. Since the industry downturn, contractors have responded by retiring assets, stacking certain idle equipment and deferring newbuild deliveries. Since the beginning of 2014, we estimate that approximately 50 jack-ups and 101 floaters have been removed from the total fleet in various forms of attrition. Partly as a result of these actions, overall marketed utilization, for both jack-ups and floaters, appears to have stabilized. However, excessive levels of idle capacity continue to pressure day rates.
Further, as of February 13, 2018, there were 91 additional jack-up rigs on order or under construction worldwide for delivery through 2020 (relative to approximately 328 jack-up rigs currently on contract), and 42 floaters on order or under construction worldwide for delivery through 2021 (relative to approximately 150 floater rigs currently on contract). Only 14 floaters currently on order or under construction have contracts secured for their future delivery dates. To our knowledge, none of the jack-up newbuilds have contracts in place. We expect several of these rigs may eventually be cancelled and many others will likely continue to be deferred until a recovery in demand is visible.
In response to market conditions over the past three years, we have reduced day rates on certain drilling contracts, some in exchange for extended contract duration, agreed to certain contract terminations, sold six of our oldest jack-ups, cold-stacked two of our older jack-ups, and have had as many as six warm stacked jack-ups and three warm stacked ultra-deepwater drillships. As of February 13, 2018, five jack-ups and three ultra-deepwater drillships were marketed and not under contract.
While we have seen some recent improvement in tender activity, given the current offshore rig supply and demand dynamics, we expect the marketing environment to remain extremely competitive across the broad offshore rig market for the next few years until a more pronounced recovery in offshore rig demand materializes. Due to the short cycle nature of the shallow water markets, we expect jack-up demand to improve in advance of the floater market.
Despite the challenging business environment, we believe that we are strategically well-positioned to take advantage of the next up-cycle given our financial condition, solid operational reputation, and modern fleet of high-specification jack-ups and state-of-the-art ultra-deepwater drillships. While challenging market conditions persist, we continue to focus on operating efficiencies, cost cutting initiatives, upgrade of various systems and data analytics to drive improved drilling performance and predictive maintenance.
RESULTS OF OPERATIONS
We analyze the financial results of each of our operating segments. The operating segments presented are consistent with our reportable segments discussed in Note 13 of our consolidated financial statements in Part II, Item 8 of this Annual Report on Form 10-K.
The following table presents certain key performance indicators by rig classification (7):
Rig Utilization (4)
The following table sets forth an analysis of time that our rigs were idle or out-of-service as a percentage of available days (which excludes cold-stacked rigs) and time that our rigs experienced operational downtime and are off-rate as a percentage of revenue-producing day:
2017 Compared to 2016
A summary of our consolidated results of operations follows (in millions):
Revenue
Consolidated. The decrease in consolidated revenue is described below.
Deepwater. An analysis of the net changes in revenue for 2017, compared to 2016, are set forth below (in millions):
Jack-ups. An analysis of the net changes in revenue for 2017, compared to 2016, are set forth below (in millions):
Unallocated. From October 17, 2017 to December 31, 2017, we recorded $7.4 million of revenue related to transition services provided to ARO (see Note 1 and Note 3 to our consolidated financial statements in Part II, Item 8 of this Annual Report on Form 10-K).
Direct operating costs
Consolidated. The decrease in consolidated direct operating costs is described below.
Deepwater. An analysis of the net changes in direct operating costs for 2017, compared to 2016, are set forth below (in millions):
Jack-ups. An analysis of the net changes in direct operating costs for 2017, compared to 2016, are set forth below (in millions):
Gain on sale of assets to unconsolidated subsidiary
We recognized a gain of $157.4 million on the sale of assets to ARO. See Notes 1, 3 and 14 to our consolidated financial statements in Part II, Item 8 of this Annual Report on Form 10-K for additional information.
Other operating items
Material charges for 2016 included a $34.3 million non-cash impairment charge to reduce the carrying values of five of our jack-up drilling units, partially offset by a $1.4 million reversal of an estimated liability for settlement of a withholding tax matter during a tax amnesty period which was related to a legal settlement for a 2014 termination of a contract for refurbishment work on the Rowan Gorilla III. Payment of such withholding taxes during the tax amnesty period resulted in the waiver of applicable penalties and interest.
In 2017, we had a loss on disposals of property and equipment of $9.4 million compared to a loss of $8.7 million in 2016.
Other expense, net
The decrease in Other expense, net, is primarily due to a $1.7 million gain on the early extinguishment of debt in 2017 compared to a net loss on the early extinguishment of debt of $31.2 million in 2016. Interest income increased in 2017 primarily due to higher cash balances in 2017 as compared to 2016, and $2.1 million of interest income related to the note receivable from ARO (see Note 3 to our consolidated financial statements in Part II, Item 8 of this Annual Report on Form 10-K). Additionally, our foreign currency exchange losses decreased to $0.4 million in 2017 compared to $9.7 million in 2016 primarily due to the devaluation of the Egyptian pound in 2016.
Provision for income taxes
In 2017, we recognized an income tax provision of $26.6 million on pretax income of $99.3 million. The 2017 tax provision primarily includes $28.7 million of tax expense for current year operations, $20.5 million of tax expense due to an increase in the valuation allowance assessed on deferred tax assets, and a partial offset by a $27.3 million reduction in accrued unrecognized tax benefits due to a lapse in statutes of limitation and an audit settlement.
In 2016, we recognized an income tax provision of $5.0 million on pretax income of $325.6 million. The 2016 tax provision was primarily due to 2016 operations offset by the amortization of deferred intercompany gains and losses and deferred tax benefit as a result of 2016 restructuring.
2016 Compared to 2015
A summary of our consolidated results of operations follows (in millions):
Revenue
Consolidated. The decrease in consolidated revenue is described below.
Deepwater. An analysis of the net changes in revenue for 2016, compared to 2015, are set forth below (in millions):
Jack-ups. An analysis of the net changes in revenue for 2016, compared to 2015, are set forth below (in millions):
Direct operating costs
Consolidated. The decrease in consolidated direct operating costs is described below.
Deepwater. An analysis of the net changes in direct operating costs for 2016, compared to 2015, are set forth below (in millions):
Jack-ups. An analysis of the net changes in direct operating costs for 2016, compared to 2015, are set forth below (in millions):
Depreciation and amortization
Depreciation and amortization for 2016 increased largely due to the addition of the Rowan Reliance and Rowan Relentless in 2015.
Selling, general and administrative
Selling, general and administrative expenses for 2016 decreased largely due to lower personnel costs. In addition, professional fees and information technology expenses decreased in 2016 as compared to 2015.
Other operating items
Material charges for 2016 included a $34.3 million non-cash impairment charge to reduce the carrying values of five of our jack-up drilling units, partially offset by a $1.4 million reversal of an estimated liability for settlement of a withholding tax matter during a tax amnesty period which was related to a legal settlement for a 2014 termination of a contract for refurbishment work on the Rowan Gorilla III, as noted below in the 2015 period. Payment of such withholding taxes during the tax amnesty period resulted in the waiver of applicable penalties and interest.
Material charges for 2015 included a $329.8 million non-cash impairment charge to reduce the carrying values of ten of our jack-up drilling units and a $7.6 million adjustment to an estimated liability for the 2014 termination of a contract for refurbishment work on the Rowan Gorilla III. A settlement agreement for this matter was signed during the third quarter of 2015.
In 2016, we had a loss on disposals of property and equipment of $8.7 million compared to a gain of $7.7 million in 2015.
Other expense, net
The increase in Other Expense, Net, is primarily due to a $31.2 million net loss on the early extinguishment of debt in 2016 compared to $1.5 million in 2015. Interest capitalization was $16.2 million in 2015. There was no interest capitalization in 2016 as the drillship construction program was completed in 2015. Additionally, our foreign currency exchange losses increased to $9.7 million in 2016 compared to $3.9 million in 2015 primarily due to the devaluation of the Egyptian pound. Partially offsetting these increases, our debt retirements in late 2015 and early 2016 resulted in a reduction in interest expense in 2016.
Provision for income taxes
In 2016, we recognized an income tax provision of $5.0 million on pretax income of $325.6 million. The 2016 tax provision was primarily due to 2016 operations offset by the amortization of deferred intercompany gains and losses and deferred tax benefit as a result of 2016 restructuring.
In 2015, we recognized an income tax provision of $64.4 million on pretax income of $157.7 million. The 2015 tax provision was primarily due to the establishment of a valuation allowance on the U.S. deferred tax assets, impairments of assets in jurisdictions with no tax benefits, and an increase in income in high-tax jurisdictions, offset by additional tax benefit for the U.S. impaired assets and an increase in income in low-tax jurisdictions.
LIQUIDITY AND CAPITAL RESOURCES
Key balance sheet amounts and ratios at December 31 were as follows (dollars in millions):
Sources and uses of cash and cash equivalents were as follows (in millions):
Operating Cash Flows
Cash flows from operations decreased to approximately $300 million in 2017 from $906 million in 2016 primarily due to lower drilling activity in the current year as well as the impact of contract termination settlements in the prior year. Operating cash flows for 2016 compared to 2015 decreased primarily due to lower drilling activity, the cash loss on early extinguishment of debt, combined with uses of cash for current assets and liabilities, partially offset by deferred revenue and changes in other non-current assets and liabilities.
We have not provided deferred income taxes on certain undistributed earnings of non-U.K. subsidiaries. No subsidiary of RCI has a plan to distribute earnings to RCI in a manner that would cause those earnings to be subject to U.S., U.K. or other local country taxation.
Backlog
Our backlog by geographic area as of the date of our most recent Fleet Status Report is presented below (in millions):
We estimate our backlog as of February 13, 2018, will be realized as follows (in millions):
Our contract backlog represents remaining contractual terms and may not reflect actual revenue due to renegotiations or a number of factors such as rig downtime, out of service time, estimated contract durations, customer concessions or contract cancellations.
About 34% of our remaining available rig days in 2018 and 4% of available rig days in 2019 are included in backlog as revenue producing days as of February 13, 2018, excluding cold-stacked rigs. As of that date, we had two jack-ups that were cold-stacked and five jack-ups and three drillships that were available.
Since 2014, we have recognized asset impairment charges on several of our jack-up drilling units as a result of the decline in market conditions and the expectation of future demand and day rates. If market conditions deteriorate further, we could be required to recognize additional impairment charges in future periods.
Investing Activities
Capital expenditures in 2017 totaled $100.6 million and included the following:
•
$70.5 million for improvements to the existing fleet, including contractually required modifications; and
•
$30.1 million for rig equipment and other.
A cash deposit of $7.7 million was made toward the purchase of two jack-up rigs. See Note 19 to our consolidated financial statements in Part II, Item 8 of this Annual Report on Form 10-K.
In connection with the formation of ARO, we contributed $25 million to be used by the joint venture for working capital needs and incurred $5.0 million in transaction costs that were both capitalized to the investment in ARO. We deconsolidated $200.3 million worth of rigs and related assets which were sold to ARO for cash of $357.7 million.
Also, in connection with the ARO joint venture, we contributed $357.7 million in cash to ARO in exchange for a note receivable from ARO, our unconsolidated joint venture. We received $87.5 million in cash from ARO for repayment of the shareholder note receivable. As of December 31, 2017, $271.3 million was outstanding on this shareholder note receivable consisting of $270.2 million Long-term note receivable from unconsolidated subsidiary and the current portion of $1.1 million included in Receivables - trade and other, both on the Company's Consolidated Balance Sheets.
We currently estimate our 2018 capital expenditures, exclusive of ARO's capital expenditures, will range from approximately $100-110 million, which is primarily for fleet maintenance, rig equipment, spares, upgrades to prepare two newly purchased rigs for service (see below) and other. This amount excludes any contractual modifications that may arise due to our securing additional work. In addition to our capital expenditure estimate, we spent $69.3 million for the purchase of two premium cantilever jack-ups in January 2018 (see Note 19 to our consolidated financial statements in Part II, Item 8 of this Annual Report on Form 10-K).
We expect to fund our 2018 capital expenditures using cash on hand.
Our capital forecast reflects cash that we may or may not spend, and the timing of such expenditures may change. We will periodically review and adjust the capital forecast as necessary based upon current and expected cash flows and liquidity, anticipated market conditions in our business, the availability of financial resources, and alternative uses of capital to enhance shareholder value.
Capital expenditures for 2016 totaled $117.6 million and included $68.5 million for improvements to the existing fleet, including contractually required modifications, and $49.1 million for rig equipment and other.
Capital expenditures for 2015 totaled $722.9 million and included $541.3 million towards drillship construction, including costs for mobilization, commissioning, riser gas-handling equipment, software certifications and spares; $132.5 million for improvements to the existing fleet, including contractually required modifications; and $49.1 million for rig equipment spares and other. With the delivery of our fourth and final drillship in March 2015, we concluded our ultra-deepwater drillship construction program. We took delivery of the first three drillships in 2014.
Financing Activities
The Senior Notes and amounts outstanding under our Revolving Credit Facility are fully, unconditionally and irrevocably guaranteed on a senior and unsecured basis by Rowan plc. We were in compliance with our debt covenants at December 31, 2017, and expect to remain in compliance throughout 2018.
Annual interest payments on the Senior Notes are estimated to be approximately $150 million in 2018. No principal payments are required until each series’ final maturity date. Management believes that cash flows from operating activities, existing cash balances, and amounts available under our Revolving Credit Facility will be sufficient to satisfy the Company’s cash requirements for the following twelve months.
Additional information related to our Senior Notes and Revolving Credit Facility is described in Note 5 to our consolidated financial statements in Part II, Item 8 of this Annual Report on Form 10-K and the information discussed therein is incorporated by reference into this Part II, Item 7.
Cash Dividends
In January 2016, the Company announced that it had discontinued its quarterly dividend.
Prior to 2014, the Company had not paid a quarterly cash dividend since 2008. Cash dividends for 2015 are set forth below:
Off-balance Sheet Arrangements and Contractual Obligations
The Company had no off-balance sheet arrangements as of December 31, 2017 or 2016, other than operating lease obligations and other commitments in the ordinary course of business.
The following is a summary of our contractual obligations at December 31, 2017, including obligations recognized on our balance sheet and those not required to be recognized (in millions):
As of December 31, 2017, our liability for unrecognized tax benefits related to uncertain tax positions totaled $113 million, inclusive of interest and penalties. Due to the high degree of uncertainty related to these tax matters, we are unable to make a reasonably reliable estimate as to the timing of cash settlement with the respective taxing authorities, and we have therefore excluded this amount from the contractual obligations presented in the table above.
We periodically employ letters of credit in the normal course of our business and had outstanding letters of credit of approximately $7.3 million at December 31, 2017, of which $5.0 million were issued under our Revolving Credit Facility.
Rowan has a potential obligation to fund ARO for newbuild jack-up rigs. See Note 1 to our consolidated financial statements in Part II, Item 8 of this Annual Report on Form 10-K and the information discussed therein is incorporated by reference into this Part II, Item 7.
Pension Obligations
Minimum contributions under defined benefit pension plans are determined based upon actuarial calculations of pension assets and liabilities that involve, among other things, assumptions about long-term asset returns and interest rates. Similar calculations were used to estimate pension costs and obligations as reflected in our consolidated financial statements (see “Critical Accounting Policies and Management Estimates - Pension and other postretirement benefits”). As of December 31, 2017, our financial statements reflected an aggregate unfunded pension liability of $226 million. We expect to make minimum contributions to our defined benefit pension plans of approximately $25 million in 2018, and we will continue to make significant pension contributions over the next several years. Additional funding may be required if, for example, future interest rates or pension asset values decline or there are changes in legislation.
Contingent Liabilities
We are involved in various legal proceedings incidental to our businesses and are vigorously defending our position in all such matters. The Company believes that there are no known contingencies, claims or lawsuits that could have a material effect on its financial position, results of operations or cash flows.
CRITICAL ACCOUNTING POLICIES AND MANAGEMENT ESTIMATES
Our significant accounting policies are presented in Note 2 to our consolidated financial statements in Part II, Item 8 of this Annual Report on Form 10-K. These policies and management judgments, assumptions and estimates made in their application underlie reported amounts of assets and liabilities at the date of the financial statements and reported amounts of revenue and expenses during the reporting period. We believe that our most critical accounting policies and management estimates involve carrying values of long-lived assets, principles of consolidation and our equity method investment, pension and other postretirement benefit liabilities and costs (specifically assumptions used in actuarial calculations), and income taxes (particularly our estimated reserves for uncertain tax positions), as changes in such policies and/or estimates would produce significantly different amounts from those reported herein.
Depreciation and impairments of long-lived assets
We depreciate our assets using the straight-line method over their estimated useful service lives after allowing for salvage values. We estimate useful lives and salvage values by applying judgments and assumptions that reflect both historical experience and expectations regarding future operations, utilization and performance. Useful lives may be affected by a variety of factors including technological advances in methods of oil and gas exploration, changes in market or economic conditions, and changes in laws or regulations that affect the drilling industry. Applying different judgments and assumptions in establishing useful lives and salvage values may result in values that differ from recorded amounts.
We evaluate the carrying value of our property and equipment, primarily our drilling rigs, whenever events or changes in circumstances indicate that their carrying values may not be recoverable. Potential impairment indicators include rapid declines in commodity prices, stock prices, rig utilization and day rates, among others. The offshore drilling industry has historically been highly cyclical, and it is not unusual for rigs to be underutilized or idle for extended periods of time and subsequently resume full or near full utilization when business cycles improve. Similarly, during periods of excess supply, rigs may be contracted at or near cash break-even rates for extended periods. Impairment situations may arise with respect to specific rigs, specific categories or classes of rigs, or rigs in a certain geographic region. Our rigs are mobile and may generally be moved from regions with excess supply, if economically feasible.
Asset impairment evaluations are, by nature, highly subjective. In most instances, they involve expectations of future cash flows to be generated by our drilling rigs and are based on management's judgments and assumptions regarding future industry conditions and operations, as well as management's estimates of future expected utilization, contract rates, expense levels and capital requirements. The estimates, judgments, and assumptions used by management in the application of our asset impairment policies reflect both historical experience and an assessment of current operational, industry, market, economic and political environments. The use of different estimates, judgments, assumptions (including discount rates) and expectations regarding future industry conditions and operations would likely result in materially different asset carrying values and operating results.
We conducted an impairment test of our assets during the fourth quarter of 2017; however, the test resulted in no impairment as the estimated undiscounted cash flows from the assets exceeded the assets' carrying values (see Note 2 to our consolidated financial statements in Part II, Item 8 of this Annual Report on Form 10-K).
In 2016 and 2015, we conducted impairment tests of our assets and determined that the carrying values of certain jack-up rigs were not recoverable from their undiscounted cash flows and exceeded their fair values. As a result, we recognized non-cash asset impairment charges of approximately $34 million and $330 million in 2016 and 2015, respectively (see Note 2 to our consolidated financial statements in Part II, Item 8 of this Annual Report on Form 10-K).
Principles of Consolidation
The consolidated financial statements include our accounts and those of our wholly-owned subsidiaries. Intercompany balances and transactions have been eliminated in consolidation. Investments in operating entities where we have the ability to exercise significant influence, but where we do not control operating and financial policies are accounted for using the equity method. Significant influence generally exists if we have an ownership interest representing between 20% and 50% of the voting stock of the investee. Under the equity method of accounting, investments are stated at initial cost and are adjusted for subsequent additional investments and our proportionate share of earnings or losses and distributions. We account for our interest in ARO using the equity method of accounting and only recognize our portion of equity earnings in our consolidated financial statements. ARO is a variable interest entity; however, we are not the primary beneficiary and therefore do not consolidate ARO. Our judgment regarding the level of influence over ARO included considering key factors such as each company's ownership interest, representation on the board of managers of ARO, ability to direct activities that most significantly impact the ARO's economic performance, as well as the ability to influence policy-making decisions.
Pension and other postretirement benefits
Our pension and other postretirement benefit liabilities and costs are based upon actuarial computations that reflect our assumptions about future events, including long-term asset returns, interest rates, annual compensation increases, mortality rates and other factors. Key assumptions at December 31, 2017, included i) a weighted average discount rate of 3.68% to determine pension benefit obligations, ii) a weighted average discount rate of 4.29% to determine net periodic pension cost and iii), an expected long-term rate of return on pension plan assets of 6.70%. The assumed discount rate is based upon the average yield for Moody’s Aa-rated corporate bonds, and the rate of return assumption reflects a probability distribution of expected long-term returns that is weighted based upon plan asset allocations. A one-percentage-point decrease in the assumed discount rate would increase our recorded pension and other postretirement benefit liabilities by approximately $103.9 million, while a one-percentage-point decrease (increase) in the expected long-term rate of return on plan assets would increase (decrease) annual net benefits cost by approximately $5.3 million. To develop the expected long-term rate of return on assets assumption, we considered the current level of expected returns on risk-free investments (primarily government bonds), the historical level of the risk premium associated with the plans’ other asset classes, and the expectations for future returns of each asset class. The expected return for each asset class was then weighted based upon the current asset allocation to develop the expected long-term rate of return on assets assumption for the plan, which was reduced to 6.70% at December 31, 2017, from 7.15% at December 31, 2016.
Income taxes
In accordance with accounting guidelines for income tax uncertainties, we evaluate each tax position to determine if it is more likely than not that the tax position will be sustained upon examination, based on its merits. A tax position that meets the more-likely-than-not recognition threshold is subject to a measurement assessment to determine the amount of benefit to recognize in income for the period and appropriate reserve. Income tax returns are subject to audit by taxing authorities in most jurisdictions. Determinations by such taxing authorities that differ materially from our recorded estimates, either favorably or unfavorably, may have a material impact on our results of operations, financial position and cash flows. We believe our reserve for uncertain tax positions totaling $102 million at December 31, 2017, is properly recorded in accordance with the accounting guidelines.
On December 22, 2017, the U.S. Tax Act was enacted into law and the new legislation contains several key tax provisions, including a one-time mandatory transition tax on certain non-U.S. earnings, a reduction of the corporate income tax rate to 21%, a change in the taxability of certain non-U.S. subsidiaries, an additional tax on certain payments made from U.S. affiliates to non-U.S. affiliates, a limitation on interest deduction and a tax imposed on non-U.S. income in excess of a deemed return on tangible assets of non-U.S. corporations among others. In December 2017, the SEC staff issued Staff Accounting Bulletin No. 118, Income Tax Accounting Implications of the Tax Cuts and Jobs Act (SAB 118), which allows us to record provisional amounts during a measurement period not to extend beyond one year of the enactment date. Since the U.S. Tax Act was passed late in the fourth quarter of 2017, we consider our accounting of the one-time transition tax, deferred tax remeasurements, and other impacted items to be incomplete due to expected issuance of accounting interpretations and our ongoing analysis of data and tax positions. We expect to complete our analysis within the measurement period in accordance with SAB 118.
In January 2018, the FASB released guidance on the accounting for tax on the global intangible low-taxed income ("GILTI") provisions of the U.S. Tax Act. The GILTI provisions impose a tax on non-U.S. income in excess of a deemed return on tangible assets of non-U.S. corporations. The guidance indicates that either accounting for deferred taxes related to GILTI inclusions or
treating any taxes on GILTI inclusions as period cost are both acceptable methods subject to an accounting policy election. The Company is still evaluating which accounting policy to elect but currently believes the impact to the financial statements will be immaterial.
Recent Accounting Pronouncements
Information relating to recent accounting pronouncements is described in Note 2 to our consolidated financial statements in Part II, Item 8 of this Annual Report on Form 10-K and the information discussed therein is incorporated by reference into this Part II, Item 7.
ITEM 7A.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS
Interest rate risk - Our outstanding debt at December 31, 2017, consisted entirely of fixed-rate debt with a carrying value of $2.510 billion and a weighted-average annual interest rate of 5.8%. We are subject to interest rate risk on our fixed-interest rate borrowings. Fixed rate debt, where the interest rate is fixed over the life of the instrument, exposes us to changes in market interest rates reflected in the fair value of the debt and to the risk that we may need to refinance maturing debt with new debt at a higher rate.
Our Long-term note receivable from unconsolidated subsidiary consisted of a 10-year shareholder note receivable from ARO at a stated interest rate of LIBOR plus two percent with a carrying value of $270.2 million at December 31, 2017. A one-percentage-point decrease in LIBOR would decrease our interest income by approximately $3 million in the next twelve months, while a one-percentage-point increase in LIBOR would increase our interest income by approximately $3 million in the same period.
Currency exchange rate risk - A substantial majority of our revenue is received in USD, which is our functional currency. However, in certain countries in which we operate, local laws or contracts may require us to receive some payment in the local currency. We are exposed to foreign currency exchange risk to the extent the amount of our monetary assets denominated in the foreign currency differs from our obligations in that foreign currency. In order to mitigate the effect of exchange rate risk, we attempt to limit foreign currency holdings to the extent they are needed to pay liabilities in the local currency. We did not enter into such transactions for the purpose of speculation, trading or investing in the market. Our risk policy allows us to enter into such forward exchange contracts; however, we do not currently anticipate entering into such transactions in the future and had no such contracts outstanding as of December 31, 2017.
Commodity price risk - Fluctuating commodity prices affect our future earnings materially to the extent that they influence demand for our products and services.
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the shareholders and the Board of Directors of Rowan Companies plc
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Rowan Companies plc and subsidiaries (the “Company”) as of December 31, 2017 and 2016, the related consolidated statements of operations, comprehensive income, changes in shareholders’ equity, and cash flows for each of the three years in the period ended December 31, 2017, and the related notes and the schedule listed in the Index at Item 15 (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2017 and 2016, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2017, in conformity with accounting principles generally accepted in the United States of America.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company’s internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control-Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 28, 2018, expressed an unqualified opinion on the Company’s internal control over financial reporting.
Change in Accounting Principle
As discussed in Note 2 to the financial statements, the Company has changed its method of accounting for current and deferred income tax effects for intra-entity transfers of assets other than inventory in 2017 due to the adoption of Accounting Standards Update No. 2016-16, Income Taxes (ASC 740): Intra-Entity Transfers of Assets Other than Inventory.
Basis for Opinion
These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. We are a public accounting firm registered with the 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 audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the 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 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 financial statements. We believe that our audits provide a reasonable basis for our opinion.
/s/ DELOITTE & TOUCHE LLP
Houston, Texas
February 28, 2018
We have served as the Company’s auditor since 1966.
ROWAN COMPANIES PLC
MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
The management of Rowan is responsible for establishing and maintaining adequate internal control over financial reporting for the Company as defined in Rules 13a-15(f) and 15d-15(f) of the Securities Exchange Act of 1934, as amended. Our internal controls were designed to provide reasonable assurance as to the reliability of our financial reporting and the preparation and presentation of consolidated financial statements in accordance with accounting principles generally accepted in the United States, as well as to safeguard assets from unauthorized use or disposition.
We are required to assess the effectiveness of our internal controls relative to a suitable framework. The Committee of Sponsoring Organizations of the Treadway Commission (COSO) in its Internal Control - Integrated Framework (2013), developed a formalized, organization-wide framework that embodies five interrelated components - the control environment, risk assessment, control activities, information and communication and monitoring, as they relate to three internal control objectives - operating effectiveness and efficiency, financial reporting reliability and compliance with laws and regulations.
Our assessment included an evaluation of the design of our internal control over financial reporting relative to COSO and testing of the operational effectiveness of our internal control over financial reporting. Based upon our assessment, we have concluded that our internal controls over financial reporting were effective as of December 31, 2017.
The independent registered public accounting firm Deloitte & Touche LLP has audited Rowan’s consolidated financial statements and financial statement schedule included in our 2017 Annual Report on Form 10-K and has issued an attestation report on the Company’s internal control over financial reporting.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the shareholders and the Board of Directors of Rowan Companies plc
Opinion on Internal Control over Financial Reporting
We have audited the internal control over financial reporting of Rowan Companies plc and subsidiaries (the "Company") as of December 31, 2017, 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 Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control - Integrated Framework (2013) issued by COSO.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated financial statements and financial statement schedule as of and for the year ended December 31, 2017, of the Company and our report dated February 28, 2018 expressed an unqualified opinion on those financial statements and financial statement schedule, and included an explanatory paragraph relating to the Company's adoption of Accounting Standards Update No. 2016-16, Income Taxes (ASC 740): Intra-Entity Transfers of Assets Other than Inventory.
Basis for Opinion
The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company's internal control over financial reporting based on our audit. We are a public accounting firm registered with the 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 audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
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 (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) 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 (3) 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.
/s/ DELOITTE & TOUCHE LLP
Houston, Texas
February 28, 2018
ROWAN COMPANIES PLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(In millions, except per share amounts)
See Notes to Consolidated Financial Statements.
ROWAN COMPANIES PLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(In millions)
See Notes to Consolidated Financial Statements.
ROWAN COMPANIES PLC AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(In millions, except par value)
See Notes to Consolidated Financial Statements.
ROWAN COMPANIES PLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY
(In millions)
See Notes to Consolidated Financial Statements.
ROWAN COMPANIES PLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In millions)
See Notes to Consolidated Financial Statements.
NOTE 1 - NATURE OF OPERATIONS AND BASIS OF PRESENTATION
Rowan Companies plc, a public limited company incorporated under the laws of England and Wales, is a global provider of offshore contract drilling services to the oil and gas industry, with a focus on high-specification and premium jack-up rigs and ultra-deepwater drillships. Prior to ARO commencing operations on October 17, 2017 (see "ARO Joint Venture" below), we operated in two segments: Deepwater and Jack-ups; however, as of December 31, 2017, the Company operated in three segments: Deepwater, Jack-ups and ARO. The Deepwater segment includes four ultra-deepwater drillships. The Jack-ups segment is composed of 21 self-elevating jack-up rigs and the impact of the various arrangements with ARO (see discussion below and Note 3), in addition, two LeTourneau Super 116E jack-up rigs were purchased in January 2018, (see Note 19). The ARO segment is the 50/50 joint venture with Rowan and Saudi Aramco that owns a fleet of five self-elevating jack-up rigs for operation in the Arabian Gulf for Saudi Aramco. The Company contracts its drilling rigs, related equipment and work crews primarily on a day-rate basis in markets throughout the world, currently including the US GOM, U.K. and Norwegian sectors of the North Sea, the Middle East and Trinidad.
The consolidated financial statements included herein are presented in USD and include the accounts of Rowan plc and its direct and indirect subsidiaries. Unless the context otherwise requires, the terms “Rowan,” and “Company” are used to refer to Rowan plc and its consolidated subsidiaries. Intercompany balances and transactions have been eliminated in consolidation.
The financial information presented in this report does not constitute the Company's statutory accounts within the meaning of the U.K. Companies Act 2006 for the years ended December 31, 2017 or 2016. The audit of the statutory accounts for the year ended December 31, 2017, was not complete as of February 28, 2018. These accounts will be finalized by the directors on the basis of the financial information presented herein adjusted to meet the requirements of International Financial Reporting Standards as adopted by the European Union and the U.K. Companies Act 2006 and will be delivered to the Registrar of Companies in the U.K.
ARO Joint Venture
On November 21, 2016, Rowan and Saudi Aramco, through their subsidiaries, entered into a Shareholders’ Agreement to create a 50/50 joint venture (the "Shareholders' Agreement") to own, manage and operate offshore drilling units in Saudi Arabia. The new entity, ARO, was formed in May 2017 with each of Rowan and Saudi Aramco contributing $25 million to be used for working capital needs. In addition, $5 million in transaction costs were incurred by Rowan and capitalized to the investment in ARO. ARO commenced operations on October 17, 2017 (see Note 3 to our consolidated financial statements for additional information).
On October 17, 2017, Rowan and Saudi Aramco amended the asset transfer and contribution agreements (the "Amended Agreements"), previously entered into in connection with the Shareholders' Agreement, to, among other things, modify and clarify the mechanics associated with the formation of ARO to provide for: (1) equal cash contributions to ARO by each of Rowan and Saudi Aramco, (2) the receipt of cash from both Rowan and Saudi Aramco in exchange for shareholder notes, (3) the subsequent sale of: (a) three rigs and related assets to ARO by Rowan in exchange for cash and (b) one rig and related assets to ARO by Saudi Aramco in exchange for cash, and (4) the distribution by ARO of excess cash in the amount of approximately $88 million to each party, to be applied as a repayment to each party's shareholder note, maintaining each party’s 50% ownership interest in ARO following such asset sales. On October 17, 2017, these transactions were completed at which point the Company derecognized the related rig assets and began recording its interest in the ARO joint venture under the equity method of accounting. Pursuant to the terms of the Shareholders' Agreement and the Amended Agreements, Saudi Aramco also sold an additional rig to ARO in late December 2017 for cash. Rowan expects to sell two more rigs to ARO in late 2018 when those rigs complete their current contracts. Rowan expects the sale transactions to be similar to the October 2017 transactions. Rigs sold will receive contracts for an aggregate 15 years, renewed and re-priced every three years, provided that the rigs meet the technical and operational requirements of Saudi Aramco.
Rowan rigs in Saudi Arabia not selected for sale to the JV will be managed by ARO until the end of their current contracts with Saudi Aramco pursuant to a management services agreement that provides for a management fee equal to a percentage of revenue to cover overhead costs.
Each of Rowan and Saudi Aramco have agreed to take all steps necessary to ensure that ARO purchases at least 20 new build jack-up rigs ratably over 10 years once Saudi Aramco's joint venture to manufacture rigs commences operations. The first rig is expected to be delivered as early as 2021. The partners intend that the newbuild jack-up rigs will be financed out of available cash from operations and/or funds available from third party debt financing. The parties agreed that Saudi Aramco as a customer will provide drilling contracts to ARO in connection with the acquisition of the new rigs, which contracts could be used as security for third party debt financing if needed. If cash from operations or financing is not available to fund the cost of the newbuild jack-up rig, each partner is obligated to contribute funds, in the form of additional shareholder loans, to purchase such rigs, over time of up to a maximum amount of $1.25 billion per partner in the aggregate for all 20 newbuild jack-up rigs, which total investment amount
is subject to a reduction formula as rigs are delivered. Further, no shareholder will be required to fund the delivery of more than three rigs during any twelve (12) month period.
Customer Contract Termination Amendment
On September 15, 2016, the Company amended its contract with Cobalt, for the drillship Rowan Reliance, which was scheduled to conclude on February 1, 2018. The amendment provided cash settlement payments to the Company totaling $95.9 million, that the drillship remain at its day rate of approximately $582,000 and that the drilling contract may be terminated as early as March 31, 2017. The Company received cash payments totaling $76.3 million in 2016 and received a final cash payment of $19.6 million during the first quarter of 2017. In addition, the amendment provided that if Cobalt continued its operations with the Rowan Reliance after March 31, 2017, the day rate would be reduced to approximately $262,000 per day for the remaining operating days through February 1, 2018 (subject to further adjustment thereafter). Cobalt International Energy, Inc., the parent of Cobalt, also committed to use the Company as its exclusive provider of comparable drilling services for a period of five years. As the Company had the obligation and intent to have the drillship or a substitute available through the pre-amended contract scheduled end date, in certain circumstances (including a 90 day notice of intent to use the rig prior to the original contract scheduled end date of February 1, 2018), the $95.9 million settlement was recorded as a deferred revenue liability at December 31, 2016. Amortization of deferred revenue began on April 1, 2017 and was fully amortized as of December 31, 2017 as Cobalt did not provide notice to the Company by November 2, 2017 (90 day notice of intent to use the rig).
Customer Contract Termination and Settlement
On May 23, 2016, the Company reached an agreement with FMOG and its parent company, FCX in connection with the drilling contract for the drillship Rowan Relentless ("FCX Agreement"), which was scheduled to terminate in June 2017. The FCX Agreement provided that the drilling contract be terminated immediately, and that FCX pay the Company $215 million to settle outstanding receivables and early termination of the contract, which was received in 2016. In addition, the Company received the right to receive up to two additional contingent payments from FCX, payable on September 30, 2017, of $10 million (the "First FCX Contingent Payment Provision") and $20 million (the "Second FCX Contingent Payment Provision" and, together with the First FCX Contingent Payment Provision, the "FCX Contingent Payments Provisions") depending on the average price of WTI crude oil over a 12-month period beginning June 30, 2016. The FCX Contingent Payments Provisions would have been due if the average price over the period was greater than $50 per barrel with respect to the First FCX Contingent Payment Provision and $65 per barrel with respect to the Second FCX Contingent Payment Provision ("Price Targets"). During the quarter ended June 30, 2016, the Company recognized $173.2 million in revenue for the Rowan Relentless, including $130.9 million for the cancelled contract value, $6.2 million for the fair value of the derivative associated with the FCX Contingent Payments Provisions, $5.6 million for previously deferred revenue related to the contract, and $30.5 million for operations through May 22, 2016. For additional information related to the FCX Contingent Payments Provisions see Note 6.
NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Use of Estimates
The preparation of financial statements in conformity with US 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 amounts of revenue and expenses during the reporting period. Actual results could differ from those estimates.
Revenue and Expense Recognition
The Company's drilling contracts generally provide for payment on a daily rate basis, and revenue is recognized as the work progresses with the passage of time. The Company occasionally receives lump-sum payments at the outset of a drilling assignment for equipment moves or modifications. Lump-sum fees received for equipment moves (and related costs) and fees received for equipment modifications or upgrades are initially deferred and amortized on a straight-line basis over the primary term of the drilling contract. The costs of contractual equipment modifications or upgrades and the costs of the initial move of newly constructed rigs are capitalized and depreciated in accordance with the Company’s fixed asset capitalization policy. The costs of moving equipment while not under contract are expensed as incurred. The following table sets forth deferred revenue (revenue received but unearned) and deferred contracts costs on the Consolidated Balance Sheets at December 31 (in millions):
The Company recognizes revenue for certain reimbursable costs. Each reimbursable item and amount is stipulated in the Company’s contract with the customer, and such items and amounts frequently vary between contracts. The Company recognizes reimbursable costs on the gross basis, as both revenue and expenses, because the Company is the primary obligor in the arrangement, has discretion in supplier selection, is involved in determining product or service specifications and assumes full credit risk related to the reimbursable costs.
Cash Equivalents
Cash equivalents consist of highly liquid temporary cash investments with maturities no greater than three months at the time of purchase.
Accounts Receivable and Allowance for Doubtful Accounts
The Company's accounts receivable is stated at historical carrying value net of write-offs and allowance for doubtful accounts. The Company assesses the collectability of receivables and records adjustments to an allowance for doubtful accounts, which is recorded as an offset to accounts receivable, to cover the risk of credit losses. Any allowance is based on historical and other factors that predict collectability, including write-offs, recoveries and the evaluation and monitoring of credit quality. No allowance for doubtful accounts was required at December 31, 2017 or 2016.
The following table sets forth the components of Receivables - Trade and Other at December 31 (in millions):
Property and Depreciation
The Company provides depreciation for financial reporting purposes under the straight-line method over the asset’s estimated useful life from the date the asset is placed into service until it is sold or becomes fully depreciated. Estimated useful lives and salvage values are presented below:
Expenditures for new property or enhancements to existing property are capitalized and depreciated over the asset’s estimated useful life. As assets are sold or retired, property cost and related accumulated depreciation are removed from the accounts, and any resulting gain or loss is included in results of operations. The Company capitalized a portion of interest cost incurred during the drillship construction period, which ended in 2015 with the completion of the drillship construction program. The Company capitalized interest in the amount of $16.2 million in 2015. The Company did not capitalize interest in 2017 and 2016.
Expenditures for maintenance and repairs are charged to expense as incurred and totaled $113 million in 2017, $118 million in 2016 and $129 million in 2015.
Impairment of Long-lived Assets
The Company reviews the carrying values of long-lived assets for impairment whenever events or changes in circumstances indicate their carrying amounts may not be recoverable. For assets held and used, the Company determines recoverability by evaluating the undiscounted estimated future net cash flows based on projected day rates, operating costs, capital requirements and utilization of the asset under review. When the impairment of an asset is indicated, the Company measures the amount of impairment as the amount by which the asset’s carrying amount exceeds its estimated fair value. The Company measures fair value by estimating discounted future net cash flows under various operating scenarios (an income approach) and by assigning probabilities to each scenario in order to determine an expected value. The lowest level of inputs the Company uses to value assets held and used in the business are categorized as “significant unobservable inputs,” which are Level 3 inputs in the fair value hierarchy. For assets held for sale, the Company measures fair value based on equipment broker quotes, less anticipated selling costs, which are considered Level 3 inputs in the fair value hierarchy.
The Company conducted an impairment test of its assets during the fourth quarter of 2017; however, the test resulted in no impairment as the estimated undiscounted cash flows from the assets exceeded the assets' carrying values.
In 2016, the Company conducted an impairment test of its assets and determined that the carrying values for five of its jack-up drilling units aggregating $43.6 million were not recoverable and as a result, the Company recognized a non-cash impairment charge of $34.3 million in 2016. In 2015, the Company conducted an impairment test of its assets and determined that the carrying values for ten of its jack-up drilling units aggregating $457.8 million were not recoverable, and as a result, recognized a non-cash impairment charge of $329.8 million in 2015. The Company measured fair values using the income approach described above. The fair value estimates required the Company to use significant unobservable inputs, which are internally developed assumptions not observable in the market, including assumptions related to future demand for drilling services, estimated availability of rigs and future day rates, among others. The impairments recognized in 2016 and 2015 on the jack-up rigs are included in jack-up operations in the segment information in Note 13. Impairment charges are included in Material Charges and Other Operating Items on the Consolidated Statements of Operations.
Share-based Compensation
The Company generally recognizes compensation cost for employee share-based awards on a straight-line basis over a 36-month service period. For employees who are retirement-eligible at the grant date or who will become retirement-eligible within six months of the grant date, compensation cost is generally recognized over a minimum period of six months. Generally, compensation cost for employees who become retirement eligible after six months following the grant date but before the maximum service
period which is typically 36 months is amortized over the period from the grant date to the date the employee meets the retirement eligibility requirements.
Fair value of RSAs and RSUs awarded to employees is based on the average of the high and low market price of the shares on the date of grant. Prior to January 1, 2017, compensation cost was recognized for awards that were expected to vest and were adjusted in subsequent periods if actual forfeitures differed from estimates. Pursuant to the adoption of ASU No. 2016-09 as of January 1, 2017, the Company no longer estimates forfeitures, but rather adjusts its compensation costs in the period that actual forfeitures occur.
Non-employee directors may annually elect to receive either Directors RSUs or Directors ND RSUs. Both Directors RSUs and Directors ND RSUs vest at the earlier of the first anniversary of the grant date or the next annual meeting of shareholders following the grant date. Directors ND RSUs are settled on the vesting date, while Director RSUs are not settled until the director terminates service from the Board. Both Directors ND RSUs and Directors RSUs are settled in cash, shares or a combination thereof at the discretion of the Company Compensation Committee. Compensation cost for both Director RSUs and Director ND RSUs are recognized over the service period which is up to one year. Directors RSUs and Directors ND RSUs are accounted for under the liability method of accounting, the fair value is based on the market price of the underlying shares on the grant date, and compensation expense is adjusted for changes in fair value at each report date through the settlement date.
Performance-based awards consist of P-Units, in which the payment is contingent on the Company's TSR relative to the selected industry peer group. Fair value of P-Units is determined using a Monte-Carlo simulation model. The Company Compensation Committee has previously determined that any amount earned with respect to P-Units granted in 2015 would be settled in cash; however, P-Units granted in 2016 or after may be settled in cash, shares or a combination thereof at the Company Compensation Committee's discretion. All P-Units are accounted for under the liability method of accounting. Compensation cost is generally recognized on a straight-line basis over the service period and is adjusted for changes in fair value at each report date through the end of the performance period. For P-Units granted in 2017, the Company recognizes compensation cost on the accelerated method for those retirement eligible or who will become retirement eligible during the vesting period as the 2017 awards provide for pro-rata vesting rather than full vesting if a retirement eligible employee retires prior to the end of the 36 month service period.
Fair value of options is determined using the Black-Scholes option pricing model. The Company uses the simplified method for determining the expected life of options, because it does not have sufficient historical exercise data to provide a reasonable basis on which to estimate expected term, as permitted under US GAAP. The Company intends to share-settle options that are exercised and has therefore accounted for them as equity awards.
Fair value of SARs is determined using the Black-Scholes option pricing model. The Company uses the simplified method for determining the expected life of SARs, because it does not have sufficient historical exercise data to provide a reasonable basis on which to estimate expected term, as permitted under US GAAP. The Company has not granted any SARs since 2013. The Company intends to share-settle SARs that are exercised and has therefore accounted for them as equity awards.
Foreign Currency Transactions
A substantial majority of the Company's revenue is received in USD, which is the Company's functional currency. However, in certain countries in which the Company operates, local laws or contracts may require some payments to be received in the local currency. The Company is exposed to foreign currency exchange risk to the extent the amount of its monetary assets denominated in the foreign currency differs from its obligations in that foreign currency. In order to mitigate the effect of exchange rate risk, the Company attempts to limit foreign currency holdings to the extent they are needed to pay liabilities in the local currency. Prior to 2016, the Company entered into spot purchases or short-term derivative transactions, such as forward exchange contracts, with one-month durations. The Company did not enter into such transactions for the purpose of speculation, trading or investing in the market and believed that its use of forward exchange contracts did not expose it to material credit risk or other material market risk. Although the Company's risk policy allows it to enter into such forward exchange contracts, the Company does not currently anticipate entering into such transactions in the future and had no such contracts outstanding as of December 31, 2017.
At December 31, 2017 and 2016, the Company held Egyptian pounds in the amount of $2.8 million and $5.1 million, respectively, of which $2.2 million and $4.2 million are classified as Other Assets on the Consolidated Balance Sheets. At December 31, 2017, the Company held Angolan Kwanza in the amount of $4.3 million, which is classified as Other Assets on the Consolidated Balance Sheets. See the "Assets and Liabilities Measured at Fair Value on a Recurring Basis" section of Note 7 for further information.
Non-USD transaction gains and losses are recognized in “other - net” on the Consolidated Statements of Income. The Company recognized net currency exchange losses of $0.4 million, $9.7 million and $3.9 million in 2017, 2016 and 2015, respectively. In 2016, the exchange loss was primarily due to the devaluation of the Egyptian pound.
Income Taxes
Rowan recognizes deferred income tax assets and liabilities for the estimated future tax consequences of differences between the financial statement and tax bases of assets and liabilities. Valuation allowances are provided against deferred tax assets that are not likely to be realized. Interest and penalties related to income taxes are included in income tax expense.
The Company has not provided deferred income taxes on certain undistributed earnings of its non-U.K. subsidiaries. No subsidiary of RCI has a plan to distribute earnings to RCI in a manner that would cause those earnings to be subject to U.S., U.K. or other local country taxation.
Principles of Consolidation
The consolidated financial statements include the Company's accounts and those of its wholly-owned subsidiaries. Intercompany balances and transactions have been eliminated in consolidation. Investments in operating entities where the Company has the ability to exercise significant influence, but where it does not control operating and financial policies are accounted for using the equity method. Significant influence generally exists if the Company has an ownership interest representing between 20% and 50% of the voting stock of the investee. Under the equity method of accounting, investments are stated at initial cost and are adjusted for subsequent additional investments and the Company's proportionate share of earnings or losses and distributions. Equity in earnings of ARO, in the consolidated statements of operations, reflects the Company's proportionate share of ARO's net income, including any associated affiliate taxes. See the Note 3 for additional details related to the Company's equity method investment.
Income Per Common Share
Basic income (loss) per share is computed by dividing net income (loss) available to common shareholders by the weighted-average number of common shares outstanding during the period. Diluted income per share includes the additional weighted effect of dilutive securities outstanding during the period, which includes nonvested restricted stock, RSUs, P-Units, share options and SARs granted under share-based compensation plans. The effect of share equivalents is not included in the computation for periods in which a net loss occurs because to do so would be anti-dilutive.
A reconciliation of net income for basic and diluted income per share is set forth below (in millions):
A reconciliation of shares for basic and diluted income per share is set forth below (in millions):
Share options, SARs, nonvested restricted stock, P-Units and RSUs granted under share-based compensation plans are anti-dilutive and excluded from diluted earnings per share when the hypothetical number of shares that could be repurchased under the treasury stock method exceeds the number of shares that can be exercised, or when the Company reports a net loss from continuing operations. Anti-dilutive shares, which could potentially dilute earnings per share in the future, are set forth below (in millions):
Recent Accounting Pronouncements - Adopted
Stock Compensation - In March 2016, the FASB issued ASU No. 2016-09, Improvements to Employee Share-based Payment Accounting ASC 718), which simplifies several aspects of accounting for employee share-based payment awards, including the accounting for income taxes, withholding taxes and forfeitures, as well as classification on the statement of cash flows. The Company adopted this ASU as of January 1, 2017 and elected to account for forfeitures when they occur, on a modified retrospective basis. As required by this ASU, the Consolidated Statement of Cash Flows was retroactively adjusted for the years ended December 31, 2016 and 2015, to reclass $5.0 million and $1.2 million, respectively, from operating activities to financing activities related to shares repurchased for tax withholdings on vesting of RSUs. The Company prospectively adopted the provision of this ASU related to the classification of excess tax benefits on the statement of cash flows as an operating cash flow. The adoption did not have a material impact on the Company's consolidated financial statements.
Income Taxes - In October 2016, the FASB issued ASU No. 2016-16, Income Taxes (ASC 740): Intra-Entity Transfers of Assets Other than Inventory, which eliminates the exception that prohibits the recognition of current and deferred income tax effects for intra-entity transfers of assets other than inventory until the asset has been sold to an outside party. As permitted under this ASU, the Company elected early adoption of this ASU as of January 1, 2017 and recorded a $206.6 million increase to retained earnings for the remaining unamortized deferred tax liability resulting from intra-entity transactions. The impact of the adoption of this ASU was a reduction in tax benefits of $39.2 million, or a reduction per share of $0.31 for the year ended December 31, 2017.
Business Combinations - In January 2017, the FASB issued ASU No. 2017-01, Business Combinations (ASC 805): Clarifying the Definition of a Business, which clarifies the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. As permitted under this ASU, the Company early adopted this guidance as of October 17, 2017 in conjunction with the finalization of the ARO joint venture discussed in Note 1 and Note 3. The adoption did not have a material impact on the Company's consolidated financial statements.
Stock Compensation (Scope of Modification) - In May 2017, the FASB issued ASU No. 2017-09, Compensation - Stock Compensation (ASC 718): Scope of Modification Accounting, which provides guidance about which changes to the terms or conditions of a share-based payment award require an entity to apply modification accounting in Topic 718. This ASU was issued to provide clarity and reduce both (1) diversity in practice and (2) cost and complexity when applying the guidance in Topic 718 to a change to the terms or conditions of a share-based payment award. An entity will not have to account for the effects of a modification if all of the following are met: (1) The fair value of the modified award is the same as that of the original award immediately before the modification; (2) the vesting conditions of the modified award are the same as that of the original award immediately before the modification; and (3) the classification of the modified award as either an equity instrument or liability instrument is the same as that of the original award immediately before the modification. The Company adopted this guidance in the fourth quarter of 2017 and it did not have a material impact on its consolidated financial statements.
Recent Accounting Pronouncements - to be Adopted
Revenue Recognition - In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (ASC 606), which sets forth a global standard for revenue recognition and replaces most existing industry-specific guidance. The Company will be required to adopt the new standard in annual and interim periods beginning January 1, 2018. ASC 606 requires an entity to recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The Company will adopt ASC 606, effective January 1, 2018 utilizing the modified retrospective approach. In adopting ASC 606, the Company expects its revenue recognition to differ from its current revenue recognition pattern only as it relates to demobilization revenue. Such revenue, which is recognized upon completion of a contract under current GAAP, will be estimated at contract inception and recognized over the term of the contract under the new guidance for customer contracts that have demobilization provisions. While the Company continues to finalize the impact of adoption, the Company does not expect that the cumulative effect adjustment to opening retained earnings required by the modified retrospective adoption approach to be significant, as it will primarily consist of the impact of the timing difference related to recognition of demobilization revenue for affected contracts.
Lease Accounting - In February 2016, the FASB issued ASU No. 2016-02, Leases (ASC 842): Amendments to the FASB ASC, which requires an entity to recognize lease assets and lease liabilities on the balance sheet and to disclose key qualitative and quantitative information about the entity's leasing arrangements. Based on current guidance, lessees and lessors will be required to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach, including a number of optional practical expedients that entities may elect to apply. However, in January 2018, the FASB issued an exposure draft which allows for an option to apply the guidance prospectively, instead of retrospectively, and allows for other classification provisions, as described below. ASC 842 is effective for annual and interim periods beginning after December 15, 2018, with early adoption permitted. Under the updated accounting standards, the Company has preliminarily determined that its drilling contracts contain a lease component, and the adoption, therefore, will require that the Company separately recognize revenue associated with the lease and services components. As noted above, in January 2018, the FASB issued an exposure draft which
discussed a practical expedient which would allow companies to combine lease and non-lease components where the revenue recognition pattern is the same and where the combination of the service and lease component would be considered an operating lease. With respect to the applicability to the drilling industry of the practical expedients, the Company has and will continue to consult with its peers in the International Association of Drilling Contractors Accounting Sub-committee ("IADC Accounting Sub-committee") to evaluate any accounting standard updates issued as a result of the exposure draft for the applicability of this practical expedient to its drilling contracts. Although the Company had previously disclosed its intent to adopt ASC 842 and ASC 606 concurrently, due to the implications of this exposure draft, the Company elected to not adopt ASC 842 early on January 1, 2018, and as a result, is no longer adopting ASC 842 and ASC 606 concurrently.
The adoption of ASC 842 will have an impact on how the Company's consolidated balance sheets, statements of operations, cash flows and disclosures contained in our notes to consolidated financial statements will be presented, however because we are currently evaluating the impact of the new exposure draft, we are unable to quantify the overall impact at this time. As a lessee, we have estimated future minimum lease commitments of approximately $40 million with an estimated present value of approximately $30 million based on our currently identified lease portfolio. We continue to refine our estimate, which is subject to change at the adoption date of ASC 842.
Financial Instruments - In June 2016, the FASB issued ASU No. 2016-13, Financial Instruments - Credit Losses (ASC 326): Measurement of Credit Losses on Financial Instruments, which amends the FASB's guidance on the impairment of financial instruments. The ASU adds to US GAAP an impairment model that is based on expected losses rather than incurred losses. Under the new guidance, an entity recognizes as an allowance its estimate of expected credit losses. The Company will be required to adopt the amended guidance in annual and interim reports beginning January 1, 2020, with early adoption permitted for fiscal years beginning after December 15, 2018. The Company is in the process of evaluating the impact this amendment will have on its consolidated financial statements.
Statement of Cash Flows - In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows (ASC 230): Classification of Certain Cash Receipts and Cash Payments, which provides guidance on eight cash flow classification issues with the objective of reducing differences in practice. The Company will be required to adopt the amendments in this ASU in annual and interim periods beginning January 1, 2018, with early adoption permitted. Adoption is required to be on a retrospective basis, unless impracticable for any of the amendments, in which case a prospective application is permitted. The Company is in the process of finalizing its evaluation of the impact these amendments will have on its consolidated financial statements but currently believes such impact will be immaterial.
Statement of Cash Flows Restricted Cash - In November 2016, the FASB issued ASU No. 2016-18, Statement of Cash Flows (ASC 230): Restricted Cash, which requires restricted cash to be presented with cash and cash equivalents in the statement of cash flows. The changes in restricted cash and restricted cash equivalents during the period should be included in the beginning and ending cash and cash equivalents balance reconciliation on the statement of cash flows. When cash, cash equivalents, restricted cash or restricted cash equivalents are presented in more than one line item within the statement of financial position, an entity shall calculate a total cash amount in a narrative or tabular format that agrees with the amount shown on the statement of cash flows. Details on the nature and amounts of restricted cash should also be disclosed. The Company will be required to adopt the amendments in this ASU in annual and interim periods beginning January 1, 2018, with early adoption permitted. Adoption is required to be applied using a retrospective approach to each period presented. The Company is in the process of evaluating the impact these amendments may have on its consolidated financial statements.
Other Income - In February 2017, the FASB issued ASU No. 2017-05, Other Income (ASC 610): Clarifying the Scope of Asset Derecognition Guidance and Accounting for Partial Sales of Nonfinancial Assets” (“ASU 2017-05”). ASU 2017-05 clarifies the scope of the original guidance within Subtopic 610-20 that was issued in connection with ASU 2014-09, which provides guidance for recognizing gains and losses from the transfer of nonfinancial assets in contracts with non-customers. ASU 2017-05 also added guidance for partial sales of nonfinancial assets. The Company will be required to adopt the amendments in this ASU beginning January 1, 2018, concurrently with ASC 606. The Company is in the process of evaluating the impact this amendment may have on its consolidated financial statements.
Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost - In March 2017, the FASB issued ASU No. 2017-07, Compensation - Retirement Benefits (ASC 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost, which requires entities to present the service cost component of the net periodic benefit cost in the same income statement line item as other employee compensation costs. The other components of net benefit cost, including interest cost, expected return on plan assets, amortization of prior service cost/credit and actuarial gain/loss, and settlement and curtailment effects, are to be presented outside of any subtotal of operating income. Entities will have to disclose the line(s) used to present the other components of net periodic benefit cost, if the components are not presented separately in the income statement. The ASU also allows only the service cost component to be eligible for capitalization. This ASU is effective for fiscal years and interim periods beginning after December 15, 2017, and early adoption is permitted. The Company is in the process of
finalizing its evaluation of the impact these amendments will have on its consolidated financial statements but currently believes such impact will be immaterial.
Comprehensive Income - In February 2018, the FASB issued ASU No. 2018-02, Income Statement - Reporting Comprehensive Income (ASC 220): Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income, which allow a reclassification from accumulated other comprehensive income to retained earnings for stranded tax effects resulting from the Tax Cuts and Jobs Act of 2017. The Company will be required to adopt the amendments in this ASU in annual and interim periods beginning January 1, 2019, with early adoption permitted. Adoption is required to be applied either in the period of adoption or retrospectively to each period (or periods) in which the effect of the change in the U.S. federal corporate income tax rate in the Tax Cuts and Jobs Act is recognized. The Company is in the process of finalizing its evaluation of the impact these amendments will have on its consolidated financial statements but estimates a reclassification of $40-$50 million from Accumulated other comprehensive income to increase Retained earnings.
NOTE 3 - Equity Method Investments and Variable Interest Entities
On November 21, 2016, Rowan and Saudi Aramco, through their subsidiaries, entered into a Shareholders’ Agreement to create a 50/50 joint venture, known as ARO (see Note 1). ARO commenced operations on October 17, 2017 and owns, manages and operates offshore drilling units in Saudi Arabia. The Company accounts for its interest in ARO using the equity method of accounting and only recognizes its portion of equity earnings in the Company's consolidated financial statements. ARO is a variable interest entity; however, the Company is not the primary beneficiary and therefore does not consolidate ARO. The Company's judgment regarding the level of influence over ARO included considering key factors such as: each company's ownership interest, representation on the board of managers of ARO, ability to direct activities that most significantly impact ARO's economic performance, as well as the ability to influence policy-making decisions.
Summarized financial information
Summarized financial information for ARO, as derived from ARO's financial statements, is as follows (in millions):
Related party transactions
In connection with the establishment of ARO the Company signed an Asset Transfer and Contribution Agreement. As part of this agreement the Company contributed cash to ARO of $357.7 million in exchange for a 10-year shareholder note receivable from ARO, initially totaling $357.7 million, at a stated interest rate of LIBOR plus two percent. As of December 31, 2017, the outstanding amount for this shareholder note receivable was $271.3 million, consisting of $270.2 million and $1.1 million, respectively, included in Long-term note receivable from unconsolidated subsidiary and Receivables - trade and other on the Company's Consolidated Balance Sheets. Interest related to this note is being recognized as a part of Interest Income in the Company's Consolidated Statement of Operations and totaled approximately $2.1 million for the period from October 17, 2017 to December 31, 2017.
In conjunction with the establishment of ARO, the Company signed a series of agreements including: a Transition Services Agreement and a Secondment Agreement. Pursuant to these agreements the Company, or its seconded employees, will provide various services to ARO (see Note 13), and in return, the Company is to be provided remuneration for those services. From time to time Rowan may sell equipment or supplies to ARO. Additionally, Rowan incurred certain preparation costs prior to ARO commencing operations which will be reimbursed to Rowan by ARO. Revenue and other amounts recognized related to these agreements and transactions is as follows (in millions):
Total Accounts receivable from ARO related to these transactions totaled approximately $17.3 million as of December 31, 2017.
As discussed in Note 1, with the establishment of ARO, the Company also signed a Rig Management Agreement whereby ARO will provide certain rig management services for Rowan's rigs while they are contracted with Saudi Aramco. The Company will compensate ARO for the services in which they provide to Rowan. For the period from October 17, 2017 to December 31, 2017, the Company recognized $7.8 million in Direct operating cost in the Consolidated Statements of Operations related to these rig management services. Additionally, ARO may sell equipment or supplies to Rowan or purchase such for Rowan, in which case ARO is provided reimbursement. For the period from October 17, 2017 to December 31, 2017, the Company recognized $0.6 million in Direct operating cost in the Consolidated Statements of Operations related to these transactions as well as $2.4 million in accrued capital expenditures.
Accounts payable to ARO related to these transactions totaled approximately $10.8 million as of December 31, 2017.
The following summarizes the total assets and liabilities as reflected in the Company's consolidated balance sheets as well as the Company's maximum exposure to loss related to ARO (in millions). Generally, the Company's maximum exposure to loss is limited to its 1) equity investment in the joint venture, 2) outstanding note receivable and 3) any amounts payable to the Company for services it provides to the joint venture, reduced by payables for services which the Company owes to ARO.
NOTE 4 - ACCRUED LIABILITIES
Accrued liabilities at December 31 consisted of the following (in millions):
NOTE 5 - LONG-TERM DEBT
Long-term debt at December 31 consisted of the following (in millions):
The following is a summary of scheduled long-term debt maturities by year, as of December 31, 2017 (in millions):
Revolving Credit Facility
Availability under the Revolving Credit Facility is $1.50 billion through January 23, 2019, declining to $1.44 billion through January 23, 2020, and to approximately $1.29 billion through the maturity in 2021. As of December 31, 2017, no amounts were outstanding and $5.0 million in letters of credit had been issued under the Revolving Credit Facility leaving remaining availability of $1.495 billion.
Advances under the Revolving Credit Facility bear interest at LIBOR or Base Rate plus an applicable margin, which is dependent upon the Company's credit ratings. The applicable margins for LIBOR and Base Rate advances range from 1.125% - 2.0% and 0.125% - 1.0%, respectively. The Company is also required to pay a commitment fee on undrawn amounts of the Revolving Credit Facility, which ranges from 0.125% to 0.35%, depending on the Company's credit ratings.
The Revolving Credit Facility requires the Company to maintain a total debt-to-capitalization ratio of less than or equal to 60%. Additionally, the Revolving Credit Facility has customary restrictive covenants that, including others, restrict the Company's ability to incur certain debt and liens, enter into certain merger and acquisition agreements, sell, transfer, lease or otherwise dispose of all or substantially all of the Company's assets and substantially change the character of the Company's business from contract drilling.
Debt Reductions
During 2015, the Company paid $101.1 million in cash to retire $97.9 million aggregate principal amount of the 2017 Notes and the 2019 Notes, plus accrued interest, and recognized a $1.5 million loss on early extinguishment of debt.
During the first half of 2016, the Company paid $45.2 million in cash to retire $47.9 million aggregate principal amount of the 2017 Notes and the 2019 Notes, and recognized a $2.4 million gain on early extinguishment of debt.
In December 2016, the Company commenced cash tender offers for $750 million aggregate principal amount of the Subject Notes issued by the Company (the "Tender Offers"). The Tender Offers expired on January 3, 2017; however, there was also an early tender expiration on December 16, 2016 which provided for an early tender premium. Subject Notes validly tendered and accepted for purchase prior to the early tender expiration time on December 16, 2016, received tender offer consideration plus an early tender premium. As a result of the Tender Offers, in December 2016, the Company paid $490.5 million to repurchase $463.9 million aggregate principal amount of outstanding Subject Notes, consisting of $265.5 million of the 2017 Notes, $186.7 million of the 2019 Notes, $9.8 million of the 2022 Notes and $1.9 million of the 2024 Notes, and recognized a $33.6 million loss on the early extinguishment of debt which included approximately $5.9 million of bank and legal fees.
On December 19, 2016, Rowan plc, as guarantor, and its 100% owned subsidiary, RCI, as issuer, completed the issuance of $500 million aggregate principal amount of the 2025 Notes at a price of 100% of the principal amount. The Company used the net proceeds of the offering, approximately $492 million, along with cash on hand, to fund the repurchase of Subject Notes pursuant to the Tender Offers. $5.3 million of the cash paid to the underwriting banks in the form of the underwriters discount and structuring fee was expensed and included in the $33.6 million loss on early extinguishment of debt related to the Tender Offers. Interest on the 2025 Notes is payable on June 15 and December 15 of each year and began on June 15, 2017. The 2025 Notes contain a provision whereby upon a change of control repurchase event, as defined in the indenture governing the 2025 Notes, the Company may be required to make an offer to repurchase all outstanding notes at a price in cash equal to 101% of the aggregate principal amount of the notes repurchased, plus any accrued and unpaid interest to the repurchase date. Otherwise, the 2025 Notes contain substantially the same provisions as the Company’s other Senior Notes.
In January 2017, at the expiration of the Tender Offers, the Company paid $32.8 million to repurchase an additional $34.6 million aggregate principal amount of outstanding Subject Notes, consisting of $0.1 million of the 2017 Notes, $0.9 million of the 2019 Notes and $33.6 million of the 2022 Notes.
On January 9, 2017, the Company called for redemption $92.1 million aggregate principal amount of the 2017 Notes that remained outstanding and on February 8, 2017, the Company paid $94.0 million to redeem such notes.
In the second quarter of 2017, the Company paid $33.5 million in cash to retire $35.8 million aggregate principal amount of the 2022 Notes and recognized a $2.4 million gain on early extinguishment of debt.
In July 2017, the Company paid $7.0 million in cash to retire $6.5 million aggregate principal amount of the 2019 Notes and recognized a $0.5 million loss on early extinguishment of debt.
Debt Guarantee and Other Provisions
The Senior Notes are RCI’s senior unsecured obligations and rank senior in right of payment to all of its subordinated indebtedness and pari passu in right of payment with any of RCI’s future senior indebtedness, including any indebtedness under RCI’s senior Revolving Credit Facility. The Senior Notes rank effectively junior to RCI’s future secured indebtedness, if any, to the extent of the value of its assets constituting collateral securing that indebtedness and to all existing and future indebtedness of its subsidiaries (other than indebtedness and liabilities owed to RCI).
All or part of the Senior Notes may be redeemed at any time for an amount equal to 100% of the principal amount plus accrued and unpaid interest to the redemption date plus the applicable make-whole premium, if any.
The Senior Notes are fully and unconditionally guaranteed on a senior and unsecured basis by Rowan plc (see Note 17 ).
Restrictive provisions in the Company’s bank credit facility agreement limit consolidated debt to 60% of book capitalization. The Company's consolidated debt to total capitalization ratio at December 31, 2017, was 32%.
Other provisions of the Company's debt agreements limit the ability of the Company to create liens that secure debt, engage in sale and leaseback transactions, merge or consolidate with another company and, in the event of noncompliance, restrict investment activities and asset purchases and sales, among other things. The Company was in compliance with its debt covenants at December 31, 2017.
NOTE 6 - DERIVATIVES
In 2016, the Company determined that the FCX Contingent Payments Provisions resulting from the contract termination with FMOG (See Note 1) were freestanding financial instruments and that they each met the criteria of a derivative instrument. The FCX Contingent Payments Provisions were initially recorded to revenue at a fair value of $6.2 million on May 23, 2016, and were revalued at each reporting date with changes in the fair value reported as non-operating income or expense. The fair value of the FCX Contingent Payments Provisions was determined using a Monte Carlo simulation (see Note 7). In January 2017, the Company and FCX settled the First FCX Contingent Payment Provision with a $6.0 million payment received by the Company. At maturity, the value of the Second FCX Contingent Payment Provision was zero based on the actual results of the average price of WTI crude oil over the period determined in the agreement; therefore, no payment was due to the Company.
The following table provides the fair value of the Company’s derivative as reflected in the Consolidated Balance Sheets (in millions):
The following table provides the revaluation effect of the Company’s derivative on the Consolidated Statements of Operations (in millions):
NOTE 7 - FAIR VALUE MEASUREMENTS
Fair value is defined as the exchange price that would be received for an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date. The fair value hierarchy prescribed by US GAAP requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The three levels of inputs that may be used to measure fair value are:
•
Level 1 - Quoted prices for identical instruments in active markets;
•
Level 2 - Quoted market prices for similar instruments in active markets; quoted prices for identical instruments in markets that are not active, and model-derived valuations in which all significant inputs and significant value drivers are observable in active markets; and
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Level 3 - Valuations derived from valuation techniques in which one or more significant inputs or significant value drivers are unobservable, such as those used in pricing models or discounted cash flow methodologies, for example.
The applicable level within the fair value hierarchy is the lowest level of any input that is significant to the fair value measurement.
Derivative
The fair values of the FCX Contingent Payments Provisions (Level 3) were estimated using a Monte Carlo simulation model, which calculated the probabilities of the daily closing WTI spot price exceeding the Price Targets on a daily averaging basis during the 12-month payment measurement period ending on June 30, 2017. The probabilities were applied to the payout at each price target to calculate the probability-weighted expected payout. The following were the significant inputs used in the valuation of the FCX Contingent Payments Provisions: the WTI Spot Price on the valuation date, the expected volatility, and the risk-free
interest rate, and the slope of the WTI forward curve, which were $47.48, 37.5%, 0.765% and 5.5% at May 23, 2016, respectively, and $53.72, 28.557%, 0.734%, and 11.205% at December 31, 2016, respectively. The expected volatility was estimated from the implied volatility rates of WTI crude futures. The risk-free rate was based on yields of U.S. Treasury securities commensurate with the remaining term of the FXC Contingent Payments. At December 31, 2016, the Company valued the FCX Contingent Payments Provisions in the amount of $6.1 million which was classified as Prepaid expenses and other current assets on the Consolidated Balance Sheet. In January 2017, the Company and FCX settled the First FCX Contingent Payment Provision with a $6.0 million payment received by the Company (see Note 1). The Second FCX Contingent Payment Provision had no value at maturity, as the average price of WTI crude oil did not meet the terms specified in the FCX Agreement; therefore, no payment was due to the Company (see Note 6).
Assets and Liabilities Measured at Fair Value on a Recurring Basis
Assets measured at fair value on a recurring basis are presented below (in millions):
At December 31, 2016, the Company had FCX Contingent Payments Provisions in the amount of $6.1 million, which is classified as Prepaid expenses and other current assets on the Consolidated Balance Sheet.
At December 31, 2017 and 2016, the Company held Egyptian pounds in the amount of $2.2 million and $4.2 million, respectively, which are classified as Other assets on the Consolidated Balance Sheets. The Company ceased drilling operations in Egypt in 2014, and is currently working to obtain access to the funds for use outside Egypt to the extent they are not utilized.
Given stricter foreign currency exchange controls in Angola, the Company determined in May 2017 that its previous method of converting Angola Kwanza to USD is likely no longer feasible. As a result, at December 31, 2017, the Company classified its Angolan Kwanza USD equivalent balance of $4.3 million as a non-current asset in Other assets on the Consolidated Balance Sheet. Currently, the Company considers the amounts to be recoverable and will continue to evaluate options to convert the Angolan Kwanza to USD.
Trade receivables and trade payables, which are required to be measured at fair value, have carrying values that approximate their fair values due to their short maturities.
Assets Measured at Fair Value on a Nonrecurring Basis
Assets measured at fair value on a nonrecurring basis and whose carrying values were remeasured during the years ended December 31 are set forth below (in millions):
In 2016, the Company recognized non-cash asset impairment charges aggregating $34.3 million on five of its jack-up drilling units having an aggregate net carrying value of $43.6 million prior to the write-down. Two of these jack-up drilling units were sold in the fourth quarter of 2016 for gross proceeds of approximately $5.0 million and the Company recognized a net loss on sale of $1.2 million. In 2015, the Company recognized non-cash asset impairment charges aggregating $329.8 million on ten of its jack-up drilling units having an aggregate net carrying value of $457.8 million prior to the write-down. Impairment charges are included in Material Charges and Other Operating Items on the Consolidated Statements of Operations (see "Impairment of Long-lived Assets" in Note 2). The financial information for these rigs has been reported as part of the Jack-ups segment.
Other Fair Value Measurements
Financial instruments not required to be measured at fair value consist of the Company’s publicly traded debt securities. The Company's publicly traded debt securities had a carrying value of $2.510 billion at December 31, 2017, and an estimated fair value at that date aggregating $2.262 billion, compared to a carrying and fair value of $2.680 billion and $2.448 billion, respectively, at December 31, 2016. Fair values of the Company's publicly traded debt securities were provided by a broker who makes a market in such securities and were measured using a market-approach valuation technique, which is a Level 2 fair value measurement.
Concentrations of Credit Risk
The Company invests its excess cash primarily in time deposits and high-quality money market accounts at several large commercial banks with strong credit ratings, and therefore believes that its risk of loss is minimal.
The Company’s customers largely consist of major international oil companies, national oil companies and large investment-grade exploration and production companies. The Company routinely evaluates and monitors the credit quality of potential and current customers. The Company maintains reserves for credit losses when necessary and actual losses have been within management's expectations.
Revenue and receivables from transactions with external customers that amount to 10% or more of revenue during the years ended December 31 are set forth below:
Percentage of revenue from major customers:
Percentage of receivables from major customers:
NOTE 8 - COMMITMENTS AND CONTINGENT LIABILITIES
The Company has operating leases covering office space and equipment. Certain of the leases are subject to escalations based on increases in building operating costs. Rental expense attributable to continuing operations was $11.4 million, $10.6 million and $13.2 million in 2017, 2016 and 2015, respectively.
At December 31, 2017, future minimum payments to be made under noncancelable operating leases were as follows (in millions):
The Company had commitments for purchase obligations totaling $80.0 million at December 31, 2017.
Letters of credit - The Company periodically employs letters of credit in the normal course of its business and had outstanding letters of credit of approximately $7.3 million at December 31, 2017, of which $5.0 million were issued under the Company's Revolving Credit Facility.
Joint venture funding obligations - For the Company's potential obligation to fund ARO for newbuild jack-up rigs see Note 1.
Uncertain tax positions - The Company has been advised by the IRS of proposed unfavorable tax adjustments of $85 million including applicable penalties for the open tax years 2009 through 2012. The unfavorable tax adjustments primarily related to the following items: 2009 tax benefits recognized as a result of applying the facts of a third-party tax case that provided favorable tax treatment for certain non-U.S. contracts entered into in prior years to the Company’s situation; transfer pricing; and domestic production activity deduction. The Company has protested the proposed adjustment. However, the IRS does not agree with the Company's protest and they have submitted the proposed unfavorable tax adjustments to be reviewed by the IRS appeals group. In years subsequent to 2012, the Company has similar positions that could be subject to adjustments for the open years. The Company has provided for amounts that it believes will be ultimately payable under the proposed adjustments and intends to vigorously defend its positions; however, if the Company determines the provisions for these matters to be inadequate due to new information or the Company is required to pay a significant amount of additional U.S. taxes and applicable penalties and interest in excess of amounts that have been provided for these matters, the Company's consolidated results of operations and cash flows could be materially and adversely affected.
The gross unrecognized tax benefits excluding penalties and interest are $102 million and $120 million as of December 31, 2017 and 2016, respectively. The decrease to gross unrecognized tax benefits was primarily due to a lapse in statutes of limitation and audit settlement offset by foreign currency exchange revaluation and tax positions taken related to current year anticipated transfer pricing positions. If the December 31, 2017 net unrecognized tax benefits excluding penalties and interest were recognized, this would favorably impact the Company's tax provision by $41 million.
It is reasonable that the existing liabilities for the unrecognized tax benefits may increase or decrease over the next 12 months as a result of audit closures and statute expirations, however, the ultimate timing of the resolution and/or closure of audits is highly uncertain.
Pending or threatened litigation - The Company is involved in various routine legal proceedings incidental to its businesses and vigorously defends its position in all such matters. Although the outcome of such proceedings cannot be predicted with certainty, the Company believes that there are no known contingencies, claims or lawsuits that will have a material adverse effect on its financial position, results of operations or cash flows.
In addition to the legal proceedings described above, we are vigorously contesting a claim by a former agent in the Middle East for compensation associated with the Company's termination of the agent's services. In February 2018, the agent made a demand for approximately $45 million, which the Company believes is without merit. The Company is making payments pursuant to its agreements with the agent and has an accrual for the Company's best estimate of the potential liability. Because of the current uncertainty of the basis for the claim and the application of which law may apply to resolving the dispute, the amount of the accrual may be different from the amount of the ultimate liability.
NOTE 9 - SHARE-BASED COMPENSATION PLANS
Under the Plan, the Company Compensation Committee is authorized to grant employees and non-employee directors incentive awards in the form of RSAs, RSUs, options and SARs. In addition, the Company Compensation Committee may grant performance-based awards under the Plan (such as P-Units which may be settled in shares cash, or a combination thereof at the discretion of the Company Compensation Committee), for which the amount earned is dependent on the achievement of certain market or performance conditions over a specified period. As of December 31, 2017, there were 8,548,953 shares available for future grant under the Plan, including 2,174,572 additional shares approved for issuance by the shareholders at the Annual General Meeting on May 25, 2017. Shares issued to satisfy awards to employees are issued from the Company's EBT which are deemed treasury shares, while shares issued to satisfy awards to non-employee directors are newly issued shares. In accordance with the Company's adoption of ASU 2016-09, the Company no longer estimates forfeitures but rather accounts for forfeitures in the period in which they occur; therefore the expected to vest percentage is 100% for awards not vested.
Compensation cost charged to expense under all share-based incentive awards is presented below (in millions):
As of December 31, 2017, unrecognized compensation cost related to nonvested share-based compensation arrangements totaled $32.7 million, which is expected to be recognized over a weighted-average period of 1.7 years.
Restricted Shares (Employees and Non-employee Directors) - RSAs represent ordinary shares subject to a vesting period that restricts its sale or transfer until the vesting period ends. In general, the restricted shares granted to employees vested and the restrictions lapsed in one-third increments each year over a three-year service period, or in some cases, cliff vested at the end of a three-year service period. The Company discontinued granting restricted shares as annual awards to employees beginning in 2013 and all restricted shares granted to employees were vested as of December 31, 2016. In 2016, the Company granted RSAs to non-employee directors and such vested and were settled in shares on the date of the 2017 annual meeting of shareholders. Activity related to RSAs for the year ended December 31, 2017, is summarized below:
The weighted-average grant date fair value of restricted shares granted in 2016 was $18.60. No restricted shares were granted in 2017 and 2015. The aggregate fair value of restricted shares that vested in 2017, 2016 and 2015 was $758 thousand, $37 thousand and $4.1 million, respectively, based on share prices on the vesting dates.
Employee Restricted Share Units - RSUs are rights to receive a specified number of ordinary shares upon vesting. RSUs granted to employees typically vest in one-third increments over a three-year service period or in some cases, cliff vest at the end of three years. Employee RSU activity for the year ended December 31, 2017, follows:
The weighted-average grant date fair value of employee RSUs granted in 2017, 2016 and 2015 was $17.09, $11.62 and $21.11, respectively. The aggregate fair value of employee RSUs that vested in 2017, 2016 and 2015 was $17.8 million, $14.6 million and $8.9 million, respectively.
Non-employee Director Deferred Restricted Share Units and Non-employee Director Non-Deferred Restricted Share Units - Non-employee directors may annually elect to receive either Directors RSUs or Directors ND RSUs. Both Directors RSUs and Directors ND RSUs vest at the earlier of the first anniversary of the grant date or the next annual meeting of shareholders following the grant date. Directors ND RSUs are settled on the vesting date, while Director RSUs are not settled until the director terminates service from the Board. Both Directors ND RSUs and Directors RSUs are settled in cash, shares or a combination thereof at the discretion of the Company Compensation Committee.
Activity related to Directors RSUs for the year ended December 31, 2017, follows:
The weighted-average grant date fair value of non-employee Directors RSUs granted in 2017, 2016 and 2015 was $13.24, $17.43 and $20.96, respectively. The number and aggregate settlement-date fair value of Directors RSUs settled during the year were as follows: 2017 - 114 thousand Directors RSUs at $1.5 million; 2016 - 54 thousand Directors RSUs at $1.0 million; 2015 - 44 thousand Directors RSUs at $0.9 million.
Activity related to Directors ND RSUs for the year ended December 31, 2017, follows:
The weighted-average grant date fair value of non-employee Directors ND RSUs granted in 2017 was $13.24.
Directors RSUs and Directors ND RSUs are accounted for under the liability method. Accordingly, other long-term liabilities at December 31, 2017 and 2016, included $3.8 million and $5.2 million, respectively, related to such awards.
Performance-based Awards - The Company Compensation Committee may grant awards in which payment is contingent upon the achievement of certain market or performance-based conditions over a period of time specified by the Committee. Payment of such awards may be in ordinary shares or in cash as determined by the Committee.
During 2015, 2016 and 2017, the Company granted to certain members of management P-Units that have a target value of $100 per unit. The amount ultimately earned is determined by the Company’s TSR relative to a selected group of peer companies, as selected by the Company Compensation Committee, over a three-year period ending December 31, 2017, 2018 and 2019 for the 2015, 2016 and 2017 grants, respectively. The amount earned could range from zero to $200 per unit depending on performance. Twenty-five percent of the P-Units’ value is determined by the Company’s relative TSR ranking for each one-year period ended December 31 and 25% of the P-Units’ value is determined by the relative TSR ranking for the three-year period ended December 31. P-Units cliff vest and payment is made, if any, on the third anniversary following the grant date. Any employee who terminates employment with the Company prior to the third anniversary for any reason other than retirement will not receive any payment with respect to P-Units unless approved by the Company Compensation Committee. Settlement of the P-Units granted in 2016 and 2017 may be in cash, shares or a combination thereof at the Company Compensation Committee's discretion. The
Company Compensation Committee has previously determined that any amount earned with respect to P-Units granted in 2015 would be settled in cash.
The grant-date fair value of P-Units granted in 2017, 2016 and 2015 was estimated to be $9.5 million, $8.6 million and $9.0 million, respectively. Fair value was estimated using the Monte Carlo simulation model, which considers the probabilities of the Company’s TSR ranking at the end of each performance period, and the amount of the payout at each rank to determine the probability-weighted expected payout. The Company uses liability accounting to account for the P-Units. Compensation is recognized on a straight-line basis over a maximum period of three years from the grant date and is adjusted for changes in fair value through the end of the performance period.
Liabilities for estimated P-Unit obligations at December 31, 2017 for 2017 grants and prior, included $11.5 million and $10.5 million classified as current and noncurrent, respectively, compared to $10.9 million and $12.8 million, respectively, at December 31, 2016. Current and noncurrent estimated P-Unit liabilities are included in Accrued liabilities, and Other liabilities, respectively, in the Consolidated Balance Sheets.
In 2017, 2016 and 2015, the Company paid $11.4 million, $7.9 million and $2.7 million, respectively, in cash to settle P-Units that vested during the year.
Share Appreciation Rights - SARs give the holder the right to receive ordinary shares at no cost to the employee, or cash at the discretion of the Committee, equal in value to the excess of the market price of a share on the date of exercise over the exercise price. All SARs granted have exercise prices equal to the market price of the underlying shares on the date of grant. SARs become exercisable in one-third annual increments over a three-year service period and expire ten years following the grant date. The Company intends to share-settle any exercises of SARs and has therefore accounted for SARs as equity awards.
No SARs have been granted since 2013.
SARs activity for the year ended December 31, 2017, is summarized below:
No SARs were exercised in 2017, 2016 and 2015.
Share Options - Share options granted to employees in 2017 become exercisable and cliff vest at the end of a four-year vesting period at a price generally equal to the market price of the Company’s common shares on the date of grant. The remaining share options became exercisable over a three- year service period at a price generally equal to the market price of the Company’s common shares on the date of grant. Unexercised options expire seven to ten years after the grant date.
Fair values of Share options granted were determined using the Black-Scholes option pricing model with the following weighted-average assumptions:
Share option activity for the year ended December 31, 2017, is summarized below:
No options were exercised in 2017, 2016 or 2015.
NOTE 10 - PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS
The Company provides defined-benefit pension, health care and life insurance benefits upon retirement for certain full-time employees. Pension benefits are provided under The Rowan Pension Plan, and The Rowan SERP, and health care and life insurance benefits are provided under the Retiree Medical Plan.
The following table presents the changes in benefit obligations and plan assets for the years ended December 31 and the funded status and weighted-average assumptions used to determine the benefit obligation at each year end (dollars in millions):
The projected benefit obligations for pension benefits in the preceding table reflect the actuarial present value of benefits accrued based on services rendered to date and include the estimated effect of future salary increases. The accumulated benefit obligations, which are presented below for all plans in the aggregate at December 31, are based on services rendered to date, but exclude the effect of future salary increases (in millions):
On November 27, 2017, the Company purchased annuities to cover post-65 retiree medical benefits for current retirees as of the purchase date. The annuity purchase settled post-65 medical benefits (i.e., Health Reimbursement Account, or “HRA”, amounts) for affected participants, with the insurer taking responsibility for all benefit payments on and after January 1, 2019. The Company retained the obligation for 2018 benefit payments. The Company determined that this annuity purchase resulted in a full settlement of the post-65 medical obligation and as a result the entirety of the annuity purchase was treated as a settlement and resulted in a settlement loss of $5.8 million, calculated as of December 31, 2017.
On August 10, 2016, the Company communicated changes to the participants in its postretirement benefits plan, which was previously frozen to new entrants in 2008. Based on these changes, effective as of January 1, 2017, eligible participants now receive a health reimbursement account that provides a fixed dollar benefit per year. The impact of these changes to the plan and related, as of August 10, 2016, are presented in the table below (in millions):
During 2016, the Rowan SERP had a one-time settlement charge recognized in net periodic pension costs under US GAAP of $0.5 million as of December 31, 2016, attributable to lump sum payments during 2016 which exceeded the sum of the service cost and interest cost, the threshold that requires recognition of a settlement loss.
In 2016, the Norwegian Onshore and Offshore pension plans both experienced plan curtailments. Across Rowan Norway Limited, which employs participants of both the Onshore and Offshore pension plans, there was an employment reduction resulting in an approximate 50% reduction in active participants of the plans in early 2017. Since Rowan provided affected employees redundancy letters in November 2016, the curtailment was recognized effective December 31, 2016. The Company recognized a $0.4 million curtailment gain in net periodic pension costs for 2016.
During 2015, the Company amended the eligibility requirement with respect to the Retiree Medical Plan to exclude any participant that was previously eligible and was under the age of 50 as of January 1, 2016. The effect of the change was to reduce the projected benefit obligation by $7.2 million, which was net of an estimated $4.4 million payment to be made in early 2016 to the affected participants. The actual payment made in 2016 was $2.6 million and the Company recognized a related $0.1 million settlement loss.
Effective January 1, 2016, the Company changed its estimate of the service and interest cost components of net periodic benefit costs for its significant defined benefit pension and other postretirement benefit plans. Previously, the Company estimated the service and interest cost components utilizing a single weighted-average discount rate derived from the yield curve used to measure the benefit obligation. The new estimate utilizes a full yield curve approach in the estimation of these components by applying the specific spot rates along the yield curve used in the determination of the benefit obligation to their underlying projected cash flows. The new estimate provides a more precise measurement of service and interest costs by improving the correlation between projected benefit cash flows and their corresponding spot rates. While the benefit obligation measured under this approach is unchanged, more granular application of the spot rates reduced the service and interest cost for fiscal 2016.
Each of the Company’s pension plans has a benefit obligation that exceeds the fair value of plan assets.
The Company estimates the following amounts, which are classified in accumulated other comprehensive loss, a component of shareholders’ equity, will be recognized as net periodic benefit cost in 2018 (in millions):
Cumulative gains and losses in excess of 10% of the greater of projected benefit obligation or market-related value of plan assets are amortized over the expected average remaining service of the current active membership.
Each unrecognized prior service cost base is amortized on a straight line basis over the average remaining service period of participants expected to receive a benefit and who are active at the date of the plan amendment. If all or almost all of the plan’s participants offered a benefit by the plan amendment are inactive, the amortization is based on their average remaining life expectancy instead of average remaining service.
The components of net periodic pension cost and the weighted-average assumptions used to determine net cost were as follows (dollars in millions):
The components of net periodic cost of other postretirement benefits and the weighted average discount rate used to determine net cost were as follows (dollars in millions):
The pension plans’ investment objectives for fund assets are: to achieve over the life of the plans a return equal to the plans’ expected investment return or the inflation rate plus 3%, whichever is greater; to invest assets in a manner such that contributions are minimized and future assets are available to fund liabilities; to maintain liquidity sufficient to pay benefits when due; and to diversify among asset classes so that assets earn a reasonable return with an acceptable level of risk. The plans employ several active managers with proven long-term records in their specific investment discipline.
Target allocations among asset categories and the fair values of each category of plan assets as of December 31, 2017 and 2016, classified by level within the US GAAP fair value hierarchy is presented below. The plans will periodically reallocate assets in accordance with the allocation targets, after giving consideration to the expected level of cash required to pay current benefits and plan expenses (dollars in millions):
Assets in the U.S. equities category include investments in common and preferred stocks (and equivalents such as American Depository Receipts and convertible bonds) and may be held through separate accounts, commingled funds or an institutional mutual fund. Assets in the international equities category include investments in a broad range of international equity securities, including both developed and emerging markets, and may be held through a commingled or institutional mutual fund. The real estate category includes investments in pooled and commingled funds whose objectives are diversified equity investments in income-producing properties. Each real estate fund is intended to provide broad exposure to the real estate market by property type, geographic location and size and may invest internationally. Securities in both the aggregate and core plus fixed income categories include U.S. government, corporate, mortgage- and asset-backed securities and Yankee bonds, and both categories target an average credit rating of “A” or better at all times. Individual securities in the aggregate fixed income category must be investment grade or above at the time of purchase, whereas securities in the core plus category may have a rating of “B” or above. Additionally, the core plus category may invest in non-U.S. securities. Assets in the aggregate and core plus fixed income categories are held primarily through a commingled fund and an institutional mutual fund, respectively. Group annuity contracts are invested in a combination of equity, real estate, bond and other investments in connection with a pension plan in Norway.
The following is a description of the valuation methodologies used for the pension plan assets at December 31, 2017, and 2016:
•
Fair values of all U.S. equity securities, the international all cap equity securities and aggregate fixed income securities categorized as Level 2 were held in commingled funds which were valued daily based on a net asset value.
•
Fair value of international small cap equity securities categorized as Level 2 were held in a limited partnership fund which was valued monthly based on a net asset value.
•
The real estate categorized as Level 2 was held in two accounts (a commingled fund and a limited partnership). The assets in the commingled fund were valued monthly based on a net asset value and the assets in the limited partnership were valued quarterly based on a net asset value.
•
Cash and equivalents categorized as Level 2 were valued at cost, which approximates fair value.
•
Fair value of mutual fund investments in core plus fixed income securities categorized as Level 1 were based on quoted market prices which represent the net asset value of shares held.
To develop the expected long-term rate of return on assets assumption, the Company considered the current level of expected returns on risk-free investments (primarily government bonds), the historical level of the risk premium associated with the plans’ other asset classes and the expectations for future returns of each asset class. The expected return for each asset class was then weighted based upon the current asset allocation to develop the expected long-term rate of return on assets assumption for the plans, which was reduced to 6.70% at December 31, 2017, from 7.15% at December 31, 2016.
The Company's estimates for its net benefit expense (income) are partially based on the expected return on pension plan assets. The Company uses a market-related value of plan assets to determine the expected return on pension plan assets. In determining the market-related value of plan assets, differences between expected and actual asset returns are deferred and recognized over two years. If the Company used the fair value of its plan assets instead of the market-related value of plan assets in determining the expected return on pension plan assets, its net benefit expense would have been $2.7 million higher for the year ended December 31, 2017.
The Company bases its determination of the asset return component of pension expense on a market-related valuation of assets, which reduces year-to-year volatility. This market-related valuation recognizes investment gains or losses over a two-year period from the year in which they occur. Investment gains or losses for this purpose are the difference between the expected return calculated using the market-related value of assets and the actual return based on the fair value of assets. Since the market-related value of assets recognizes gains or losses over a two-year period, the future value of assets will be impacted as previously deferred gains or losses are recorded. As of January 1, 2018, cumulative asset gains of approximately $31.7 million remained to be recognized in the calculation of the market-related value of assets.
The Company currently expects to contribute approximately $25 million to its pension plans in 2018 and to directly pay other postretirement benefits of approximately $2 million.
Estimated future annual benefit payments from plan assets are presented below. Such amounts are based on existing benefit formulas and include the effect of future service (in millions):
The Company sponsors defined contribution plans covering substantially all employees. Employer contributions to such plans are expensed as incurred and totaled $12.5 million in 2017, $16.7 million in 2016 and $20.0 million in 2015.
NOTE 11 - SHAREHOLDERS’ EQUITY
Reclassifications from Accumulated Other Comprehensive Loss
The following table sets forth the significant amounts reclassified out of each component of accumulated other comprehensive loss and their effect on net income (loss) for the period (in millions):
The Company records unrealized gains and losses related to net periodic pension and other postretirement benefit cost net of estimated taxes in Accumulated other comprehensive income (loss). The Company has a valuation allowance against its net U.S. deferred tax asset that is not expected to be realized. A portion of this valuation allowance is related to deferred tax benefits or expense as recorded in Accumulated other comprehensive income (loss).
Cash Dividends
Under English law, a public company may only declare dividends and make other distributions to shareholders (such as a share buyback) if the company has sufficient distributable reserves and meets certain net asset requirements. If the Company does not have sufficient distributable reserves or cannot meet the net asset requirements, the Company may be limited in its ability to timely pay dividends and effect other distributions to its shareholders.
In January 2016, the Company announced that it had discontinued its quarterly dividend.
During 2015, the Board approved quarterly cash dividends of $0.10 per Class A ordinary share, which were paid on March 3, May 26, August 25, and November 23, 2015, to shareholders of record at the close of business on February 9, May 12, August 11, and November 9, 2015, respectively.
NOTE 12 - INCOME TAXES
Rowan plc, the parent company, is domiciled in the U.K. and is subject to the U.K. statutory rate of 21% for the period January 1 through March 31, 2015; 20% for the financial year beginning April 1, 2015; and 19% for the financial year beginning April 1, 2017. On September 15, 2016, the U.K. enacted tax law to reduce the tax rate to 17% for the financial year beginning April 1, 2020. The computed statutory tax rate for 2017 is using a weighted average U.K. rate of 19.25%.
On December 22, 2017, the U.S. government enacted tax legislation commonly referred to as the U.S. Tax Act. The U.S. Tax Act significantly changes U.S. corporate income tax laws including but not limited to reducing the U.S. corporate income tax rate from 35% to 21%, requiring a one-time transition tax on mandatory deemed repatriation of certain unremitted non-U.S. earnings as of December 31, 2017, and changing how non-U.S. subsidiaries are taxed in the U.S. as of January 1, 2017.
The U.S. Tax Act requires complex computations to be performed that were not previously provided in U.S. tax law. As such, additional work is necessary as these computations require the preparation and analysis of information not previously relevant or regularly produced. Although the Company has not completed its accounting of the U.S. Tax Act, reasonable estimates were used in accordance with the SEC Staff Accounting Bulletin No. 118. The reasonable estimates made primarily include a one-time transition tax of $34.1 million, a tax on non-U.S. subsidiaries of $38.3 million, and additional tax due to the remeasurement of the U.S. deferred tax assets and liabilities for the tax rate change of $56.7 million, totaling $129.1 million. These charges do not materially impact the financials as they are fully offset by unbenefited net operating losses utilized of $72.4 million and adjustments to the valuation allowance of $56.7 million related to the deferred tax asset and liability remeasurement. The Company must finalize, in addition to other factors, the amount of the post-1986 non-U.S. earnings and profits, the amount of the U.S. tax on non-U.S. subsidiaries, and the earnings held in cash and other assets. As the Company completes its analysis of the U.S. Tax Act including finalizing the calculations and interpreting existing regulatory guidance, there may be adjustments to the provisional amounts. The provisional estimates will be finalized within one year from the date of enactment.
The significant components of income taxes attributable to continuing operations are presented below (in millions):
The reconciliation of differences between the Company's provision for income taxes and the amount determined by applying the U.K. statutory rate to income before income taxes are set forth below (dollars in millions):
In 2016, organizational restructuring resulted in a Luxembourg net operating loss of $4,534 million resulting in a deferred tax asset of $1,180 million with an offsetting deferred tax liability for book over tax asset basis difference of $409 million and a valuation allowance of $747 million for the net deferred tax asset that is not expected to be realized.
Temporary differences and carryforwards which gave rise to deferred tax assets and liabilities at December 31 were as follows (in millions):
Management continues to assess available positive and negative evidence to evaluate the existing deferred tax assets’ ability to be realized including determining if there is sufficient future taxable income. The Company records the portion of the deferred tax assets that is more likely to be realized. There have been no changes on the prior assessment regarding the ability to realize the U.S. and Luxembourg deferred tax assets and the Company has assessed the need for a valuation allowance as of December 31, 2017. The Company increased the valuation allowance on the Luxembourg deferred tax assets by $19.8 million to $766.5 million, at December 31, 2017, primarily due to lower current year earnings than expected. In 2017, the U.S. valuation allowance on U.S. deferred tax assets was decreased by $41.7 million primarily due to a decrease of provisional estimate of $56.7 million for the remeasurement to the lower U.S. corporate income tax rate, a decrease of provisional estimate of $52.1 million for current year activity, and an increase of $60.3 million for a deferred intra-entity asset transfer.
As of December 31, 2016, an additional valuation allowance of $747 million was recorded on Luxembourg deferred tax assets primarily related to net operating losses. The valuation allowance on the U.S. deferred tax assets was increased by $12 million to $132 million, primarily due to the changes in deferred tax assets related to net operating loss, interest limitations and depreciation.
The amount of the deferred tax assets considered realizable, however, could be adjusted if estimates of future taxable income during the carryforward period are reduced or increased or if negative evidence in the form of cumulative losses is no longer present, and additional weight may be given to evidence such as projections for growth. As of each reporting date, the Company’s management considers new evidence, both positive and negative, that could impact management’s view with regard to future realization of deferred tax assets.
At December 31, 2017, the Company had approximately $306 million of NOLs in the U.S., which expire at various times between 2034 and 2041 and which is subject to a valuation allowance as discussed in the preceding paragraphs; $49 million of NOLs in the U.S. attributable to the Company’s non-U.S. subsidiaries expiring in 2032 and which is subject to a valuation allowance of $49 million; $4,472 million of non-expiring NOLs in Luxembourg of which $2,947 million is subject to a valuation allowance; $14 million of non-expiring NOLs in the U.K., of which $14 million is subject to a valuation allowance; and $23 million of non-expiring NOLs in Trinidad, of which $23 million is subject to a valuation allowance. In addition, at December 31, 2017, the Company had $15 million of non-expiring NOLs in other foreign jurisdictions, of which $15 million is subject to a valuation allowance. A U.S. foreign tax credit of $29 million is intended to be carried back and does not have a valuation allowance. Due to the uncertainty of realization, the Company has a tax-effected valuation allowance as of December 31, 2017, in the amount of $870 million against the deferred tax assets for foreign tax credits, NOL carryforwards, and other deferred tax assets that may not be realizable, primarily relating to countries where the Company no longer operates or does not expect to generate sufficient future taxable income. Management has determined that no other valuation allowances were necessary at December 31, 2017, as
anticipated future tax benefits relating to all recognized deferred income tax assets are expected to be fully realized when measured against a more likely than not standard.
The NOL carryforwards included unrecognized tax benefits taken in prior years. The NOLs for which a deferred tax asset is recognized for financial statement purposes in accordance with ASC 740 are presented net of these unrecognized tax benefits.
The Company has not provided deferred income taxes on certain undistributed earnings of non-U.K. subsidiaries. No subsidiary of RCI has a plan to distribute earnings to RCI in a manner that would cause those earnings to be subject to U.S., U.K., or other local country taxation. If facts and circumstances cause a change in expectations regarding future tax consequences, the resulting tax impact could have a material effect on the Company's consolidated financial statements.
At December 31, 2017, 2016 and 2015, the net unrecognized tax benefits attributable to continuing operations was approximately $41 million, $59 million and $62 million, respectively. At December 31, 2017, $41 million would reduce the Company’s income tax provision if recognized.
The following table sets forth the changes in the Company’s gross unrecognized tax benefits for the years ended December 31 (in millions):
Interest and penalties relating to income taxes are included in income tax expense. At December 31, 2017, 2016 and 2015, accrued interest was $1.4 million, $11.8 million and $7.9 million, respectively, and accrued penalties were $2.2 million, $3.1 million and $2.8 million, respectively. Accrued interest and penalties relating to uncertain tax positions that are not actually assessed will be reversed in the year of the resolution.
The Company has been advised by the IRS of proposed unfavorable tax adjustments of $85 million including applicable penalties for the open tax years 2009 through 2012. The unfavorable tax adjustments primarily related to the following items: 2009 tax benefits recognized as a result of applying the facts of a third-party tax case that provided favorable tax treatment for certain non-U.S. contracts entered into in prior years to the Company’s situation; transfer pricing; and domestic production activity deduction. The Company has protested the proposed adjustment. However, the IRS does not agree with the Company's protest and they have submitted the proposed unfavorable tax adjustments to be reviewed by the IRS appeals group. In years subsequent to 2012, the Company has similar positions that could be subject to adjustments for the open years. The Company has provided for amounts that it believes will be ultimately payable under the proposed adjustments and intends to vigorously defend its positions; however, if the Company determines the provisions for these matters to be inadequate due to new information or the Company is required to pay a significant amount of additional U.S. taxes and applicable penalties and interest in excess of amounts that have been provided for these matters, the Company's consolidated results of operations and cash flows could be materially and adversely affected.
The Company’s U.S. federal tax returns for 2009 through 2012 are currently under audit by the IRS. The U.S. tax years open for examination are for periods 2014 and subsequent years. Various state tax returns for 2009 and subsequent years remain open for examination. In the Company’s non-U.S. tax jurisdictions, returns for 2006 and subsequent years remain open for examination. The Company is undergoing other routine tax examinations in various U.S. and non-U.S. taxing jurisdictions in which the Company has operated. These examinations cover various tax years and are in various stages of finalization. The Company believes that any income taxes ultimately assessed by any taxing authorities will not materially exceed amounts for which the Company has already provided, however, if it is determined that the provisions for these matters are inadequate due to new information or that taxing authorities assess a significant amount of additional taxes and applicable penalties and interest in excess of amounts that have been provided for these matters, consolidated results of operations and cash flows could be materially and adversely affected.
The components of income (loss) from continuing operations before income taxes were as follows (in millions):
NOTE 13 - SEGMENT AND GEOGRAPHIC AREA INFORMATION
Prior to ARO commencing operations on October 17, 2017 (see Note 1), the Company operated in two segments: Deepwater and Jack-ups. The Company now operates in three principal operating segments: Deepwater, which consists of its drillship operations, Jack-ups, which is composed of the Company's jack-up operations and results associated with the Company's arrangements with ARO primarily under the Transition Services Agreement (direct operating costs only), Rig Management Agreement and Secondment Agreement (see Note 1 and Note 3), and ARO a company formed to own, manage and operate offshore drilling units in Saudi Arabia. These segments provide one primary service - contract drilling. The Company evaluates performance primarily based on income from operations.
"Gain on sale of assets to unconsolidated subsidiary" is related to the sale of three jack-ups and related assets to ARO and is included in the Jack-ups segment (see Note 1 and Note 14). Depreciation and amortization and Selling, general and administrative expenses related to the Company's corporate function and other administrative offices have not been allocated to its operating segments for purposes of measuring segment operating income and are included in "Unallocated and other." In addition, revenue and general and administrative costs related to providing transition services to ARO are included in "Unallocated and other" (see Note 3). "Other operating items" consists of, to the extent applicable, non-cash impairment charges, gains and losses on asset sales and litigation related items. Segment results are presented below:
A cash deposit of $7.7 million was made toward the purchase of two jack-up rigs. See Note 19 for more details on the purchase of these rigs.
Not all assets are associated with specific segments. Those assets specific to segments include receivables, certain identified property, plant and equipment (including rigs), investment in unconsolidated subsidiary and note receivable from unconsolidated subsidiary. The remaining assets, such as cash and equivalents, are considered to be shared among the segments and therefore reported in Unallocated and other.
The classifications of revenue and assets among geographic areas in the tables which follow were determined based on the physical location of assets. Because the Company’s offshore drilling rigs are mobile, classifications by area are dependent on the rigs’ location at the time revenue is earned and may vary from one period to the next.
NOTE 14 - GAIN ON SALE OF ASSETS TO UNCONSOLIDATED SUBSIDIARY
On October 17, 2017, pursuant to an Asset Transfer and Contribution Agreement, as amended, with ARO, the Company agreed to sell three rigs to ARO: the JP Bussell, the Bob Keller and the Gilbert Rowe and related assets for a total cash consideration of $357.7 million. The book value of these assets was approximately $200.3 million. As a result of this sale transaction with ARO, the Company recognized a gain on the disposal of rig assets in the amount of $157.4 million in 2017. See Note 1 and Note 3 for more details of the ARO joint venture.
NOTE 15 - MATERIAL CHARGES AND OTHER OPERATING ITEMS
Operating expenses for 2016 include (i) non-cash asset impairment charges totaling $34.3 million on five jack-up drilling units (see Note 7) and (ii) a $1.4 million reversal of an estimated liability for settlement of a withholding tax matter during a tax amnesty period which was related to a legal settlement for a 2014 termination of a contract for refurbishment work on the Rowan Gorilla III, as noted below in the 2015 period. Payment of such withholding taxes during the tax amnesty period resulted in the waiver of applicable penalties and interest.
Operating expenses for 2015 include non-cash asset impairment charges totaling $329.8 million on ten jack-up drilling units (see Note 7) and an adjustment of $7.6 million to an estimated liability for the 2014 contract termination in connection with refurbishment work on the Rowan Gorilla III. A settlement agreement for this matter was signed during the third quarter of 2015.
NOTE 16 - SUPPLEMENTAL CASH FLOW INFORMATION
Non-cash investing and financing activities and other supplemental cash flow information follows (in millions):
NOTE 17 - GUARANTEES OF REGISTERED SECURITIES
Rowan plc and its 100%-owned subsidiary, RCI, have entered into agreements providing for, among other things, the full, unconditional and irrevocable guarantee by Rowan plc of the prompt payment, when due, of any amount owed to the holders of RCI's Senior Notes and amounts outstanding under RCI’s Revolving Credit Facility, if any.
The condensed consolidating financial information that follows is presented on the equity method of accounting in accordance with Rule 3-10 of Regulation S-X in connection with Rowan plc’s guarantee of the Senior Notes and reflects the corporate ownership structure as of December 31, 2017. Financial information as of December 31, 2016, and for the years ended December 31, 2016 and 2015 has been recast to reflect changes to the corporate ownership structure that occurred in 2017 and is presented as though the structure at December 31, 2017, was in place at January 1, 2015.
Rowan Companies plc and Subsidiaries
Condensed Consolidating Statements of Operations
Year ended December 31, 2017
(In millions)
Rowan Companies plc and Subsidiaries
Condensed Consolidating Statements of Operations
Year ended December 31, 2016
(In millions)
Rowan Companies plc and Subsidiaries
Condensed Consolidating Statements of Operations
Year ended December 31, 2015
(In millions)
Rowan Companies plc and Subsidiaries
Condensed Consolidating Statements of Comprehensive Income (Loss)
Year ended December 31, 2017
(In millions)
Rowan Companies plc and Subsidiaries
Condensed Consolidating Statements of Comprehensive Income (Loss)
Year ended December 31, 2016
(In millions)
Rowan Companies plc and Subsidiaries
Condensed Consolidating Statements of Comprehensive Income (Loss)
Year ended December 31, 2015
(In millions)
Rowan Companies plc and Subsidiaries
Condensed Consolidating Balance Sheets
December 31, 2017
(In millions)
Rowan Companies plc and Subsidiaries
Condensed Consolidating Balance Sheets
December 31, 2016
(In millions)
Rowan Companies plc and Subsidiaries
Condensed Consolidating Statements of Cash Flows
Year ended December 31, 2017
(In millions)
Rowan Companies plc and Subsidiaries
Condensed Consolidating Statements of Cash Flows
Year ended December 31, 2016
(In millions)
Rowan Companies plc and Subsidiaries
Condensed Consolidating Statements of Cash Flows
Year ended December 31, 2015
(In millions)
NOTE 18 - RELATED PARTIES
On October 17, 2017 the Company entered into a series of agreements with Saudi Aramco to form a joint venture, ARO. In connection with these transactions the Company has a number of relationships which are related party in nature. See Note 1 and Note 3 for a description of the Company's relationship with ARO and the related party transactions that have resulted from the commencement of this joint venture.
Mr. Tore Sandvold is a director of the Company and a director of Schlumberger, a provider of equipment and services to the Company. The Company has engaged in transactions in the ordinary course of business with Schlumberger totaling $20.9 million
and $28.4 million in 2017 and 2016, respectively, for the purchase of equipment and services. At December 31, 2017, the Company had a payable to Schlumberger of $8.3 million. These transactions were on an arm’s-length basis and Mr. Sandvold was not involved in such transactions in any way.
NOTE 19 - SUBSEQUENT EVENT
On January 5, 2018, the Company purchased two 2013 Le Tourneau Super 116E jack-up rigs, the P-59 and P-60, which were both delivered new into service in 2013, in a public auction from a subsidiary of Petroleo Brasileiro S.A. (“Petrobras”). The purchase price was $38.5 million per unit, or an aggregate $77.0 million, of which $7.7 million was paid as a deposit in December 2017. As previously reported on the Company's Current Report on Form 8-K dated May 11, 2017, Rowan was the high bidder in a Petrobras public auction with a bid price of $30.0 million per rig. Rowan's bid was not accepted by Petrobras; however, after negotiations, both parties agreed to the revised price.
SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)
Unaudited quarterly financial data for each full quarter within the two most recent years follows (in millions except per share amounts):
The sum of the per-share amounts for the quarters may not equal the per-share amounts for the full year due to differences in the computation of weighted average shares for the quarters and full year.
Income from operations in the fourth quarter of 2017 included a $157.4 million gain on the disposal of rig assets as a result of the sale of three rigs: the JP Bussell, the Bob Keller and the Gilbert Rowe and related assets to ARO in October 2017.
Income from operations in the third quarter 2016 included a $34.3 million noncash impairment charge to reduce the carrying values of five jack-up drilling units, partially offset by a $1.4 million reversal of an estimated liability for settlement of a withholding tax matter during a tax amnesty period which was related to a legal settlement for a 2014 termination of a contract for refurbishment work on the Rowan Gorilla III. Payment of such withholding taxes during the tax amnesty period resulted in the waiver of applicable penalties and interest.
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None
ITEM 9A.
ITEM 9A. CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures
The Company’s management has evaluated, with the participation of the Company’s Chief Executive Officer and Chief Financial Officer, the effectiveness of the Company’s disclosure controls and procedures, as of the end of the period covered by this report, pursuant to Exchange Act Rule 13a-15. Based upon that evaluation, the Company’s Chief Executive Officer and Chief Financial Officer concluded that the Company’s disclosure controls and procedures were effective as of December 31, 2017.
Management's Report on Internal Control Over Financial Reporting
Our management is responsible for establishing and maintaining internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act ("ICFR"). Our internal control system was designed to provide reasonable assurance to the Company’s management and Board regarding the preparation and fair presentation of published financial statements. All internal control systems, no matter how well designed, have inherent limitations, and therefore can only provide reasonable assurance with respect to financial statement preparation and presentation.
Our management’s assessment is that the Company did maintain effective ICFR as of December 31, 2017, within the context of the Internal Control - Integrated Framework (2013) established by the Committee of Sponsoring Organizations of the Treadway Commission, and that the Company did not have a material change in ICFR during the fourth quarter of 2017.
See “Management’s Report on Internal Control over Financial Reporting” included in Item 8 of this Form 10-K.
Changes in Internal Control Over Financial Reporting
There have been no changes to our internal controls over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act) during the quarter ended December 31, 2017 that have materially affected, or that are reasonably likely to materially affect, our internal control over financial reporting.
ITEM 9B.
ITEM 9B. OTHER INFORMATION
Not applicable
PART III
ITEM 10.
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
EXECUTIVE OFFICERS OF THE REGISTRANT
The names, positions and ages of the executive officers of the Company as of February 28, 2018, are listed below. Our executive officers are appointed by the Board and serve at the discretion of the Board. There are no family relationships among these officers, nor any arrangements or understandings between any officer and any other person pursuant to which the officer was selected.
Dr. Burke was appointed President and Chief Executive Officer and elected a director of the Company in April 2014. He served as Chief Operating Officer beginning in July 2011 and was appointed President in March 2013. Dr. Burke first joined the Company in December 2009, serving as Chief Executive Officer and President of LeTourneau Technologies until the sale of LeTourneau in June 2011. From 2006 to 2009, Dr. Burke was a Division President at Complete Production Services, an oilfield services company, and from 2004 to 2006, served as its Vice President for Corporate Development.
Mr. Butz became Executive Vice President and Chief Financial Officer upon joining the Company in December 2014, and also served as Treasurer from December 2014 through February 2016. Prior to joining the Company, Mr. Butz served as Executive Vice President and Chief Financial Officer at Hercules Offshore, Inc. He was Senior Vice President and Chief Financial Officer of Hercules Offshore from 2010 to 2013 and held a number of other key positions after joining Hercules Offshore in 2005, including Director of Corporate Development and Vice President, Finance and Treasurer. Prior to joining Hercules Offshore, Mr. Butz held positions in both investment and commercial banking.
Mr. Mai became Executive Vice President, General Counsel and Company Secretary in May 2017. Prior to joining the Company, he was at Dresser-Rand Group Inc. from October 2007 to August 2015, serving as its Vice President, General Counsel and Secretary. Prior to this time, Mr. Mai served in various roles at Cooper Industries, including Associate General Counsel, Corporate and Litigation, and was a partner at the law firm of Thompson & Knight LLP.
Mr. Baldwin became Chief Accounting Officer in April 2016. Prior to joining the Company, he served as Vice President, Controller and Chief Accounting Officer for Cameron International Corporation from March 2014 until March 2016. Prior to such time, he was Senior Vice President and Chief Accounting Officer of KBR, Inc. from August 2010 to March 2014, and Vice President and Chief Accounting Officer of McDermott International from October 2007 to August 2010. He also previously served at Integrated Electrical Services and Veritas DGC.
Mr. Brooks became Executive Vice President, Operations and Engineering in February 2017. Prior to that time, he served as Senior Vice President, Operations from October 2012 through January 2017, and as Vice President, Deepwater Operations from March 2011 through September 2012. Prior to joining the Company, Mr. Brooks served as Senior Vice President of Operations at Northern Offshore from 2008 through 2010. He also served in various management positions at GlobalSantaFe from 1998 through 2007, including Vice President of West Africa Operations, and Vice President of Worldwide Deepwater & Gulf of Mexico Operations.
Mr. Quintero became Senior Vice President, Business Development in January 2018, after serving as Senior Vice President, Chief Technology Officer since June 2017. Prior to joining the Company, Mr. Quintero served as Senior Vice President at Transocean from 2010 through 2015 overseeing Operations, Asset Management, and Major Capital Projects. He also served in various management roles at Atwood Oceanics from 1993 through 2010, where he ended as Senior Vice President with responsibilities
over Operations, Technical Services, Supply Chain, Projects, Quality Assurance, and Maintenance. Immediately prior to joining Rowan, Mr. Quintero was a Partner at Trenegy Incorporated, a management consulting firm.
Mr. McHenry was appointed Chief Executive Officer of ARO Drilling upon its inception in May 2017. Prior to this time, Mr. McHenry managed Rowan’s Middle East and Southeast Asia operations for 10 years. He served Rowan most recently as Vice President, Drilling Operations from 2013 to 2017 and in several other key operations management positions from 2004 through 2013. Mr. McHenry has more than 27 years of experience in the drilling industry.
Mr. Anderson became Vice President, Human Resources in May 2017, after serving as Senior Director, Human Resources since March 2016. He previously served in several key human resources and compliance positions since joining the Company in May 2007. Prior to this time, Mr. Anderson served in various audit and consulting roles.
Information concerning our directors will appear in our proxy statement for the 2018 annual general meeting of shareholders to be filed pursuant to Regulation 14A of the Exchange Act (Regulation 14A) on or before April 30, 2018 under the caption “Election of Directors.” Such information is incorporated herein by reference.
Information concerning our Audit, Compensation and Nominating Committees will appear in our proxy statement for the 2018 annual general meeting of shareholders under the caption “Board of Directors Information.” Such information is incorporated herein by reference. Our committee charters and corporate governance guidelines are available on our website, www.rowan.com.
Information concerning compliance with Section 16(a) of the Securities Exchange Act will appear in our proxy statement for the 2018 annual general meeting of shareholders under the caption “Additional Information - Section 16(a) Beneficial Ownership Reporting Compliance.” Such information is incorporated herein by reference.
We have adopted a code of ethics that applies to the Company’s directors, officers and employees, including the Chief Executive Officer, Chief Financial Officer, Chief Accounting Officer and other persons performing similar functions. Our code of ethics is available on our website, www.rowan.com. We will disclose on our website any amendment to or waiver from our code of ethics on behalf of any of our executive officers or directors.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION
Information concerning director and executive compensation will appear in our proxy statement for the 2018 annual general meeting of shareholders under the captions “Non-Executive Director Compensation,” “Compensation Discussion and Analysis,” and “Executive Compensation.” Such information is incorporated herein by reference.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
Information concerning the security ownership of management will appear in our proxy statement for the 2018 annual general meeting of shareholders under the caption “Security Ownership of Management and Certain Beneficial Owners.” Such information is incorporated herein by reference.
The business address of all directors is the principal executive offices of the Company as set forth on the cover page of this Form 10-K.
Equity Compensation Plan Information
The following table provides information about our ordinary shares that may be issued under equity compensation plans as of December 31, 2017.
(1)
The number of securities to be issued includes (i) 454,946 options and no shares issuable under outstanding SARs (see note (2) below).
(2)
The weighted-average exercise price in column (b) is based on (i) 454,946 shares under outstanding options with a weighted average exercise price of $17.08 per share, and (ii) no shares of stock that would be issuable in connection with 1,028,532 SARs outstanding at December 31, 2017. The number of shares issuable under SARs is equal in value to the excess of the Company’s share price on the date of exercise over the exercise price. The number of shares issuable under SARs included in column (a) was based on a December 31, 2017 closing stock price of $15.66 and a weighted-average exercise price of $31.03 per share.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
Information concerning director and executive related party transactions will appear in our proxy statement for the 2018 annual general meeting of shareholders within the section and under the captions “Corporate Governance - Director Independence” and “Corporate Governance - Related Party Transaction Policy.” Such information is incorporated herein by reference.
ITEM 14.
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
Information required by this Item is included in the proxy statement for the 2018 annual general meeting of shareholders under the caption “Audit Committee Report - Approval of Fees.” Such information is incorporated herein by reference.
PART IV
ITEM 15.
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a) Index to Financial Statements, Financial Statement Schedules and Exhibits
(1) Financial Statements
See Part II, Item 8, “Financial Statements and Supplementary Data,” of this Form 10-K for a list of financial statements filed as a part of this report.
(2) Financial Statement Schedules
For the year ended December 31, 2017, management has assessed the need for continued valuation allowances on deferred tax assets. The changes to the valuation allowance balance is discussed in Note 12 to our consolidated financial statements in Part II, Item 8 of this Annual Report on Form 10-K.
For the year ended December 31, 2016, management assessed negative and positive evidence and determined the need to establish a valuation allowance against the Luxembourg deferred tax assets of $747 million as discussed in Note 12 to our consolidated financial statements in Part II, Item 8 of this Annual Report on Form 10-K.
For the year ended December 31, 2015, an additional valuation allowance of $62 million on the U.S. 2014 and prior years’ deferred tax assets and an additional valuation allowance of $43 million on the U.S. 2015 deferred tax assets has been recorded in 2015 to recognize only the portion of the deferred tax assets that is more likely to be realized.
Financial Statement Schedules I, III, IV, and V are not included in this Form 10-K because such schedules are not required, the required information is not significant, or the information is presented elsewhere in the financial statements.
(3) Exhibits
Unless otherwise indicated below as being incorporated by reference to another filing of the Company with the Securities and Exchange Commission, each of the following exhibits is filed herewith:
__________
*
Executive compensatory plan or arrangement.
²
Filed herewith.
v
Confidential Information has been omitted and filed separately with the Securities and Exchange Commission. Confidential treatment has been requested with respect to this omitted information.
ª
Schedules and exhibits have been omitted pursuant to Item 601(b)(2) of Regulation S-K. The registrant agrees to furnish supplementally a copy of the omitted schedules and exhibits to the Securities and Exchange Commission upon request.
Rowan agrees to furnish to the Commission upon request a copy of all instruments defining the rights of holders of long-term debt of the Company and its subsidiaries.
ITEM 16. FORM 10-K SUMMARY
Not applicable
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.
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 date indicated.