ROWAN COMPANIES PLC
ITEM 1. BUSINESS
On May 4, 2012, Rowan Companies plc, a public limited company incorporated under the laws of England and Wales (Rowan plc), became the successor issuer to Rowan Companies, Inc. (RCI) pursuant to an agreement and plan of merger and reorganization (the “redomestication”) approved by the stockholders of RCI on April 16, 2012. As a result of the redomestication, Rowan plc became the parent company of the Rowan group of companies and our place of incorporation was effectively changed from Delaware to the United Kingdom. We remain subject to the Securities and Exchange Commission (SEC) reporting requirements, the mandates of the Sarbanes-Oxley Act and the applicable listing standards of the New York Stock Exchange (NYSE), and we continue to report our consolidated financial results in U.S. dollars and in accordance with United States generally accepted accounting principles (US GAAP). We must also comply with additional reporting requirements under English law. The redomestication was accounted for as an internal reorganization of entities under common control; accordingly, the carrying values of assets and liabilities of the merged entities were carried forward without adjustment. Unless the context otherwise requires, the
terms “Rowan,” “Company,” “we,” “us” and “our” are used to refer to Rowan plc (or RCI for periods prior to the redomestication) and its consolidated subsidiaries.
In 2011 we completed the sales of our manufacturing and land drilling businesses, which we previously reported as separate business segments. Following the sales, the Company has reported under one business segment. The Company's revenues and assets by geographic area are presented in Note 12 of “Notes to Consolidated Financial Statements” in Item 8 of this Form 10-K.
Our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (the Exchange Act) are made available free of charge on our website at www.rowancompanies.com as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC.
Overview
We are a global provider of offshore oil and gas contract drilling services utilizing a fleet of 30 self-elevating mobile offshore “jack-up” drilling units and four ultra-deepwater drillships, three of which are currently under construction. Historically, our primary focus has been on high-specification and premium jack-up rigs, which our customers use for exploratory and development drilling and associated drilling services. In 2009, we began executing a new strategic plan that included divesting non-core assets and investing in ultra-deepwater assets, with a goal of balancing earnings from jack-ups and deepwater rigs over the long term. In 2011 and 2012 we entered into contracts with Hyundai Heavy Industries Co., Ltd (Hyundai) for the construction of four ultra-deepwater drillships. In January 2014, we took delivery of the first of these drillships, the Rowan Renaissance, which is expected to commence drilling operations under a three-year contract offshore West Africa in April 2014. Our three remaining drillships under construction are scheduled for delivery in June 2014, October 2014, and March 2015, respectively.
The Company conducts offshore drilling operations in various markets throughout the world including the United Kingdom (U.K.) and Norwegian sectors of the North Sea, the Middle East, the United States Gulf of Mexico (US GOM), Southeast Asia, West Africa, Trinidad and Egypt.
During 2013, we generated revenues of $1.579 billion and operating income of $331.7 million, compared with $1.393 billion and $255.1 million, respectively, in 2012. Our results of operations are further discussed in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Item 7 of this Form 10-K.
Drilling Fleet
We own and operate 30 jack-up rigs and one ultra-deepwater drillship, with three additional drillships under construction. 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 250 to 550 feet, depending on rig size and location. 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 is jacked up to the elevation required to drill the well. Our ultra-deepwater drillships will be capable of drilling wells to maximum depths of 40,000 feet and in maximum water depths of 12,000 feet.
We have aggressively grown our jack-up fleet in recent years to better serve the needs of the industry and we are particularly well positioned to serve the niche market for high-pressure/high-temperature (HPHT) wells. All of our rigs feature top-drive drilling systems, solids-control equipment, AC power and mud pumps that accelerate the drilling process. Our drilling fleet comprises the following:
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One ultra-deepwater drillship, the Rowan Renaissance, and three additional ultra-deepwater drillships currently under construction;
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Nineteen high-specification cantilever jack-up rigs, including one Gorilla class rig, three N-Class rigs, four enhanced Super Gorilla class rigs, four Tarzan Class rigs, three 240C class rigs, and four EXL class rigs, as described below. We use the term “high-specification” to describe jack-ups with a hook-load capacity of at least two million pounds.
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Eight premium cantilever jack-up rigs, including two Gorilla class rigs and six 116-C class rigs. We use the term “premium jack-ups” to denote independent-leg cantilever rigs that can operate in at least 300 feet of water in benign environments.
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Three conventional or slot jack-up rigs with skid-off capability, two of which are cold-stacked.
Our ultra-deepwater drillships will be self-propelled vessels equipped with computer-controlled dynamic-positioning thruster systems, which allow them to maintain position without anchors through the use of their onboard propulsion and station-keeping systems. Drillships have greater variable deck loading capacity than semisubmersible rigs, enabling them to carry more supplies on board, making them better suited for drilling in deep water in remote locations. Our drillships will be equipped with two drilling stations within a single derrick allowing the drillships to perform off-line and potentially simultaneous drilling tasks during some parts of the well, subject to legal restrictions in various jurisdictions. This can increase efficiency during exploration and development drilling programs which make them very attractive to our customers.
Cantilever jack-ups can extend a portion of the sub-structure containing the drilling equipment over fixed production platforms to perform drilling operations with a minimum of interruption to production. Our conventional jack-ups use “skid-off” technology, which allows the rig floor drilling equipment to be “skidded” out over the top of a fixed platform, enabling these slot type jack-up rigs to be used on drilling assignments that would otherwise require a cantilever jack-up or platform rig.
Our three Gorilla class rigs, designed in the early 1980s as a heavier-duty class of jack-up rig, are capable of operating in water depths up to 328 feet in extreme hostile environments (winds up to 100 miles per hour and seas up to 90 feet) such as the North Sea and offshore eastern Canada. Gorillas II and III can drill to 30,000 feet, and Gorilla IV is equipped to drill to 35,000 feet.
Three of our four Super Gorilla class rigs were delivered during the period from 1998 to 2002 and are enhanced versions of our Gorilla class rigs that can be equipped for simultaneous drilling and production operations. They can operate year-round in 400 feet of water south of the 61st parallel in the North Sea, within the worst-case combination of 100-year storm criteria for waves, wave periods, winds and currents. The Bob Palmer is the fourth Super Gorilla class rig and was delivered in 2003, is an enhanced version of the Super Gorilla class jack-up and is designated a Super Gorilla XL. With 713 feet of leg, 139 feet more than the Super Gorillas, and 30 percent larger spud cans, the Bob Palmer can operate in water depths to 550 feet in normally benign environments like the US GOM and the Middle East or in water depths to 400 feet in hostile environments such as the North Sea and offshore eastern Canada.
Our four Tarzan Class rigs were delivered during the period from 2004 to 2008 and are specifically designed for deep-well, HPHT drilling in up to 300 feet of water in benign environments.
Our three 240C class rigs were designed for HPHT drilling in water depths up to 400 feet. The Rowan Mississippi and the Ralph Coffman were added to the fleet in 2008 and 2009, respectively, and the Joe Douglas was added to the fleet in 2011.
Our four EXL class rigs also enable drilling of HPHT and extended-reach wells in most of the prominent jack-up markets throughout the world, and are equipped with the hook-load and horsepower required to efficiently drill up to 35,000 feet with respect to the EXL I and EXL II, and up to 40,000 feet with respect to the EXL III and EXL IV. The first three EXL class rigs were delivered in 2010, and the EXL IV was delivered in 2011.
Our three N-Class rigs are capable of drilling up to 35,000 feet in harsh environments such as the North Sea and in maximum water depths of approximately 450 feet depending on location. 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. Our first N-Class rig, the Rowan Viking, was delivered in 2010, and the Rowan Stavanger and Rowan Norway were delivered in 2011.
See Item 2, “Properties,” for additional information regarding our fleet.
Our operations are subject to many uncertainties and hazards. See Item 1A, “Risk Factors,” 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 also 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, many 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. Many of our drilling contracts provide for separate lump-sum payments for rig mobilization and demobilization. We recognize lump-sum fees and related expenses over the primary contract term. We recognize reimbursement of certain costs as revenues and expenses at the time they are incurred. Our contracts for work in foreign countries generally provide for payment
in United States (U.S.) dollars 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 area. Such factors, which are discussed further under “Competition” and in "Risk Factors" include, among other things, the price of oil and gas which can affect our customers' drilling budgets, location and availability of competitive equipment, the suitability of equipment for the project, comparative operating cost of the equipment, competence of drilling personnel and other competitive factors. Profitability may also depend on receiving adequate compensation for the cost of moving equipment to drilling locations.
During periods of weak demand and declining day rates, we have historically accepted lower rates in order to keep our rigs working and to mitigate the substantial costs of maintaining and reactivating stacked rigs. We have, however, stacked certain rigs in the past rather than make the substantial improvements required to secure ongoing work. We generally have a mix of short- and long-term contracts that enable us to take advantage of higher rates in rising markets (and to cover potential higher operating costs) as well as to provide down-side protection when markets decline.
Our contract backlog was estimated to be approximately $5.0 billion at February 20, 2014, up from approximately $3.6 billion at February 21, 2013. See “Outlook” in Management’s Discussion and Analysis of Financial Condition and Results of Operations in Item 7 of this Form 10-K for further information with respect to the Company’s backlog.
Competition
The contract drilling industry is highly competitive, and success in obtaining contracts involves many factors, including price, rig capability, operating and safety performance, and reputation.
We compete with several offshore drilling contractors that together have 829 mobile rigs available worldwide, including 513 jack-ups. We estimate that 55 or 11 percent of the world’s existing jack-up fleet are high-specification, including our 19 high-specification rigs. As of February 13, 2014, 135 additional jack-up rigs were under construction for delivery through 2017, 38 of which are considered high-specification.
At February 13, 2014, there were 98 drillships operating worldwide plus another 74 under construction or on order for delivery through 2020, including our three drillships under construction. We estimate that 65, or approximately 66 percent of the world’s existing drillship fleet, are capable of drilling in water depths of 10,000 feet or more, and 72 of the 74 under construction will have 10,000-foot water depth capabilities.
Based on the number of rigs as tabulated by IHS-Petrodata, we are the ninth largest offshore drilling contractor in the world and the fifth largest jack-up rig operator. Based on the most recent publicly available information, we are the sixth largest publicly traded offshore drilling contractor ranked by revenues. Some of our competitors have greater financial and other resources and may be more able to make technological improvements to existing equipment or replace equipment that becomes obsolete. In addition, those contractors with larger and more diversified drilling fleets may be better positioned to withstand unfavorable market conditions.
We market our drilling services to present and potential customers, including large international energy companies, smaller independent energy companies and foreign government-owned or government-controlled energy companies. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Item 7 of this Form 10-K for a discussion of current and anticipated industry conditions and their impact on our operations.
Governmental Regulation
Many aspects of our operations are subject to governmental regulation, including equipping and operating vessels, drilling practices and methods, and taxation. In addition, the U.K., the U.S. and other countries in which we operate have regulations relating to environmental protection and pollution control. We could become liable for damages resulting from pollution of offshore waters in some circumstances, and in certain jurisdictions we must document financial responsibility.
Generally, we are indemnified under our drilling contracts for pollution, well damage and environmental damage, except in certain cases of pollution emanating above the surface of water from spills of pollutants emanating from our drilling rigs. This indemnity includes all costs associated with regaining control of a wild well, removal and disposal of the pollutant, environmental remediation and claims by third parties for damages. However, as noted below, such contractual indemnification provisions may not adequately protect the Company for several reasons including: (a) the contractual indemnity provisions may require the Company to assume
a portion of the liability; (b) our customers may not have financial resources necessary to honor the contractual indemnity provisions; and (c) the contractual indemnity provisions may be unenforceable under applicable law.
Our customers often require us to assume responsibility for pollution damages where we are at fault. We seek to limit our liability exposure to a non-material amount, or an amount within the limits of our available insurance coverage. For example, a contract may provide that we will assume the first $500,000 of costs related to an incident resulting in wellbore pollution due to our negligence, with the customer assuming responsibility for all costs in excess of $500,000. We can provide no assurance that we will be able to negotiate indemnities and/or limitation of liability provisions for all of our contracts or that such indemnification and/or limitation of liability provisions can be enforced or will be sufficient. Our customers may challenge the validity or enforceability of the indemnity provision for several reasons, including but not limited to applicable law, judicial decisions, the language of the indemnity provision, reasons of public policy, degree of fault and/or the circumstances resulting in the pollution.
In the event of an incident resulting in wellbore pollution and a customer who is unable or unwilling to honor its indemnity obligation, the impact on our financial position, operations and liquidity would depend on the scope of the incident. In this instance, we would seek to enforce our legal rights, including the enforcement of the indemnity obligation and redress from all parties at fault. In addition, we maintain limited insurance for liability related to negative environmental impacts of a sudden and accidental pollution event, as described below. If both insurance and indemnity protection were unavailable or insufficient and the incident was significant, there could be a material adverse effect on our results of operations, financial position and cash flows.
Pursuant to the Clean Water Act, a National Pollutant Discharge Elimination Permit (NPDES permit) is required for discharges into the US GOM. These permits are issued and administered by the Environmental Protection Agency (EPA). Historically, permit coverage has been the responsibility of the lease holder (the Operator); however, effective October 2012, the vessel owner must also obtain coverage for those discharges directly under their controls if such discharges are not covered by the lease holder. As a contract driller in the US GOM, we operate in accordance with the NPDES permit regardless of the holder. According to the NPDES permit, the permit holder is the designated Responsible Party and is thus responsible for any environmental impacts that would occur in the event of the discharge of any unpermitted substance, including a fuel spill or oil leak from an offshore installation such as a mobile drilling unit.
Additionally, pursuant to the International Maritime Organization (IMO), we are required to have a Shipboard Oil Pollution Emergency Plan (SOPEP) for each of our drilling units. Our SOPEP establishes detailed procedures for rapid and effective response to spill events that may occur as a result of our operations or those of the Operator. This plan is reviewed annually and updated as necessary. Onboard drills are conducted periodically to maintain effectiveness of the plan, and each rig is outfitted with equipment to respond to minor spills. The drills include participation of key personnel, spill response contractors and representatives of governmental agencies. For operations in the United States, our SOPEPs are subject to review and approval by various organizations including the United States Coast Guard, the EPA and the Bureau of Safety and Environmental Enforcement (BSEE), and are recertified every five years by the American Bureau of Shipping, a Recognized Organization under the IMO.
As the designated responsible party, the Operator has the primary responsibility for spill response, including having contractual arrangements in place with emergency spill response organizations to supplement any onboard spill response equipment. Pursuant to our SOPEPs, we have certain resources and supplies onboard our rigs which would be used to mitigate the impact of an incident until an emergency spill response organization could deploy its resources. However, we also have an agreement with an emergency spill response organization should we have an incident that exceeds the scope of our onboard spill response equipment.
Our primary spill response provider has been in business since 1994 and specializes in helping industries prevent and clean up oil and other hydrocarbon spills throughout the Gulf Coast, with response centers in Texas and Louisiana with 24-hour response capabilities and equipment. Our provider’s website states that it holds all necessary licenses, certifications and permits to respond to emergencies in the US GOM and that it has significant spill response resources to meet the needs of its customers.
We believe these resources have adequate equipment to respond to an emergency spill; however, we can provide no assurance that adequate resources will be available should multiple concurrent spills occur. Other foreign jurisdictions in which we operate may also have similar regulations and requirements.
In addition, we are actively involved in various industry-led initiatives and task forces, including the American Petroleum Institute’s Center for Offshore Safety, that are intended to improve safety and protect the environment.
Except as discussed above, we do not believe regulatory compliance has materially affected our capital expenditures, earnings or competitive position to date, although such measures increase drilling costs and may adversely affect drilling operations. Further regulations may reasonably be anticipated, but any effects on our drilling operations cannot be accurately predicted at this time.
In the U.S., we are subject to the requirements of the Occupational Safety and Health Act of 1970 (OSHA) and comparable state statutes. OSHA requires us to provide our employees with information about the chemicals used in our operations. There are comparable requirements in other non-U.S. jurisdictions in which we operate.
In addition to the federal, state, and foreign regulations that directly affect our operations, regulations associated with the production and transportation of oil and gas affect our customers and thereby could potentially impact demand for our services.
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. Our insurance coverage is subject to deductibles and self-insured retentions which must be met prior to any recovery. Additionally, our insurance is subject to exclusions and limitations, and we can provide no assurance that such coverage will adequately protect us against liability from all potential consequences and damages.
Our current insurance policies provide coverage for loss or damage to our fleet of drilling rigs on an agreed value basis (which varies by unit) subject to a deductible of $25 million per occurrence. This coverage does not include damage to our rigs arising from a US GOM named windstorm, for which we are self-insured.
We maintain insurance policies providing limited coverage for liability associated with negative environmental impacts of a sudden and accidental pollution event, third-party liability, employers’ liability (including Jones Act liability), automobile liability and aviation liability, and these policies are subject to various exclusions, deductibles and underlying limits. In addition, we maintain excess liability coverage with an annual aggregate limit of $700 million subject to a self-insured retention of $10 million except for liabilities (including removal of wreck) arising out of a US GOM named windstorm, which are subject to a self-insured retention of $200 million.
Our rig physical damage and liability insurance renews each June. We can provide no assurance we will be able to secure coverage of a similar nature with similar limits at comparable costs.
Employees
At December 31, 2013, we had 3,499 employees worldwide, compared to 3,119 and 2,719 at December 31, 2012 and 2011, respectively. Certain of our employees and contractors in international markets, such as Trinidad and Norway, are represented by labor unions and work under collective bargaining or similar agreements, which are subject to periodic renegotiation. We consider relations with our employees to be satisfactory.
Customers
Saudi Aramco and Total Exploration & Production accounted for 26% and 11%, respectively, of our 2013 consolidated revenues.
ITEM 1A. RISK FACTORS
You should consider carefully the following risk factors, in addition to the other information contained and incorporated by reference in this Form 10-K, before deciding to invest in our equity or debt securities.
We operate in a volatile business that is heavily dependent upon commodity prices and other factors beyond our control.
The success of our drilling operations depends heavily upon conditions in the oil and gas industry and the level of demand for drilling services. Demand for our drilling services is vulnerable to declines that are typically associated with depressed oil and natural gas prices. Even the perceived risk of a decline in oil or natural gas prices may cause oil and gas companies to reduce their spending, in which case demand for our drilling services could decrease and our drilling revenues may be adversely affected by lower rig utilization and/or day rates. 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 also depends on additional factors that are beyond our control, including:
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worldwide demand for drilling services;
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worldwide demand for and prices of oil and natural gas;
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the level of exploration and development expenditures by energy companies;
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the willingness and ability of the Organization of Petroleum Exporting Countries (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 increased economic sanctions that affect the energy industry;
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the general economy, including inflation;
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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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expectations regarding future energy prices;
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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 and/or confiscation;
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domestic and international tax policies;
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political and military conflicts in oil-producing areas and the effects of terrorism;
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advances in exploration and development technology such as unconventional drilling and the development of shale resources;
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the development and exploitation of alternative fuels and energy sources;
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consolidation of our customer base, and
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consolidation of our competitors.
Our drilling operations have been and will continue to be adversely affected by dramatic declines in oil and natural gas prices, but we cannot predict such events. Other reasons may cause a reduction in offshore drilling activity.
We are dependent upon our ability to secure contracts for our drilling units at sufficient day rates. An oversupply of drilling units may lead to a reduction in rig utilization and day rates and, therefore, may materially impact our profitability.
Our ability to meet our cash flow obligations will depend on our ability to secure ongoing work for our drilling units at sufficient day rates. As of February 20, 2014, we had 16 rigs with contract terms ending in 2014, and our fourth drillship, which is expected to be delivered in March 2015, is not currently under contract. We cannot predict the future level of demand for our drilling units or future conditions in the oil and gas industry. If oil and gas operators reduce their exploration, development and production expenditures, we may have difficulty securing drilling contracts, or we may be forced to enter into contracts at unattractive day rates. Failure to secure economical contracts for our drilling units could impair our ability to generate sufficient cash flow to fund our capital expenditures and/or meet our other obligations and could negatively impact our operating results and financial position.
During the recent period of high utilization and day rates, industry participants have increased the supply of drilling units by ordering construction of new offshore drilling units. Historically, significant increases in construction activity has resulted in an oversupply of drilling units and, in turn, has caused a subsequent decline in utilization and day rates when the drilling units have entered the market, sometimes for extended periods of time until the new units have been absorbed into the active fleet. According to industry sources, there were 513 jack-ups and 98 drillships in the worldwide fleets as of February 13, 2014, and an additional 135 jack-ups and 74 drillships were under construction or on order. A large number of the drilling units currently under construction have not been contracted for future work, which could intensify price competition as scheduled delivery dates grow near and lead to a reduction in day rates. Lower utilization and day rates could adversely affect our revenues and profitability. Prolonged periods of low utilization and day rates could also result in the recognition of 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 Item 8 of this Form 10-K for information regarding impairment charges recognized in 2012 and 2013.
We are subject to operating risks such as blowouts, fires, collisions and punch throughs that could result in environmental damage, property loss, personal injury, death and other loss.
Our drilling operations are subject to many hazards that could increase the likelihood of accidents. Accidents can result in:
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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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serious damage to or destruction of property and equipment;
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personal injury or death;
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significant impairment of producing wells, leased properties, pipelines or underground geological formations;
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damage to the property of others;
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damage to fisheries and 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 high-pressure drilling accidents resulting in lost or damaged formations and towing accidents resulting in lost or damaged equipment. Any future such events could result in operating losses and have a significant impact on our business.
Failure to obtain and retain highly skilled personnel could hurt our operations.
We require highly skilled personnel to operate our rigs and provide technical services and support for our business in each of the areas of our operations. To the extent that demand for drilling services and the size of the worldwide industry fleet increase (including due to the impact of newly constructed rigs), shortages of qualified personnel could arise, creating upward pressure on wages and difficulty in staffing and servicing our rigs, which could, in turn, adversely affect our results of operations. In addition, the entrance of new participants into the offshore drilling market would cause further competition for qualified and experienced personnel as these entities seek to hire personnel with expertise in the offshore drilling industry. The heightened competition for skilled personnel could adversely impact our financial position, results of operations and cash flows by limiting our operations or further increasing our costs.
Our business is capital intensive, and we have significant future commitments to construct additional rigs.
Our total estimated project cost for the four ultra-deepwater drillships that were under construction at December 31, 2013, is approximately $2.9 billion, of which approximately $2.0 billion had not yet been incurred as of December 31, 2013.
Construction upgrades, enhancements, conversions, mobilizations and repairs of rigs and drillships are subject to risks, including delays and cost overruns, which could have an adverse impact on our financial position, results of operations and cash flows.
At December 31, 2013, we had four ultra-deepwater drillships under construction at Hyundai Heavy Industries Co. Ltd.'s shipyard in Ulsan, South Korea, at a cost of approximately $2.9 billion. Although there is certain insurance coverage and financial and bank guarantees associated with the drillship construction contracts, in the event Hyundai is, for any reason, unable to perform under its agreements, there may be a material adverse effect on our results of operations, financial condition and cash flows.
From time to time in the future, we may also undertake additional new construction projects. In addition, we may make significant upgrade, refurbishment and repair expenditures for our fleet from time to time, particularly as our drilling units age.
Initial operations of new drilling units and mobilization of existing units often result in delays and other complications that could result in significant unexpected costs, uncompensated downtime, reduced day rates or the cancellation or termination of drilling contracts.
Some of the costs associated with construction projects, upgrades, enhancements, conversions, mobilizations and repairs of drilling units could be unplanned and are subject to risks of cost overruns or delays as a result of numerous factors, including the following:
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shipyard unavailability;
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shortages of equipment, materials or skilled labor for completion of repairs or upgrades to our equipment;unscheduled delays in the delivery or cost increases of materials and equipment or in shipyard construction;
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failure of equipment to meet quality or performance standards;
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loss of or damage to essential equipment while in transit;
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financial or operating difficulties experienced by equipment vendors or the shipyard;
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unanticipated actual or purported change orders;
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local customs strikes or related work slowdowns that could delay importation of equipment or materials;
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engineering problems, including those relating to the commissioning of newly designed equipment;
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design or engineering changes;
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latent damages or deterioration to the hull, equipment and machinery in excess of engineering estimates and assumptions;
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work stoppages;
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client acceptance delays;
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weather interference, storm damage or other events of force majeure;
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disputes with shipyards and suppliers;
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shipyard failures and difficulties;
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failure of third-party equipment vendors or service providers;
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unanticipated cost increases, including relating to raw materials used in construction of our drilling units; and
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difficulty in obtaining necessary permits or approvals or in meeting permit or approval conditions.
These factors may contribute to cost variations and delays in the delivery of our ultra-deepwater newbuild drillships or upgrade projects. Delays in the delivery of these drillships or other drilling units or the inability to complete construction in accordance with their design specifications may, in some circumstances, result in a delay in contract commencement, resulting in a loss of revenue to us, and may also cause customers to renegotiate, terminate or shorten the term of a drilling contract pursuant to applicable late delivery clauses. In the event of termination of one of these contracts, we may not be able to secure a replacement contract on as favorable terms or at all. Additionally, capital expenditures for upgrades, refurbishment and construction projects could materially exceed our planned capital expenditures. Moreover, our drilling units that may undergo upgrade, refurbishment or repair may not earn a day rate during the periods they are out of service. In addition, in the event of a shipyard failure or other difficulty, we may be unable to enforce certain provisions under our newbuild contracts such as our contractual rights to recover amounts paid as installments under such contracts. The occurrence of any of these events may have a material adverse effect on our results of operations, financial position or cash flows.
Our markets are highly competitive, and satisfactory price levels are difficult to maintain.
Our drilling markets are highly competitive, and no single participant is dominant. Some of our competitors may have greater financial or other resources than we do. The drilling industry has experienced consolidation in the past and may experience
additional consolidation, which could create additional competitors larger than us. Drilling contracts are often awarded on a competitive-bid basis, and intense price competition is frequently the primary factor determining which qualified contractor is awarded the job. Relocation of offshore rigs from areas of lower activity to more active markets can further increase the competition among rigs looking for work in such areas. The anticipated delivery of 135 new jack-ups and 74 drillships over the next three and six years, respectively, and ongoing consolidation by oil and gas exploration and production companies will further increase the supply of rigs while reducing the number of available customers. This consolidation has also resulted in drilling projects being delayed. We may have to reduce our prices in order to remain competitive, which would have an adverse effect on our operating results and cash flows.
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 revenues 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. 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 significant 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 Bureau of Ocean Energy Management (BOEM) and the Bureau of Safety and Environmental Enforcement (BSEE), have implemented significant environmental and safety regulations applicable to drilling operations in the US GOM. These regulations have 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.
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. 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 revenues associated with downtime required to implement regulatory requirements.
In the aftermath of the Macondo well blowout in 2010 and the subsequent investigation into the causes of the event, new rules have been implemented for oil and gas operations in the US GOM and in many of the international locations in which we operate, including new standards for 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.
As awareness of climate change issues increases, governments around the world are beginning to adopt laws and regulations to address the matter. Lawmakers and regulators in the U.S., the U.K. and other jurisdictions where we operate have focused increasingly on restricting and reporting the emission of carbon dioxide, methane and other “greenhouse” gases that may contribute to warming of the Earth’s atmosphere and other climatic changes. This may result in new environmental regulations that may
unfavorably impact us, our suppliers and our customers. We may be exposed to risks related to new laws, regulations, treaties or international agreements pertaining to climate change, greenhouse gases, carbon emissions or energy use that could decrease the use of oil or natural gas, thus reducing demand for hydrocarbon-based fuel and our drilling services. Governments may also pass laws or regulations incentivizing or mandating the use of alternative energy sources such as wind power and solar energy, which may reduce demand for oil and natural gas and our drilling services. Such laws, regulations, treaties or international agreements could result in increased compliance costs or additional operating restrictions, which may have a negative impact on our business, and could 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.
We will experience reduced profitability if our customers terminate or seek to renegotiate our drilling contracts, and our backlog of contracts may not be ultimately realized.
Most of our term drilling contracts are cancelable by the customer without penalty upon the occurrence of events beyond our control such as the loss or destruction of the rig, or the suspension of drilling operations for a specified period of time as a result of a breakdown of major equipment, and require the customer to pay a termination fee in the event of a cancelation without cause. Not all of our contracts require the customer to make an early termination payment upon cancellation. Any early termination payments that may be required under our contracts may not be sufficient to fully compensate us for the loss of the contract and could result in the rig becoming idle for an extended period of time. Additionally, a customer may be able to obtain a comparable rig at a lower daily rate and seek to renegotiate the terms of its existing drilling contract with us. In some cases, we may be unable to negotiate or complete definitive contracts following announcements of receipt of letters of intent. If we or our customers are unable to perform under existing contracts for any reason, our backlog of estimated revenues from drilling contracts would decline and may have a material adverse effect on our operating results, financial position and cash flows.
We have and will likely continue to have certain customer concentrations which increase our risks and may reduce profitability in certain situations.
Our two largest customers, Saudi Aramco and Total Exploration & Production, accounted for 26% and 11%, respectively, of our 2013 consolidated revenues. The loss or material reduction of business from any such significant customer could have a material adverse impact on our results of operations and cash flows. Moreover, to the extent that we may be dependent on any single customer, we could be subject to the risks faced by that customer to the extent that such risks impede the customer's ability to continue operating and make timely payments to us.
Many of our drilling rigs 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 still experience disruptions in our operations due to evacuation plans, reduced ability to transport personnel to the drilling unit, or damage to our customers’ platforms and other related facilities. Additionally our customers may choose not to contract our rigs for use during hurricane season, particularly in the US GOM. We lost a total of six rigs due to hurricanes during the period from 2002 to 2008 and a seventh was significantly damaged. Future severe weather could result in the loss or damage of additional rigs or curtailment of our operations, which could adversely affect our financial position, results of operations and cash flows.
We are currently self-insured with respect to physical damage due to named windstorms in the US GOM.
Hurricanes (or named windstorms) have caused tremendous damage to drilling and production equipment and facilities throughout the US GOM in recent years, and insurance companies have incurred substantial losses as a result. Accordingly, insurance companies have substantially reduced the levels of available coverage for named windstorms in the US GOM and have dramatically increased the price of such coverage. Coverage for potential liabilities to third parties associated with property damage and personal injuries, as well as coverage for environmental liabilities and removal of wreckage and debris associated with these named windstorm losses, has also been limited.
As a result of the increased cost and reduced availability, we do not maintain named windstorm physical damage coverage on any of our rigs located in the US GOM. Our coverage for liabilities (including removal of wreck) arising out of a US GOM named windstorm are subject to a self-insured retention of $200 million per occurrence. Losses due to future US GOM named windstorms not covered by insurance 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.
Our tax positions are subject to audit by U.K., U.S., and other tax authorities. The tax authorities 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 transactions we have undertaken. We could therefore incur material amounts of unrecorded income tax cost if our positions are challenged, and we are unsuccessful in defending them.
For example, in 2009, we recognized certain tax benefits as a result of applying the facts of a third-party tax case to our tax situation. That case provided a more favorable tax treatment for certain foreign contracts entered into in prior years. Determinations by tax authorities which differ materially from our recorded estimates, favorably or unfavorably, may have a material impact on our results of operations, financial position and cash flows. This position is currently under audit and has been challenged by U.S. Internal Revenue Service (IRS) field agents. We have appealed their findings and expect to come to a conclusion within the next twelve months. There can be no assurance that we will prevail in our position.
Changes in or non-compliance with tax laws and changes to our income tax estimates could adversely impact our financial results.
On May 4, 2012, we completed a change in our legal domicile to the U.K. where we had substantial operations. As a result of the redomestication, Rowan plc became the parent company of the Rowan group of companies and our former Delaware parent company, RCI, became an indirect, wholly owned subsidiary of Rowan plc. There are frequently legislative proposals in the U.S. that attempt 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, the ultimate repatriation of earnings from non-U.S. subsidiaries to the U.S., or by 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 undistributed earnings of the Company’s non-U.K. subsidiaries, including RCI’s non-U.S. subsidiaries. It is the Company’s policy and intention to permanently reinvest earnings of non-U.S. subsidiaries of RCI outside the U.S. Should the non-U.S. subsidiaries of RCI make a distribution from these earnings, we may be subject to additional U.S. income taxes.
Our international operations typically present additional risks, and operations in certain foreign areas present higher costs.
In recent years, we have significantly diversified our operations internationally. Foreign operations are often subject to additional political, economic and other uncertainties, such as with respect to taxation policies, customs restrictions, currency exchange, security threats including terrorism, piracy and the risk of asset expropriation due to foreign sovereignty over operating areas. Political unrest in our areas of operations could potentially delay current or planned projects or could impact us in other unforeseen ways.
In foreign areas where legal protections may be less available to the Company, 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, are highly regulated and have higher compliance and operating costs in general.
The majority of our transactions are denominated in U.S. dollars. In order to reduce the impact of exchange rate fluctuations, we generally require customer payments to be in U.S. dollars and limit non-U.S. currency holdings to the extent they are needed to pay liabilities of operations denominated in local currencies. In certain countries in which we operate such as Egypt, local laws or contracts may require us to receive payment for a portion of the contract in the local currency. In such instances, we may hold a greater amount of local currency than would otherwise be the case exposing us to devaluation and other risk of exchange loss.
Political disturbances, war, or terrorist attacks and changes in global trade policies and economic sanctions could adversely impact our operations.
Our operations, and particularly those in the Middle East and Egypt, 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, nationalization, expropriation, confiscation or deprivation of our assets or military action impacting our operations, assets or financial performance in our areas of operations, including the Middle East.
Most of our contracts are fixed-price contracts, and changes in customer requirements, increased regulatory requirements and increases in our operating costs or price levels in general could have an adverse effect on the profitability of those contracts.
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. Our long-term contracts may be at day rates lower than current prevailing rates, and therefore unable to benefit from the higher prevailing rates. Long-term contracts may also be at day rates higher than prevailing rates, and our revenues may decline at the end of such favorable contracts. Many of our operating costs are unpredictable and can vary based on events beyond our control, including increased customer and regulatory requirements. Operators and regulators are requiring higher standards than in the past, including more robust back-up redundancy systems. Our margins will therefore vary over the terms of our contracts as a result of applicable day rates and operating costs. If our costs increase or we encounter unforeseen costs, we may not be able to recover them from our customers, which could adversely affect our financial position, results of operations and cash flows.
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 10% of our available rig days in 2013, down from approximately 12% in 2012. Operating revenue may fluctuate as a function of changes in day rates, 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 used to prepare the rig for its next contract. During times of reduced activity, reductions in costs may not be immediate as portions of the crew may be required to prepare our rigs for stacking. Moreover, as our rigs are mobilized from one geographic location to another, the labor and other operating and maintenance costs may increase significantly.
Shortages of significant parts or equipment, supplier capacity constraints, supplier production disruptions, supplier quality and sourcing issues or price increases could increase our operating costs, decrease our revenues and adversely impact our operations.
Our reliance on third-party suppliers, manufacturers and service providers to secure equipment, parts, components and sub-systems used in our drilling operations exposes us to volatility in the quality, prices and availability of such items, as well as poor customer service in general. Certain high specification 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, quality-control issues, recalls or other decreased availability or servicing of parts and equipment could adversely affect our ability to meet our commitments to customers, adversely impact our operations and revenues by resulting in uncompensated downtime, reduced day rates or the cancellation or termination of contracts, or increase our operating costs.
High costs associated with maintaining idle rigs may cause us to experience losses, and cold-stacking rigs could result in impairment charges.
During extended periods that rigs are idle, we may choose to cold-stack our rigs. In 2012, we recognized a $5.2 million asset impairment charge on the Rowan Juneau, which has been cold-stacked since 2010. In the event markets deteriorate, we could be exposed to impairment charges on any of our rigs, regardless of whether they are operating or stacked, and we could be exposed to severance costs in the event we stack additional rigs.
Some of our operating risks 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 damages and losses. Our insurance coverage is subject to deductibles and self-insured retentions which must be met prior to any recovery. Additionally, our insurance is subject to exclusions and limitations, and we can provide no assurance that such coverage will adequately protect us against liability from all potential consequences and damages. 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 a material adverse effect on our financial position, results of operations and cash flows.
Our current insurance policies provide coverage for loss or damage to our fleet of drilling rigs on an agreed value basis (which varies by unit) subject to a deductible of $25 million per occurrence. This coverage does not include damage arising from a US GOM named windstorm, for which we are self-insured.
We maintain insurance policies providing coverage for liability associated with negative environmental impacts of a sudden and accidental pollution event, third-party liability, employers’ liability (including Jones Act liability), automobile liability and aviation liability, and these policies are subject to various deductibles and underlying limits. In addition, we maintain excess liability coverage with an annual aggregate limit of $700 million subject to a self-insured retention of $10 million except in cases of liabilities (including removal of wreck) arising out of US GOM named windstorms, which are subject to a self-insured retention of $200 million per occurrence.
Our rig physical damage and liability insurance renews each June. We can provide no assurance we will be able to secure coverage of a similar nature with similar limits at comparable costs.
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.
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 our customers and us 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 receive from operators against liabilities varies from contract to contract based on market conditions and customer requirements existing when the contract was negotiated. However, the enforceability of our indemnities may be subject to differing interpretations, or further limited or prohibited under applicable law or by contract, particularly in cases of gross negligence, willful misconduct, punitive damages or punitive fines and/or penalties. For example, in 2012 a U.S. District Court in the Eastern District of Louisiana invalidated certain contractual indemnities for punitive damages and for civil penalties in a drilling contract governed by U.S. maritime law as a matter of public policy. We could therefore be liable for certain liabilities even in cases where we have contractual indemnification rights. Notwithstanding a contractual indemnity from a customer, there can be no assurance that our customers will be financially able to indemnify us or will otherwise honor their contractual indemnity obligations. 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 could have a material adverse effect on our financial position, results of operations and cash flows.
Regulation of greenhouse gases and climate change could have a negative impact on our business.
Some scientific studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases” (GHGs) and including carbon dioxide and methane, may be contributing to warming of the Earth’s atmosphere and other climatic changes. In response to such studies, the issue of climate change and the effect of GHG emissions, in particular emissions from fossil fuels, is attracting increasing attention worldwide. International treaties, legislative and regulatory measures to address concerns that emissions of GHGs are contributing to climate change are in various phases of discussions or implementation at the international, national, regional and state levels.
Because our business depends on the level of activity in the oil and natural gas industry, existing or future laws, regulations, treaties or international agreements related to GHGs and climate change, including incentives to conserve energy or use alternative energy sources, could have an adverse impact on our business if such laws, regulations, treaties or international agreements reduce the worldwide demand for oil and natural gas or otherwise result in reduced economic activity generally. In addition, such laws, regulations, treaties or international agreements could result in increased compliance costs or additional operating restrictions, which may have an adverse impact on our business. In addition to potential impacts on our business directly or indirectly resulting from climate-change legislation or regulations, our business also could be negatively affected by climate-change related physical changes or changes in weather patterns. An increase in severe weather patterns could result in damages to or loss of our rigs, impact our ability to conduct our operations and/or result in a disruption of our customers' operations. The effect on our operations could include increased costs to operate and maintain our equipment and facilities, install new emission controls on our equipment or facilities, measure and report our emissions, acquire allowances to authorize our greenhouse gas emissions, pay any taxes related to our greenhouse gas emissions and administer and manage a greenhouse gas emissions program.
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 dispute, 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.
A downgrade in the ratings of our debt could restrict our ability to access the debt capital markets and increase our interest costs.
We currently have investment grade credit ratings, which are subject to review and change by the rating agencies from time to time. There can be no assurance that any particular rating assigned to us will remain in effect for any given period of time or that a rating will not be changed or withdrawn by a rating agency, if in that rating agency’s judgment, future circumstances relating to the basis of the rating so warrant. Changes in the ratings or outlook that rating agencies assign to our debt may ultimately limit our access to the debt capital markets and increase the costs we incur to borrow funds. If ratings for our debt fall below investment grade, our access to the debt capital markets would become restricted. Tightening in the credit markets and the reduced level of liquidity in many financial markets due to turmoil in the financial and banking industries could also affect our access to the debt capital markets or the price we pay to issue debt. Our revolving credit facility includes an increase in interest rates if the ratings for our debt are downgraded. Further, an increase in the level of our indebtedness may increase our vulnerability to adverse general economic and industry conditions and may affect our ability to obtain additional financing.
Our operations present hazards and risks that require significant oversight, and we depend upon the security and reliability of our technologies, systems and networks in numerous locations where we conduct business.
We depend on technologies, systems and networks to manage our international locations in numerous locations, and our digital technologies may be subject to cybersecurity breaches. If our systems for protecting against cybersecurity risks prove to be insufficient, we could be adversely affected by having our business and financial systems compromised, our proprietary information altered, lost or stolen, or our business operations and safety procedures disrupted. Such events could impact our financial position, results of operations and cash flows.
Failure to comply with corruption laws could have an adverse impact on our business.
The U.S. Foreign Corrupt Practices Act (FCPA), the United Kingdom Bribery Act 2010 and similar anti-corruption laws in other jurisdictions generally prohibit companies and their intermediaries from making improper payments to foreign officials for the purpose of obtaining or retaining business. Although we have programs in place covering compliance with anti-corruption laws, any failure to comply with the FCPA or other anti-corruption laws could subject us to civil and criminal penalties or other sanctions, which could have a material adverse effect on our business, financial position, results of operations or cash flows. We could also face fines, sanctions and other penalties from authorities in the relevant foreign jurisdictions, including prohibition of our participating in or curtailment of business operations in those jurisdictions and the seizure of rigs or other assets.
Unionization efforts and labor regulations in certain countries in which we operate could materially increase our costs or limit our flexibility.
Certain of our employees and contractors in international markets, 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 portions of our workforce. In addition, we may in the future be subject to 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 revenues or limit our flexibility.
The expected benefits of the redomestication may not be realized.
We cannot be assured that the benefits of the redomestication will be achieved, particularly those subject to factors beyond our control. These factors include such things as the reactions of third parties with whom we do business and the reactions of investors, analysts and U.K. and U.S. taxing authorities.
We operate through subsidiaries in various countries throughout the world including the United States. We are or may become subject to changes in tax laws, treaties or regulations or the interpretation or enforcement thereof in the U.K., U.S. or any other jurisdictions in which we or any of our subsidiaries operate or are resident. Our income tax expense is based upon our interpretation of the tax laws in effect in various countries at the time that the expense was incurred. If the U.K., U.S., or other taxing authorities successfully challenge our application and/or interpretation of such laws, treaties and regulations or valuations and methodologies or other supporting documentation, we may not experience the level of tax benefits we anticipate or we may be subject to adverse tax consequences, which could have a material adverse effect on us. In addition, our realization of expected tax benefits is based upon the assumption that we take successful planning steps and that we maintain and execute adequate processes to support our planning activities. If we fail to do so, we may not achieve the expected benefits. Even if we are successful in maintaining our positions, we may incur significant expense in contesting positions asserted or claims made by tax authorities.
We also could be subject to future audits conducted by various tax authorities, and the resolution of such audits could significantly impact our effective tax rate in future periods, as would any reclassification or other matter (such as changes in applicable accounting rules) that increases the amounts we have provided for income taxes in our consolidated financial statements. There can be no assurance that we would be successful in attempting to mitigate the adverse impacts resulting from any changes in law, audits and other matters. Our inability to mitigate the negative consequences of any changes in the law, audits and other matters could cause our effective tax rate to increase and our results of operations to be negatively impacted.
Our effective tax rates and the benefits are also subject to a variety of other factors, many of which are beyond our ability to control, such as changes in the rate of economic growth in the U.K. and the U.S., the financial performance of our business in various jurisdictions, currency exchange rate fluctuations, and significant changes in trade, monetary or fiscal policies of the U.K. or the U.S., including changes in interest rates.
Further, realization of the logistical and operational benefits of the redomestication is also dependent on a variety of factors including the geographic regions in which our rigs are deployed, the location of the business unit offices that oversee our global offshore contract drilling operations, the locations of our customers' corporate offices and principal areas of operation and the location of our investors. If events or changes in circumstances occur affecting the aforementioned factors, we may not be able to continue to realize the expected logistical and operational benefits of the redomestication.
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 (or impossible) 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, except with the consent of our Board or the prior approval of the shareholders, a Rowan plc shareholder, together with persons acting in concert, would be at risk of certain Board sanctions if they 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. 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 increased shareholder approval requirements, we may have less flexibility as a U.K. public limited company than as a Delaware corporation with respect to certain aspects of capital management.
Under Delaware law, directors may issue, without further stockholder approval, any shares authorized in a company’s certificate of incorporation that are not already issued or reserved. Delaware law also provides substantial flexibility in establishing the terms of preferred shares. However, English law provides that a board of directors may generally only allot shares with the prior authorization of shareholders; such authorization must state the maximum amount of shares that may be allotted and may only be for a maximum period of five years.
English law also generally provides shareholders with preemptive rights when new shares are issued for cash while Delaware law does not. However, it is possible for the articles of association, or shareholders in a general meeting, to exclude preemptive rights for a maximum period of up to five years from the date of adoption of the exclusion.
English law also generally prohibits a company from repurchasing its own shares by way of “off market purchases” without the prior approval of shareholders by special resolution (i.e., 75 percent of votes cast), which approval lasts for a maximum period of five years. English law prohibits Rowan plc from conducting “on market purchases” as its shares will not be traded on a recognized investment exchange in the U.K.
Prior to the redomestication, resolutions were adopted to authorize the allotment of a certain amount of shares, exclude certain preemptive rights and permit off market purchases, in each case without further shareholder approval, but these authorizations will expire in 2017 unless further approved by our shareholders prior to the expiration date.
We cannot assure you that situations will not arise where U.K. shareholder approval requirements for the extension or expansion of any of these actions would deprive our shareholders of substantial capital management benefits.
We have incurred higher costs as a result of the redomestication and we expect to continue to do so.
The redomestication has resulted in an increase in some of our ongoing expenses and requires us to incur some new expenses. Some costs, including those related to holding worldwide operational management meetings and holding board and shareholder meetings in the U.K., are higher than would be the case if we had not redomesticated. We are also incurring new or increased expenses, including professional fees, to comply with U.K. corporate and tax laws.
ITEM 1B. UNRESOLVED STAFF COMMENTS
The Company has no unresolved SEC staff comments.
ITEM 2. PROPERTIES
The Company's primary U.S. offices are located in 116,562 square feet of leased space in an office tower located at 2800 Post Oak Boulevard in Houston, Texas. Additionally, we lease other office, maintenance and warehouse facilities in Houston, Texas; Aberdeen, Scotland; Dammam, Saudi Arabia; Doha, Qatar; Cairo, Egypt; Chaguaramas, Trinidad; Stavanger, Norway; Ulsan, South Korea; Jakarta, Indonesia; Kuala Lumpur, Malaysia, and Singapore.
Drilling Rigs
Following are the principal drilling equipment owned by the Company and location at February 20, 2014. Water depths are the "rated" water depths; actual water depths may vary depending on operating location:
______________________________
(1)
Indicates rated water and drilling depths.
(2)
High-specification rigs are those that have hook-load capacity of at least two million pounds.
(3)
Unit is equipped with three mud pumps.
(4)
Unit is equipped with four mud pumps.
(5)
Premium jack-ups are cantilevered rigs capable of operating in water depths of 300 feet or more.
(6)
Units are equipped with skid-off capability, which is described under “Drilling Fleet” in Item 1, Business.
ITEM 3. LEGAL PROCEEDINGS
On May 2, 2012, while attempting to enter the Port of Corpus Christi Ship Channel, the tanker M/V FR8 PRIDE lost engine power and propulsion and collided with the Company’s EXL I rig causing extensive damage to the rig. On May 18, 2012, the Company filed suit in federal court in the Southern District of Texas, Corpus Christi Division, against the M/V FR8 PRIDE, FR8 Pride Shipping Corp. PTE. Ltd. (FR8 Pride Shipping), Thome Ship Management PTE. Ltd. (Thome Ship Management), Scorpio USA LLC, and Scorpio Panamax Tanker Pool Ltd., the M/V FR8 PRIDE’s owners and operators, seeking damages for repairs to the rig of approximately $12 million, which were recognized and included in material charges and other operating expenses in the Consolidated Statement of Income for the year ended December 31, 2012. The EXL I returned to work on November 5, 2012, and the Company estimates its loss of use claim to be an additional $12.5 million. The repair costs to the EXL I are not covered by the Company's insurance because such costs were below the $25 million deductible. In addition, loss of use is not an insured risk.
Mediation was conducted on December 11 and 12, 2013. As a result of the mediation, the parties entered into a binding settlement agreement on December 12, 2013, which resolved all of the damage claims on confidential terms. At present, the parties are working toward finalizing the documentation in order to formally end the litigation. Once a final settlement and release agreement is executed, settlement funds are required to be paid to the Company within thirty days. Until the final settlement agreement and release is executed and the settlement has been funded, we cannot guarantee receipt of any revenue associated with the resolution of the disputed claims.
We are from time to time a party to various lawsuits filed by current or former employees that are incidental to our operations in which the claimants seek unspecified amounts of monetary damages for personal injury, including injuries purportedly resulting from exposure to asbestos on our drilling rigs. At December 31, 2013, there were approximately 27 asbestos related lawsuits in which we are one of many defendants. These lawsuits have been filed in the state courts of Louisiana, Mississippi and Texas. We intend to vigorously defend against the litigation. We are unable to predict the ultimate outcome of these lawsuits; however, we do not believe the ultimate resolution of these matters will have a material adverse effect on our financial position, results of operations or cash flows.
We are involved in various other legal proceedings incidental to our businesses and are vigorously defending our position in all such matters. We believe that there are no other known contingencies, claims or lawsuits that could have a material adverse effect on our financial position, results of operations or cash flows.
ITEM 4. MINE SAFETY DISCLOSURES
Not applicable.
EXECUTIVE OFFICERS OF THE REGISTRANT
The names, positions and ages of the executive officers of the Company as of March 3, 2014, are listed below. Our executive officers are appointed by the Board of Directors and serve at the discretion of the Board of Directors. 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.
Mr. Ralls has been Chief Executive Officer of the Company since January 2009. Additionally, Mr. Ralls served as President of the Company from January 2009 until March 2013. From June 2005 until his retirement in November 2007, Mr. Ralls served as
Executive Vice President and Chief Operating Officer of GlobalSantaFe Corporation. Mr. Ralls also serves on the Boards of Superior Energy Services and Cabot Oil & Gas Corporation.
Dr. Burke became President of the Company in March 2013 and has served as Chief Operating Officer since July 2011. He joined the Company in December 2009 to serve as President and Chief Executive Officer of LeTourneau Technologies, Inc. (LeTourneau) and served in such capacity until the sale of LeTourneau in June 2011. Prior to that time, he was employed by Complete Production Services, Inc., an oilfield services company, as Division President from 2006 to 2009.
Mr. Bartol became Executive Vice President, Chief Financial Officer and Treasurer in September 2012. In July 2012, Mr. Bartol was appointed Executive Vice President, Finance and Corporate Development, and from March 2010 to July 2012, served as Senior Vice President, Corporate Development. From June 2007 to March 2010, he served as Vice President, Strategic Planning.
Since January 2007, Mr. Buvens’ principal occupation has been Executive Vice President, Legal.
Since January 2007, Mr. Keller’s principal occupation has been Executive Vice President, Business Development.
Ms. Trent became Senior Vice President, Chief Administrative Officer and Corporate Secretary in July 2011. From March 2010 to July 2011, she served as Vice President and Corporate Secretary. Ms. Trent has served as Corporate Secretary since she joined the Company in 2005, and also served as Compliance Officer from 2005 to January 2007 and as Special Assistant to the CEO from January 2007 to December 2008.
Mr. Hatfield has served as Vice President and Controller since March 2010. From May 2005 to March 2010, he served as Controller.
As previously announced, Mr. Ralls plans to retire as Chief Executive Officer of the Company effective as of the 2014 annual general meeting of shareholders (the annual meeting) and, subject to his reelection at the annual meeting, will assume the role of Executive Chairman of the Board as of such date. Dr. Burke will assume the role of Chief Executive Officer as of Mr. Ralls’ retirement and has been nominated by the Board for election at the annual meeting as a director. As part of the succession transition, the Board has determined that Mr. Ralls’ extensive experience and leadership in the energy industry and as President and CEO of the Company since 2009 are invaluable and his continued role as Executive Chairman will help the Board leverage his expertise and knowledge during the transition period as Dr. Burke assumes the role of CEO. Subject to his re-election by shareholders, Mr. Ralls has agreed to serve as Executive Chairman for a transition period of two years until the 2016 annual general meeting of shareholders, at which time he plans to retire from the Board.
PART II
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 for each quarterly period within the two most recent years as reported by the NYSE Consolidated Transaction Reporting System.
On January 31, 2014, there were 77 shareholders of record.
Restrictive provisions in the Company’s debt agreements require the Company to maintain a minimum level of shareholders’ equity equal to no less than the 67 percent of the book value of outstanding debt.
On January 31, 2014, the Board of Directors approved a quarterly cash dividend policy, with the first dividend expected to be paid in the second quarter of 2014. The Board anticipates the initial quarterly cash dividend will be $0.10 per share.
The graph below presents the relative investment performance of our ordinary shares, the Dow Jones U.S. Oil Equipment and Services Index, and the S&P 500 Index for the five-year period ended December 31, 2013, assuming reinvestment of dividends.
Issuer Purchases of Equity Securities
The following table summarizes acquisitions of our shares for the fourth quarter of 2013:
For information concerning our shares to be issued in connection with equity compensation plans, see Item 12, “Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters,” of this Form 10-K.
ITEM 6. SELECTED FINANCIAL DATA
Selected financial data for each of the last five years is presented below:
___________________
(1)
Material charges and other operating expenses consisted of the following: 2013 - $4.5 million of noncash asset impairment charges; 2012 - $13.8 million of legal and consulting fees incurred in connection with the Company’s redomestication, $12.0 million of repair costs for the EXL I following its collision with a tanker, $8.7 million of pension settlement costs in connection with lump sum pension payments to employees of the Company’s former manufacturing subsidiary, $8.1 million of noncash asset impairment charges, $2.3 million of incremental noncash share-based compensation cost in connection with the retirement of an employee, partially offset by a $4.7 million gain for cash received in connection with the settlement of a 2005 dispute with a customer; 2011 - a $6.1 million payment to settle a lawsuit in connection with the Company’s obligation under a charter agreement for the Rowan Halifax and $4.9 million of incremental noncash and cash compensation cost in connection with the separation of an employee; and 2010 - the cost of terminating the Company’s agency agreement in Mexico.
(2)
In 2011, the Company sold its manufacturing and land drilling operations. Operating results for manufacturing and land drilling have been reclassified to discontinued operations for each year presented.
(3)
Current ratio excludes assets and liabilities of discontinued operations.
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
OVERVIEW
Results of operations continued their upward trend in 2013 over 2012 and 2011 as both day rates and utilization were up over prior years, and out-of-service days and unbilled downtime decreased. Fleet utilization improved to 81% in 2013 from 77% and 66% in 2012 and 2011, respectively, and fleet average day rates improved to $170,912 in 2013 from $156,306 and $142,083 in 2012 and 2011. Out-of-service days decreased to less than 10% of available rig days in 2013 from approximately 12% in 2012 and 22% in 2011 as a result of decreased shipyard time and fewer rig mobilizations in 2013 compared to the previous two years. Operational downtime, which represents unbillable hours due to equipment breakdowns or procedural failures, decreased to approximately 1% of in-service days from 2% in 2012.
In January 2014, we took delivery of the Rowan Renaissance, the first of our four new drillships. The Rowan Renaissance is expected to commence drilling operations offshore West Africa under a three-year contract beginning in April 2014 at an effective day rate of $619,000. Our three remaining ultra-deepwater drillships under construction, the Rowan Resolute, Rowan Reliance, and Rowan Relentless, are scheduled for delivery in June 2014, October 2014, and March 2015, respectively. The Rowan Resolute has a three-year contract commencing in the US GOM in late September 2014 at an effective day rate of $608,000. The Rowan Reliance has a three-year contract commencing operations in the US GOM in late January 2015 at an effective day rate of $602,000, and the Rowan Relentless is not yet contracted.
With the addition of the drillship contracts, we increased our backlog to $5.0 billion as of February 20, 2014, from $3.6 billion at the same time last year.
As of February 20, 2014, the date of our most recent Fleet Status Report, we had six jack-ups in the North Sea, ten in the Middle East, seven in the US GOM, two in each of Malaysia, Trinidad, and Indonesia and one in Egypt. As of that date, estimated contract expirations for our jack-up rigs were as follows: 2014 - 16; 2015 - 4; 2016 - 3; 2017 - 3, and 2024 - 1. At that date, three rigs were available, including two that were cold-stacked.
RESULTS OF OPERATIONS
Our profitability is primarily a function of our ability to keep our rigs under contract earning operating day rates, offset by any downtime while a rig is under contract. The Company typically receives a reduced day rate or no day rate during periods of downtime. Our ability to obtain contracts for our rigs and the day rates received are primarily determined by the level of oil and gas exploration and development expenditures, which are heavily influenced by trends in oil and natural gas prices and the availability of competitive equipment. When drilling markets are strengthening, day rates generally lag the upward trend in rig utilization, and day rate increases can be more significant as fleet utilization approaches 90% or more. When drilling markets are weakening, contractors often reduce day rates in an effort to maintain fleet utilization. Both rig utilization and day rates have historically declined much faster than they have risen. Our average utilization and day rates by rig classification are presented below:
Current Operations and Markets
Worldwide demand for offshore drilling services is inherently volatile and has historically varied among geographic markets, as has the supply of competitive equipment. Exploration and development expenditures can be impacted by many local factors, such as political and regulatory policies, seasonal weather patterns, lease expirations, new oil and gas discoveries and reservoir depletion. Over time, the level and expected direction of oil and natural gas prices are the principal determinants of drilling activity, and oil and gas prices are ultimately a function of the supply of and demand for those commodities.
Our primary drilling markets are currently the U.K. and Norwegian sectors of the North Sea, the Middle East, the US GOM and Southeast Asia. As demand shifts among geographic areas, the Company may from time to time relocate rigs from one major geographic area to another. The relocation of rigs is a significant undertaking, and often interrupts revenues and cash flows for several months, particularly when equipment upgrades are involved. Thus, major relocations are typically carried out only when the likelihood of higher long-term returns outweighs the short-term costs. During 2012 we relocated three rigs from the US GOM to Egypt, Indonesia and Malaysia. There were no significant rig repositionings in 2013.
The North Sea is a mature, harsh-environment offshore drilling market that has long been dominated by major oil and gas companies operating within a relatively tight regulatory environment. Project lead times are often lengthy, and drilling assignments, which typically require ultra-premium equipment capable of handling extreme weather conditions and high down-hole pressures and temperatures, can range from several months to several years. Drilling activity and day rates in the North Sea move slowly in response to market conditions, and generally follow trends in oil prices. As of February 20, 2014, industry utilization for jack-up rigs in the North Sea was 100%, and we had six rigs in the U.K. and Norwegian sectors with expected contract completion dates ranging from 2014 through 2017.
The Middle East is a market in which we have had a significant presence in recent years. As of February 20, 2014, industry utilization in the Middle East for jack-up rigs was 89%, and we had nine rigs under contract in Saudi Arabia and one under contract in Qatar. Seven of our ten rigs working there have contracts estimated to complete in 2014, one has a contract estimated complete in 2015, one has a contract estimated to complete in 2016 and one has a contract estimated to complete in 2024.
The US GOM jack-up drilling market is highly fragmented among many participants, many of which are independent operators whose drilling activities may be highly dependent on near-term operating cash flows. A typical drilling assignment may call for 60 days of exploration or development work performed under a single-well contract with negotiable renewal options. Long-term contracts for jack-up rigs have been relatively rare, and generally are available only from the major integrated oil companies and a few of the larger independent operators. Jack-up drilling demand and day rates in the US GOM have tended to move quickly and generally follow trends in natural gas prices. Demand in the shallower waters of the US GOM has been relatively weak over the last few years as a result of the availability of natural gas and relatively low prices. As of February 20, 2014, industry utilization for jack-up rigs in the US GOM was 59%, and we had seven rigs there - five under contracts estimated to complete in 2014, and two that were stacked.
In late 2011, we reentered the Southeast Asia market after a long absence and currently have one rig operating in Malaysia, two in Indonesia and one stacked in Malaysia. We see increasing opportunities in Southeast Asia due to strong regional economies, a growing emphasis on higher specification rigs and strong interest in contractors with high-pressure/high-temperature well experience. Industry utilization for jack-up rigs in Southeast Asia was 92% at February 20, 2014. Two of our rigs there have contracts estimated to complete in 2014 and one has a contract estimated to complete in 2016.
Key Performance Measures
The following table presents certain key performance measures for our fleet:
2013 Compared to 2012
Our operating results for the years ended December 31, 2013 and 2012 are highlighted below (dollars in millions):
Revenues for 2013 increased by $186.7 million or 13% compared to 2012 as a result of the following (in millions):
Operating costs other than depreciation, selling, general and administrative expenses and material charges and other operating expenses for 2013 increased by $108.7 million or 14% over the prior year, as a result of the following (in millions):
Our operating margin (revenues in excess of operating costs, other than depreciation, selling, general and administrative expenses and material charges and other operating expenses) was approximately 45% in 2013 and 46% in 2012. Depreciation increased by $23.1 million or 9% over 2012 due to capital improvements to the fleet.
In July 2013, while the Gorilla VII was changing locations, the legs were severely damaged as the hull was being lowered into the water. Extended poor weather conditions in the North Sea hampered the rig's ability to return to its operating location following repairs. As a result of the incident, the rig was out of service for 174 days in 2013, resulting in a loss of revenue of approximately $43 million. In 2013, we incurred $12.4 million in incremental repair costs to the rig, which are included in direct operating costs. The rig returned to service in February 2014.
Selling, general and administrative expenses increased by $31.7 million or 32% primarily due to professional services and fees for corporate restructuring, initiatives related to the Company's internationalization and entry into the ultra-deepwater market; the noncash impact of a new retirement policy on the vesting period for share-based compensation; incremental incentive-based compensation based on the Company's projected performance; and fair market adjustments to certain share-based awards based on changes in the share price.
In 2013, the Company sold the Rowan Paris, one of the Company's older rigs, for approximately $40.0 million in cash and recognized a gain of $19.1 million.
Material charges and other operating expenses for 2013 consisted of a $4.5 million noncash asset impairment charge on a maintenance and storage facility.
Material charges and other operating expenses for 2012 consisted of $13.8 million of legal and consulting fees incurred in connection with the Company’s redomestication, $12.0 million of repair costs for the EXL I following its collision with a tanker, $8.7 million of pension settlement costs in connection with lump sum pension payments to employees of the Company’s former manufacturing subsidiary, $8.1 million of noncash asset impairment charges, $2.3 million of incremental noncash share-based compensation cost in connection with the retirement of an employee, partially offset by a $4.7 million gain for cash received in connection with a legal settlement.
In 2013, we recognized income tax expense of $8.7 million on $261.2 million of pretax income from continuing operations, as compared to a benefit of $19.8 million on $183.5 million of pretax income from continuing operations in 2012. The low effective tax rate of 3.3% in 2013 was due in part to the amortization of benefits related to outbounding certain U.S.-owned rigs to our non-U.S. subsidiaries in prior years; a significant proportion of income earned in low-tax foreign jurisdictions; the implementation of our international restructuring plan, which resulted in the utilization of non-U.S. subsidiaries’ foreign taxes paid as credits against U.S. taxable income; additional tax basis in fixed assets due to the application of a ruling in a third-party tax case to the Company's situation; and the continued recognition of tax benefits related to the application of certain tax planning strategies implemented in 2012 related to interest capitalization. The recognition of an income tax benefit in 2012 was due in part to the amortization of benefits related to outbounding certain rigs to our non-U.S. subsidiaries in prior years; a significant proportion of income earned in low-tax foreign jurisdictions; and the implementation of tax planning strategies with regard to capitalized interest.
2012 Compared to 2011
Our operating results for the years ended December 31, 2012 and 2011 are highlighted below (dollars in millions):
Revenues for 2012 increased by $453.4 million or 48% compared to 2011 as a result of the following (in millions):
The addition of seven newbuild rigs to the fleet in 2011 and 2012 contributed 1,198 incremental revenue-producing days in 2012 (14% of total revenue-producing days) over 2011.
Operating costs other than depreciation, selling, general and administrative expenses and material charges and other operating expenses for 2012 increased by $244.1 million or 48% over the prior year, as a result of the following (in millions):
Our operating margin (revenues in excess of operating costs, other than depreciation, selling, general and administrative expenses and material charges and other operating expenses) was approximately 46% of revenues in both 2012 and 2011. Depreciation increased by $64.0 million or 35% over 2011 due to the rig additions. Selling, general and administrative expenses increased by $11.5 million or 13% primarily due to increases in personnel and related costs in connection with the expansion of operations in 2011 and 2012 and to increases in professional fees.
Material charges and other operating expenses for 2012 consisted of $13.8 million of legal and consulting fees incurred in connection with the Company’s redomestication, $12.0 million of repair costs for the EXL I following its collision with a tanker, $8.7 million of pension settlement costs in connection with lump sum pension payments to employees of the Company’s former manufacturing subsidiary, $8.1 million of noncash asset impairment charges, $2.3 million of incremental noncash share-based compensation cost in connection with the retirement of an employee, partially offset by a $4.7 million gain for cash received in connection with a legal settlement.
Material charges and other operating expenses for 2011 consisted of a $6.1 million charge for the settlement of litigation in connection with the 2005 loss of the Rowan Halifax and a cash and noncash charge of $4.9 million for incremental compensation cost in connection with the separation of an employee.
For 2012, we recognized an income tax benefit of $19.8 million on $183.5 million of pretax income from continuing operations as compared to a benefit of $5.7 million on $130.1 million of pretax income from continuing operations in 2011. The recognition of income tax benefits in 2012 and 2011 were due in part to the amortization of benefits related to outbounding certain rigs to our non-U.S. subsidiaries in prior years, and with respect to 2012, the implementation of tax planning strategies with regard to capitalized interest. Also impacting taxes in 2012 and 2011 were the removal of the Company’s manufacturing and land drilling operations, whose earnings were subject to a 35% U.S. statutory rate, and a significant proportion of income earned in lower-tax jurisdictions.
Outlook
Our backlog by geographic area as of the date of our most recent Fleet Status Report, compared to our backlog as reported in our 2012 Form 10-K, is set forth below. Backlog for the US GOM at February 20, 2014, includes $1.8 billion attributable to the three remaining drillships under construction (in millions):
We estimate our backlog will be realized as follows (in millions):
About 61% of our remaining available rig days in 2014 and 35% of available rig days in 2015 were under contract or commitment as of February 20, 2014. As of that date, we had 16 rigs with contract terms ending in 2014. As existing contracts expire, we expect our rigs to roll over at day rates higher than prior contract rates.
We define out-of-service days as those for which no revenues are recognized other than operational downtime and cold-stacked days. The Company may be compensated for certain out-of-service days, such as for shipyard stays or for rig transit periods preceding a contract; however, recognition of any such compensation is deferred and recognized over the period of drilling operations.
Our out-of-service days declined to 10% of available rig days in 2013 from 12% in 2012 and 22% in 2011. Out-of-service time was down from the prior year as there were no major rigs relocations in 2013 compared to three in 2012. Partially offsetting such improvement was the unplanned downtime for the Gorilla VII, which was out of service for 174 days in 2013 while in a shipyard for leg repairs and waiting on weather, in addition to planned shipyard stays for upgrades, repairs and inspections for other rigs. Out-of-service days in 2011 was negatively impacted due to several major rig relocations and the start-up of six newly constructed rigs. We currently estimate out-of-service days for our jack-up fleet to be approximately 7% to 9% of available rig days in 2014 for inspections and special surveys, customer required equipment upgrades and other equipment modifications.
Operational downtime is defined as the unbillable time a rig is under contract and unable to conduct planned operations due to equipment breakdowns or procedural failures. Our operational downtime, which is in addition to out-of-service days, was approximately 1% of in-service days for 2013 compared to 2% for 2012. We estimate operational downtime will typically approximate 2.5% of operating days on a go-forward basis.
We expect our first two ultra-deepwater drillships to commence initial operations in mid April and late September 2014. We project that operational downtime for our ultra-deepwater drillships will be less than 5% following their initial break-in period of operations, during which time the actual rate could be somewhat higher.
As the Company has expanded its operations internationally, the costs of complying with local laws and regulations have increased. We expect this trend of higher compliance costs, as well as higher costs due to wage pressures, to continue into 2014. Additionally, the Company has incurred substantial "off-rig" costs over the last several quarters in preparation of its entrance into the ultra-deepwater market. We expect the growth of such costs to moderate in 2014 and be mitigated somewhat with the commencement of operations of our first two ultra-deepwater drillships in 2014.
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:
Operating Cash Flows
Cash flows from operations increased to approximately $623 million in 2013 from $394 million in 2012, and $95 million in 2011. Operating cash flows for 2013 were favorably impacted by higher day rates and rig utilization, receipt of an approximately $53 million U.S. federal income tax refund, improved timing of collections of accounts receivables and a reduction in the required minimum pension contribution as a result of U.S. legislation. Operating cash flows for 2012 compared to 2011 were positively impacted by the addition of seven newbuild rigs to the fleet in 2011 and 2012.
The Company has not provided deferred income taxes on undistributed earnings of its non-U.K. subsidiaries, including RCI's non-U.S. subsidiaries. It is the Company’s policy and intention to permanently reinvest earnings of non-U.S. subsidiaries of RCI outside the U.S. Generally, earnings of non-U.K. subsidiaries that are not subsidiaries of RCI can be distributed to the Company without imposition of either U.K. or local country tax.
As of December 31, 2013, unremitted earnings of RCI’s non-U.S. subsidiaries were approximately $419 million. Should the non-U.S. subsidiaries of RCI make a distribution from these earnings, we may be subject to additional U.S. income taxes. It is not practicable to estimate the amount of deferred tax liability related to the undistributed earnings, and RCI's non-U.S. subsidiaries have no plan to distribute earnings in a manner that would cause them to be subject to U.S., U.K. or other local country taxation.
At December 31, 2013, RCI’s non-U.S. subsidiaries held approximately $374 million of the $1.1 billion of consolidated cash and cash equivalents. The Company has significant net assets, liquidity, contract backlog and/or other financial resources available to meet its operational and capital investment requirements and otherwise allow us to continue to maintain our policy of reinvesting such undistributed earnings outside the U.K. and U.S. indefinitely.
Investing Activities
In January 2014, the Company took delivery of the first of four newly constructed drillships, the Rowan Renaissance, which is expected to commence drilling operations offshore West Africa under a three-year contract beginning in April 2014 at an effective day rate of $619,000. The Company's three remaining ultra-deepwater drillships under construction, the Rowan Resolute, Rowan Reliance, and Rowan Relentless, are scheduled for delivery in June 2014, October 2014, and March 2015, respectively. Reference should be made to Note 7 of Notes to Consolidated Financial Statements in this Form 10-K for the status of our newbuild rig projects.
Capital expenditures in 2013 totaled $607 million and included the following:
•
$229 million towards construction of the ultra-deepwater drillships Rowan Renaissance, Rowan Resolute, Rowan Reliance and Rowan Relentless;
•
$323 million for improvements to the existing fleet, including contractually required modifications; and
•
$55 million for rig equipment inventory and other.
We currently estimate our 2014 capital expenditures to be approximately $2.1 billion, including $1.7 billion towards construction of our four ultra-deepwater drillships and related costs, including mobilization, commissioning, and capital expenditures for riser gas-handling equipment, software certifications and drillship fleet spares in support of deepwater operations; $254 million for life enhancement projects and existing fleet maintenance capital; $61 million for partially reimbursed contractually required modifications to the fleet; and $67 million for jack-up equipment spares, drill pipe and improvements to our shore bases.
The capital budget reflects an appropriation of money that we may or may not spend, and the timing of such expenditures may change. We will periodically review and adjust the capital budget as necessary based upon current and forecast cash flows and liquidity, anticipated market conditions in our business, the availability of financial resources, and alternative uses of capital to enhance shareholder value.
We expect to fund the three drillships currently under construction and other capital expenditures from available cash, cash flows from operations, and our revolving credit facility, if necessary.
Capital expenditures for 2012 totaled $685 million and included $287 million towards construction of the Rowan Renaissance, Rowan Resolute, Rowan Reliance and Rowan Relentless; $350 million for improvements to the existing fleet, including contractually required modifications; and $48 million for rig equipment, inventory and other.
Capital expenditures for 2011 totaled $1.5 billion and included $539 million towards completion of our two N-Class rigs, the Rowan Stavanger and Rowan Norway; $456 million towards construction the Rowan Renaissance, Rowan Resolute, and Rowan Reliance; $296 million for improvements to the existing fleet, including contractually required modifications; $89 million towards completion of the 240C-class rig, Joe Douglas; $94 million towards completion of the EXL IV, and $44 million for manufacturing, drilling and equipment spares, drill pipe and other.
In 2011 we completed the sales of our manufacturing and land drilling businesses for approximately $1.042 billion and $514 million, respectively. We used the proceeds from the sales in our rig construction program.
Financing Activities
In 2012, we completed the issuance and sale in public offerings of $700 million aggregate principal amount of 4.875% Senior Notes due 2022, and $400 million aggregate principal amount of 5.4% Senior Notes due 2042. Net proceeds of the offerings were approximately $1.104 billion, which were used in part for the Company's rig construction program and the redemption of outstanding debt.
As of December 31, 2013, we had $2.0 billion of outstanding long-term debt consisting of $400 million principal amount of 5% Senior Notes due 2017; $500 million principal amount of 7.875% Senior Notes due 2019; $700 million principal amount of 4.875% Senior Notes due 2022; and $400 million principal amount of 5.4% Senior Notes due 2042 (together, the “Senior Notes”). The Senior Notes are fully and unconditionally guaranteed on a senior and unsecured basis by Rowan plc (see Note 15 of Notes to Financial Statements).
On January 15, 2014, we completed the issuance and sale in a public offering of $400 million aggregate principal amount of 4.75% Senior Notes due 2024, and $400 million aggregate principal amount of 5.85% Senior Notes due 2044. Net proceeds of the offering were approximately $792 million, which the Company intends to use in its rig construction program and for general corporate purposes.
Annual interest payments on the Senior Notes, including the January 2014 offering, total $160 million. No principal payments are required until each series’ final maturity date. Management believes that cash flows from operating activities and existing cash balances will be sufficient to satisfy all of the Company’s cash requirements for the following 12 months.
On January 23, 2014, the Company amended and restated its credit agreement to increase the borrowing capacity under the revolving credit facility from $750 million to $1.0 billion, among other things. There were no amounts drawn under the revolving credit facility at December 31, 2013.
Restrictive provisions in the Company’s debt agreements require the Company to maintain a minimum level of shareholders’ equity equal to no less than the 67% of the book value of outstanding debt.
Our debt agreements contain provisions that limit the amount of long-term debt, 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. Additionally, the revolving credit
facility agreement provides that the facility will not be available in the event of a material adverse change in the Company’s condition, operations, business, assets, liabilities or ability to perform. The Company was in compliance with its debt covenants at December 31, 2013, and expects to remain in compliance throughout 2014.
Cash Dividends
On January 31, 2014, the Board of Directors approved a quarterly cash dividend policy, with the first dividend expected to be paid in the second quarter of 2014. The Board anticipates the initial quarterly cash dividend will be $0.10 per share.
Off-balance Sheet Arrangements and Contractual Obligations
The Company had no off-balance sheet arrangements as of December 31, 2013 or 2012, 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, 2013, adjusted to include the January 2014 debt offering, and includes obligations recognized on our balance sheet and those not required to be recognized (in millions):
We periodically employ letters of credit or other bank-issued guarantees in the normal course of our businesses, and had outstanding letters of credit of approximately $27.2 million at December 31, 2013.
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, 2013, our financial statements reflected an aggregate unfunded pension liability of $137 million. We expect to make minimum contributions to our defined benefit pension plans of approximately $46 million in 2014, and we will continue to make significant pension contributions over the next several years. Additional funding may be required if pension asset values decline.
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 of “Notes to Consolidated Financial Statements” in Item 8 of this 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 revenues and expenses during the reporting period. We believe that our most critical accounting policies and management estimates involve carrying values of long-lived assets, 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.
Impairment of long-lived assets
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, day rates and utilization, among others. The offshore drilling industry has historically been highly cyclical and it is not unusual for rigs to be unutilized or underutilized 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 individual rigs, groups of rigs, such as a specific type of drilling rig, 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 of our drilling rigs. 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 and expectations regarding future industry conditions and operations would likely result in materially different asset carrying values and operating results.
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, 2013, included weighted average discount rates of 4.58% and 4.16% used to determine pension benefit obligations and net cost, respectively, an expected long-term rate of return on pension plan assets of 8% and annual healthcare cost increases ranging from 7.3% in 2014 to 4.5% in 2026 and beyond. 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 $100.2 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 $4.8 million. A one-percentage-point increase in the assumed healthcare cost trend rate would increase 2014 other postretirement benefit cost by $0.3 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 maintained at 8% at December 31, 2013, unchanged from December 31, 2012.
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 a reserve, if any. Our income tax returns are subject to audit by U.S. federal, state, and foreign tax authorities. 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 $82 million at December 31, 2013, is properly recorded in accordance with the accounting guidelines.
Recent Accounting Pronouncements
In July 2013 the Financial Accounting Standards Board issued Accounting Standards Update No. 2013-11, which requires an unrecognized tax benefit to be presented in the financial statements as a reduction to a deferred tax asset for a net operating loss carryforward, a similar tax loss or a tax credit carryforward if net settlement is required or expected. We will be required to adopt the new standard effective January 1, 2014. We are evaluating the potential effect of this accounting standard update; however, we do not expect that our adoption will have a material effect on our financial statements.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS
Our outstanding debt at December 31, 2013, consisted entirely of fixed-rate debt with a carrying value of $2.009 billion and a weighted-average annual interest rate of 5.7%. Due to the fixed-rate nature of our debt, management believes the risk of loss due to changes in market interest rates is not material.
The majority of our transactions are denominated in U.S. dollars, although a significant volume of transactions are conducted in British pounds. In order to reduce the impact of exchange rate fluctuations, we generally require customer payments to be in U.S. dollars and generally limit local currency holdings to the extent they are needed to pay liabilities denominated in local currencies. In certain countries in which we operate such as Egypt, local laws or contracts may require us to receive payment for a portion of the contract in the local currency. In such instances, we may hold a greater amount of local currency than would otherwise be the case.
Fluctuating commodity prices affect our future earnings materially to the extent that they influence demand for our products and services. As a general practice, we do not hold or issue derivative financial instruments and had no derivatives outstanding during the periods covered by this report.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders of
Rowan Companies plc
Houston, Texas
We have audited the accompanying consolidated balance sheets of Rowan Companies plc and subsidiaries (the "Company") as of December 31, 2013 and 2012, and the related consolidated statements of income, comprehensive income, changes in shareholders' equity, and cash flows for each of the three years in the period ended December 31, 2013. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Rowan Companies plc and subsidiaries at December 31, 2013 and 2012, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2013, in conformity with accounting principles generally accepted in the United States of America.
As discussed in Note 3 to the consolidated financial statements, on June 22, 2011, and September 1, 2011, the Company completed the sale of its wholly owned manufacturing subsidiary, LeTourneau Technologies, Inc., and land drilling services business, respectively.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company's internal control over financial reporting as of December 31, 2013, based on the criteria established in Internal Control-Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 3, 2014, expressed an unqualified opinion on the Company's internal control over financial reporting.
/s/ DELOITTE & TOUCHE LLP
Houston, Texas
March 3, 2014
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 (1992), 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, 2013.
The registered public accounting firm Deloitte & Touche LLP has audited Rowan’s consolidated financial statements included in our 2013 Annual Report on Form 10-K and has issued an attestation report on the Company’s internal control over financial reporting.
/s/ W. MATT RALLS
/s/ J. KEVIN BARTOL
W. Matt Ralls
J. Kevin Bartol
Chief Executive Officer
Executive Vice President, Chief Financial Officer and Treasurer
March 3, 2014
March 3, 2014
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders of
Rowan Companies plc
Houston, Texas
We have audited the internal control over financial reporting of Rowan Companies plc and subsidiaries (the "Company") as of December 31, 2013, based on criteria established in Internal Control - Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission. 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 Pursuant to Section 404 of the Sarbanes-Oxley Act of 2002. Our responsibility is to express an opinion on the Company's internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). 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.
A company's internal control over financial reporting is a process designed by, or under the supervision of, the company's principal executive and principal financial officers, or persons performing similar functions, and effected by the company's board of directors, management, and other personnel 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 the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2013, based on the criteria established in Internal Control - Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements as of and for the year ended December 31, 2013 of the Company and our report dated March 3, 2014, expressed an unqualified opinion on those financial statements.
/s/ DELOITTE & TOUCHE LLP
Houston, Texas
March 3, 2014
ROWAN COMPANIES PLC
CONSOLIDATED BALANCE SHEETS
See Notes to Consolidated Financial Statements.
ROWAN COMPANIES PLC
CONSOLIDATED STATEMENTS OF INCOME
See Notes to Consolidated Financial Statements.
ROWAN COMPANIES PLC
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
See Notes to Consolidated Financial Statements.
ROWAN COMPANIES PLC
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY
See Notes to Consolidated Financial Statements.
ROWAN COMPANIES PLC
CONSOLIDATED STATEMENTS OF CASH FLOWS
See Notes to Consolidated Financial Statements.
NOTE 1 - NATURE OF OPERATIONS AND BASIS OF PRESENTATION
On May 4, 2012, Rowan Companies plc, a public limited company incorporated under the laws of England and Wales (Rowan plc), became the successor issuer to Rowan Companies, Inc. (RCI) pursuant to an agreement and plan of merger and reorganization (the “redomestication”) approved by the stockholders of RCI on April 16, 2012. As a result of the redomestication, Rowan plc became the parent company of the Rowan group of companies, and our place of incorporation was effectively changed from Delaware to the United Kingdom. The redomestication was accounted for as an internal reorganization of entities under common control; accordingly, the carrying values of assets and liabilities of the merged entities were carried forward without adjustment. Unless the context otherwise requires, the terms “Rowan,” “Company,” “we,” “us” and “our” are used to refer to Rowan plc (or RCI for periods prior to the redomestication) and its consolidated subsidiaries.
We are a global provider of offshore oil and gas contract drilling services utilizing a fleet of 30 self-elevating mobile offshore “jack-up” drilling units and four ultra-deepwater drillships, three of which are currently under construction. Historically, our primary focus is on high-specification and premium jack-up rigs, which our customers use for exploratory and development drilling and associated drilling services. In recent years the trend in offshore exploration has shifted to drilling in deeper waters of up to 12,000 feet. Beginning in 2009, we determined the best prospects for future growth lie in the ultra-deepwater market, and as a result, in 2011 and 2012 we entered into contracts for the construction of four ultra-deepwater drillships. In January 2014, the Company took delivery of the first of these drillships, the Rowan Renaissance, which is expected to commence operations under a three-year contract in April 2014. The Rowan Resolute is scheduled for delivery in June 2014 and is expected to commence operations under a three-year contract in late September 2014. The Rowan Reliance is scheduled for delivery in October 2014 and expected to commence operations under a three-year contract in late January 2015, and the Rowan Relentless is scheduled for delivery in March 2015 and is not yet under contract.
The Company conducts offshore drilling operations in various markets throughout the world including the U.K. and Norwegian sectors of the North Sea, the Middle East, the United States Gulf of Mexico (US GOM), Southeast Asia, West Africa, Trinidad and Egypt.
The consolidated financial statements included herein include the accounts of Rowan plc and its subsidiaries, all of which are wholly owned. 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, 2013 or 2012. The audit of the statutory accounts for the year ended December 31, 2013, was not complete as of March 3, 2014. These accounts will be finalized by the directors on the basis of the financial information presented herein and will be delivered to the Registrar of Companies in the U.K. following the Company’s annual general meeting of shareholders.
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 revenues and expenses during the reporting period. Actual results could differ from those estimates.
Revenue and Expense Recognition
Our drilling contracts generally provide for payment on a daily rate basis, and revenues are recognized as the work progresses with the passage of time. We frequently receive 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 acquired 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. Revenues received but unearned are included in current and long-term liabilities and totaled $81.8 million and $78.8 million at December 31, 2013 and 2012, respectively. Deferred contract costs are included in prepaid expenses and other assets and totaled $19.8 million and $41.5 million at December 31, 2013 and 2012, respectively.
We recognize 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. We recognize reimbursable costs on the gross basis, as both revenues and expenses, because we are the primary obligor in the arrangement, have discretion in supplier selection, are involved in determining product or service specifications and assume 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 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. The allowance is based on historical and other factors that predict collectability, including write-offs, recoveries and the monitoring of credit quality. No allowance for doubtful accounts was required at December 31, 2013 or 2012.
The following table sets forth the components of Receivables - trade and other at December 31 (in thousands):
Property and Depreciation
We provide 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 capitalizes a portion of interest cost incurred during the construction period. We capitalized interest in the amount of $48.7 million in 2013, $33.4 million in 2012 and $54.5 million in 2011.
Expenditures for maintenance and repairs are charged to operations as incurred. Repairs and maintenance expense attributable to continuing operations totaled $151.6 million in 2013, $132.2 million in 2012 and $97.6 million in 2011.
Impairment of Long-lived Assets
We review 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, we determine recoverability by evaluating the undiscounted estimated future net cash flows based on projected day rates, operating costs and utilization of the asset under review. When the impairment of an asset is indicated, we measure the amount of impairment as the amount by which the asset’s carrying amount exceeds its estimated fair value. We measure fair value by estimating discounted future net cash flows under various operating scenarios (an income approach) and by determining an estimated exchange price that would be received for the asset in an orderly transaction between two market participants based on historical sale prices of similar equipment (a market approach) and by assigning probabilities to each scenario in order to determine an expected value. The lowest level of inputs we use 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, we measure fair value based on equipment broker quotes, less anticipated selling costs, which are considered Level 3 inputs in the fair value hierarchy.
In 2013 we recognized a $4.5 million impairment charge for a maintenance and storage facility, which had a carrying value $23.5 million prior to the write-down. In 2012 we recognized a $5.2 million impairment charge for the Rowan Juneau, which had a carrying value of $18.7 million prior to the write-down. Such amounts are included in material charges and other operating expenses on the Consolidated Statements of Income. The Rowan Juneau last worked in 2009, and we concluded it was unlikely we would secure a contract to operate the rig profitably without substantial improvements. No impairment charges for long-lived assets held and used in the business were required in 2011.
In 2011 the Company recognized an $8.0 million impairment charge for a land rig that was retained by the Company in connection with the sale of its manufacturing operations. In 2012 we recognized an additional $3.9 million impairment charge for the rig, which had a carrying value of $26.9 million prior to the write-down. Such amounts are classified as discontinued operations in the Consolidated Statements of Income. In February 2014 we sold the rig for approximately $26 million, resulting in a gain of approximately $2 million.
Foreign Currency Transactions
The U.S. dollar is the functional currency for all of our operations. Non-U.S. dollar transaction gains and losses are recognized in “other income” on the Consolidated Statements of Income. Our primary exposure to currency exchange is the British pound. In order to reduce the impact of exchange rate fluctuations, we generally require customer payments to be in U.S. dollars and generally limit local currency holdings to the extent they are needed to pay liabilities denominated in local currencies. In certain countries in which we operate however such as Egypt, local laws or contracts may require us to receive payment for a portion of the contract in the local currency. In such instances, we may hold a greater amount of local currency than would otherwise be the case. The Company recognized a net currency exchange loss of $2.3 million in 2013, a net exchange gain of $0.5 million in 2012 and a net exchange loss of $0.8 million in 2011.
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. Income tax related interest and penalties are included in other income and expense.
The Company does not provide deferred income taxes on undistributed earnings of its non-U.K. subsidiaries, including RCI’s non-U.S. subsidiaries. It is the Company’s policy and intention to permanently reinvest earnings of non-U.S. subsidiaries of RCI outside the U.S. Should the non-U.S. subsidiaries of RCI make a distribution from these earnings, we may be subject to additional U.S. income taxes. Generally, earnings of non-U.K. subsidiaries that are not subsidiaries of RCI can be distributed to the Company without the imposition of either U.K. or local country tax. See Note 11 for further information regarding the Company’s income taxes.
Income Per Common Share
Basic income per share is computed by dividing income available to common shareholders by the weighted-average number of common shares outstanding during the period. Diluted income per share includes the additional effect of all potentially dilutive securities, which includes nonvested restricted stock and units and dilutive stock options and appreciation rights granted under share-based compensation plans.
A reconciliation of shares for basic and diluted income per share is set forth below. There were no income adjustments to the numerators of the basic or diluted computations for the periods presented (in thousands):
Share options and appreciation rights are antidilutive and excluded from diluted earnings per share when their exercise or strike price exceeds the average market price during the period. The following table sets forth antidilutive shares excluded from diluted earnings per share. Such securities could potentially dilute earnings per share in the future (in thousands):
Recent Accounting Pronouncements
In July 2013 the Financial Accounting Standards Board issued Accounting Standards Update No. 2013-11, which requires an unrecognized tax benefit to be presented in the financial statements as a reduction to a deferred tax asset for a net operating loss carryforward, a similar tax loss or a tax credit carryforward if net settlement is required or expected. We will be required to adopt the new standard effective January 1, 2014. We are evaluating the potential effect of this accounting standard update; however, we do not expect that our adoption will have a material effect on our financial statements.
NOTE 3 - DISCONTINUED OPERATIONS
In 2011 the Company completed the sales of its manufacturing and land drilling operations. Discontinued operations for 2012 included a $3.9 million asset impairment charge on a land rig that the Company retained in the sale of the land drilling operations and sold in February 2014, write-offs of receivables assumed, a working capital adjustment to the sale price of the land drilling business, and a prior year return-to-provision tax adjustment, among other items. The following table sets forth the components of “Discontinued operations, net of tax” (in thousands):
NOTE 4 - ACCRUED LIABILITIES
Accrued liabilities at December 31 consisted of the following (in thousands):
NOTE 5 - LONG-TERM DEBT
Long-term debt at December 31 consisted of the following (in thousands):
As of December 31, 2013, no principal payments are required with respect to our outstanding debt through 2016; $400 million becomes due in September 2017.
The 4.875% Notes and the 5.4% 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 existing and future senior indebtedness, including its 5% Senior Notes due 2017, 7.875% Senior Notes due 2019, and any indebtedness under RCI’s senior revolving credit facility. The 4.875% Notes and the 5.4% 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 4.875% Notes and 5.4% 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. There will be no make-whole premium applicable to the redemption of the 4.875% Notes on or after March 1, 2022, or applicable to redemption of the 5.4% Notes on or after June 1, 2042.
The 5% Senior Notes due 2017, 7.875% Senior Notes due 2019, 4.875% Senior Notes due 2022, and 5.4% Senior Notes due 2042 (together, the “Senior Notes”) are fully and unconditionally guaranteed on a senior and unsecured basis by Rowan plc (see Note 15).
On January 15, 2014, Rowan plc, as guarantor, and its 100% owned subsidiary, RCI, as issuer, completed the issuance and sale in a public offering of $400 million aggregate principal amount of its 4.75% Senior Notes due 2024 at a price to the public of 99.898% of the principal amount and $400 million aggregate principal amount of its 5.85% Senior Notes due 2044 at a price to the public of 99.972% of the principal amount. Net proceeds of the offering were approximately $792 million, which the Company intends to use in its rig construction program and for general corporate purposes.
On January 23, 2014, the Company amended and restated its credit agreement to increase the borrowing capacity under the revolving credit facility from $750 million to $1.0 billion, among other things. There were no amounts drawn under the revolving credit facility at December 31, 2013.
Restrictive provisions in the Company’s debt agreements require the Company to maintain a minimum level of shareholders’ equity equal to no less than the 67% of the book value of outstanding debt.
Our debt agreements contain provisions that limit the amount of long-term debt, 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. Additionally, the revolving credit facility agreement provides that the facility will not be available in the event of a material adverse change in the Company’s condition, operations, business, assets, liabilities or ability to perform. The Company was in compliance with its debt covenants at December 31, 2013.
NOTE 6 - FINANCIAL INSTRUMENTS
Fair Values of Financial Instruments
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
•
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.
A financial instrument’s level within the fair value hierarchy is based on the lowest level of any input that is significant to the fair value measurement.
Certain of our assets and liabilities are required to be measured at fair value on a recurring basis. Assets and liabilities measured at fair value are summarized below (in thousands):
Trade receivables and trade payables, which are also required to be measured at fair value, have carrying values that approximate their fair values due to their short maturities.
Those financial instruments not required to be measured at fair value consist of the Company’s publicly traded debt securities. Fair values of the Company’s debt securities were provided by one to two brokers who make a market in our debt securities and were measured using a market-approach valuation technique. Fair value was determined by adding a spread based on actual trades for that security (or a trader quote where actual trades were unavailable) to the applicable benchmark Treasury security with a comparable maturity in order to derive a current yield. The yield is then used to determine a price given the individual security’s coupon rate and maturity. Such inputs are considered “significant other observable inputs,” which are categorized as Level 2 inputs in the fair value hierarchy. Estimated fair values and related carrying values of our long-term debt securities at December 31 are presented below (in thousands):
Concentrations of Credit Risk
We invest our excess cash primarily in time deposits and high-quality money market accounts at several large commercial banks with strong credit ratings, and therefore believe that our risk of loss is minimal.
The Company’s customers largely consist of international oil and gas exploration companies and national oil companies. We routinely evaluate the credit quality of potential customers. In 2013, one customer accounted for 26% and another accounted for 11% of consolidated revenues. In 2012, one customer accounted for 29% and another accounted for 11% of consolidated revenues. In 2011, three customers accounted for 29%, 21%, and 11% of consolidated revenues, respectively. The Company maintains reserves for credit losses when necessary and actual losses have been within management’s expectations.
NOTE 7 - 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 $9.3 million in 2013, $8.0 million in 2012 and $5.6 million in 2011.
At December 31, 2013, future minimum payments to be made under noncancelable operating leases were as follows (in thousands):
The following table presents the status of the Company’s rigs under construction as of December 31, 2013. Project costs include capitalized interest (in millions):
In addition, the Company expects to incur approximately $205 million of capital expenditures in 2014 for mobilization, commissioning, riser gas-handling equipment, software certifications and drillship fleet spares to support its deepwater operations.
We have commitments for other purchase obligations totaling $190 million at December 31, 2013.
We periodically employ letters of credit in the normal course of our business, and had outstanding letters of credit of approximately $27.2 million at December 31, 2013.
Uncertain tax positions - In 2009 the Company recognized a $25.4 million tax benefit as a result of applying the facts of a third-party tax case to the Company’s situation. That case provided a more favorable tax treatment for certain foreign contracts entered into in prior years. This position is currently under audit and has been challenged by IRS field agents. We have appealed their findings and expect to come to a conclusion within the next twelve months. We plan to vigorously defend our position and continue to believe that we will more likely than not prevail (see Note 11).
Asbestos related claims - We are from time to time a party to various lawsuits filed by current or former employees that are incidental to our operations in which the claimants seek unspecified amounts of monetary damages for personal injury, including
injuries purportedly resulting from exposure to asbestos on our drilling rigs. At December 31, 2013, there were approximately 27 asbestos related lawsuits in which we are one of many defendants. These lawsuits have been filed in the state courts of Louisiana, Mississippi and Texas. We intend to vigorously defend against the litigation. We are unable to predict the ultimate outcome of these lawsuits; however, we do not believe the ultimate resolution of these matters will have a material adverse effect on our financial position, results of operations or cash flows.
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.
NOTE 8 - SHARE-BASED COMPENSATION PLANS
Under the 2013 Rowan Companies plc Incentive Plan (the Plan), the Compensation Committee of the Company’s Board of Directors is authorized to grant employees and nonemployee directors incentive awards covering up to 7,500,000 of our ordinary shares. The awards may be in the form of restricted share awards, restricted share units, options and share appreciation rights. In addition, the Compensation Committee may grant performance-based awards under the Plan, in which the amount earned is dependent on the achievement of certain long-term market or performance conditions over a specified period. As of December 31, 2013, there were 7,298,333 shares available for future grant under the Plan.
Restricted shares and restricted share units, share appreciation rights and options granted generally have multiple vesting dates. The Company recognizes compensation cost for share-based awards on a straight-line basis over the requisite service period for the entire award. Compensation cost charged to expense under all share-based incentive awards is presented below (in thousands):
As of December 31, 2013, unrecognized compensation cost related to nonvested share-based compensation arrangements totaled $29.7 million, which is expected to be recognized over a weighted-average period of 1.7 years.
Restricted Shares - A restricted share represents an ordinary share subject to a vesting period that restricts its sale or transfer until the vesting period ends. In general, the restricted shares vest and the restrictions lapse in one-third increments each year over a three-year service period, or in some cases, cliff vest at the end of a three-year service period. The Company measures compensation based on the market price of the shares on the date of grant. Restricted share activity for the year ended December 31, 2013, is summarized below:
The aggregate fair value of restricted shares that vested in 2013, 2012 and 2011 was $16.2 million, $17.8 million and $17.5 million, respectively, based on share prices on the vesting dates.
Employee Restricted Share Units - 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. The Company measures compensation based on the market price of the underlying shares on the grant date. Employee RSU activity for the year ended December 31, 2013, follows:
The aggregate fair value of employee RSUs that vested in 2013 was $0.5 million. The aggregate fair value of employee RSUs that vested in 2012 was not material.
Non-employee Director Restricted Share Units - RSUs granted to nonemployee directors generally cliff vest at the earlier of the first anniversary of the grant date or the next annual meeting of shareholders following the grant date and are settled in either cash or shares at the discretion of the Compensation Committee determined at the time the director terminates service to the Board. The Company accounts for RSUs granted to non-employee directors under the liability method of accounting. Compensation is recognized over the service period initially based on the market price of the underlying shares on the grant date and is adjusted for changes in market value through the settlement date. Non-employee director RSU activity for the year ended December 31, 2013, follows:
In 2013, the Company settled 23,928 non-employee director RSUs with a settlement date fair value of $0.8 million. In 2012, the Company settled 43,072 non-employee director RSU's with a settlement date fair value of $1.4 million. No RSUs were settled in 2011. Other liabilities included $8.1 million and $5.8 million at December 31, 2013 and 2012, respectively, for non-employee director RSUs.
Performance-based Awards - The 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.
In March 2013 the Company granted to certain members of management performance units (P-Units) that have a target value of $100 per unit. The amount ultimately earned with respect to the P-Units will depend on the Company’s total shareholder return (TSR) ranking compared to a group of peer companies over a three-year period ending December 31, 2015, and 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, 2013, 2014, and 2015, respectively, and 25% of the P-Units’ value is determined by the relative TSR ranking for the three-year period ended December 31, 2015. Vesting of awards and any payment with respect to the P-Units would not occur until 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 Compensation Committee. The Compensation Committee has determined that any amount earned with respect to P-Units granted in 2013 would be settled in cash.
The grant-date fair value of P-Units granted in 2013 was estimated to be $5.8 million. 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 vesting date. In the event there is no payout of the P-Units for any 25% tranche as a result of a failure to meet the performance thresholds, any previously recognized expense relating to that tranche would be reversed at the end of the tranche’s performance period. Other liabilities included $4.5 million and $0.7 million at December 31, 2013, and 2012, respectively, for estimated P-Unit obligations.
No performance-based awards vested in 2013 or 2012. The aggregate fair value of performance-based share awards granted in prior years that vested in 2011 was $2.3 million.
Share Appreciation Rights - 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 settle any exercises of SARs in shares and has therefore accounted for SARs as equity awards.
Fair values of SARs granted were determined using the Black-Scholes option pricing model with the following weighted-average assumptions:
The Company uses the simplified method for determining the expected life of SARs because the Company does not have sufficient historical exercise data to provide a reasonable basis upon which to estimate expected term, as permitted under US GAAP.
SARs activity for the year ended December 31, 2013, is summarized below:
The aggregate intrinsic value of SARs exercised in 2013 was $0.5 million. The aggregate intrinsic value of SARs exercised in 2012 was $0.4 million. No SARs were exercised in 2011.
Share Options - Share options granted to employees generally became exercisable in one-third or one-quarter annual increments over a three or four-year service period at a price generally equal to the market price of the Company’s common shares on the date of grant. The Company has not granted any share options since 2008. Unexercised options expire ten years after the grant date.
Share option activity for the year ended December 31, 2013, is summarized below:
The aggregate intrinsic value of options exercised was $2.0 million in 2013, $0.3 million in 2012 and $15.9 million in 2011.
Award modifications - In 2012 the Company accelerated the vesting of share-based awards and P-Units and extended the exercise period for vested options held by a retiring employee whose awards would otherwise have been forfeited upon retirement. As a result of the modification, the Company recognized additional compensation expense in 2012 in the amount of $2.3 million, which is classified within material charges and other operating expenses in the Consolidated Statements of Income. The Company valued the modified options assuming they are to be outstanding near or until such time as they expire.
In 2011 the Company accelerated the vesting of nonvested awards upon an employee's termination of employment. As a result of the modification, the Company recognized additional compensation expense totaling $2.0 million.
NOTE 9 - 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 Restoration Plan of Rowan Companies, Inc. (the “Rowan SERP”), and health care and life insurance benefits are provided under the Retiree Life & Medical Supplemental Plan of Rowan Companies, Inc.
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 thousands):
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 thousands):
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 2014 (in thousands):
In 2012 a pension plan that was assumed by the Company in connection with the sale of its former manufacturing operations made lump sum payments totaling $19.0, which exceeded the threshold that required the recognition of a settlement loss in the amount of $8.7 million. Such amount is classified within material charges and other operating expenses on the Consolidated Statements of Income.
In 2011 the Company recognized a pension curtailment gain of $12.0 million in connection with the sale of its land drilling division. Such gain was recognized in net periodic pension cost and classified within discontinued operations.
The components of net periodic pension cost and the weighted-average assumptions used to determine net cost were as follows (dollars in thousands):
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 thousands):
The assumed health care cost trend rates used to measure the expected cost of retirement health benefits was 7.3% for 2014, gradually decreasing to 4.5% for 2026 and thereafter. A one-percentage-point change in the assumed health care cost trend rates would change the reported amounts as follows (in thousands):
The pension plans’ investment objectives for fund assets are: to achieve over the life of the plans a return equal 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, 2013 and 2012, 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 thousands):
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. Assets in the “other” category were held through a commingled fund that invested in hedge funds. (This investment was liquidated on December 31, 2013. The proceeds from the liquidation were included in cash and cash equivalents at that date and were reinvested in January 2014 according to target allocations.)
The following is a description of the valuation methodologies used for the pension plan assets at December 31, 2013:
•
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.
The following is a description of the valuation methodologies used for the pension plan assets at December 31, 2012:
•
Fair values of mutual fund investments in U.S. equity securities, core plus fixed income securities and cash and equivalents categorized as Level 1 were based on quoted market prices which represent the net asset value of shares held.
•
Fair values of small cap U.S. equity securities categorized in Level 1 are primarily based on quoted market prices.
•
Fair values of 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.
•
The assets categorized as Level 3 within the other category were held through a commingled fund that invested in hedge funds. The hedge fund of funds was not actively traded. The fair value disclosed represents the fair value as determined by the hedge fund manager.
Set forth below is a summary of the changes in Level 3 plan assets (in thousands):
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 maintained at 8% at December 31, 2013, unchanged from December 31, 2012.
The Company currently expects to contribute approximately $46 million to its pension plans in 2014 and to directly pay other postretirement benefits of approximately $4 million, net of estimated Medicare subsidy receipts.
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 thousands):
The Company sponsors defined contribution plans covering substantially all employees. Employer contributions to such plans are expensed as incurred and totaled $14.3 million in 2013, $9.6 million in 2012 and $8.0 million in 2011.
NOTE 10 - SHAREHOLDERS’ EQUITY
Accumulated Other Comprehensive Income
In February 2013, the Financial Accounting Standards Board issued Accounting Standards Update No. 2013-2 (“ASU 2013-2”), Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income. ASU 2013-2 requires entities to disclose, among other items, the changes in accumulated balances for each component of other comprehensive income and current-period reclassifications out of accumulated other comprehensive income. The Company had accumulated other comprehensive losses (AOCL) totaling $142.5 million, $221.1 million, and $225.7 million at December 31, 2013, 2012, and 2011 respectively, all of which were solely attributable to pension and other postretirement benefits. All amounts reclassified from AOCL for the years ended December 31, 2013, 2012, and 2011, were attributable to amortization of pension and postretirement benefit cost and totaled $15.3 million, $19.5 million and ($0.3) million respectively, net of tax (see Note 9).
Share Repurchase Program
On July 25, 2012, the Board of Rowan plc, as successor issuer to RCI, approved the continuation of RCI’s $150 million share repurchase program, of which approximately $25 million remained available. The Company did not acquire any shares under its share repurchase program in 2013. Share repurchases may be commenced or suspended from time to time without prior notice. Any shares acquired under the share repurchase program would be canceled.
NOTE 11 - INCOME TAXES
RCI, our predecessor company, was domiciled in the U.S. and subject to a statutory rate of 35%. As a result of our redomestication to the U.K. we are now subject to the U.K. statutory main rate, which was 24% for the financial year starting April 1, 2012 and 23% for the financial year starting April 1, 2013. The main rate reduces to 21% for the financial year starting April 1, 2014 and 20% for the financial year starting April 1, 2015. We have computed our statutory tax rate for 2013 using a weighted average U.K. rate of 23.3%. Income tax information for 2011 is presented from the perspective of an enterprise domiciled in the U.S.
The significant components of income taxes attributable to continuing operations consisted of (in thousands):
Differences between our provision for income taxes and the amount determined by applying our applicable statutory rate to income before income taxes are set forth below (dollars in thousands):
Temporary differences and carryforwards which gave rise to deferred tax assets and liabilities at December 31 were as follows (in thousands):
At December 31, 2013, the Company had approximately $32.1 million of net operating loss carryforwards (NOLs) in the U.S. expiring in 2028 and 2029; $49.3 million of NOLs in the U.S. attributable to the Company’s foreign subsidiaries expiring in 2032 and which was subject to a valuation allowance of $35.7 million at December 31, 2013; $41.4 million of non-expiring NOLs in the U.K. of which $18.6 million was subject to a valuation allowance; and $51.7 million of non-expiring NOLs in Norway, of which $28.7 million was subject to a valuation allowance. In addition, at December 31, 2013, the Company had $17.0 million of non-expiring NOLs in other foreign jurisdictions, of which $13.9 million was subject to a valuation allowance. During 2013, the Company released a valuation allowance against the other foreign jurisdiction NOLs, which totaled $2.8 million at December 31, 2012. Management has determined that no other valuation allowances were necessary at December 31, 2013, 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 Company has not provided deferred income taxes on undistributed earnings of the Company’s non-U.K. subsidiaries, including RCI’s non-U.S. subsidiaries. It is the Company’s policy and intention to permanently reinvest earnings of non-U.S. subsidiaries of RCI outside the U.S. The earnings of non-U.K. subsidiaries that are not subsidiaries of RCI can be distributed to Rowan plc without the imposition of either U.K. or local country tax.
As of December 31, 2013, unremitted earnings of RCI’s non-U.S. subsidiaries were approximately $419 million. Should the non-U.S. subsidiaries of RCI make a distribution from these earnings, we may be subject to additional U.S. income taxes. It is not practicable to estimate the amount of deferred tax liability related to the undistributed earnings, and RCI's non-U.S. subsidiaries have no plan to distribute earnings in a manner that would cause them to be subject to U.S., U.K., or other local country taxation.
At December 31, 2013, 2012 and 2011, we had approximately $82 million, $59 million and $55 million, respectively, of net unrecognized tax benefits attributable to continuing operations, all of which would reduce the Company’s income tax provision if recognized. The Company’s unrecognized tax benefits largely include U.S. tax return issues for periods 2006 - 2008 regarding the application of a third party tax case to Rowan’s tax returns as mentioned below. As a result of the anticipated settling of these claims, the Company believes that is reasonably possible that a decrease of up to $64 million may be necessary within the next twelve months.
The following table sets forth the changes in the Company’s gross unrecognized tax benefits during the years ended December 31 (in thousands):
Interest and penalties relating to income taxes are included in other income and expense. At December 31, 2013, 2012 and 2011, accrued interest was $2.4 million, $2.5 million and $2.1 million, respectively, and accrued penalties were $1.7 million, $1.4 million and $1.1 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’s U.S. federal tax returns for 2006 through 2011 are currently under audit by the Internal Revenue Service (“IRS”), and 2002 and later years remain subject to examination. Various state tax returns for 2005 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. We are undergoing other routine tax examinations in various U.S. and non-US. 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.
In 2009, the Company recognized a $25.4 million tax benefit as a result of applying the facts of a third-party tax case to the Company’s situation. That case provided a more favorable tax treatment for certain non-U.S. contracts entered into in prior years. This position is currently under audit and has been challenged by IRS field agents. We have appealed their findings and expect to come to a conclusion within the next twelve months. The Company plans to vigorously defend its position and continues to believe it is more likely than not that the Company will prevail. The Company has deferred recognition of a remaining $49.2 million estimated benefit in accordance with the accounting guidelines for income tax uncertainties. As of December 31, 2013, the Company had recognized a $46.6 million long-term receivable, which is included in other assets on the Consolidated Balance Sheet, and a long-term liability of approximately $48.8 million, in connection with its tax position.
The components of income (loss) from continuing operations before income taxes were as follows (in thousands):
NOTE 12 - GEOGRAPHIC AREA INFORMATION
The classifications of revenues 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 revenues are earned, and may vary from one period to the next.
Revenues by geographic area are set forth below (in thousands):
Long-lived assets by geographic area at December 31 are set forth below (in thousands):
NOTE 13 - MATERIAL CHARGES AND OTHER OPERATING EXPENSES
Operating expenses in 2013 included a $4.5 million noncash impairment charge on a maintenance and storage facility.
Operating expenses in 2012 included $13.8 million of legal and consulting fees incurred in connection with the Company’s redomestication, $12.0 million of repair costs for the EXL I following its collision with a tanker, $8.7 million of pension settlement costs in connection with lump sum pension payments to employees of the Company’s former manufacturing subsidiary, $8.1 million of noncash asset impairment charges, $2.3 million of incremental noncash share-based compensation cost in connection with the retirement of an employee, partially offset by a $4.7 million gain for cash received in connection with the settlement of a 2005 dispute with a customer.
Operating expenses in 2011 included a $6.1 million charge for the settlement of litigation with Textron relating to the loss of the Rowan Halifax in 2005 and $4.9 million of incremental noncash and cash compensation cost in connection with the separation of an employee.
NOTE 14 - SUPPLEMENTAL CASH FLOW INFORMATION
Noncash investing and financing activities excluded from the Consolidated Statements of Cash Flows and other supplemental cash flow information follows (in thousands):
NOTE 15 - 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 5% Senior Notes due 2017, 7.875% Senior Notes due 2019, 4.875% Senior Notes due 2022, and 5.4% Senior Notes due 2042 (the "Senior Notes").
The following condensed consolidating financial information 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.
Rowan Companies plc and Subsidiaries
Condensed Consolidating Balance Sheets
December 31, 2013
(in thousands)
Rowan Companies plc and Subsidiaries
Condensed Consolidating Balance Sheets
December 31, 2012
(in thousands)
Rowan Companies plc and Subsidiaries
Condensed Consolidating Income Statements
Year ended December 31, 2013
(in thousands)
Rowan Companies plc and Subsidiaries
Condensed Consolidating Income Statements
Year ended December 31, 2012
(in thousands)
Rowan Companies plc and Subsidiaries
Condensed Consolidating Income Statements
Year ended December 31, 2011
(in thousands)
Rowan Companies plc and Subsidiaries
Condensed Consolidating Statements of Comprehensive Income
Year ended December 31, 2013
(in thousands)
Rowan Companies plc and Subsidiaries
Condensed Consolidating Statements of Comprehensive Income
Year ended December 31, 2012
(in thousands)
Rowan Companies plc and Subsidiaries
Condensed Consolidating Statements of Comprehensive Income
Year ended December 31, 2011
(in thousands)
Rowan Companies plc and Subsidiaries
Condensed Consolidating Statements of Cash Flows
Year ended December 31, 2013
(in thousands)
Rowan Companies plc and Subsidiaries
Condensed Consolidating Statements of Cash Flows
Year ended December 31, 2012
(in thousands)
Rowan Companies plc and Subsidiaries
Condensed Consolidating Statements of Cash Flows
Year ended December 31, 2011
(in thousands)
SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)
Unaudited quarterly financial data for each full quarter within the two most recent fiscal years follows (in thousands 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 continuing operations in the second and fourth quarters of 2013 include a $19.1 million gain on sale of the Rowan Paris and a $4.5 million noncash asset impairment charge, respectively.
Income from continuing operations in each quarter of 2012 included the following: First quarter - $2.9 million of noncash impairment charges to the carrying value of steel and $1.7 million of legal, consulting and other expenses in connection with the Company’s redomestication; Second quarter - $8.1 million of redomestication expenses; Third quarter - $8.9 million of repair costs for the EXL I, $5.1 million of pension settlement costs, $2.3 million of incremental noncash share-based compensation expense in connection with a retiring employee and $1.9 million of redomestication expenses; Fourth quarter - $5.2 million of noncash asset impairment charges, $3.6 million of pension settlement costs, $3.1 million of repair costs for the EXL I, $2.1 million of redomestication expenses, partially offset by a $4.7 million gain for cash received in connection with the settlement of a 2005 dispute with a customer.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None
ITEM 9A. 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, along with the Company’s Chief Financial Officer, concluded that the Company’s disclosure controls and procedures were effective as of December 31, 2013.
Our management is responsible for establishing and maintaining internal control over financial reporting (ICFR). Our internal control system was designed to provide reasonable assurance to the Company’s management and Board of Directors 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, 2013, within the context of the Internal Control - Integrated Framework (1992) established by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and that the Company did not have a material change in ICFR during the fourth quarter of 2013.
See “Management’s Report on Internal Control over Financial Reporting” included in Item 8 of this Form 10-K.
ITEM 9B. OTHER INFORMATION
Not applicable
PART III
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Information concerning our directors will appear in our proxy statement for the 2014 annual general meeting of shareholders, to be filed pursuant to Regulation 14A of the Exchange Act (Regulation 14A) on or before April 30, 2014, under the caption “Election of Directors.” Such information is incorporated herein by reference.
Information concerning our executive officers appears in Part I under the caption “Executive Officers of the Registrant” of this Form 10-K.
Information concerning our Audit Committee will appear in our proxy statement for the 2014 annual general meeting of shareholders, to be filed pursuant to Regulation 14A on or before April 30, 2014, under the caption “Committees of the Board of Directors.” Such information is incorporated herein by reference.
Information concerning compliance with Section 16(a) of the Securities Exchange Act will appear in our proxy statement for the 2014 annual general meeting of shareholders, to be filed pursuant to Regulation 14A on or before April 30, 2014, under the caption “Additional Information - Section 16(a) Beneficial Ownership Reporting Compliance.” Such information is incorporated herein by reference.
ITEM 11. EXECUTIVE COMPENSATION
Information concerning director and executive compensation will appear in our proxy statement for the 2014 annual general meeting of shareholders, to be filed pursuant to Regulation 14A on or before April 30, 2014, under the captions “Director Compensation and Attendance,” “Compensation Discussion & Analysis,” “Compensation Committee Report,” and “Executive Compensation.” Such information is incorporated herein by reference.
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 2014 annual general meeting of shareholders, to be filed pursuant to Regulation 14A on or before April 30, 2014, under the caption “Security Ownership of Certain Beneficial Owners and Management.” 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, 2013.
(1)
The number of securities to be issued includes (i) 384,643 options and 313,746 shares issuable under outstanding SARs (see note (2) below).
(2)
The weighted-average exercise price in column (b) is based on (i) 384,643 shares under outstanding options with a weighted average exercise price of $24.52 per share, and (ii) 313,746 shares of stock that would be issuable in connection with 1,831,695 stock appreciation rights (SARs) outstanding at December 31, 2013. 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, 2013 closing stock price of $35.36 and a weighted-average exercise price of $30.45 per share.
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 2014 annual general meeting of shareholders, to be filed pursuant to Regulation 14A on or before April 30, 2014, within the section and under the captions “Director Independence” and “Related Party Transactions.” Such information is incorporated herein by reference.
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
Information concerning principal accounting fees and services will appear in our proxy statement for the 2014 annual general meeting of shareholders, to be filed pursuant to Regulation 14A no later than April 30, 2014, in the last paragraph under the caption “Fees of Audit Firm.” Such information is incorporated herein by reference.
PART IV
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a) Index to Financial Statements, Financial Statement Schedules and Exhibits
(1) Financial Statements
See Item 8, “Financial Statements and Supplementary Data,” beginning on page 39 of this Form 10-K for a list of financial statements filed as a part of this report.
(2) Financial Statement Schedules
Financial Statement Schedules I, II, 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.
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.
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.
ROWAN COMPANIES plc
(Registrant)
By: /s/ W. MATT RALLS
W. Matt Ralls
Chief Executive Officer
Date: March 3, 2014
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.
Signature
Title
Date
/s/ W. MATT RALLS
Chief Executive Officer and Director
March 3, 2014
(W. Matt Ralls)
/s/ J. KEVIN BARTOL
Principal Financial Officer
March 3, 2014
(J. Kevin Bartol)
/s/ GREGORY M. HATFIELD
Principal Accounting Officer
March 3, 2014
(Gregory M. Hatfield)
WILLIAM T. FOX III
Director
March 3, 2014
(William T. Fox III)
SIR GRAHAM HEARNE
Director
March 3, 2014
(Sir Graham Hearne)
THOMAS R. HIX
Director
March 3, 2014
(Thomas R. Hix)
H.E. LENTZ
Chairman of the Board
March 3, 2014
(H.E. Lentz)
LORD MOYNIHAN
Director
March 3, 2014
(Lord Moynihan)
SUZANNE P. NIMOCKS
Director
March 3, 2014
(Suzanne P. Nimocks)
P. DEXTER PEACOCK
Director
March 3, 2014
(P. Dexter Peacock)
JOHN J. QUICKE
Director
March 3, 2014
(John J. Quicke)
TORE I. SANDVOLD
Director
March 3, 2014
(Tore I. Sandvold)