10-K 1 rdc-12312016x10k.htm 10-K Document

 
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-K

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ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the year ended December 31, 2016
 
OR
 
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from __________ to __________

Commission File Number: 1-5491

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Rowan Companies plc
 
(Exact name of registrant as specified in its charter)
England and Wales
98-1023315
(State or other jurisdiction of incorporation or organization)
(I.R.S. Employer Identification No.)

2800 Post Oak Boulevard, Suite 5450
Houston, Texas 77056-6189
(Address of principal executive offices)

Registrant’s telephone number, including area code: (713) 621-7800

Securities registered pursuant to Section 12(b) of the Act:
Title of each class
Name of each exchange on which registered
Class A ordinary shares, $0.125 par value
New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.  Yes þ   No ¨

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act.  Yes ¨   No þ

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  Yes þ   No ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  Yes þ   No ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  þ

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company.  See definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.    Large accelerated filer þ    Accelerated filer ¨    Non-accelerated filer ¨   Smaller reporting company ¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).  Yes ¨   No þ

The aggregate market value of common equity held by non-affiliates of the registrant was approximately $2.2 billion as of June 30, 2016, based upon the closing price of the registrant’s ordinary shares on the New York Stock Exchange Composite Tape of $17.66 per share.

The number of Class A ordinary shares, $0.125 par value, outstanding at February 17, 2017, was 125,495,703, which excludes 2,479,014 shares held by an affiliated employee benefit trust.

DOCUMENTS INCORPORATED BY REFERENCE

Document
Part of Form 10-K
Portions of the Proxy Statement for the 2017 Annual General Meeting of Shareholders
Part III, Items 10-14




 
Page 
 
 
 
 
 
 
 
 
 
 




FORWARD-LOOKING STATEMENTS
Statements contained in this report, including in the documents incorporated by reference herein, that are not historical facts are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934.  Forward-looking statements include words or phrases such as “anticipate,” “believe,” “estimate,” “expect,” “intend,” “plan,” “project,” “could,” “may,” “might,” “should,” “will,” “forecast,” “potential,” “outlook,” “scheduled,” “predict,” “will be,” “will continue,” “will likely result,” and similar words and specifically include statements regarding expected financial and operating performance; dividend payments; share repurchases or repayment of debt; business strategies; expected utilization, day rates, revenues, operating expenses, contract terms, contract backlog and fleet status; benefits of our joint venture with Saudi Aramco; capital expenditures; tax rates and positions; impairments; insurance coverages; access to financing and funding sources, including borrowings under our credit facility; the availability, delivery, mobilization, contract commencement, relocation or other movement of rigs and the timing thereof; construction, enhancement, upgrade or repair and costs and timing thereof; the suitability of rigs for future contracts; general market, business and industry conditions, trends and outlook; rig demand; future operations; the impact of increasing regulatory requirements; divestiture of selected assets; expense management; the likely outcome of legal proceedings the impact of competition and consolidation in the industry; the timing of acquisitions, dispositions and other business transactions; customer financial position; and commodity prices. Such statements are subject to numerous risks, uncertainties and assumptions that may cause actual results to vary materially from those indicated, including:
prices of oil and natural gas and industry expectations about future prices and impacts of regional or global financial or economic downturns;
changes in the offshore drilling market, including fluctuations in worldwide rig supply and demand, competition or technology, including as a result of delivery of newbuild drilling units;
variable levels of drilling activity and expenditures in the energy industry, whether as a result of actions by OPEC, global capital markets and liquidity, prices of oil and natural gas or otherwise, which may result in decreased demand and/or cause us to idle or stack, sell or scrap additional rigs;
possible termination, suspension, renegotiation or cancellation of drilling contracts (with or without cause) as a result of general and industry economic conditions, distressed financial condition of our customers, force majeure, mechanical difficulties, delays, labor disturbances, strikes, performance or other reasons; payment or operational delays by our customers; or restructuring or insolvency of significant customers;
changes or delays in actual contract commencement dates, contract option exercises, contract revenues and contract awards;
our ability to enter into, and the terms of, future drilling contracts for drilling units whose contracts are expiring and drilling units currently idled or stacked;
downtime, lost revenue and other risks associated with drilling operations, operating hazards, or rig relocations and transportation, including rig or equipment failure, collisions, damage and other unplanned repairs, the availability of transport vessels, hazards, self-imposed drilling limitations and other delays due to weather conditions, work stoppages or otherwise, and the availability or high cost of insurance coverage for certain offshore perils or associated removal of wreckage or debris and other losses;
regulatory, legislative or permitting requirements affecting drilling operations and other compliance obligations in the areas in which our rigs operate;
tax matters, including our effective tax rates, tax positions, results of audits, tax disputes, changes in tax laws, treaties and regulations, tax assessments and liabilities for taxes;
our ability to realize the expected benefits of our joint venture with Saudi Aramco, and increased risks of concentrated operations in the Middle East;
access to spare parts, equipment and personnel to maintain, upgrade and service our fleet;
potential cost overruns and other risks inherent to repair, inspections or upgrade of drilling units, unexpected delays in rig and equipment delivery and engineering or design issues, delays in acceptance by our customers, or delays in the dates our drilling units will enter a shipyard, be transported and delivered, enter service or return to service;

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operating hazards, including environmental or other liabilities, risks, expenses or losses, whether related to well-control issues, collisions, groundings, blowouts, fires, explosions, weather or hurricane delays or damage, losses or liabilities (including wreckage or debris removal) or otherwise;
our ability to retain highly skilled personnel on commercially reasonable terms, whether due to competition, cost cutting initiatives, labor regulations, unionization or otherwise; our ability to seek and receive visas for our personnel to work in our areas of operation in a timely manner;
governmental action and political and economic uncertainties, including uncertainty or instability resulting from civil unrest, military or political demonstrations, acts of war, strikes, terrorism, piracy or outbreak or escalation of hostilities or other crises in areas in which we operate, which may result in expropriation, nationalization, confiscation or deprivation of assets, extended business interruptions, suspended operations, or suspension and/or termination of contracts and payment disputes based on force majeure events;
cyber-breaches, outbreaks of any disease or epidemic and other related travel restrictions in any of our areas of operations;
the outcome of legal proceedings, or other claims or contract disputes, including inability to collect receivables or resolve significant contractual or day rate disputes, any renegotiation, nullification, cancellation or breach of contracts with customers or other parties;
potential for additional asset impairments;
our liquidity, adequacy of cash flows to meet obligations, or our ability to access or obtain financing and other sources of capital, such as in the debt or equity capital markets;
volatility in currency exchange rates and limitations on our ability to use or convert illiquid currencies;
effects of accounting changes and adoption of accounting policies;
potential unplanned expenditures and funding requirements, including investments in pension plans and other benefit plans;
economic volatility and political, legal and tax uncertainties following the vote in the U.K. to exit the European Union (“Brexit”) and any subsequent referendum in Scotland to seek independence from the U.K.;
other important factors described from time to time in the reports filed by us with the Securities and Exchange Commission and the New York Stock Exchange.
All forward-looking statements contained in this Form 10-K speak only as of the date of this document and are expressly qualified in their entirety by such factors.  We undertake no obligation to update or revise publicly any revisions to any such forward-looking statements that may be made to reflect events or circumstances after the date of this Form 10-K, or to reflect the occurrence of unanticipated events, except as required by applicable law.
Other relevant factors are included in Item 1A, “Risk Factors,” of this Form 10-K.

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PART I
ITEM 1.  BUSINESS
Overview
Rowan Companies plc is a public limited company incorporated under the laws of England and Wales and listed on the New York Stock Exchange. The terms “Rowan,” “Rowan plc,” “Company,” “we,” “us” and “our” refer to Rowan plc and its consolidated subsidiaries, unless the context otherwise requires.
Rowan plc is a global provider of offshore contract drilling services to the international oil and gas industry, with a focus on high-specification and premium jack-up rigs and ultra-deepwater drillships. Our fleet currently consists of 29 mobile offshore drilling units, including 25 self-elevating jack-up rigs and four ultra-deepwater drillships. Our fleet operates worldwide, including the United States Gulf of Mexico (US GOM), the United Kingdom (U.K.) and Norwegian sectors of the North Sea, the Middle East and Trinidad.
As of February 14, 2017, the date of our most recent Fleet Status Report, two of our four drillships were under contract in the US GOM. Additionally, we had three jack-up rigs under contract in the North Sea, nine under contract in the Middle East, three under contract in Trinidad and two under contract in the US GOM. We had an additional six marketed jack-up rigs, two cold-stacked jack-up rigs and two marketed drillship without a contract.
We contract our drilling rigs, related equipment and work crews primarily on a “day rate” basis. Under day rate contracts, we generally receive a fixed amount per day for each day we are performing drilling or related services. In addition, our customers may pay all or a portion of the cost of moving our equipment and personnel to and from the well site. Contracts generally range in duration from one month to multiple years.
For information with respect to our revenues, operating income and assets by operating segment, and revenues and long-lived assets by geographic area, see Note 13 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K.
Drilling Fleet
We believe our high-specification and premium jack-up fleet and ultra-deepwater drillships are well positioned to serve the worldwide market for high-pressure/high-temperature (HPHT) wells, including those in demanding locations. As of February 14, 2017, our drilling fleet consists of the following:
Four ultra-deepwater drillships;
Nineteen high-specification cantilever jack-up rigs; and
Six premium cantilever jack-up rigs. 
We use the term “high-specification” to describe jack-ups with a hook-load capacity of at least two million pounds and the term “premium” to denote independent-leg cantilever jack-ups that can operate in at least 300 feet of water in benign environments.
Ultra-Deepwater Drillships Our ultra-deepwater drillships are self-propelled vessels equipped with computer-controlled dynamic-positioning systems, which allow them to maintain position without anchors through the use of their onboard propulsion and station-keeping systems. Drillships have greater variable loading capacity than semisubmersible rigs, enabling them to carry more supplies on board and, thus, making them better suited for drilling in deep water in remote locations. Our drillships are equipped with two drilling stations within a single derrick allowing the drillships to perform preparatory activities off-line and potentially simultaneous drilling tasks during certain stages of drilling, subject to legal restrictions in various jurisdictions, enabling increased drilling efficiency particularly during the initial stages of a well. In addition, our drillships are equipped to drill in 12,000-foot water depths, are equipped with 2,500,000 pound hook-load capability, and are capable of drilling HPHT wells to 40,000-foot depths. Each is equipped with two fully redundant blowout preventers, which significantly reduce non-productive time associated with repair and maintenance. In addition, each drillship is equipped with an active-heave crane for simultaneous deployment of subsea equipment. The sum total of these and other advanced features make the drillships very attractive to our customers.
High-Specification and Premium Jack-up Rigs Our jack-ups are capable of drilling wells to maximum depths ranging from 25,000 to 40,000 feet and in maximum water depths ranging from 300 to 550 feet, depending on rig size, location and outfitting. All of our high-specification rigs are equipped with the high pressure circulation and pressure control equipment that are necessary for HPHT operations. Each of our jack-ups is designed with a hull that is fully equipped to serve as a drilling platform supported by three independently elevating legs. The rig is towed to the drilling site where the legs are lowered into and penetrate the ocean

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floor, and the hull raises itself out of the water up to the elevation required to drill the well using a self-contained rack and pinion system.
Our three N-Class rigs are capable of drilling in water depths to 435 feet in harsh environments such as the North Sea depending on location and outfitting. The N-Class rigs, which were designed for operation in the highly regulated Norwegian sector of the North Sea, can be equipped to perform drilling and production operations simultaneously. Our first N-Class rig, the Rowan Viking, was delivered in 2010, and the Rowan Stavanger and Rowan Norway were delivered in 2011.
Our four EXL class rigs enable HPHT drilling in water depths up to 350 feet and are equipped with a hook-load capacity of two million pounds. The first three EXL class rigs were delivered in 2010, and the Rowan EXL IV was delivered in 2011.
Our three 240C class rigs were designed for HPHT drilling in water depths up to 400 feet in benign environments and are equipped with a hook-load capacity of 2.5 million pounds. 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 2012.
Three of our four Super Gorilla class rigs were delivered during the period from 1998 to 2001 and can be equipped for simultaneous drilling and production operations. They can operate year-round in 400 feet of water in harsh environments such as the North Sea. The Bob Palmer, our fourth Super Gorilla class rig delivered in 2003, is an enhanced version of the Super Gorilla class jack-up 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.
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 Rowan Gorilla class rig, the Rowan Gorilla IV, was designed in the mid 1980s as a heavier-duty class of jack-up rig and is capable of operating in water depths to 450 feet in benign environments.
In 2016, we sold two of our older rigs in our jack-up fleet, the Rowan Gorilla II in November and the Rowan Gorilla III in December. The units were sold under agreements that prohibit their future use as drilling units.
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.
Joint Venture
On November 21, 2016, Rowan and the Saudi Arabian Oil Company (“Saudi Aramco”), through their subsidiaries, entered into a Shareholders’ Agreement to create a 50/50 joint venture to own, manage and operate offshore drilling units in Saudi Arabia. The new entity is anticipated to commence operations in the second quarter of 2017.
At formation of the new company, each of Rowan and Saudi Aramco will contribute $25 million to be used for working capital needs. The Asset Contribution and Transfer Agreements provide that at commencement of operations, Rowan will contribute three rigs and its local shore based operations, and Saudi Aramco will contribute two rigs and cash to maintain equal equity ownership in the new company. Rowan will then contribute two more rigs in late 2018 when those rigs complete their current contracts, and Saudi Aramco will make a matching cash contribution at that time. At the various asset contribution dates, excess cash is expected to be distributed in equal parts to the shareholders. Rigs contributed will receive contracts for an aggregate 15 years, renewed and re-priced every three years, provided that the rigs meet the technical and operational requirements of Saudi Aramco.
Rowan rigs in Saudi Arabia not selected for contribution will be managed by the new company until the end of their current contracts pursuant to a management services agreement that provides for a management fee equal to a percentage of revenue to cover overhead costs. After the management period ends, such rigs may be selected for contribution, lease, or they will be required to relocate outside of the Kingdom.
Each of Rowan and Saudi Aramco will be obligated to fund their portion of the purchase of up to 20 new build jack-up rigs ratably over 10 years. The first rig is expected to be delivered as early as 2021. The partners intend that the newbuild jack-up rigs will be financed out of available cash from operations and/or funds available from third party debt financing. Saudi Aramco as a customer will provide drilling contracts to support the new company in the acquisition of the new rigs. If cash from operations or financing is not available to fund the cost of the newbuild jack-up rig, each partner is obligated to contribute funds to purchase such rigs, up to a maximum amount of $1.25 billion per partner in the aggregate for all 20 newbuild jack-up rigs.

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Contracts
Our drilling contracts generally provide for a fixed amount of compensation per day (day rate), and are either “well-to-well,” “multiple-well” or "fixed-term" generally ranging from one month to several years. Well-to-well contracts are typically cancellable by either party upon completion of drilling.  Fixed-term contracts usually contain a termination provision such that either party may terminate if drilling operations are suspended for extended periods as a result of events of force majeure.  While many fixed-term contracts are for relatively short periods of three months or less, 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 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 region.  Such factors, which are discussed further under “Competition” and in “Risk Factors” include the global economic climate, the price of oil and gas which can affect our customers' drilling budgets, over- or under-supply of drilling units, 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 entered into contracts at lower rates in order to keep our rigs working. At times, however, market conditions have forced us to "warm-stack" rigs to reduce costs during extended periods between contracts.  We currently have two ultra-deepwater drillships and five jack-ups warm stacked. We have also cold stacked certain of our idle older rigs to reduce cost further and have ultimately sold five such rigs over the last two years, the Rowan Juneau, Rowan Alaska, Rowan Louisiana, Rowan Gorilla II and Rowan Gorilla III. All but the Rowan Louisiana were sold under agreements that prohibit their future use as drilling units.
Our contract backlog was estimated to be approximately $1.7 billion at February 14, 2017, down from approximately $3.6 billion at January 20, 2016. Backlog at February 14, 2017 does not account for anticipated changes to the Middle East fleet due to the formation of the 50/50 joint venture with Saudi Aramco expected to commence operations in second quarter 2017. See "Joint Venture" above and "Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources" in Part II, Item 7 of this Form 10-K for further information with respect to our backlog.
Competition
The contract drilling industry is highly competitive, and success in obtaining contracts involves many factors, including supply and demand for drilling units, price, rig capability, operating and safety performance, and reputation.
In the jack-up drilling market, we compete with numerous offshore drilling contractors that together have 458 marketed jack-up rigs worldwide as of February 14, 2017, with an additional 103 units that are under construction or on order.  (We define marketed rigs as all rigs that are not cold-stacked.) We estimate that 69 delivered and marketed jack-ups, or 15 percent of the world’s marketed jack-up fleet, are high-specification, including Rowan's 19 high-specification rigs. At February 14, 2017, there were 213 marketed floaters (drillships and semi-submersibles) worldwide, with an additional 48 units that are under construction or on order. We estimate that 100 of these floaters, or approximately 47 percent of the world’s marketed fleet, are capable of drilling in water depths of 10,000 feet or more, but only an estimated 32 floaters, or approximately 15 percent of the world's marketed fleet, have 2,500,000 pound hook-load capability and are equipped with dual blow-out preventers, which are key specifications valued by our customers.
A significant contributing factor to the softness in the offshore drilling market has been the influx of 231 newbuild jack-ups and 158 newbuild floaters delivered since early 2006. The addition of newbuild units, combined with numerous rigs having rolled off contracts in past months, has continued to increase competition, putting additional downward pressure on day rates and utilization. Of the approximately 103 jack-up rigs under construction worldwide scheduled for delivery through 2020 (33% of the currently utilized jack-up fleet of approximately 310 rigs), approximately 50 are considered high-specification (72% of the delivered high-specification fleet). Currently, there are approximately 77 competitive newbuild jack-up rigs scheduled for delivery during 2017, and only five have contracts. For the floater market there are approximately 48 floaters under construction worldwide for delivery through 2020 (32% of the currently utilized floater fleet of approximately 149 rigs). Following the negotiated delivery delays on several units into future years, there are approximately 30 competitive newbuild floaters scheduled for delivery during 2017, with 11 having contracts.

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Based on the number of rigs as tabulated by IHS-Petrodata, we are the seventh largest offshore drilling contractor in the world and the fifth largest jack-up rig operator. Based on market capitalization, we are the fourth largest publically traded pure play offshore driller. 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 Part II, 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 those relating to environmental protection and pollution control. In addition, governmental regulations concerning licensing and permitting, 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.
We could become liable for damages resulting from pollution which could materially affect our financial position, operations and liquidity. 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 from our drilling rigs. This indemnity includes costs associated with regaining control of a wild well, removal and disposal of pollutants, environmental remediation and claims by third parties for damages. However, such contractual indemnification provisions may not adequately protect us for several reasons such as (i) the contractual indemnity provisions may require us to assume some of the liability; (ii) our customers may not have the financial resources necessary to honor the contractual indemnity provisions; or (iii) the contractual indemnity provisions may be unenforceable under applicable law.
Our customers often require us to assume responsibility for pollution damages when 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 $5 million 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 $5 million. We can provide no assurance that we will be able to negotiate indemnities and/or limitation of liability provisions 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 where we are liable for all or a portion of such event, 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. Such an event would adversely affect our results of operations, financial position and cash flows if both insurance and indemnity protection were unavailable or insufficient and the incident was significant.
The U.S., U.K. and other other jurisdictions in which we operate have various regulations and requirements with which we must comply. For example, pursuant to the Clean Water Act, a National Pollutant Discharge Elimination Permit (NPDES permit) is required for discharges into the US GOM. The permit holder is the designated responsible party for any environmental impacts that 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. We operate in accordance with NPDES permit standards regardless of the holder.
Pursuant to the U.K. Offshore Directive, we are required to have an approved Oil Pollution Emergency Plan (OPEP) for each drilling unit operating in U.K. waters. The Offshore Directive also specifies additional regulations related to safety, licensing, environmental protection, emergency response and liability with which we comply.
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. For operations in the U.S., 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.

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As the designated responsible party, an 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 drilling units to mitigate the impact of an incident until an emergency spill response organization can 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 in the U.S. has been in business since 1994 and specializes in helping industries prevent and clean up oil and other hydrocarbon spills. Our provider has represented it holds all necessary licenses, certifications and permits to respond to environmental emergencies in the US GOM and maintains contacts with other response resources and organizations outside the US GOM. We believe we have adequate equipment and third-party resources available to us to respond to an emergency spill; however, we can provide no assurance that adequate resources will be available. 
We are actively involved in various industry-led initiatives and work groups, including but not limited to those of the American Petroleum Institute, the International Association of Drilling Contractors, the Ocean Energy Safety Institute, and the British Rig Owners Association, which are intended to improve safety and protection of the environment.
Oil and gas operations in the US GOM and in many of the other jurisdictions in which we operate are subject to regulation with respect to well design, casing and cementing and well control procedures, as well as rules requiring operators to systematically identify risks and establish safeguards against those risks through a comprehensive safety and environmental management system, or SEMS. Any serious oil and gas industry related event heightens governmental and environmental concerns and may lead to legislative proposals being introduced which may materially limit or prohibit offshore drilling in certain areas. 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.
On July 28, 2016, BSEE published a final rule, Oil and Gas and Sulfur Operations in the Outer Continental Shelf-Blowout Preventer Systems and Well Control to implement recommendations of the Deepwater Horizon Commission. The new regulations took effect on July 28, 2016, with a number of requirements to be phased in over several years.
Regulatory compliance has and may continue to materially impact our capital expenditures and earnings, particularly in the event of an environmental incident. Given the state-of-the-art design of our drillships and high specification of our jack-up fleet, we believe we are well positioned competitively to our peers to be able to comply with current and future governmental regulations.
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 either $25 million or $15 million per occurrence, depending on the unit's geographic location. 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) and automobile 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, 2016, we had 2,917 employees worldwide, compared to 3,496 and 4,051 at December 31, 2015 and 2014, respectively, and 264 independent contractors. 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.

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Customers
In 2016, Saudi Aramco, Freeport-McMoRan, Cobalt International, Repsol and ConocoPhillips accounted for 20%, 12%, 12%, 12% and 11%, respectively, of consolidated revenues. Saudi Aramco and ConocoPhillips revenue was derived from our jack-up segment, and Repsol and Cobalt International revenue, as well as nearly all of Freeport-McMoRan revenue, was derived from our deepwater segment.
Reports filed with or furnished to the SEC
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.rowan.com as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. Information contained on or accessible from our website is not incorporated by reference into this Form 10-K and should not be considered a part of this report or any other filing that we make with the SEC.
ITEM 1A.  RISK FACTORS
There are numerous factors that affect our business and operating results, many of which are beyond our control. The following is a description of significant factors that might cause our future operating results to differ materially from those currently expected. The risks described below are not the only risks facing our Company. Additional risks and uncertainties not specified herein, not currently known to us or currently deemed to be immaterial also may materially adversely affect our business, financial position, operating results and/or cash flows.
Our business depends on the level of activity in the offshore oil and gas industry, which is significantly affected by declines in oil or gas prices and reduced demand for oil and gas products.
Our business depends heavily on a variety of economic and political factors and the level of oil and gas activity worldwide. Sustained declines in oil or natural gas prices, combined with market expectations of a prolonged weakened global market, have caused oil and gas companies to significantly reduce their exploration, development and production activities, thereby decreasing demand for offshore drilling services and leading to lower rig utilization and day rates for our services. Oil and natural gas prices have historically been very volatile, and our drilling operations have in the past suffered through long periods of weak market conditions.
Demand for our drilling services depends on many factors beyond our control, including:
worldwide demand for and prices of oil and natural gas, and expectations regarding future energy prices;
the supply of drilling units in the worldwide fleet versus demand;
the level of exploration and development expenditures by energy companies and their ability to raise capital;
the willingness and ability of the Organization of Petroleum Exporting Countries (OPEC) to limit production levels and influence prices;
the level of production in non-OPEC countries;
the effect of economic sanctions that affect the energy industry;
the general economy, including inflation and changes in the rate of economic growth;
the condition of global capital markets;
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;
the cost of exploring for, developing, producing and delivering oil and natural gas;
environmental and other laws and regulations;
policies of various governments regarding exploration and development of oil and natural gas reserves;
nationalization of assets or workforce and/or confiscation of assets;
worldwide tax policies and treaties;
political and military conflicts in oil-producing areas and the effects of terrorism;                                                                                                                  

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increased supply of oil and gas from onshore development and relative cost of offshore drilling versus onshore oil and gas production;
the development and exploitation of alternative fuels and energy sources, and
merger, divestiture, restructuring and consolidation of our customers and competitors and their assets.
Adverse developments affecting the industry as a result of one or more of these factors, including any further decline in oil or gas prices or the failure of oil or gas prices to increase, a global recession, continued declines in demand for oil and gas products, increased oversupply of drilling units, and increased regulation of drilling and production, would adversely affect our business, financial condition and results of operations.
The success of our business is dependent upon our ability to secure contracts for our drilling units at sufficient day rates. Depressed oil and gas prices and an oversupply of drilling units have led to further reductions in rig utilization and day rates, which may materially impact our profitability.
Our ability to meet our cash flow obligations depends on our ability to secure ongoing work for our drilling units at sufficient day rates. As of February 14, 2017, we had eight jack-up drilling units without contracts (including two cold-stacked); ten with contract terms ending in 2017; six with contract terms ending in 2018; and one with a contract term ending in 2024; and two of our four drillships without contracts; one of our drillships has a contract ending in 2017 and the other contract ends in early 2018. Given current market conditions future demand for offshore drilling units and day rates may continue to remain at low levels, possibly for an extended period of time. Failure to secure profitable contracts for our drilling units could negatively impact our operating results and financial position, impair our ability to generate sufficient cash flow to fund our capital expenditures and/or meet our other obligations.
Prior to the downturn in the drilling sector, the industry experienced a significant increase in construction activity. The resulting increase in supply of newbuild drilling units, combined with the decrease in demand for offshore drilling services, has led to an oversupply of drilling units and further declines in utilization and day rates that is expected to continue for some time. According to industry sources, there were 458 marketed jack-up rigs worldwide as of February 14, 2017, an additional 103 units that are under construction or on order and 213 marketed floaters (drillships and semi-submersible) worldwide, with an additional 48 units that are under construction or on order. (We define marketed rigs as all rigs that are not cold-stacked.) A continued decline in utilization and day rates would further impact our revenues and profitability. 
A further decline in the market for contract drilling services could result in additional asset impairment charges.
We recognized asset impairment charges on our jack-up drilling units aggregating approximately $566 million in 2014, $330 million in 2015 and $34 million in 2016, or approximately 7%, 4% and 0.5%, respectively, of our fixed asset carrying values. Prolonged periods of low utilization and day rates, the cold-stacking of idle assets, or the sale of assets below their then carrying value could result in the recognition of additional impairment charges on our drilling units if future cash flow estimates, based upon information available to management at the time, indicate that their carrying value may not be recoverable. See “Impairment of Long-lived Assets” in Note 2 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Form 10-K for additional information.
We are subject to operating risks that could result in environmental damage, property loss, personal injury, death, business interruptions and other losses.
Our drilling operations are subject to many operational hazards such as blowouts, explosions, fires, collisions, punch-throughs (i.e., when one leg of a jack-up rig breaks through the hard crust of the ocean floor, placing stress on the other legs), mechanical or technological failures, navigation errors, or equipment defects that could increase the likelihood of accidents. Accidents can result in:
serious damage to or destruction of property and equipment;
personal injury or death;
costly delays or cancellations of drilling operations;
interruption or cessation of day rate revenue;
uncompensated downtime;
reduced day rates;
significant impairment of producing wells, leased properties, pipelines or underground geological formations;

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damage to fisheries and pollution of the marine and coastal environment; and
fines and penalties.
Our drilling operations are also subject to marine hazards, whether at drilling sites or while equipment is under tow, such as a vessel capsizing, sinking, colliding or grounding. In addition, raising and lowering jack-up rigs and drilling into high-pressure formations are complex, hazardous activities, and we periodically encounter problems.  Any ongoing change in weather or sea patterns or climate conditions could increase the adverse impact of marine hazards.
In past years, we have experienced some of the types of incidents described above, including punch-throughs and towing accidents resulting in lost or damaged equipment and high-pressure drilling accidents resulting in lost or damaged formations. Any future such events could result in operating losses and have a significant impact on our business.
The global nature of our operations involves additional risks, particularly in certain foreign jurisdictions.
Our operations are significantly diversified internationally.  Foreign operations are often subject to additional political, economic and other uncertainties, such as with respect to taxation policies, customs restrictions, local content requirements, regulatory requirements, currency convertibility and repatriation, security threats including terrorism, piracy, and the risk of asset expropriation.  Political unrest and regulatory restrictions could halt operations or impact us in other unforeseen ways.
Many countries have regulations or policies requiring or rewarding the participation of local companies and individuals in the petroleum-related activities. Such participation requirements can include, without limitation, the ownership of oil and gas concessions, the hiring of local agents and partners, the procurement of goods and services from local sources, and the employment of local workers. The requirements can also include co-ownership of our drilling units, in whole or in part, by home country companies or citizens and /or require reflagging of our drilling units under the flag of the home country. The governments of many of these foreign countries have become increasingly active in requiring higher levels of local participation which may increase our costs and risks of operating in these regions, thereby limiting our ability to enter into, relocate from, or compete in these regions.
In addition, our inability to obtain visas and work permits for our employees in foreign jurisdictions on a timely basis could delay or interrupt our operations resulting in an adverse impact on our business. Further, governmental restrictions in some jurisdictions may make it difficult for us to move our personnel, assets and operations in and out of these regions without delays or downtime.
In foreign areas where legal protections may be less available to us, we assume greater risk that our customer may terminate contracts without cause on short notice, contractually or by governmental action.  Additionally, operations in certain areas, such as the North Sea and US GOM, are highly regulated and have higher compliance and operating costs in general.
Although we are a U.K. company, a significant majority of our revenues and expenses are transacted in U.S. dollars, which is our functional currency. However, in certain countries in which we operate, local laws or contracts may require us to receive some portion of payment in the local currency.  We are exposed to foreign currency exchange risk to the extent the amount of our monetary assets denominated in the foreign currency differs from our obligations in that foreign currency. In order to mitigate the effect of exchange rate risk, we attempt to limit foreign currency holdings to the extent they are needed to pay liabilities denominated in the foreign currency. At December 31, 2016, we held Egyptian pounds in the amount of $5.1 million. We ceased drilling operations in Egypt in 2014, and are currently working to obtain access to the funds for use outside Egypt to the extent they are not utilized; however, we can provide no assurance we will be able to convert or utilize such funds in the future.
The offshore drilling industry is highly competitive and cyclical, with intense price competition.
The offshore contract drilling industry is a highly competitive and cyclical business characterized by numerous competitors, high capital and operating costs and evolving capability of newer rigs. Drilling contracts are often awarded on a competitive-bid basis, and intense price competition, rig availability, location and suitability, experience of the workforce, efficiency, safety performance record, technical capability and condition of equipment, operating integrity, reputation, industry standing and client relations are all factors in determining which contractor is awarded a contract. Our future success and profitability will partly depend upon our ability to keep pace with our customers’ demands with respect to these factors.
In addition to intense competition, our industry has historically been cyclical. The contract drilling industry is currently in a period of low demand for offshore drilling services, excess rig supply, a prolonged period of declining oil and gas prices and reduced worldwide drilling activity. These conditions have intensified the competition in the industry and put significant downward pressure on day rates. As a result, we may be unable to secure profitable contracts for our drilling units, we may have to contract our rigs at substantially lower rates for long periods of time, enter into nontraditional fee arrangements, or idle or cold-stack some of our drilling units, all of which would adversely affect our operating results, cash flows and financial position.

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We may experience reduced profitability if our customers terminate or seek to renegotiate our drilling contracts, and our backlog of drilling revenue may not be fully realized.
We may be subject to the increased risk of our customers seeking to terminate or renegotiate their contracts. Our customers’ ability to perform their obligations under drilling contracts with us may also be adversely affected by their own financial position, restricted credit markets and the current industry downturn. If our customers cancel or are unable to renew some of their contracts and we are unable to secure new contracts on a timely basis and on substantially similar terms, if contracts are disputed or suspended for an extended period of time, or if a number of our contracts are renegotiated, such events would adversely affect our business, financial condition and results of operations.
Most of our term drilling contracts may be canceled by the customer without penalty upon the occurrence of events beyond our control such as the loss or destruction of the drilling unit, or the suspension of drilling operations for a specified period of time as a result of a breakdown of major equipment. While most of our contracts require the customer to pay a termination fee in the event of an early cancellation without cause, early termination payments may not fully compensate us for the loss of the contract, and could result in the drilling unit becoming idle or cold-stacked for an extended period of time.  If we or our customers are unable to perform under existing contracts for any reason or replace terminated contracts with new contracts having less favorable terms, our backlog of estimated revenues would decline, adversely affecting our financial results.
We must make substantial capital and operating expenditures to maintain, and upgrade our drilling fleet.
Our business is highly capital intensive and dependent on having sufficient cash flow and or available sources of financing in order to fund capital expenditure requirements. We can provide no assurance that we will have access to adequate or economical sources of capital to fund necessary capital expenditures.
We have and will likely continue to have certain customer concentrations, and the loss of a significant customer would adversely impact our financial results.
A concentration of customers increases the risks associated with any possible (i) termination or nonperformance of drilling contracts, (ii) failure to renew contracts or award new contracts, or (iii) reduction of our customers' drilling programs. In 2016, five customers accounted for 67% of our consolidated revenues. The loss or material reduction of business from a significant customer would have an adverse impact on our results of operations and cash flows.  Moreover, our drilling contracts subject us to counterparty risks. The ability of each of our counterparties to perform its obligations under a contract with us will depend on a number of factors that are beyond our control such as the overall financial condition of the counterparty. Should a significant counterparty fail to honor its obligations under an agreement with us, we could sustain losses, which could have a material adverse effect on our business, financial condition and results of operations.
If we or our customers are unable to acquire or renew permits and approvals required for drilling operations, we may be forced to suspend or cease our operations, and our profitability may be reduced.
Crude oil and natural gas exploration and production operations require numerous permits and approvals for us and our customers from governmental agencies in the areas in which we operate.  In addition, many governmental agencies have increased regulatory oversight and permitting requirements in recent years.  If we or our customers are not able to obtain necessary permits and approvals in a timely manner, our operations will be adversely affected.  Obtaining all necessary permits and approvals may necessitate substantial expenditures to comply with the requirements of these permits and approvals, future changes to these permits or approvals, or any adverse change in the interpretation of existing permits and approvals.  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 and the BSEE, have implemented significant environmental and safety regulations applicable to drilling operations in the US GOM.  These regulations have at times adversely impacted the ability of our customers to obtain necessary permits and approval on a timely basis and/or to continue operations uninterrupted under existing permits.  
We may not realize the expected benefits of our joint venture with Saudi Aramco and the joint venture may introduce additional risks to our business.
In November 2016, Rowan and Saudi Aramco announced plans to form a 50/50 joint venture with Rowan and Saudi Aramco each contributing existing drilling units and capital as the foundation of the new company. The new venture is anticipated to commence operations in the second quarter of 2017, subject to regulatory approvals and start-up efforts, and is expected to add up to 20 newbuild jack-up rigs to its fleet over ten years commencing as early as 2021. There can be no assurance that this venture will

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commence operations on schedule, that the new jack-up rigs will begin operations as anticipated or that we will realize the expected return on our investment. We may also experience difficulty jointly managing the venture, and integrating our existing employees, business systems, technologies and services with those of Saudi Aramco in order to operate the joint venture efficiently. Further, in the event the new company has insufficient cash from operations or is unable to obtain third party financing, we may periodically be required to make additional capital contributions to the new company, up to a maximum aggregate contribution of $1.25 billion, which could affect our liquidity position. As a result of these risks, it may take longer than expected for us to realize the expected returns from this venture or such returns may ultimately be less than anticipated. Additionally, if we are unable to make any required contributions, our ownership in the new company could be diluted which could hinder our ability to effectively manage the new company and harm our operating results or financial condition.
Increases in regulatory requirements could significantly increase our costs or delay our operations.
Many aspects of our operations are subject to governmental regulation, including equipping and operating vessels, drilling practices and methods, and taxation. For example, operations in certain areas, such as the US GOM and the North Sea, are highly regulated and have higher compliance and operating costs in general. We may be required to make significant expenditures in order to comply with existing or new governmental laws and regulations. It is also possible that such laws and regulations may in the future add significantly to our operating costs or result in a reduction of revenues associated with downtime required to implement regulatory requirements.
Oil and gas operations in the US GOM and in many of the international locations in which we operate are subject to regulation with respect to well design, casing and cementing and well control procedures, as well as rules requiring operators to systematically identify risks and establish safeguards against those risks through a comprehensive safety and environmental management system, or SEMS. New regulations continue to be implemented, including rules regarding drilling systems and equipment, such as blowout preventer and well-control systems and lifesaving systems, as well as rules regarding employee training, engaging personnel in safety management and requiring third-party audits of SEMS programs. Such new regulations may require modifications or enhancements to existing systems and equipment, or require new equipment, and could increase our operating costs and cause downtime for our units if we are required to take any of them out of service between scheduled surveys or inspections, or if we are required to extend scheduled surveys or inspections to meet any such new requirements. Additional governmental regulations concerning licensing, taxation, equipment specifications, training requirements or other matters could increase the costs of our operations and could reduce exploration activity in the areas in which we operate.
Governments in some countries are increasingly active in regulating and controlling the ownership of concessions, the exploration for oil and gas, and other aspects of the oil and gas industry. These governmental regulations may limit or substantially increase the cost of drilling activity in an operating area generally. The modification of existing laws or regulations or the adoption of new laws or regulations curtailing exploratory or developmental drilling for oil and gas for economic, environmental or other reasons could materially and adversely affect our operations by limiting drilling opportunities. In addition, the offshore drilling industry is highly dependent on demand for services from the oil and gas industry and accordingly, regulations of the production and transportation of oil and gas generally could impact demand for our services.
Regulation of greenhouse gases and climate change could have a negative impact on our business.
Governments around the world are increasingly focused on enacting laws and regulations regarding climate change and regulation of greenhouse gases. Lawmakers and regulators in the U.S., the U.K. and other jurisdictions where we operate have proposed or enacted regulations requiring reporting of greenhouse gas emissions and the restriction thereof. In addition, efforts have been made and continue to be made in the international community toward the adoption of international treaties or protocols that would address global climate change issues and impose reductions of hyrdrocarbon-based fuels. Laws or regulations incentivizing or mandating the use of alternative energy sources such as wind power and solar energy have also been enacted in certain jurisdictions. Laws, regulations, treaties and international agreements related to greenhouse gases and climate change may unfavorably impact our business, our suppliers and our customers, and result in increased compliance costs, operating restrictions and could reduce drilling in the offshore oil and gas industry, all of which would have a negative impact on our business.
Our drilling units are subject to damage or destruction by severe weather, and our drilling operations may be affected by severe weather conditions.
Our drilling rigs are located in areas that frequently experience hurricanes and other forms of severe weather conditions. These conditions can cause damage or destruction to our drilling units. Further, high winds and turbulent seas can cause us to suspend operations on drilling units for significant periods of time.  Even if our drilling units are not damaged or lost due to severe weather, we may experience disruptions in our operations due to evacuations, reduced ability to transport personnel to the drilling unit, or damage to our customers’ platforms and other related facilities.  Additionally, our customers may not choose to contract our rigs for use during hurricane season, particularly in the US GOM.  Future severe weather could result in the loss or damage to our rigs or curtailment of our operations, which could adversely affect our financial position, results of operations and cash flows.

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Taxing authorities may challenge our tax positions, and we may not be able to realize expected benefits.
We are subject to tax laws, regulations and treaties in many jurisdictions. Changes to these laws or interpretations could affect the taxes we pay in various jurisdictions. Our tax positions are subject to audit by relevant tax authorities who may disagree with our interpretations or assessments of the effects of tax laws, treaties, or regulations, or their applicability to our corporate structure or certain of our transactions we have undertaken.  We could therefore incur material amounts of unrecorded income tax cost if our positions are challenged and we are unsuccessful in defending them.
Changes in or non-compliance with tax laws and changes to our income tax estimates could adversely impact our financial results.
In 2012, we changed our legal domicile to the U.K. There are 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 the non-U.S. subsidiaries of Rowan Companies Inc. (RCI), a wholly owned, indirect subsidiary of the Company, to RCI, 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 non-U.K. subsidiaries, except for certain subsidiaries that are not permanently reinvested or that will not be permanently reinvested in the future. It is generally our 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 income taxes.

Political disturbances, war, or terrorist attacks and changes in global trade policies and economic sanctions could adversely impact our operations.
Our operations are subject to political and economic risks and uncertainties, including instability resulting from civil unrest, political demonstrations, mass strikes, or an escalation or additional outbreak of armed hostilities or other crises in oil or natural gas producing areas, which may result in extended business interruptions, suspended operations and danger to our employees, or result in claims by our customers of a force majeure situation and payment disputes.  Additionally, we are subject to risks of terrorism, piracy, political instability, hostilities, expropriation, confiscation or deprivation of our assets or military action impacting our operations, assets or financial performance in many of our areas of operations.
Operating and maintenance costs of our drilling units may be significant, and could have an adverse effect on the profitability of our contracts. In addition, operational interruptions or maintenance or repair work may cause our customers to suspend or reduce payment of day rates until operation is resumed, which may lead to loss of revenue or termination or renegotiation of the drilling contract.
Most of our drilling contracts provide for the payment of a fixed day rate during periods of operation and reduced day rates during periods of other activities.  Given current market conditions, we may not be able to negotiate day rates sufficient to cover increased or unanticipated costs. Our operating expenses and maintenance costs can be unpredictable, and depend on a variety of factors including: crew costs, costs of provisions, equipment, insurance, maintenance and repairs, customer and regulatory requirements, and shipyard costs, many of which are beyond our control. Our profit margins may therefore vary over the terms of our contracts, which could adversely affect our financial position, results of operations and cash flows.
Our customers may be entitled to pay a waiting, or standby, rate lower than the full operational day rate if a drilling unit is idle for reasons that are not related to the ability of the rig to operate. In addition, if a drilling unit is taken out of service for maintenance and repair for a period of time exceeding the scheduled maintenance periods set forth in the drilling contract, we may not be entitled to payment of day rates until the unit is able to work. If the interruption of operations were to exceed a determined period, our customers may have the right to pay a rate that is significantly lower than the waiting rate for a period of time, and, thereafter, may terminate the drilling contracts related to the subject rig. Suspension of drilling contract payments, prolonged payment of reduced rates or termination of any drilling contract as a result of an interruption of operations could materially adversely affect our business, financial condition and results of operations.

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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 4.5% of our available rig days in 2016. Operating revenue may fluctuate as rigs are recontracted at prevailing market rates upon termination of a contract, but costs for operating a rig are generally fixed or only slightly variable regardless of the day rate being earned.  Additionally, if our rigs are idle between contracts, we typically continue to incur operating and personnel costs because the crew is retained to prepare the rig for its next contract.  During times of reduced activity, reductions in costs may not be immediate as some crew members may be required to assist in the rig's removal from service.  Moreover, as our rigs are mobilized from one geographic location to another, the labor and other operating and maintenance costs may increase significantly.
We may have difficulty obtaining or maintaining insurance in the future, and some of our losses may not be covered by insurance.
We maintain insurance coverage for damage to our drilling rigs, third-party liability, workers’ compensation and employers’ liability, sudden and accidental pollution, and other types of loss or damage.  There are some losses, however, for which insurance may not be available or only available at much higher prices. For example, we do not currently maintain named windstorm physical damage coverage on any of our drilling units located in the US GOM.  
We can provide no assurance that our insurance coverage will adequately protect us against liability from potential consequences and damages, or that we will be able to maintain adequate insurance in the future. A significant event which is not adequately covered by insurance and /or the failure of one or more of our insurance providers to meet claim obligations or losses or liabilities resulting from uninsured or underinsured events could adversely affect our financial position, results of operations and cash flows.
Our contractual indemnification provisions may not be sufficient to cover our liabilities.
Our drilling contracts provide for varying levels of indemnification and allocation of liabilities between the parties with respect to liabilities resulting from various hazards associated with the drilling industry, such as loss of well control, well-bore pollution and damage to subsurface reservoirs and injury or death to personnel.  The degree of indemnification we may receive from operators varies from contract to contract based on market conditions and customer requirements existing when the contract was negotiated and recovery is dependent on the customer's financial condition. Our drilling contracts generally indemnify us for injuries and death of our customers’ employees and loss or damage to our customers’ property.  Our service agreements generally indemnify us for injuries and death of our service providers’ employees. However, the enforceability of our indemnities may be subject to differing interpretations, or further limited or prohibited under applicable law or by contract, particularly in cases of gross negligence, willful misconduct, punitive damages or punitive fines and/or penalties.  The failure of a customer to meet its indemnification obligations, or losses or liabilities resulting from events excluded from or unenforceable under contractual indemnification obligations would adversely affect our financial position, results of operations and cash flows.
Our information technology systems are subject to cybersecurity risks and threats.
We depend heavily on technologies, systems and networks that we manage, and others that are managed by our third-party service and equipment providers or customers, to conduct our business and operations.  Cybersecurity risks and threats to such systems continue to grow and may be difficult to anticipate, prevent, identify or mitigate. If any of our, our service providers' or our customers' security systems prove to be insufficient, we could be adversely affected by having our business and financial systems compromised, our companies’, employees’, vendors’ or customers’ confidential or proprietary information altered, lost or stolen, or our (or our customers’) business operations or safety procedures disrupted, degraded or damaged. A breach or failure could also result in injury (financial or otherwise) to people, loss of control of, or damage to, our (or our customers’) assets, harm to the environment, reputational damage, breaches of laws or regulations, litigation and other legal liabilities.  In addition, we may incur significant costs to prevent, respond to or mitigate cybersecurity risks or events and to defend against any investigations, litigation or other proceedings that may follow such events.  Such a failure or breach of our systems could adversely and materially impact our business operations, financial position, results of operations and cash flows.
Failure to comply with anti-corruption and anti-bribery laws could result in fines, criminal penalties and drilling contract terminations and could have an adverse impact on our business.
The U.S. Foreign Corrupt Practices Act (FCPA), the U.K. Bribery Act 2010 (UK Bribery Act) and similar 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. We have operated and may in the future operate in parts of the world where strict compliance with anti-corruption and anti-bribery laws may conflict with local customs and practices. Any failure to comply with the FCPA, UK

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Bribery Act, or other anti-corruption laws due to our own acts or omissions or the acts or omissions of others, including our partners, agents or vendors, could subject us to civil and criminal penalties or other sanctions, which would adversely affect our business, financial position, results of operations or cash flows. We could also face fines, sanctions and other penalties from authorities in the relevant foreign jurisdictions, including prohibition of our participation in or curtailment of business operations in those jurisdictions and the seizure of drilling units or other assets.
Failure to retain highly skilled personnel could hurt our operations.
We require highly skilled and experienced personnel to operate our rigs and provide technical services and support for our operations.  In the past, during periods of high demand for drilling services and increasing worldwide industry fleet size, shortages of qualified personnel have occurred. Such shortages could result in our loss of qualified personnel to competitors, impair the timeliness and quality of our work and create upward pressure on costs. If we are unable to retain or train skilled personnel, our operations and quality of service could be adversely impacted.
We are involved in litigation and legal proceedings from time to time that could have a negative effect on us if determined adversely.
We are, from time to time, involved in various legal proceedings, which may include, among other things, contract disputes, personal injury, environmental, toxic tort, employment, tax and securities litigation, governmental investigations or proceedings, and litigation that arises in the ordinary course of our business. Although we intend to defend any of these matters vigorously, we cannot predict with certainty the outcome or effect of any claim or other litigation matter.  Our profitability may be adversely affected by the outcome of claims or contract disputes, including any inability to collect receivables or resolve significant contractual or day rate disputes, and any purported nullification, cancellation or breach of contracts with customers or other parties.  Litigation may have an adverse effect on us because of potential negative outcomes, the costs associated with defending the lawsuits, the diversion of resources, reputational damage, and other factors.
Recent downgrades in our credit ratings may affect our ability to access the credit and debt capital markets.
Our ability to maintain a sufficient level of liquidity to meet our financial and operating needs is dependent upon our future performance, operating cash flows, and our access to credit and debt capital markets. In turn, our level of liquidity and access to credit and debt capital markets depends on general economic conditions, industry cycles, financial, business and other factors affecting our operations, as well as our credit ratings. Tightening in the credit markets due to the current economic environment, concerns about the offshore drilling industry and our credit ratings may restrict our access to the credit and debt capital markets in the future and increase the cost of such indebtedness. As a result, our future cash flows and access to capital may be insufficient to meet all of our capital requirements, debt obligations and contractual commitments, and any insufficiency could have an adverse impact on our business.
Certain credit rating agencies have downgraded our credit ratings below investment grade, and may further downgrade our credit ratings at any time. A further downgrade in our ratings could have adverse consequences on our business and future prospects, including the following:
Restrict our ability to access credit and debt capital markets;
Cause us to refinance or issue debt with less favorable terms and conditions;
Pay increased fees under our debt agreements;
Negatively impact current and prospective customers’ willingness to transact business with us;
Impose additional insurance, guarantee and collateral requirements; or
Limit our access to bank and third-party guarantees, surety bonds and letters of credit.
Technology disputes could negatively impact our operations or increase our costs.
Drilling rigs use proprietary technology and equipment which can involve potential infringement of a third party’s rights, including patent rights. The majority of the intellectual property rights relating to our jack-ups and drillships are owned by us or our suppliers or sub-suppliers, however, in the event that we or one of our suppliers or sub-suppliers becomes involved in a dispute over infringement rights relating to equipment owned or used by us, we may lose access to repair services or replacement parts, or we could be required to cease use of some equipment or forced to modify our jack-ups or drillships. We could also be required to pay license fees or royalties for the use of equipment. Technology disputes involving us or our suppliers or sub-suppliers could adversely affect our financial results and operations.

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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 other portions of our workforce. In addition, we have experienced, and in the future may experience, strikes or work stoppages and other labor disruptions. Additional unionization efforts, new collective bargaining agreements or work stoppages could materially increase our costs, reduce our revenues or limit our operations.
Supplier capacity constraints or shortages in parts or equipment, supplier production disruptions, supplier quality and sourcing issues or price increases could increase our operating costs, decrease our revenues and adversely impact our operations.
Our reliance on third-party suppliers, manufacturers and service providers to secure equipment used in our drilling operations could expose us to volatility in the quality, price and availability of such items. Certain specialized parts and equipment we use in our operations may be available only from a single or small number of suppliers. A disruption in the deliveries from such third-party suppliers, capacity constraints, production disruptions, price increases, defects or quality-control issues, recalls or other decreased availability or servicing of parts and equipment could adversely affect our ability to meet our commitments to customers, adversely impact our operations and revenues by resulting in uncompensated downtime, reduced day rates or the cancellation or termination of contracts, or increase our operating costs.
The enforcement of civil liabilities against Rowan plc may be more difficult.
Because Rowan plc is a public limited company incorporated under English law, investors could experience more difficulty enforcing judgments obtained against Rowan plc in U.S. courts than would be the case for U.S. judgments obtained against a U.S. company.  In addition, it may be more difficult to bring some types of claims against Rowan plc in courts in the U.K. than it would be to bring similar claims against a U.S. company in a U.S. court.
Our articles of association include mandatory offer provisions that may have the effect of discouraging, delaying or preventing hostile takeovers, including those that might result in a premium being paid over the market price of our shares, and discouraging, delaying or preventing changes in control or management.
Although Rowan plc is not currently subject to the U.K. Takeover Code, certain provisions similar to the mandatory offer provisions and certain other aspects of the U.K. Takeover Code are included in our articles of association. As a result, among other matters, a Rowan plc shareholder, that together with persons acting in concert, acquired 30 percent or more of our issued shares without making an offer to all of our other shareholders that is in cash or accompanied by a cash alternative would be at risk of certain Board sanctions unless they acted with the consent of our Board or the prior approval of the shareholders.  The ability of shareholders to retain their shares upon completion of a mandatory offer may depend on whether the offeror subsequently causes us to propose a court-approved scheme of arrangement that would compel minority shareholders to transfer or surrender their shares in favor of the offeror or, if the offeror has acquired at least 90 percent of the relevant shares, the offeror requires minority shareholders to accept the offer under the ‘squeeze-out’ provisions in our articles of association.  The mandatory offer provisions in our articles of association could have the effect of discouraging the acquisition and holding of interests of 30 percent or more of issued shares and encouraging those shareholders who may be acting in concert with respect to the acquisition of shares to seek to obtain the consent of our Board before effecting any additional purchases.  In addition, these provisions may adversely affect the market price of our shares or inhibit fluctuations in the market price of our shares that could otherwise result from actual or rumored takeover attempts.
As a result of shareholder approval requirements required under U.K. law, we may have less flexibility than as a Delaware corporation with respect to certain aspects of capital management.
Unlike most U.S. state corporate law, English law provides that a board of directors may generally only allot shares with the prior authorization of shareholders, which such authorization may only extend for a maximum period of five years. English law also generally provides shareholders preemptive rights when new shares are issued for cash unless such rights are waived by the shareholders.
English law also generally prohibits us from repurchasing our shares on the open market, and prohibits us from repurchasing our shares by way of “off-market purchases” without the prior approval of shareholders, which approval may only extend for a maximum period of five years.
Prior to the redomestication, our Board was authorized to allot a certain amount of shares, exclude certain preemptive rights in shares for cash offerings and effect off market purchases, in each case without further shareholder approval. However, these authorizations expire in April 2017. As such, we will be unable to issue new shares or repurchase shares unless and until we

17


receive renewed shareholder approval. In addition, even if approved by shareholders, our ability to issue and repurchase shares may be substantially more restricted than a U.S. company.
English law requires that we meet certain additional financial requirements before we declare dividends and return funds to shareholders.
Under English law, a public company may only declare dividends and make other distributions to shareholders (such as a share buyback) if the company has sufficient distributable reserves and meets certain net asset requirements. If we do not have sufficient distributable reserves or cannot meet the net asset requirements, we may be limited in our ability to timely pay dividends and effect other distributions to our shareholders.
The United Kingdom’s referendum to exit from the European Union (E.U.) will have uncertain effects and could adversely impact our business, results of operations and financial condition.
On June 23, 2016, the U.K. voted to exit from the E.U. (commonly referred to as “Brexit”). The terms of Brexit and the resulting U.K./E.U. relationship are uncertain for companies doing business both in the U.K. and the overall global economy. In addition, our business and operations may be impacted by any subsequent vote in Scotland to seek independence from the U.K. Risks related to Brexit that we may encounter include:
adverse impact on macroeconomic growth and oil and gas demand resulting from the strength of the U.S. dollar;
continued volatility in currencies including the British pound and U.S. dollar that may impact our financial results;
reduced demand for our services in the U.K. and globally;
increased costs of doing business in the U.K. and in the North Sea;
increased regulatory costs and challenges for operating our business in the North Sea;
volatile capital and debt markets, and access to other sources of capital;
risks related to our global tax structure and the tax treaties upon which we rely;
business uncertainty resulting from prolonged political negotiations; and
uncertain stability of the E.U. and global economy if other countries exit the E.U.
ITEM 1B.  UNRESOLVED STAFF COMMENTS
The Company has no unresolved SEC staff comments.

18


ITEM 2.  PROPERTIES
Our primary U.S. offices are located in leased space in Houston, Texas. Additionally, we own or lease other office, maintenance and warehouse facilities in Texas, Scotland, Saudi Arabia, Bahrain, Dubai, Qatar, Trinidad, Norway, Luxembourg, Angola, Egypt, Singapore, Indonesia, Cyprus and Malaysia.
Drilling Rigs
Following are the principal drilling equipment owned by Rowan and their location at February 14, 2017.
 
 
Depth (feet)
 
 
Rig Name/Type
Class Name
Water (4)
Drilling (5)
Year of Shipyard Delivery
Location
 
 
 
 
 
 
Ultra-Deepwater Drillships:
 
 
 
 
 
Rowan Renaissance
Gusto MSC P10,000
12,000
40,000
2014
US GOM
Rowan Resolute
Gusto MSC P10,000
12,000
40,000
2014
US GOM
Rowan Reliance
Gusto MSC P10,000
12,000
40,000
2014
US GOM
Rowan Relentless
Gusto MSC P10,000
12,000
40,000
2015
US GOM
 
 
 
 
 
 
Jack-ups:
 
 
 
 
 
Rowan Norway (1)
N-Class
400
35,000
2011
U.K.
Rowan Stavanger (1)
N-Class
400
35,000
2011
U.K.
Rowan Viking (1)
N-Class
435
35,000
2010
Norway
Rowan EXL IV  (1)
EXL
320
35,000
2011
Bahrain
Rowan EXL III (1)
EXL
350
35,000
2010
US GOM
Rowan EXL II (1)
EXL
350
35,000
2010
Trinidad
Rowan EXL I (1)
EXL
350
35,000
2010
Bahrain
Joe Douglas (1)
240C
350
35,000
2012
Trinidad
Ralph Coffman (1)
240C
350
35,000
2009
Trinidad
Rowan Mississippi (1)
240C
375
35,000
2008
Saudi Arabia
J.P. Bussell (1)
Tarzan
300
35,000
2008
Bahrain
Hank Boswell (1)
Tarzan
300
35,000
2006
Saudi Arabia
Bob Keller (1)
Tarzan
300
35,000
2005
Saudi Arabia
Scooter Yeargain (1)
Tarzan
300
35,000
2004
Saudi Arabia
Bob Palmer (1)
Super Gorilla XL
475
35,000
2003
Saudi Arabia
Rowan Gorilla VII (1)
Super Gorilla
400
35,000
2001
U.K.
Rowan Gorilla VI (1)
Super Gorilla
400
35,000
2000
U.K.
Rowan Gorilla V (1)
Super Gorilla
400
35,000
1998
U.K.
Rowan Gorilla IV (1)
Gorilla
450
30,000
1986
US GOM
Rowan California (2)(3)
116C
300
25,000
1983
Bahrain
Cecil Provine (2)(3)
116C
300
25,000
1982
US GOM
Gilbert Rowe (2)
116C
300
30,000
1981
Saudi Arabia
Arch Rowan (2)
116C
300
25,000
1981
Saudi Arabia
Charles Rowan (2)
116C
300
25,000
1981
Saudi Arabia
Rowan Middletown (2)
116C
300
25,000
1980
Saudi Arabia
______________________________     
(1)     High-specification jack-up, which is defined as having hook-load capacity of at least two million pounds.
(2)     Premium jack-up, which is defined as an independent leg, cantilevered rig capable of operating in water depths of 300 feet or more.    
(3)     Currently cold-stacked.
(4)    Water depths are the maximum "rated" depths in the current region, as currently outfitted.
(5)    Maximum estimated drilling depth, subject to well characteristics and rig outfitting.

19


ITEM 3.  LEGAL PROCEEDINGS
We are involved in various routine legal proceedings incidental to our businesses and are vigorously defending our position in all such matters.  We believe there are no 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 February 24, 2017, 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.
Name
 Position
Age 
Thomas P. Burke
President and Chief Executive Officer
49
Stephen M. Butz
Executive Vice President and Chief Financial Officer
45
Mark A. Keller
Executive Vice President, Business Development
64
Melanie M. Trent
Executive Vice President, General Counsel, Chief Administrative Officer and Company Secretary
52
Dennis Baldwin
Chief Accounting Officer
56
T. Fred Brooks
Executive Vice President, Operations and Engineering
59
Dr. Burke was appointed Chief Executive Officer and elected a director of the Company in April 2014. He served as Chief Operating Officer beginning in July 2011 and was appointed President in March 2013. Dr. Burke first joined the Company in December 2009, serving as Chief Executive Officer and President of LeTourneau Technologies until the sale of LeTourneau in June 2011. From 2006 to 2009, Dr. Burke was a Division President at Complete Production Services, an oilfield services company, and from 2004 to 2006, served as its Vice President for Corporate Development.
Mr. Butz became Executive Vice President and Chief Financial Officer upon joining the Company in December 2014, and also served as Treasurer from December 2014 through February 2016. Prior to joining the Company, Mr. Butz served as Executive Vice President and Chief Financial Officer at Hercules Offshore, Inc. He was Senior Vice President and Chief Financial Officer of Hercules Offshore from 2010 to 2013 and held a number of other key positions after joining Hercules Offshore in 2005, including Director of Corporate Development and Vice President, Finance and Treasurer. Prior to joining Hercules Offshore, Mr. Butz held positions in both investment and commercial banking.
Since January 2007, Mr. Keller’s principal occupation has been Executive Vice President, Business Development. Prior to that time, Mr. Keller served as Senior Vice President, Marketing.
Ms. Trent became Executive Vice President and General Counsel in September 2014. Prior to that time, Ms. Trent served as Senior Vice President, Chief Administrative Officer and Company Secretary since 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.
Mr. Baldwin became Chief Accounting Officer in April 2016. Prior to joining the Company, he served as Vice President, Controller and Chief Accounting Officer for Cameron International Corporation from March 2014 until March 2016. Prior to such time, he was Senior Vice President and Chief Accounting Officer of KBR, Inc. from August 2010 to March 2014, and Vice President and Chief Accounting Officer of McDermott International from October 2007 to August 2010. He also previously served at Integrated Electrical Services and Veritas DGC.
Mr. Brooks became Executive Vice President, Operations and Engineering in February 2017. Prior to that time, he served as Senior Vice President, Operations from October 2012 through January 2017, and as Vice President, Deepwater Operations from March 2011 through September 2012. Prior to joining the Company, Mr. Brooks served as Senior Vice President of Operations at Northern Offshore from 2008 through 2010. He also served in various management positions at GlobalSantaFe from 1998 through 2007, including Vice President of West Africa Operations, and Vice President of Worldwide Deepwater & Gulf of Mexico Operations.

20


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.
 
 
2016
 
2015
Quarter
 
High
 
Low
 
High
 
Low
First
 
$
18.43

 
$
10.67

 
$
25.13

 
$
17.23

Second
 
19.94

 
14.58

 
24.31

 
17.56

Third
 
19.06

 
12.00

 
21.14

 
14.63

Fourth
 
21.68

 
13.02

 
21.83

 
15.41

On February 17, 2017, there were 72 shareholders of record. Many of our shareholders hold their shares in "street name" by a nominee of Depository Trust Company, which is one shareholder of record.
We declared and paid a dividend of $0.10 per share in each quarter of 2015. In January 2016, our Board of Directors discontinued dividend payments.

21


The graph below presents the relative investment performance of our ordinary shares, the Dow Jones U.S. Oil Equipment & Services Index, and the S&P 500 Index for the five-year period ended December 31, 2016, assuming reinvestment of dividends.
 chart2016a01.jpg

 
 
12/31/2011
 
12/31/2012
 
12/31/2013
 
12/31/2014
 
12/31/2015
12/31/2016
Rowan
 
100.00

 
103.10

 
116.58

 
77.73

 
57.62

64.21

S&P 500 Index
 
100.00

 
116.00

 
153.58

 
174.60

 
177.01

198.18

Dow Jones US Oil Equipment & Services Index
 
100.00

 
100.33

 
128.83

 
106.64

 
82.67

105.26



22


Issuer Purchases of Equity Securities
The following table summarizes acquisitions of our shares for the fourth quarter of 2016:
Month ended
 
Total number of shares purchased 1
 
Average price paid per share 1
 
Total number of shares purchased as part of publicly announced plans or programs2
 
Approximate dollar value of shares that may yet be purchased under the plans or programs2
October 31, 2016
 
3,495

 
$
14.16

 

 
$

November 30, 2016
 
2,003,817

 
$
0.16

 

 
$

December 31, 2016
 
2,625

 
$
18.10

 

 
$

Total
 
2,009,937

 
$
0.20

 

 
 

 
 
 
 
 
 
 
 
 
(1) The total number of shares acquired includes shares acquired from employees by an affiliated employee benefit trust ("EBT") upon forfeiture of nonvested awards or in satisfaction of tax withholding requirements and shares purchased, if any, pursuant to a publicly announced share repurchase program. The price paid for shares acquired as a result of forfeitures is the nominal value of $0.125 per share. The price paid for shares acquired in satisfaction of withholding taxes is the share price on the date of the transaction. In November 2016, the Company issued 2.0 million shares to the EBT, which shares were acquired at a price equal to the nominal value of $0.125 per share. There were no shares repurchased under any share repurchase program during the fourth quarter of 2016.
(2)  The ability to make share repurchases is subject to the discretion of the Board of Directors and the limitations set forth in the Companies Act, which generally provide that share repurchases may only be made out of distributable reserves. In addition, U.K. law also generally prohibits a company from repurchasing its own shares through “off market purchases” without the prior approval of shareholders, which approval lasts for a maximum period of five years. Prior to and in connection with the redomestication, the Company obtained approval to purchase its own shares. To effect such repurchases, the Company entered into a purchase agreement with a specified dealer in July 2012, pursuant to which the Company may purchase up to a maximum of 50,000,000 shares over a five-year period, subject to an annual cap of 10% of the shares outstanding at the beginning of each applicable year. Subject to Board approval, share repurchases may be commenced or suspended from time to time without prior notice and, in accordance with the shareholder approval and U.K. law, any shares repurchased by the Company will be cancelled. The authority to repurchase shares terminates in April 2017 unless otherwise reapproved by the Company’s shareholders. U.K. law prohibits the Company from purchasing its shares in the open market because Rowan is not traded on a recognized investment exchange in the U.K.
For information concerning our shares to be issued in connection with equity compensation plans, see Part III, Item 12, “Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters,” of this Form 10-K.

23


ITEM 6.  SELECTED FINANCIAL DATA
Selected financial data for each of the last five years is presented below:
 
2016
 
2015
 
2014
 
2013
 
2012
 
(Dollars in millions, except per share amounts)
Operations
 
 
 
 
 
 
 
 
 
Revenues
$
1,843.2

 
$
2,137.0

 
$
1,824.4

 
$
1,579.3

 
$
1,392.6

Costs and expenses:
 

 
 

 
 

 
 

 
 

Direct operating costs (excluding items shown below)
778.2

 
993.1

 
991.3

 
860.9

 
752.2

Depreciation and amortization
402.9

 
391.4

 
322.6

 
271.0

 
247.9

Selling, general and administrative
102.1

 
115.8

 
125.8

 
131.3

 
99.7

(Gain) loss on disposals of property and equipment
8.7

 
(7.7
)
 
(1.7
)
 
(20.1
)
 
(2.5
)
Gain on litigation settlement (1)

 

 
(20.9
)
 

 
(4.7
)
Material charges and other operating items (2)
32.9

 
337.3

 
574.0

 
4.5

 
45.0

Total costs and expenses
1,324.8

 
1,829.9

 
1,991.1

 
1,247.6

 
1,137.6

Income (loss) from operations
518.4

 
307.1

 
(166.7
)
 
331.7

 
255.0

Other income (expense) — net (3)
(192.8
)
 
(149.4
)
 
(102.9
)
 
(70.5
)
 
(71.5
)
Income (loss) from continuing operations before income taxes
325.6

 
157.7

 
(269.6
)
 
261.2

 
183.5

Provision (benefit) for income taxes
5.0

 
64.4

 
(150.7
)
 
8.6

 
(19.8
)
Income (loss) from continuing operations
320.6

 
93.3

 
(118.9
)
 
252.6

 
203.3

Discontinued operations, net of taxes (4)

 

 
4.0

 

 
(22.7
)
Net income (loss)
$
320.6

 
$
93.3

 
$
(114.9
)
 
$
252.6

 
$
180.6

Basic income (loss) per common share:
 

 
 

 
 

 
 

 
 

Income (loss) from continuing operations
$
2.56

 
$
0.75

 
$
(0.96
)
 
$
2.04

 
$
1.65

Income (loss) from discontinued operations

 

 
0.03

 

 
(0.18
)
Net income (loss)
$
2.56

 
$
0.75

 
$
(0.93
)
 
$
2.04

 
$
1.47

Diluted income (loss) per common share:
 

 
 

 
 

 
 

 
 

Income (loss) from continuing operations
$
2.55

 
$
0.75

 
$
(0.96
)
 
$
2.03

 
$
1.64

Income (loss) from discontinued operations

 

 
0.03

 

 
(0.18
)
Net income (loss)
$
2.55

 
$
0.75

 
$
(0.93
)
 
$
2.03

 
$
1.46

Financial Position
 

 
 

 
 

 
 

 
 

Cash and cash equivalents
$
1,255.5

 
$
484.2

 
$
339.2

 
$
1,092.8

 
$
1,024.0

Property and equipment — net
$
7,060.0

 
$
7,405.8

 
$
7,432.2

 
$
6,385.8

 
$
6,071.7

Total assets
$
8,675.6

 
$
8,347.3

 
$
8,392.3

 
$
7,975.8

 
$
7,699.5

Current portion of long-term debt
$
126.8

 
$

 
$

 
$

 
$

Long-term debt, less current portion
$
2,553.4

 
$
2,692.4

 
$
2,788.5

 
$
2,008.7

 
$
2,009.6

Shareholders’ equity
$
5,113.9

 
$
4,772.5

 
$
4,691.4

 
$
4,893.8

 
$
4,531.7

Statistical Information
 

 
 

 
 

 
 

 
 

Current ratio (5)
3.27

 
2.80

 
2.82

 
4.50

 
5.61

Debt to capitalization ratio
34
%
 
36
%
 
37
%

29
%

31
%
Book value per share of common stock outstanding
$
40.76

 
$
38.24

 
$
37.66

 
$
39.39

 
$
36.48

Price range of common stock:
 

 
 

 
 

 
 

 
 

High
$
21.68

 
$
25.13

 
$
35.17

 
$
38.65

 
$
39.40

Low
$
10.67

 
$
14.63

 
$
19.50

 
$
30.21

 
$
28.62

Cash dividends declared per share
$

 
$
0.40

 
$
0.30

 
$

 
$

___________________
(1)
Gain on litigation settlement includes: 2014 – a gain of $20.9 million in cash received for damages incurred as a result of a tanker’s collision with the Rowan EXL I in 2012; and 2012 – a $4.7 million gain for cash received in connection with the settlement of a 2005 dispute with a customer.
(2)
Material charges and other operating expenses consisted of the following: 2016 – $34.3 million of non-cash impairment charges and a $1.4 million reversal of an estimated liability for settlement of a withholding tax matter during a tax amnesty period which was related to a legal settlement for a 2014 termination of a contract for refurbishment work on the Rowan Gorilla III, as noted below in the 2015 period. A payment of such withholding taxes during the tax amnesty period resulted in the waiver of applicable penalties and interest; 2015 – $329.8 million of non-cash asset impairment charges and a $7.6 million adjustment to an estimated liability for the 2014 termination of a contract for refurbishment work on the Rowan Gorilla III. A settlement agreement for this matter was signed during the third quarter of 2015; 2014 – $574.0 million of non-cash asset impairment charges; 2013 – $4.5 million of non-cash asset impairment charges; and 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 Rowan 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 non-cash asset impairment charges, and $2.3 million of incremental non-cash share-based compensation cost in connection with the retirement of an employee.
(3)
In 2016, other income (expense), net includes $31.2 million loss on debt extinguishment.

24


(4)
In 2011, the Company sold its manufacturing and land drilling operations, which are classified as discontinued operations. In 2014, we sold a land rig retained from the sale and recognized a $4.0 million gain, net of tax.
(5)
Current ratio excludes assets and liabilities of discontinued operations.
ITEM 7.  MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
OUR BUSINESS
Rowan plc is a global provider of offshore contract drilling services to the international oil and gas industry, with a focus on high-specification and premium jack-up rigs and ultra-deepwater drillships. Our fleet currently consists of 29 mobile offshore drilling units, including 25 self-elevating jack-up rigs and four ultra-deepwater drillships. Our fleet operates worldwide, including the United States Gulf of Mexico, the United Kingdom and Norwegian sectors of the North Sea, the Middle East and Trinidad.
As of February 14, 2017, the date of our most recent Fleet Status Report, two of our four drillships were under contract in the US GOM. Additionally, we had three jack-up rigs under contract in the North Sea, nine under contract in the Middle East, three under contract in Trinidad and two under contract in the US GOM. We had an additional six marketed jack-up rigs, two cold-stacked jack-up rigs and two marketed drillships without a contract.
We contract our drilling rigs, related equipment and work crews primarily on a “day rate” basis. Under day rate contracts, we generally receive a fixed amount per day for each day we are performing drilling or related services. In addition, our customers may pay all or a portion of the cost of moving our equipment and personnel to and from the well site. Contracts generally range in duration from one month to multiple years.
Joint Venture
On November 21, 2016, Rowan and the Saudi Arabian Oil Company (“Saudi Aramco”), through their subsidiaries, entered into a Shareholders’ Agreement to create a 50/50 joint venture to own, manage and operate offshore drilling units in Saudi Arabia. The new entity is anticipated to commence operations in the second quarter of 2017 (see Part I, Item 1, "Business" of this Form 10-K).
Customer Contract Termination and Settlement
On May 23, 2016, we reached an agreement with Freeport-McMoRan Oil and Gas LLC (“FMOG”) and its parent company, Freeport-McMoRan Inc. (“FCX”) in connection with the drilling contract for the drillship Rowan Relentless (“FMOG Agreement”), which was scheduled to terminate in June 2017. The FMOG Agreement provided that the drilling contract be terminated immediately, and that FCX pay us $215 million to settle outstanding receivables and early termination of the contract, which was received in 2016. In addition, we signed rights to receive two additional contingent payments from FCX, payable on September 30, 2017, of $10 million and $20 million depending on the average price of West Texas Intermediate (“WTI”) crude oil over a 12-month period beginning June 30, 2016. The $10 million payment will be due if the average price over the period is greater than $50 per barrel and the additional $20 million payment will be due if the average price over the period is greater than $65 per barrel (“FMOG Provision”). The Company warm-stacked the Rowan Relentless in order to reduce costs. During the quarter ended June 30, 2016, the Company recognized $173.2 million in revenue for the Rowan Relentless, including $130.9 million for the cancelled contract value, $6.2 million for the fair value of the derivative associated with the FMOG Provision, $5.6 million for previously deferred revenue related to the contract, and $30.5 million for operations through May 22, 2016. In January 2017, Rowan and FCX settled the $10 million contingent payment provision with a $6.0 million payment received by Rowan.
Customer Contract Amendment
On September 15, 2016, we amended our contract with Cobalt International Energy, L.P. (“Cobalt”), for the drillship Rowan Reliance, which was scheduled to conclude on February 1, 2018. The amendment provided cash settlement payments to Rowan totaling $95.9 million, that the drillship remains at its current day rate of approximately $582,000 and that the drilling contract may be terminated as early as March 31, 2017. The Company received cash payments totaling $76.3 million in 2016 and expects to receive a final cash payment of $19.6 million on or before March 31, 2017. In addition, if Cobalt continues its operations with the Rowan Reliance after March 31, 2017, the day rate will be reduced to approximately $262,000 per day for the remaining operating days through February 1, 2018 (subject to further adjustment thereafter). Cobalt International Energy, Inc., the parent of Cobalt, also committed to use the Company as its exclusive provider of comparable drilling services for a period of five years. As we have the obligation and intent to have the drillship or a substitute available through the pre-amended contract scheduled end date, in certain circumstances, the $95.9 million settlement was recorded as a deferred revenue liability. As of December 31, 2016, $86.5 million and $9.4 million of the deferred revenue liability is classified as current and noncurrent, respectively, and is included in Deferred Revenue, and Other Liabilities, respectively, in the Consolidated Balance Sheet. Amortization of deferred

25


revenue will begin on April 1, 2017 and extend no further than the pre-amended contract scheduled end date.
CURRENT BUSINESS ENVIRONMENT
Despite some recent signs of stabilization in commodity prices, the business environment for offshore drillers continues to be challenging as operators' capital expenditures have declined dramatically over the past two years. The resulting cancellation or postponement of drilling programs have resulted in significantly reduced demand for offshore drilling services globally. Additionally, the 231 new jack-ups and 158 new floaters that have been delivered since the beginning of the current newbuild cycle in early 2006 have exacerbated the situation. The rate of drilling contract terminations and expirations has continued to outpace new contract awards, resulting in reduced rig utilization and downward pressure on day rates. We expect this dynamic to continue in 2017. Contractors have responded by stacking certain idle equipment and deferring newbuild deliveries, however, the jack-up and floater markets remain oversupplied.
Further, as of February 14, 2017, there were 103 additional jack-up rigs on order or under construction worldwide for delivery through 2020 (relative to approximately 310 jack-up rigs currently on contract), and 48 floaters on order or under construction worldwide for delivery through 2020 (relative to approximately 149 floater rigs currently on contract). Only five jack-ups and 18 floaters currently on order or under construction have contracts secured for their future delivery dates. We expect several of these rigs may eventually be cancelled and many others will likely continue to be deferred until a recovery in demand is visible.
In response to market conditions over the past two years, we have reduced day rates on certain drilling contracts, some in exchange for extended contract duration, sold five of our oldest jack-ups, cold-stacked two of our older jack-ups, and have warm stacked five of our jack-ups and two of our ultra-deepwater drillships. We have agreed to one termination of an ultra-deepwater drillship contract and agreed to reduce the duration of another contract in exchange for certain upfront payments. Similarly, we have had two early terminations of jack-up rig contracts in recent months. Though in each case we have received or expect to receive a substantial portion of the backlog, these terminations add to the number of rigs available for work over the near term, likely increasing idle time in our fleet.
While we have seen some recent improvement in tender activity, given the current supply and demand dynamics and in the absence of a sustained recovery in commodity prices, we expect the business environment to continue to deteriorate in 2017 for the broad market. We believe that utilization rates for jack-ups could bottom sometime in 2017, and floater utilization could bottom sometime in 2018. These market conditions have increased our risk of customer defaults, restructurings or insolvency which may prompt further renegotiations or terminations of our drilling contracts.
However, we believe that we are strategically well-positioned to take advantage of the expected increase in activity given our strong and stable financial condition, current backlog of $1.7 billion as of February 14, 2017 (excluding anticipated changes to the Middle East fleet due to the formation of the 50/50 joint venture with Saudi Aramco expected to commence operations in second quarter 2017, see Part I, Item 1, "Business" of this Form 10-K), solid operational reputation, and modern fleet of high-specification jack-ups and state-of-the-art ultra-deepwater drillships. While challenging market conditions persist, we continue to focus on operating and cost efficiencies which could include cold-stacking or retiring additional drilling rigs, layoffs or other cost cutting initiatives.


26


RESULTS OF OPERATIONS
The following table presents certain key performance indicators by rig classification:
 
2016
 
2015
 
2014
Revenues (in millions):
 
 
 
 
 
Deepwater
$
824.7

 
$
730.8

 
$
170.5

Jack-ups
994.7

 
1,361.3

 
1,598.8

Subtotal - Day rate revenues
1,819.4

 
2,092.1

 
1,769.3

Other revenues (1)
23.8

 
44.9

 
55.1

Total revenues
$
1,843.2

 
$
2,137.0

 
$
1,824.4

 
 
 
 
 
 
Revenue-producing days:
 
 
 
 
 
Deepwater
1,238

 
1,178

 
262

Jack-ups
5,999

 
7,852

 
9,019

Total revenue-producing days
7,237

 
9,030

 
9,281

 
 
 
 
 
 
Available days: (2)
 
 
 

 
 

Deepwater
1,464

 
1,263

 
330

Jack-ups
8,784

 
9,558

 
10,220

Total available days
10,248

 
10,821

 
10,550

 
 
 
 
 
 
Average day rate (in thousands): (3)
 

 
 

 
 

Deepwater (4)
$
550.7

 
$
620.5

 
$
650.4

Jack-ups
$
165.8

 
$
173.4

 
$
177.3

Total fleet (4)
$
231.7

 
$
231.7

 
$
190.6

 
 
 
 
 
 
Utilization: (5)
 
 
 
 
 
Deepwater
85
%
 
93
%
 
80
%
Jack-ups
68
%
 
82
%
 
88
%
Total fleet
71
%
 
83
%
 
88
%
 
 
 
 
 
 
(1) Other revenues, which are primarily revenues received for contract reimbursable costs, are excluded from the computation of average day rate.
(2) Available days are defined as the aggregate number of calendar days (excluding days for which a rig is cold-stacked) in the period, or, with respect to new rigs entering service, the number of calendar days in the period from the date the rig was placed in service.
(3) Average day rate is computed by dividing day rate revenues by the number of revenue-producing days, including fractional days. Day rate revenues include the contractual rates and amounts received in lump sum, such as for rig mobilization or capital improvements, which are amortized over the initial term of the contract. Revenues attributable to reimbursable expenses are excluded from average day rates.
(4) Average day rate for 2016 includes operating days for the Rowan Relentless up to the contract termination which was 143 days for 2016.
(5) Utilization is the number of revenue-producing days, including fractional days, divided by the number of available days.

27


Rig Utilization
The following table sets forth an analysis of time that our rigs were idle or out-of-service as a percentage of available days (which excludes cold-stacked rigs) and time that our rigs experience operational downtime and are off-rate as a percentage of revenue-producing day:
 
2016
 
2015
 
2014
Deepwater:
 
 
 
 
 
Idle (1)
15.2
%
 

 

Out-of-service (2) (3)
0.1
%
 

 
15.1
%
Operational downtime (4)
0.1
%
 
6.7
%
 
6.3
%
 
 
 
 
 
 
Jack-up:
 
 
 
 
 
Idle (1)
25.4
%
 
13.5
%
 
1.4
%
Out-of-service (2)
5.3
%
 
3.3
%
 
9.5
%
Operational downtime (4)
1.4
%
 
1.2
%
 
1.0
%
 
 
 
 
 
 
(1) Idle Days – We define idle days as the time a rig is not under contract and is available to work. Idle days exclude cold-stacked rigs, which are not marketed.
(2) Out-of-Service Days – We define out-of-service days as those days when a rig is (or is planned to be) out of service and is not able to earn revenue. 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 primary term of the drilling contract.
(3) Out-of-service time for our deepwater fleet for 2014 included 27 days attributable to the Rowan Resolute (35% of in-service time) for commissioning.
(4) Operational Downtime – We define operational downtime as the unbillable time when a rig is under contract and unable to conduct planned operations due to equipment breakdowns or procedural failures.

28


2016 Compared to 2015
A summary of our consolidated results of operations follows (in millions):
 
Year ended December 31,
 
 
 
 
 
2016
 
2015
 
Change
 
% Change
Deepwater:
 
 
 
 
 
 
 
Revenues
$
827.5

 
$
747.8

 
$
79.7

 
11
 %
Operating expenses:
 
 
 
 
 
 
 
Direct operating costs (excluding items below)
222.0

 
276.6

 
(54.6
)
 
(20
)%
Depreciation and amortization
115.0

 
94.6

 
20.4

 
22
 %
Other operating items
0.1

 

 
0.1

 
n/m

Income from operations
$
490.4

 
$
376.6

 
$
113.8

 
30
 %
 
 
 
 
 
 
 
 
Jack-ups:
 
 
 
 
 
 
 
Revenues
$
1,015.7

 
$
1,389.2

 
$
(373.5
)
 
(27
)%
Operating expenses:
 
 
 
 
 
 
 
Direct operating costs (excluding items below)
556.2

 
716.5

 
(160.3
)
 
(22
)%
Depreciation and amortization
282.6

 
283.9

 
(1.3
)
 
 %
Other operating items
40.9

 
328.8

 
(287.9
)
 
n/m

Income from operations
$
136.0

 
$
60.0

 
$
76.0

 
127
 %
 
 
 
 
 
 
 
 
Unallocated costs and other:
 
 
 
 
 
 
 
Operating expenses:
 
 
 
 
 
 
 
Depreciation and amortization
$
5.3

 
$
12.9

 
$
(7.6
)
 
(59
)%
Selling, general and administrative
102.1

 
115.8

 
(13.7
)
 
(12
)%
Other operating items
0.6

 
0.8

 
(0.2
)
 
n/m

Loss from operations
$
(108.0
)
 
$
(129.5
)
 
$
21.5

 
(17
)%
 
 
 
 
 
 
 
 
Total company:
 
 
 
 
 
 
 
Revenues
$
1,843.2

 
$
2,137.0

 
$
(293.8
)
 
(14
)%
Direct operating costs (excluding items below)
778.2

 
993.1

 
(214.9
)
 
(22
)%
Depreciation and amortization
402.9

 
391.4

 
11.5

 
3
 %
Selling, general and administrative
102.1

 
115.8

 
(13.7
)
 
(12
)%
Other operating items
41.6

 
329.6

 
(288.0
)
 
n/m

Income from operations
518.4

 
307.1

 
211.3

 
69
 %
Other (expense), net
(192.8
)
 
(149.4
)
 
(43.4
)
 
29
 %
Income from continuing operations before income taxes
325.6

 
157.7

 
167.9

 
106
 %
Provision for income taxes
5.0

 
64.4

 
(59.4
)
 
(92
)%
Income from continuing operations
320.6

 
93.3

 
227.3

 
244
 %
Discontinued operations, net of tax

 

 

 
n/m

Net income
$
320.6

 
$
93.3

 
$
227.3

 
244
 %
 
 
 
 
 
 
 
 
“n/m” means not meaningful.
 
 
 
 
 
 
 

29


Revenues
Consolidated. The decrease in consolidated revenue is described below.
Deepwater. An analysis of the net changes in revenues for 2016, compared to 2015, are set forth below (in millions):
 
Increase (decrease)
Contract termination for Rowan Relentless and related items
$
142.7

Rowan Reliance and Rowan Relentless fully in service in 2016 versus startup in February and June of 2015, respectively, net of idle time in the current period
21.5

Lower unbillable downtime
14.6

Lower drillship average day rates
(84.8
)
Lower reimbursable revenues
(14.3
)
Net increase
$
79.7

Jack-ups. An analysis of the net changes in revenues for 2016, compared to 2015, are set forth below (in millions):
 
Increase (Decrease)
Lower jack-up utilization
$
(319.8
)
Lower jack-up average day rates
(46.1
)
Lower reimbursable revenues
(7.9
)
Other
0.3

Net decrease
$
(373.5
)
Direct operating costs
Consolidated. The decrease in consolidated direct operating costs is described below.
Deepwater. An analysis of the net changes in direct operating costs for 2016, compared to 2015, are set forth below (in millions):
 
Increase (decrease)
Addition of the Rowan Reliance and Rowan Relentless
$
19.7

Reduction in drillship direct operating expense
(34.8
)
Decrease due to idle drillship
(15.4
)
Lower reimbursable costs
(14.3
)
Reduction in shore base costs and other
(9.8
)
Net decrease
$
(54.6
)
Jack-ups. An analysis of the net changes in direct operating costs for 2016, compared to 2015, are set forth below (in millions):
 
Decrease
Decrease due to idle or cold-stacked rigs
$
(115.9
)
Reduction in jack-up direct operating expense
(29.9
)
Lower reimbursable costs
(7.9
)
Reduction in shore base costs and other
(6.6
)
Decrease
$
(160.3
)
Depreciation and amortization
Depreciation and amortization for 2016 increased largely due to the addition of the Rowan Reliance and Rowan Relentless in 2015.

30


Selling, general and administrative
Selling, general and administrative expenses for 2016 decreased largely due to lower personnel costs. In addition, professional fees and information technology expenses decreased in 2016 as compared to 2015.
Other operating items
Material charges for 2016 included a $34.3 million non-cash impairment charge to reduce the carrying values of five of our jack-up drilling units, partially offset by a $1.4 million reversal of an estimated liability for settlement of a withholding tax matter during a tax amnesty period which was related to a legal settlement for a 2014 termination of a contract for refurbishment work on the Rowan Gorilla III, as noted below in the 2015 period. Payment of such withholding taxes during the tax amnesty period resulted in the waiver of applicable penalties and interest.
Material charges for 2015 included a $329.8 million non-cash impairment charge to reduce the carrying values of ten of our jack-up drilling units and a $7.6 million adjustment to an estimated liability for the 2014 termination of a contract for refurbishment work on the Rowan Gorilla III. A settlement agreement for this matter was signed during the third quarter of 2015.
In 2016 we had a loss on disposals of property and equipment of $8.7 million, compared to a gain of $7.7 million in 2015.
Other expense, net
The increase in Other Expense, Net, is primarily due to a $31.2 million net loss on the early extinguishment of debt in 2016 compared to $1.5 million in 2015. Interest capitalization was $16.2 million in 2015. There was no interest capitalization in 2016 as the drillship construction program was completed in 2015. Additionally, our foreign currency exchange losses increased to $9.7 million in 2016 compared to $3.9 million in 2015 primarily due to the devaluation of the Egyptian pound. Partially offsetting these increases, our debt retirements in late 2015 and early 2016 resulted in a reduction in interest expense in 2016.
Provision for income taxes
In 2016, we recognized an income tax provision of $5.0 million on pretax income of $325.6 million. The 2016 tax provision was primarily due to the current year operations offset by the amortization of deferred intercompany gains and losses and deferred tax benefit as a result of current year restructuring.
In 2015, we recognized an income tax provision of $64.4 million on pretax income of $157.7 million. The 2015 tax provision was primarily due to the establishment of a valuation allowance on the U.S. deferred tax assets, impairments of assets in foreign jurisdictions with no tax benefits, and an increase in income in high-tax jurisdictions, offset by additional tax benefit for the U.S.-impaired assets and an increase in income in low-tax jurisdictions.

31


2015 Compared to 2014
A summary of our consolidated results of operations follows (in millions):
 
Year ended December 31,
 
 
 
 
 
2015
 
2014
 
Change
 
% Change
Deepwater:
 
 
 
 
 
 
 
Revenues
$
747.8

 
$
179.8

 
$
568.0

 
316
 %
Operating expenses:
 
 
 
 
 
 
 
Direct operating costs (excluding items below)
276.6

 
87.8

 
188.8

 
215
 %
Depreciation and amortization
94.6

 
24.4

 
70.2

 
288
 %
Income from operations
$
376.6

 
$
67.6

 
$
309.0

 
457
 %
 
 
 
 
 
 
 
 
Jack-ups:
 
 
 
 
 
 
 
Revenues
$
1,389.2

 
$
1,644.6

 
$
(255.4
)
 
(16
)%
Operating expenses:
 
 
 
 
 
 
 
Direct operating costs (excluding items below)
716.5

 
903.5

 
(187.0
)
 
(21
)%
Depreciation and amortization
283.9

 
283.5

 
0.4

 
 %
Other operating items
328.8

 
544.9

 
(216.1
)
 
n/m

Income (loss) from operations
$
60.0

 
$
(87.3
)
 
$
147.3

 
n/m

 
 
 
 
 
 
 
 
Unallocated costs and other:
 
 
 
 
 
 
 
Operating expenses:
 
 
 
 
 
 
 
Depreciation and amortization
$
12.9

 
$
14.7

 
$
(1.8
)
 
(12
)%
Selling, general and administrative
115.8

 
125.8

 
(10.0
)
 
(8
)%
Other operating items
0.8

 
6.5

 
(5.7
)
 
n/m

Loss from operations
$
(129.5
)
 
$
(147.0
)
 
$
17.5

 
(12
)%
 
 
 
 
 
 
 
 
Total company:
 
 
 
 
 
 
 
Revenues
$
2,137.0

 
$
1,824.4

 
$
312.6

 
17
 %
Direct operating costs (excluding items below)
993.1

 
991.3

 
1.8

 
 %
Depreciation and amortization
391.4

 
322.6

 
68.8

 
21
 %
Selling, general and administrative
115.8

 
125.8

 
(10.0
)
 
(8
)%
Other operating items
329.6

 
551.4

 
(221.8
)
 
n/m

Income (loss) from operations
307.1

 
(166.7
)
 
473.8

 
n/m

Other (expense), net
(149.4
)
 
(102.9
)
 
(46.5
)
 
45
 %
Income (loss) from continuing operations before income taxes
157.7

 
(269.6
)
 
427.3

 
n/m

Provision (benefit) for income taxes
64.4

 
(150.7
)
 
215.1

 
n/m

Income (loss) from continuing operations
93.3

 
(118.9
)
 
212.2

 
n/m

Discontinued operations, net of tax

 
4.0

 
(4.0
)
 
n/m

Net income (loss)
$
93.3

 
$
(114.9
)
 
$
208.2

 
n/m

 
 
 
 
 
 
 
 
“n/m” means not meaningful.
 
 
 
 
 
 
 


32


Revenues
Consolidated. The increase in consolidated revenue is described below.
Deepwater. An analysis of the net changes in revenues for 2015, compared to 2014, are set forth below (in millions):
 
Increase
Addition of the Rowan Reliance and Rowan Relentless in 2015
$
290.4

Addition of the Rowan Renaissance and Rowan Resolute in 2014
269.9

Revenues for reimbursable costs and other, net
7.7

Increase
$
568.0

Jack-ups. An analysis of the net changes in revenues for 2015, compared to 2014, are set forth below (in millions):
 
Decrease
Lower jack-up utilization
$
(206.9
)
Lower average day rates for existing rigs
(30.6
)
Revenues for reimbursable costs and other, net
(17.9
)
Decrease
$
(255.4
)
Direct operating costs
Consolidated. An analysis of the net changes in direct operating costs for 2015, compared to 2014, are set forth below (in millions):
 
Increase (decrease)
2015 Compared to 2014:
 
Addition of the Rowan Reliance and Rowan Relentless in 2015
$
76.4

Addition of the Rowan Renaissance and Rowan Resolute in 2014
68.4

Return to work of the Rowan Gorilla III, Rowan Gorilla VI and the Rowan Viking
32.2

Decrease due to idle, sold or cold-stacked rigs
(75.8
)
Reduction of regional shorebases
(13.5
)
Reimbursable costs
(10.1
)
Other, net - primarily repair and maintenance and personnel costs for other rigs
(75.8
)
Net increase
$
1.8

Depreciation and amortization
The increase in depreciation was primarily due to the addition of the four drillships.
Selling, general and administrative
Selling, general and administrative expenses decreased primarily due to cost-reduction measures, which included reductions in headcount and fewer professional services.
Other operating items
As a result of the extended downturn in the market for offshore contract drilling services, we conducted an impairment test of our assets in 2015 and determined that the carrying values for ten of our jack-up rigs were not recoverable from their undiscounted expected future cash flows and exceeded their fair values. As a result, we recognized an aggregate non-cash asset impairment charge in 2015 in the amount of $329.8 million. In 2014, we recognized non-cash asset impairment charges totaling $565.7 million on twelve jack-up rigs and a charge of $8.3 million for impairment of a Company aircraft, which we sold later in 2014 at an immaterial loss.
In 2015, we sold the Rowan Louisiana, Rowan Alaska and Rowan Juneau jack-up drilling rigs in separate sales and recognized a net gain totaling $8.8 million on proceeds of $15.9 million.

33


In 2015, we recognized a $7.6 million charge for the termination of a contract in connection with refurbishment work on the Rowan Gorilla III.
In 2014, the Company settled its litigation with the owners and operators of a tanker that collided with the Rowan EXL I in 2012 and received $20.9 million in cash as compensation for damages incurred in 2012 for repair costs to and loss of use of the rig. We recognized the cash receipt in 2014 as a component of operating income.
Provision (benefit) for income taxes
In 2015, we recognized an income tax provision of $64.4 million on pretax income of $157.7 million. The 2015 tax provision was primarily due to the establishment of a valuation allowance on the U.S. deferred tax assets, impairments of assets in foreign jurisdictions with no tax benefits, and an increase in income in high-tax jurisdictions, offset by additional tax benefit for the U.S.-impaired assets and an increase in income in low-tax jurisdictions.
In 2014, we recognized an income tax benefit of $150.7 million on a $269.6 million pretax loss from continuing operations. The benefit was primarily due to the acceleration of previously deferred intercompany gains and losses associated with impaired assets, the amortization of deferred intercompany gains and losses related to outbounding certain U.S.-owned rigs to our non-U.S. subsidiaries in prior years, and the settlement agreement reached with the U.S. Internal Revenue Service in September 2014.
Discontinued operations, net of tax
In 2014, we sold a land rig that was retained in connection with the 2011 sale of the Company's manufacturing operations and recognized a gain on sale of $4.0 million, net of tax effects.
LIQUIDITY AND CAPITAL RESOURCES
Key balance sheet amounts and ratios at December 31 were as follows (dollars in millions):
 
2016
 
2015
Cash and cash equivalents
$
1,255.5

 
$
484.2

Current assets
$
1,580.3

 
$
921.3

Current liabilities
$
483.8

 
$
328.7

Current ratio
3.27

 
2.80

Current portion of long-term debt
$
126.8

 
$

Long-term debt, less current portion
$
2,553.4

 
$
2,692.4

Shareholders' equity
$
5,113.9

 
$
4,772.5

Debt to capitalization ratio
34
%
 
36
%

Sources and uses of cash and cash equivalents were as follows (in millions):
 
2016
 
2015
 
2014
Net operating cash flows
$
900.6

 
$
996.9

 
$
423.0

Borrowings, net of issue costs
491.3

 
220.0

 
792.7

Reduction of long-term debt
(511.8
)
 
(317.9
)
 

Capital expenditures
(117.6
)
 
(722.9
)
 
(1,958.2
)
Payment of cash dividends

 
(50.5
)
 
(37.7
)
Proceeds from disposals of property and equipment
6.2

 
19.4

 
22.0

Proceeds from exercise of share options

 

 
4.7

All other, net
2.6

 

 
(0.1
)
Total net source (use)
$
771.3

 
$
145.0

 
$
(753.6
)
Operating Cash Flows
Cash flows from operations decreased to approximately $901 million in 2016 from $997 million in 2015 primarily due to lower drilling activity, the cash loss on early extinguishment of debt, combined with uses of cash for current assets and liabilities, partially offset by deferred revenues and changes in other non-current assets and liabilities. Operating cash flows for 2015 compared to

34


2014 were positively impacted by the startup of the drillships in 2014 and 2015 and favorable changes in working capital, including lower pension contributions in 2015.
We have not provided deferred income taxes on certain undistributed earnings of non-U.K. subsidiaries. Generally, earnings of non-U.K. subsidiaries in which RCI does not have a direct or indirect ownership interest can be distributed to Rowan plc without imposition of either U.K. or local country tax. It is generally our policy and intention to permanently reinvest earnings of non-U.S. subsidiaries of RCI outside the U.S. However, we have recognized taxes related to the earnings of certain subsidiaries that are not permanently reinvested or that will not be permanently reinvested in the future.
As of December 31, 2016, RCI's portion of the unremitted earnings of its non-U.S. subsidiaries that could be includable in taxable income of RCI, if distributed, was approximately $376 million. If facts and circumstances cause us to change our expectations regarding future tax consequences, the resulting tax impact could have a material effect on our consolidated financial statements. Should the non-U.S. subsidiaries of RCI make a distribution from these earnings, we may be subject to additional 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, 2016, RCI’s non-U.S. subsidiaries held approximately $328 million of the $1.256 billion of consolidated cash and cash equivalents. Management believes the Company has significant net assets, liquidity, contract backlog and/or other financial resources available to meet our 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.
Backlog
Our backlog by geographic area as of the date of our most recent Fleet Status Report is presented below (in millions):
 
February 14, 2017
 
Jack-ups
 
Deepwater
 
Total
US GOM
$
21.5

 
$
486.7

 
$
508.2

Middle East (1)
914.2

 

 
914.2

North Sea
189.8

 

 
189.8

Central and South America
72.4

 

 
72.4

 Total backlog
$
1,197.9

 
$
486.7

 
$
1,684.6

 
 
 
 
 
 
(1) Backlog does not account for the anticipated changes to the Middle East fleet due to the formation of the 50/50 joint venture with Saudi Aramco expected to commence operations in second quarter 2017 (see Part I, Item 1, "Business" of this Form 10-K).
We estimate our backlog will be realized as follows (in millions):
 
February 14, 2017
 
Jack-ups
 
Deepwater
 
Total
2017
$
554.7

 
$
350.8

 
$
905.5

2018
294.5

 
135.9

 
430.4

2019
65.0

 

 
65.0

2020
65.0

 

 
65.0

2021 and later years
218.7

 

 
218.7

 Total backlog
$
1,197.9

 
$
486.7

 
$
1,684.6

 
 
 
 
 
 
Backlog does not account for the anticipated changes to the Middle East fleet due to the formation of the 50/50 joint venture with Saudi Aramco expected to commence operations in second quarter 2017 (see Part I, Item 1, "Business" of this Form 10-K).
Our contract backlog represents remaining contractual terms and may not reflect actual revenue due to renegotiations or a number of factors such as rig downtime, out of service time, estimated contract durations, customer concessions or contract cancellations.
About 49% of our remaining available rig days in 2017 and 23% of available rig days in 2018 are included in backlog as revenue producing days as of February 14, 2017, excluding cold-stacked rigs. As of that date, we had two jack-ups that were cold-stacked and six jack-ups and two drillships that were available.

35


Since 2014, we have recognized asset impairment charges on several of our jack-up drilling units as a result of the decline in market conditions and the expectation of future demand and day rates. If market conditions deteriorate further, we could be required to recognize additional impairment charges in future periods.
Investing Activities
Capital expenditures in 2016 totaled $117.6 million and included the following:
$68.5 million for improvements to the existing fleet, including contractually required modifications; and
$49.1 million for rig equipment and other.
We currently estimate our 2017 capital expenditures will range from approximately $105-$115 million, primarily for fleet maintenance, rig equipment, spares and other. This amount excludes any contractual modifications that may arise due to our securing additional work.
We expect to fund our 2017 capital expenditures using available cash and cash flows from operations.
Our 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 forecasted cash flows and liquidity, anticipated market conditions in our business, the availability of financial resources, and alternative uses of capital to enhance shareholder value.
Capital expenditures for 2015 totaled $722.9 million and included $541.3 million towards drillship construction, including costs for mobilization, commissioning, riser gas-handling equipment, software certifications and spares; $132.5 million for improvements to the existing fleet, including contractually required modifications; and $49.1 million for rig equipment inventory and other. With the delivery of our fourth and final drillship in March 2015, we concluded our ultra-deepwater drillship construction program. We took delivery of the first three drillships in 2014.
Capital expenditures for 2014 totaled $2.0 billion and included $1.6 billion towards drillship construction; $345 million for improvements to the existing fleet, including contractually required modifications; and $53 million for rig equipment, spares and other.
Financing Activities
In January 2014, we completed the issuance and sale in a public offering of $400 million aggregate principal amount of 4.75% Senior Notes due 2024 (the "2024 Notes"), and $400 million aggregate principal amount of 5.85% Senior Notes due 2044 (the "2044 Notes"). Net proceeds of the offering were approximately $792 million, which the Company used for its drillship construction program and for general corporate purposes.
In May 2015, we amended and restated our revolving credit agreement to increase the borrowing capacity under the facility from $1 billion to $1.5 billion and to extend the maturity date by one year to January 2020. In January 2016, we further amended the revolving credit agreement to extend the maturity date by one year to January 2021. Availability under the facility is $1.5 billion through January 23, 2019, declining to $1.44 billion through January 23, 2020, and to approximately $1.29 billion through the maturity in 2021. There were no amounts drawn under the revolving credit agreement at December 31, 2016.
Advances under our revolving credit agreement bear interest at LIBOR or Base Rate plus an applicable margin, which is dependent upon our credit ratings. The applicable margins for LIBOR and Base Rate advances range from 1.125% - 2.0% and 0.125% - 1.0%, respectively. We are also required to pay a commitment fee on undrawn amounts of the credit agreement, which ranges from 0.125% to 0.35%, depending on our credit ratings.
The revolving credit agreement requires us to maintain a total debt-to-capitalization ratio of less than or equal to 60%. Additionally, the credit agreement has customary restrictive covenants that, including others, restrict our ability to incur certain debt and liens, enter into certain merger and acquisition agreements, sell, transfer, lease or otherwise dispose of all or substantially all of our assets and substantially change the character of our business from contract drilling.
During 2015, we paid $101.1 million in cash to retire $97.9 million aggregate principal amount of the 5% Senior Notes due 2017 (the "2017 Notes") and 7.875% Senior Notes due 2019 (the "2019 Notes"), plus accrued interest, and recognized a $1.5 million loss on early extinguishment of debt.
During the first half of 2016, we paid $45.2 million in cash to retire $47.9 million aggregate principal amount of the 2017 Notes and 2019 Notes, and recognized a $2.4 million gain on early extinguishment of debt.

36


In December 2016, we commenced cash tender offers for $750 million aggregate principal amount of certain Senior Notes (as defined below) issued by the Company, which such tender offers expired on January 3, 2017. Senior Notes validly tendered and accepted for purchase prior to the early tender expiration time on December 16, 2016, received tender offer consideration plus an early tender premium. As a result of the tender offers, in December 2016, we paid $490.5 million to redeem $463.9 million aggregate principal amount of outstanding Senior Notes, consisting of $265.5 million of the 2017 Notes, $186.7 million of the 2019 Notes, $9.8 million of 4.875% Senior Notes due 2022 (the "2022 Notes") and $1.9 million of the 2024 Notes, and recognized a $33.6 million loss on the early extinguishment of debt which included approximately $5.9 million of bank and legal fees.
On December 19, 2016, we completed the issuance of $500 million aggregate principal amount of 7.375% Senior Notes due 2025 (the "2025 Notes") at a price of 100% of the principal amount. We used the net proceeds of the offering, approximately $492 million, along with cash on hand, to fund the redemption of Senior Notes related to the tender offers. $5.3 million of the cash paid to the underwriting banks in the form of the underwriters discount and structuring fee was expensed and included in the $33.6 million loss on early extinguishment of debt related to the December 2016 tender offers. Interest on the 2025 Notes is payable on June 15 and December 15 of each year, beginning on June 15, 2017. The 2025 Notes contain a provision whereby upon a change of control repurchase event, as defined in the indenture governing the 2025 Notes, we may be required to make an offer to repurchase all outstanding notes at a price in cash equal to 101% of the aggregate principal amount of the notes repurchased, plus any accrued and unpaid interest to the repurchase date. Otherwise, the 2025 Notes contain substantially the same provisions as the Company’s other Senior Notes.
In January 2017, at the expiration of the tender offers, we paid $32.8 million to redeem $34.6 million aggregate principal amount of outstanding Senior Notes, consisting of $0.1 million of the 2017 Notes, $0.9 million of the 2019 Notes and $33.6 million of the 2022 Notes.
On January 9, 2017, we called for redemption $92.1 million aggregate principal amount of the 2017 Notes that remained outstanding and on February 8, 2017, we paid $94.0 million to redeem such notes.
As of December 31, 2016, we had $2.7 billion of outstanding long-term debt consisting of $92.2 million principal amount of the 2017 Notes; $209.8 million principal amount of the 2019 Notes; $690.2 million principal amount of the 2022 Notes; $398.1 million aggregate principal amount of the 2024 Notes; $500.0 million aggregate principal amount of the 2025 Notes; $400.0 million principal amount of 5.4% Senior Notes due 2042; and $400.0 million aggregate principal amount of the 2044 Notes (together, the “Senior Notes”). The Senior Notes are fully and unconditionally guaranteed on a senior and unsecured basis by Rowan plc (see Note 16 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K).
Annual interest payments on the Senior Notes are estimated to be approximately $150 million in 2017. No principal payments are required until each series’ final maturity date. Management believes that cash flows from operating activities, existing cash balances, and amounts available under the revolving credit facility will be sufficient to satisfy the Company’s cash requirements for the following twelve months.
Restrictive provisions in the Company’s bank credit facility agreement limit consolidated debt to 60% of book capitalization. Our consolidated debt to total capitalization ratio at December 31, 2016, was 34%.
Other provisions of our debt agreements limit the ability of the Company to create liens that secure debt, engage in sale and leaseback transactions, merge or consolidate with another company and, in the event of noncompliance, restrict investment activities and asset purchases and sales, among other things. The Company was in compliance with its debt covenants at December 31, 2016, and expects to remain in compliance throughout 2017.

37


Cash Dividends
Prior to 2014, the Company had not paid a quarterly cash dividend since 2008. Cash dividends for 2014 and 2015 are set forth below:
 
 Cash dividend per share
 
Declaration date
 
Record date
 
Payment date
2014:
 
 
 
 
 
 
 
Second quarter
$
0.10

 
4/25/2014
 
5/5/2014
 
5/20/2014
Third quarter
0.10

 
7/31/2014
 
8/11/2014
 
8/26/2014
Fourth quarter
0.10

 
10/30/2014
 
11/11/2014
 
11/25/2014
 
 
 
 
 
 
 
 
2015:
 
 
 
 
 
 
 
First quarter
$
0.10

 
1/29/2015
 
2/9/2015
 
3/3/2015
Second quarter
0.10

 
5/1/2015
 
5/12/2015
 
5/26/2015
Third quarter
0.10

 
7/31/2015
 
8/11/2015
 
8/25/2015
Fourth quarter
0.10

 
10/29/2015
 
11/9/2015
 
11/23/2015
In January 2016, the Company announced that it had discontinued its quarterly dividend.
Off-balance Sheet Arrangements and Contractual Obligations
The Company had no off-balance sheet arrangements as of December 31, 2016 or 2015, 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, 2016, including obligations recognized on our balance sheet and those not required to be recognized (in millions):
 
Payments due by period
 
Total
 
Within 1 year
 
2 to 3 years
 
4 to 5 years
 
After 5 years
Long-term debt principal payment
$
2,690

 
$
92

 
$
210

 
$

 
$
2,388

Interest on Senior Notes
1,866

 
154

 
295

 
269

 
1,148

Purchase obligations
62

 
60

 
2

 

 

Operating leases
35

 
7

 
12

 
5

 
11

Total
$
4,653

 
$
313

 
$
519

 
$
274

 
$
3,547

As of December 31, 2016, our liability for unrecognized tax benefits related to uncertain tax positions totaled $135.0 million, inclusive of interest and penalties. Due to the high degree of uncertainty related to these tax matters, we are unable to make a reasonably reliable estimate as to the timing of cash settlement with the respective taxing authorities, and we have therefore excluded this amount from the contractual obligations presented in the table above.
We periodically employ letters of credit in the normal course of our business, and had outstanding letters of credit of approximately $2.9 million at December 31, 2016.
If the new joint venture company has insufficient cash from operations or financing is not available to fund the cost of the newbuild jack-up rigs, Rowan will be obligated to contribute funds to purchase such rigs, up to a maximum amount of $1.25 billion for all 20 newbuild jack-up rigs (see Part I, Item 1, "Business" of this Form 10-K).
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, 2016, our financial statements reflected an aggregate unfunded pension liability of $228 million. We expect to make minimum contributions to our defined benefit pension plans of approximately $30 million in 2017, and we will continue to make significant pension contributions over the next several years. Additional funding may be required if, for example, future interest rates or pension asset values decline or there are changes in legislation.

38


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.
Depreciation and impairments of long-lived assets
We depreciate our assets using the straight-line method over their estimated useful service lives after allowing for salvage values. We estimate useful lives and salvage values by applying judgments and assumptions that reflect both historical experience and expectations regarding future operations, utilization and performance. Useful lives may be affected by a variety of factors including technological advances in methods of oil and gas exploration, changes in market or economic conditions, and changes in laws or regulations that affect the drilling industry. Applying different judgments and assumptions in establishing useful lives and salvage values may result in values that differ from recorded amounts. In connection with the completion of an asset impairment test in 2014, we reevaluated our policy with respect to salvage values and, in light of our historical experience, we reduced salvage values for our jack-up rigs from 20 percent to 10 percent of historical cost.
We evaluate the carrying value of our property and equipment, primarily our drilling rigs, whenever events or changes in circumstances indicate that their carrying values may not be recoverable. Potential impairment indicators include rapid declines in commodity prices, stock prices, rig utilization and day rates, among others. The offshore drilling industry has historically been highly cyclical and it is not unusual for rigs to be underutilized or idle for extended periods of time and subsequently resume full or near full utilization when business cycles improve. Similarly, during periods of excess supply, rigs may be contracted at or near cash break-even rates for extended periods. Impairment situations may arise with respect to specific rigs, specific categories or classes of rigs, or rigs in a certain geographic region. Our rigs are mobile and may generally be moved from regions with excess supply, if economically feasible.
Asset impairment evaluations are, by nature, highly subjective. In most instances, they involve expectations of future cash flows to be generated by our drilling rigs and are based on management's judgments and assumptions regarding future industry conditions and operations, as well as management's estimates of future expected utilization, contract rates, expense levels and capital requirements. The estimates, judgments, and assumptions used by management in the application of our asset impairment policies reflect both historical experience and an assessment of current operational, industry, market, economic and political environments. The use of different estimates, judgments, assumptions (including discount rates) and expectations regarding future industry conditions and operations would likely result in materially different asset carrying values and operating results.
In 2016, 2015 and 2014, we conducted impairment tests of our assets and determined that the carrying values of certain jack-up rigs were not recoverable from their undiscounted cash flows and exceeded their fair values. As a result, we recognized non-cash asset impairment charges of approximately $34 million, $330 million and $566 million in 2016, 2015 and 2014, respectively (see Note 2 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K).
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, 2016, included weighted average discount rates of 4.29% and 4.53% used to determine pension benefit obligations and net cost, respectively, an expected long-term rate of return on pension plan assets of 7.15% and annual healthcare cost increases ranging from 6.9% in 2016 to 4.5% in 2038 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 $93.7 million, while a one-percentage-point decrease (increase) in the expected long-term rate of return on plan assets would increase (decrease)

39


annual net benefits cost by approximately $5.4 million. A one-percentage-point increase in the assumed healthcare cost trend rate has no impact on 2016 other postretirement benefit cost. To develop the expected long-term rate of return on assets assumption, we considered the current level of expected returns on risk-free investments (primarily government bonds), the historical level of the risk premium associated with the plans’ other asset classes, and the expectations for future returns of each asset class. The expected return for each asset class was then weighted based upon the current asset allocation to develop the expected long-term rate of return on assets assumption for the plan, which was reduced to 7.15% at December 31, 2016, from 7.30% at December 31, 2015.
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 $120 million at December 31, 2016, is properly recorded in accordance with the accounting guidelines.
Recent Accounting Pronouncements
See Note 2 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K.
ITEM 7A.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS
Interest rate risk – Our outstanding debt at December 31, 2016, consisted entirely of fixed-rate debt with a carrying value of $2.680 billion and a weighted-average annual interest rate of 5.8%. 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.
Currency exchange rate risk A substantial majority of our revenues are received in U.S. dollars, which is our functional currency. However, in certain countries in which we operate, local laws or contracts may require us to receive some payment in the local currency. We are exposed to foreign currency exchange risk to the extent the amount of our monetary assets denominated in the foreign currency differs from our obligations in that foreign currency. In order to mitigate the effect of exchange rate risk, we attempt to limit foreign currency holdings to the extent they are needed to pay liabilities in the local currency. Prior to 2016, we entered into spot purchases or short-term derivative transactions, such as forward exchange contracts, with one-month durations. We did not enter into such transactions for the purpose of speculation, trading or investing in the market and we believe that our use of forward exchange contracts has not exposed us to material credit risk or other material market risk. Although our risk policy allows us to enter into such forward exchange contracts, we do not currently anticipate entering into such transactions in the future and had no such contracts outstanding as of December 31, 2016.
Commodity price risk Fluctuating commodity prices affect our future earnings materially to the extent that they influence demand for our products and services.
Fair Value Derivative Asset At December 31, 2016, the fair value of the Contingent Payment Derivative related to the FMOG Provision was $6.1 million. We estimate the fair value of this instrument using Monte Carlo simulation which takes into account a variety of factors including the Price Targets, the WTI Spot price, the expected volatility, the risk-free interest rate, the slope of the WTI forward curve, and the remaining contractual term of the FMOG Provision. We are required to revalue this instrument each quarter. We believe that the assumptions that have the greatest impact on the determination of fair value is the WTI Spot Price on the valuation date and the expected volatility. In January 2017, a portion of the Contingent Payment Derivative was settled with a $6.0 million payment received by the Company. (see Note 1 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K). The following table illustrates the potential effect on the fair value of the derivative asset at December 31, 2016 from changes in the assumptions made (in millions):
 
Increase (Decrease)
in Asset Value
10% decrease in WTI spot price
$
(3.3
)
10% decrease in expected volatility
$
0.2


40


ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
 

41


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, 2016 and 2015, and the related consolidated statements of operations, comprehensive income (loss), changes in shareholders’ equity, and cash flows for each of the three years in the period ended December 31, 2016. Our audits also included the financial statement schedule listed in the Index at Item 15. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on the financial statements and financial statement schedule 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, 2016 and 2015, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2016, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly, in all material respects, the information set forth therein.
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, 2016, based on the criteria established in Internal Control Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 24, 2017 expressed an unqualified opinion on the Company’s internal control over financial reporting.

 
/s/ DELOITTE & TOUCHE LLP
Houston, Texas
February 24, 2017

42


ROWAN COMPANIES PLC
MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
The management of Rowan is responsible for establishing and maintaining adequate internal control over financial reporting for the Company as defined in Rules 13a-15(f) and 15d-15(f) of the Securities Exchange Act of 1934, as amended.  Our internal controls were designed to provide reasonable assurance as to the reliability of our financial reporting and the preparation and presentation of consolidated financial statements in accordance with accounting principles generally accepted in the United States, as well as to safeguard assets from unauthorized use or disposition.
We are required to assess the effectiveness of our internal controls relative to a suitable framework.  The Committee of Sponsoring Organizations of the Treadway Commission (COSO) in its Internal Control - Integrated Framework (2013), developed a formalized, organization-wide framework that embodies five interrelated components — the control environment, risk assessment, control activities, information and communication and monitoring, as they relate to three internal control objectives — operating effectiveness and efficiency, financial reporting reliability and compliance with laws and regulations.
Our assessment included an evaluation of the design of our internal control over financial reporting relative to COSO and testing of the operational effectiveness of our internal control over financial reporting. Based upon our assessment, we have concluded that our internal controls over financial reporting were effective as of December 31, 2016.
The independent registered public accounting firm Deloitte & Touche LLP has audited Rowan’s consolidated financial statements and financial statement schedule included in our 2016 Annual Report on Form 10-K and has issued an attestation report on the Company’s internal control over financial reporting.
/s/ THOMAS P. BURKE
/s/ STEPHEN M. BUTZ                                    
Thomas P. Burke
Stephen M. Butz
President and Chief Executive Officer
Executive Vice President and Chief Financial Officer